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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(Amendment No. 1)
FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTIONS 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 2005
or
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Transition Period From to
Commission File Number 001-32331
Foundation Coal Holdings, Inc.
(Exact Name of Registrant as Specified in Its Charter)
| Delaware | 42-1638663 | |
(State or Other Jurisdiction of Incorporation or Organization)
| (I.R.S. Employer Identification No.) | |
999 Corporate Boulevard, Suite 300 Linthicum Heights, Maryland | 21090 | |
| (Address of Principal Executive Offices) | (Zip Code) |
Registrant’s telephone number, including area code) (410) 689-7500
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class | Name of Each Exchange on Which Registered | |
| Common Stock, $0.01 par value | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
The aggregate market value of the Registrant’s voting and non-voting common equity held by non-affiliates of the Registrant calculated using the June 30, 2006 closing price on the New York Stock Exchange, was $2,112.1 million. There were 45,735,643 shares of common stock outstanding on July 31, 2006.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of Registrant’s definitive Proxy Statement submitted to the Registrant’s stockholders in connection with our 2006 Annual Stockholders Meeting was held on May 18, 2006, are incorporated by reference into Part III of this report. The definitive proxy statement was filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this report relates.
Table of Contents
| Page | |||||
| PART I | |||||
ITEM 1. | BUSINESS | 4 | |||
ITEM 1A. | RISK FACTORS | 29 | |||
ITEM 1B. | UNRESOLVED STAFF COMMENTS | (1 | ) | ||
ITEM 2. | PROPERTIES | 42 | |||
ITEM 3. | LEGAL PROCEEDINGS | (1 | ) | ||
ITEM 4. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS | (1 | ) | ||
| PART II | |||||
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS | (1 | ) | ||
ITEM 6. | SELECTED FINANCIAL DATA | (1 | ) | ||
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION | 44 | |||
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 78 | |||
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | (1 | ) | ||
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | (1 | ) | ||
| PART III | |||||
ITEM 10. | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT | (1 | ) | ||
ITEM 11. | EXECUTIVE COMPENSATION | (1 | ) | ||
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT | (1 | ) | ||
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS | (1 | ) | ||
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES | (1 | ) | ||
| PART IV | |||||
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | 79 | |||
| (1) | Not affected by this Amendment No. 1. Refer to the original Form 10-K previously filed on March 16, 2006. |
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EXPLANATORY NOTE
In response to comments raised by the Staff of the Securities and Exchange Commission, this Form 10-K/A (Amendment No. 1) is being filed by Foundation Coal Holdings, Inc. (the “Company”) to (a) revise Items 1, 1A and 2 to change the terminology “reserve base” to “reserves”; (b) revise Item 1 with respect to the description of unleased federal coal that adjoins the Belle Ayr mine; (c) supplement the mine location map in Item 1 to include smaller-scale maps showing the location of and access to each mine; (d) revise Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A), to eliminate references to “combined pro forma” and “pro forma results” (Non-GAAP combined results of operations for the twelve months ended December 31, 2004 are now compared to the successor results of operations for the year ended December 31, 2005 and to the predecessor results of operations for the year ended December 31, 2003, presented on a historical basis pursuant to the requirements of Item 303(a)(3) of Regulation S-K); and (e) supplement Item 7 by inserting graphs of representative steam coal prices and discussion of the “Other” segment in the segment analysis for the year ended December 31, 2005 compared to the non-GAAP combined twelve months ended December 31, 2004 and in the segment analysis for the non-GAAP combined twelve months ended December 31, 2004 compared to the year ended December 31, 2003.
This amendment modifies Item 7A to correct a typographical error in the third paragraph of the Interest Rate Risk subheading.
As the amendment relates only to Items 1, Business, 1A, Risk Factors, 2, Properties, 7, MD&A and Item 7A, Quantitative and Qualitative Disclosures about Market Risk, the previously issued consolidated financial statements and notes thereto are unchanged. No attempt has been made in this Form 10-K/A to modify or update disclosures in the original report on Form 10-K (“original Form 10-K”) except as required to make the revisions and supplemental disclosures described in the preceding paragraph. This Form 10-K/A does not reflect events occurring after the filing of the original Form 10-K or modify or update any related disclosures. Information not affected by the amendment is unchanged and reflects the disclosure made at the time of the filing of the original Form 10-K with the Securities and Exchange Commission on March 16, 2006. Accordingly, this Form 10-K/A should be read in conjunction with the original Form 10-K and the Company’s filings made with the Securities and Exchange Commission subsequent to the filing of the original Form 10-K including any amendments to those filings.
The complete texts of Items 1, 1A, 2 and 7 are set forth herein, including those portions of the text that have not been amended from that set forth in the original form 10-K. The only changes are described in items (a) through (e) in the second preceding paragraph above.
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To aid readers unfamiliar with the terms commonly used in the coal industry, a glossary of selected terms is provided at the end of “Item 1. Business.”
Unless the context otherwise indicates, as used in this Annual Report on Form 10-K (“10-K”) the terms “we” “our” “us” and similar terms refer to Foundation Coal Holdings, Inc. and its consolidated subsidiaries. For purposes of all financial disclosure contained herein, RAG American Coal Holding, Inc. is the predecessor to Foundation Coal Holdings, Inc. We and our indirect subsidiary, Foundation Coal Corporation, were formed to acquire the North American coal mining assets of RAG Coal International AG, which acquisition closed on July 30, 2004 (the “Acquisition”). All references to Foundation Coal Holdings, Inc., including the business description, operating data and financial data, excludes RAG Coal International AG’s former Colorado operations, which were sold to a third party on April 15, 2004 and are accounted for herein as discontinued operations. On December 9, 2004, we completed an initial public offering of 24,121,900 shares of our common stock which we refer to herein as the Initial Public Offering (“IPO”). Certain statements in this 10-K are forward-looking statements. To facilitate trend analysis we compare the historical financial data of Foundation Coal Holdings, Inc. (the Successor) for the year ended December 31, 2005 and of RAG American Coal Holding, Inc. (the Predecessor) for the year ended December 31, 2003 with the “non-GAAP combined” financial data for the year ended December 31, 2004. Non-GAAP combined financial data for the year ended December 31, 2004 are determined by adding the historical amounts of the Predecessor for the period from January 1, 2004 through July 29, 2004 with the corresponding amounts of the Successor for the five month operating period ended December 31, 2004. Non-GAAP combined amounts for the year ended December 31, 2004 are not recognized measures under GAAP and do not purport to be alternatives to GAAP operating measures. Non-GAAP combined amounts are not indicative of the operating results of Foundation Coal Holdings, Inc. because of the significant difference in basis between the Successor and Predecessor caused by the acquisition on July 30, 2004 and its impact on income from operations. Management believes that the discussion of non-GAAP combined operating results is important to the readers of the financial statements to understand key operating trends over the normal operating cycle years 2005, 2004 and 2003. Non-GAAP combined amounts are reconciled to the underlying historical GAAP basis financial statements on page 47.
Overview
We are the fifth largest coal producer in the United States. We operate a diverse group of thirteen mines located in Wyoming, Pennsylvania, West Virginia and Illinois. For the year ended December 31, 2005, we sold 68.8 million tons of coal, including 66.3 million tons that were produced and processed at our operations. As of December 31, 2005, we had approximately 1.7 billion tons of proven and probable coal reserves. We are also involved in marketing coal produced by others to supplement our own production and, through blending, provide our customers with coal qualities beyond those available from our own production. We purchased and resold 2.5 million tons of coal in 2005.
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 92% of our coal sales revenue in 2005. We also sell metallurgical coal to steel producers; metallurgical sales accounted for 3% of our coal sales volume and 8% of our coal sales revenue in 2005.
As of December 31, 2005, we had a total sales backlog of over 330 million tons of coal, and our coal supply agreements have remaining terms ranging from one to 16 years. For 2005, based on sales revenues we sold approximately 79% of our sales volume under long-term coal supply agreements. We consider sales commitments with a duration of twelve months or longer as a “long-term” contract as opposed to spot sales agreements with a duration less than twelve months. As of January 24, 2006, we had sales and price commitments for approximately 96% of our planned 2006 production, approximately 75% of our planned 2007 production, approximately 50% of our planned 2008 production and approximately 37% of our planned 2009 production.
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Competitive Strengths
We believe that the following competitive strengths enhance our prominent market position in the United States:
We are the fifth largest coal producer in the United States and have significant coal reserves. Based on 2005 production of 66.3 million tons, we are the fifth largest coal producer in the United States. As of December 31, 2005, we controlled approximately 1.7 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, 2005, we have a total reserve life of approximately 26 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, Central Appalachia and the Illinois Basin, 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 by approximately 2.0% annually through 2030, according to the Energy Information Administration (“EIA”). 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 2002, 2003, 2004 and 2005. 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 2005 injury incident rates, as tracked by the Mine Safety and Health 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 25 years of experience in the coal industry, including an average of 16 years of experience operating our assets when owned by us and our predecessors, and have the management and organizational capability to successfully operate an independent public company.
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, 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.
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Capitalizing on favorable industry dynamics through an opportunistic 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 coal forward prices, we believe will continue for the foreseeable future. We employ an opportunistic 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 each of the 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 currently plan to seek to increase 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 the four 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.
On June 30, 1999, Cyprus Amax Minerals Company and its subsidiary, Amax Energy Inc., sold the stock of Cyprus Amax Coal Company and all of its subsidiaries consisting of its remaining coal properties to RAG International Mining GmbH (now RAG Coal International AG (“RAG”)).
Foundation Coal Holdings, LLC was formed on February 9, 2004, by a group of investors for the purpose of acquiring the United States coal properties owned by RAG Coal International AG. A Stock Purchase Agreement was signed on May 24, 2004.
Foundation Coal Holdings, LLC, through its subsidiary, Foundation Coal Corporation, and pursuant to the Stock Purchase Agreement, completed the Acquisition of 100% of the outstanding common shares of RAG American Coal Holding, Inc. and its subsidiaries from RAG Coal International AG, on July 30, 2004 (the “Transaction”).
Foundation Coal Holdings, LLC, merged on August 17, 2004 into its subsidiary, Foundation Coal Holdings, Inc., a Delaware corporation that was formed on July 19, 2004. Foundation Coal Holdings, Inc. was the surviving entity in this merger. On December 9, 2004, we completed the IPO of Foundation Coal Holdings, Inc.
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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 and our Wabash mine in Illinois 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 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. Much 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 1.0 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 1.1 billion tons in 2005. The growth in the demand for coal has coincided with an increased demand for coal from electric power generators.
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The following table sets forth demand trends for United States coal by consuming sector as projected by the EIA for the periods indicated (totals may not foot due to rounding).
| Actual | Preliminary(1) | Projected(2) | Annual Growth | |||||||||||||||
Consumption by Sector | 2002 | 2003 | 2004 | 2005 | 2010 | 2020 | 2004-2010 | 2010-2025 | ||||||||||
| (tons in millions) | ||||||||||||||||||
Electric Generation | 978 | 1,005 | 1,016 | 1,051 | 1,140 | 1,235 | 1.9 | % | 0.8 | % | ||||||||
Industrial | 61 | 61 | 62 | 64 | 66 | 66 | 1.1 | % | 0.0 | % | ||||||||
Steel Production | 24 | 24 | 24 | 24 | 23 | 22 | (0.6 | )% | (0.5 | )% | ||||||||
Coal-to-Liquids Processes | 0 | 0 | 0 | 0 | 0 | 62 | N/A | N/A | ||||||||||
Residential/Commercial | 4 | 4 | 5 | 4 | 4 | 4 | (0.4 | )% | 0.0 | % | ||||||||
Export | 40 | 43 | 48 | 50 | 41 | 19 | 0.4 | % | (7.5 | )% | ||||||||
Total | 1,106 | 1,138 | 1,155 | 1,194 | 1,274 | 1,408 | 1.8 | % | 1.0 | % | ||||||||
| (1) | Preliminary data estimates for 2005 are based on data published in the EIA’s Quarterly Coal Report through the third quarter of 2005 and output from the EIA’s National Energy Modeling System. |
| (2) | Projected 2004-2005 Data per EIA Annual Energy Outlook 2006 |
The nation’s power generation infrastructure is largely 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. Non-hydropower renewable power generation accounts for only 1.4% of all the electricity generated in the United States, and wind and solar power—the alternative fuel sources that may provide more environmental benefits—represent 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 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. Based on data available through November 2005, 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, as follows:
Electrical Generation Type | Cost per Megawatt Hour | ||
Natural Gas | $ | 75.29 | |
Oil | $ | 78.34 | |
Renewables* | $ | 25.01 | |
Coal | $ | 21.21 | |
Nuclear | $ | 20.21 | |
Hydroelectric | $ | 7.43 | |
| * | Includes: Energy generation from wind, solar, biomass, geothermal, tidal and wave sources. |
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Coal Production. United States coal production was approximately 1.1 billion tons in 2005. The following table, derived from data prepared by the EIA, sets forth production statistics in each of the four major coal producing regions for the periods indicated (totals may not foot due to rounding).
| Actual | Preliminary(1) | Projected(2) | Annual Growth | |||||||||||||||
Consumption by Sector | 2002 | 2003 | 2004 | 2005 | 2010 | 2025 | 2004-2010 | 2010-2025 | ||||||||||
| (tons in millions) | ||||||||||||||||||
Powder River Basin | 397 | 400 | 421 | 446 | 486 | 661 | 2.4 | % | 2.1 | % | ||||||||
Central Appalachia | 249 | 231 | 233 | 214 | 202 | 156 | (2.4 | )% | (1.7 | )% | ||||||||
Northern Appalachia | 140 | 137 | 148 | 161 | 202 | 216 | 5.3 | % | 0.5 | % | ||||||||
Illinois Basin | 96 | 92 | 94 | 102 | 133 | 180 | 5.9 | % | 2.0 | % | ||||||||
Other | 223 | 223 | 228 | 222 | 239 | 318 | 0.8 | % | 1.9 | % | ||||||||
Total | 1,105 | 1,083 | 1,125 | 1,145 | 1,261 | 1,530 | 1.9 | % | 1.3 | % | ||||||||
| (1) | Preliminary data estimates for 2005 are based on data published in the EIA’s Quarterly Coal Report through the third quarter of 2005 and output from the EIA’s National Energy Modeling System. |
| (2) | Projected 2004-2025 Data per EIA Annual Energy Outlook 2006. |
Coal Regions. Coal is mined from coal fields throughout the United States, with the major production centers located in the Western United States, Northern and Central Appalachia and the Illinois Basin. The quality of coal varies by region. Heat value and sulfur content are two of the most important coal characteristics in measuring quality and determining the best end use of particular coal types.
Competition. The coal industry is intensely competitive. The most important factors on which we compete are coal price at the mine, coal quality and characteristics, transportation costs from the mine to the customer and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which are influenced by factors beyond our control. 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 paying the ocean freight.
Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivered costs. Transportation can be a large component of a purchaser’s total cost. Although the purchaser pays the freight, transportation costs still are important to coal mining companies because the purchaser may choose a supplier largely based on cost of transportation. According to the National Mining Association (“NMA”), railroads account for nearly two-thirds of total United States coal shipments, while river barge movements account for an additional 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 various 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 and sub-bituminous coal, characteristics of which are described below.
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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.
Sub-bituminous coal typically has a lower sulfur content than bituminous coal, but some of our bituminous coal in West Virginia also has a low sulfur content.
High sulfur coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions. 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. 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 77,000 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 clean coal-burning technology.
Operations
As of December 31, 2005, we operated a total of 13 mines located in Wyoming, Pennsylvania, West Virginia and Illinois. We currently own most of the equipment utilized in our mining operations.
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The following table provides summary information regarding our principal mining complexes as of December 31, 2005.
Mining Complex | Number of Mines | Type of Mine | Mining Technology | Transportation | Tons Sold in 2005 | |||||
| (in millions) | ||||||||||
Wyoming | ||||||||||
Belle Ayr | 1 | Surface | Truck-and-Shovel | BNSF, UP | 19.5 | |||||
Eagle Butte | 1 | Surface | Truck-and-Shovel | BNSF | 24.1 | |||||
Pennsylvania | ||||||||||
Cumberland | 1 | Underground | Longwall | Barge | 7.0 | |||||
Emerald | 1 | Underground | Longwall | CSX, NS | 6.7 | |||||
West Virginia | ||||||||||
Kingston | 2 | Underground | Room-and-Pillar | Barge, CSX, NS | 1.2 | |||||
Laurel Creek | 3 | Underground | Room-and-Pillar | Barge, CSX | 1.5 | |||||
Rockspring | 1 | Underground | Room-and-Pillar | NS | 3.0 | |||||
Pioneer | 2 | Surface | Truck and Front-End Loader | Barge, NS | 1.6 | |||||
Purchased and resold coal | 1.7 | |||||||||
Illinois | ||||||||||
Wabash | 1 | Underground | Room-and-Pillar | NS | 1.7 | |||||
Other | ||||||||||
Purchased and resold coal | — | 0.8 | ||||||||
Total | 13 | 68.8 | ||||||||
| BNSF = Burlington Northern Santa Fe Railroad | NS = Norfolk Southern Railroad | |
| CSX = CSX Railroad | UP = Union Pacific Railroad |
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 1.3 million tons of metallurgical coal. The tonnage shown in the two categories labeled purchased and resold includes 0.8 million tons of metallurgical coal.
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The following map outlines our operations, sales of produced coal, tons sold and reserves as of December 31, 2005.
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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 676.8 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 43.6 million tons of coal in 2005, or 66% of our total production volume. The two mines employ approximately 510 salaried and hourly employees. Our Powder River Basin mines have produced over 900 million tons of coal since 1972.
Belle Ayr Mine
The Belle Ayr mine, located approximately 18 miles southeast of Gillette, Wyoming, extracts coal from the Wyodak-Anderson Seam, which averages 75 feet thick, using the truck-and-shovel mining method. Belle Ayr shipped 19.5 million tons of coal in 2005. The mine sells 100% of raw coal mined and no washing is necessary. Belle Ayr has approximately 330.7 million tons of reserves. The reserves at Belle Ayr will sustain projected production for approximately 13 years. 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 Burlington Northern Santa Fe Railroad and the Union Pacific Railroad.
Eagle Butte Mine
The Eagle Butte mine, located approximately eight miles north of Gillette, Wyoming, extracts coal from the Roland and Smith Seams, which total 100 feet thick, using the truck-and-shovel mining method. Eagle Butte shipped 24.1 million tons of coal in 2005. The mine sells 100% of the raw coal mined and no washing is necessary. Eagle Butte has approximately 346.1 million tons of reserves. The reserves will sustain projected production levels for 14 years. We have applied to lease approximately 240 million tons of surface mineable, unleased federal coal adjoining the western boundary of the mine property. The LBA sale is scheduled for 2007. If we prevail in the bidding process and obtain this lease, we will be able to extend the mine’s life by approximately an additional 10 years, based on the mine’s 2005 rate of production. Coal from Eagle Butte is shipped on the Burlington Northern Santa Fe Railroad to power plants located throughout the Midwest and the South.
Pennsylvania Operations
We control approximately 764.4 million tons of contiguous reserves in Northern Appalachia. Approximately 200.4 million tons are assigned to active mines. Approximately 564.0 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 13.7 million tons in 2005 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 7.0 million tons of coal in 2005. As of December 31, 2005, Cumberland had assigned reserves of 102.3 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 611 salaried and hourly employees.
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Emerald Mine
The Emerald mining complex, located approximately two miles south of Waynesburg, Pennsylvania, was established in 1977. As of December 31, 2005, Emerald had assigned reserves of approximately 98.1 million tons. Emerald shipped 6.7 million tons of coal in 2005. Emerald has the ability to store clean coal and blend variable sulfur products to meet customer requirements. All of Emerald’s coal is processed through a preparation plant before being loaded into unit trains operated by the Norfolk Southern Railroad or the CSX Railroad. The mine also has the option to ship a portion of its coal by truck. Approximately 577 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 operates two surface mines utilizing truck/loader systems to extract coal from multiple seams. Our West Virginia operations have approximately 76.7 million tons of reserves that are assigned to current operations and approximately 124.5 million tons of reserves that are unassigned and are being held for future development. Except for the two surface 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 2005, our West Virginia mines collectively sold 8.9 million tons of produced and purchased coal. Our West Virginia mines ship coal by either the Norfolk Southern Railroad or the CSX Railroad or by barge on the Kanawha and Big Sandy Rivers. These operations serve a diversified customer base, including regional and national customers. We also own and operate the Rivereagle loading facility on the Big Sandy River in Boyd County, Kentucky.
Our West Virginia operations have approximately 792 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 (the “NLRB”). If the NLRB finds that the UMWA was properly elected, approximately 248 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 2005, the Kingston complex shipped 1.1 million tons and as of December 31, 2005 had approximately 12.1 million tons of reserves of which approximately 8.9 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 delivered via the CSX Railroad or the Norfolk Southern Railroad for shipment by rail.
Laurel Creek Mines
The Laurel Creek mining complex consists of three underground mines, #1, #4 and #6 operating in the Coalburg 5 Block and Cedar Grove seams respectively, and a preparation plant located in Logan and Mingo Counties. In 2005, the mines shipped 1.5 million tons and as of December 31, 2005 had approximately 11.7 million tons of assigned reserves and approximately 15.3 million tons of unassigned reserves. The coal is shipped by truck primarily to our Rivereagle dock, other third-party docks or a rail siding on the CSX Railroad.
Rockspring Mine
Rockspring Development, Inc. operates a large multiple section mining complex in Wayne County called Camp Creek that produces coal from the Coalburg Seam. The complex shipped 3.0 million tons of coal in 2005. Assigned and unassigned coal reserves totaled approximately 44.3 million tons and 22.7 million tons, respectively. Rockspring has a mine site rail loadout. The coal is transported on the Norfolk Southern Railroad, primarily to southeastern utilities. The mine can also ship a portion of its production by truck.
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Pioneer Mines
Pioneer Fuel Corporation operates two active surface mines, Paynter Branch which is located in Wyoming County and Pax surface mine which is located in Raleigh County. These mines utilize front-end loaders with trucks to mine multiple seams. The Pioneer Mines shipped 1.5 million tons of primarily steam coal in 2005. As of December 31, 2005, the mines had assigned reserves of approximately 11.8 million tons with an additional 19.4 million tons of unassigned reserves. Based on 2005 production rates, we expect that the Paynter Branch mine has sufficient reserves to last approximately six years. We expect that the Pax mine has sufficient reserves to last approximately eight years. Coal from Paynter Branch is shipped by truck to a loading facility on the Norfolk Southern Railroad and then on to domestic utilities and exported to metallurgical coal customers. Coal from Pax is trucked to the Kanawha River for shipment by barge or may be transported by truck to an on-site loading facility utilized by Paynter Branch for rail shipment on the Norfolk Southern Railroad. The Pax mine is currently constructing an on-site loading facility which will allow loading on the CSX Railroad.
Illinois Operations
Wabash Mine
The Wabash Mine is a room-and-pillar operation, mining in the Illinois No. 5 seam, located in Wabash County, Illinois in the Illinois Basin just east of Keensburg. The mine shipped 1.7 million tons of steam coal in 2005. After cleaning in the preparation plant, the coal is shipped via the Norfolk Southern Railroad to power plants located in the Illinois Basin, in particular to the PSI Gibson Station in Owensville, Indiana, one of the largest power plants in the U.S.
The hourly work force at the Wabash Mine is represented by the UMWA. Wabash has approximately 268 salaried and hourly employees.
As of March 2006, we have existing commitments for most of the Wabash Mine production through 2009.
FutureGen Industrial Alliance, Inc.
We are a founding member of the FutureGen Industrial Alliance, Inc. This is a non-profit company that is partnering with the U.S. Department of Energy to facilitate the design, construction and operation of the world’s first near-zero emission coal-fueled power plant. The FutureGen plant will demonstrate advanced coal-based technologies to gasify coal and generate electricity, and also produce hydrogen to power fuel cells for transportation and other energy needs. The technology also will integrate the capture of carbon emissions with carbon sequestration, helping to address the issue of climate change as energy demand continues to grow worldwide. The alliance announced in December 2005 that it entered into a limited scope cooperative agreement with the U.S. Department of Energy to develop and site in the United States the cleanest coal-fueled power plant in the world with a target of zero emissions, hydrogen production and carbon dioxide sequestration capabilities. Activities for site selection and conceptual design are underway.
Long-Term Coal Supply Agreements
As of December 31, 2005, we had a total sales backlog of over 330 million tons of coal, and our coal supply agreements have remaining terms ranging from one to 16 years. For 2005, based on sales revenues we sold approximately 79% of our sales volume under long-term coal supply agreements with a duration of twelve months or longer. In 2005, 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 24, 2006, we had sales and price commitments for approximately 96% of our planned 2006 production, approximately 75% of our planned 2007 production, approximately 50% of our planned 2008 production and approximately 37% of our planned 2009 production. To the extent we do not renew or replace expiring long-term coal supply agreements, our future sales will be exposed to market fluctuations.
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The terms of our coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly by customer, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, future regulatory changes, extension options, force majeure, termination and assignment provisions.
Some of our long-term contracts provide for a predetermined adjustment to the stipulated base price at times specified in the agreement or at other periodic intervals to account for changes due to inflation or deflation. In addition, most of our contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that impact our costs related to performance of the agreement. Additionally, some of our contracts contain provisions that allow for the recovery of costs impacted by modifications or changes in the interpretations or application of any applicable statute by local, state or federal government authorities.
Price reopener provisions are present in some of our long-term contracts. These provisions may allow either party to commence a renegotiation of the contract price at a pre-determined time. In a limited number of agreements, if the parties do not agree on a new price, either party has an option to terminate the contract. Under some of our contracts, we have the right to match lower prices offered to our customers by other suppliers.
Quality and volumes for the coal are stipulated in coal supply agreements, and in some instances buyers have the option to vary annual or monthly volumes. Most of our coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat content, sulfur, ash, hardness and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts.
Some of our contracts set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions, mine closures or serious transportation problems that affect us or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement or at the discretion of the buyer. Many of our contracts contain similar clauses covering changes in environmental laws. We often negotiate the right to supply coal that complies with new environmental requirements to avoid contract termination.
In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines as long as the replacement coal meets quality specifications and will be sold at the same delivered cost.
Sales and Marketing
Through our sales, trading and marketing entities, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and agent, trade coal and emission allowances and provide transportation-related services. Our sales, marketing, and trading affiliate, Foundation Energy Sales, Inc., employs staff to handle trading, transportation, market research, contract administration and risk/credit management activities.
Transportation
Coal consumed domestically is usually sold at the mine, and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port.
We depend upon rail, barge, trucking and other systems to deliver coal to markets. In 2005, our produced coal was transported from the mines to the customer primarily by rail, with the main rail carriers being the CSX, Norfolk Southern, Burlington Northern Sante Fe and the Union Pacific. The majority of our sales volume is shipped by rail, but a portion of our production is shipped by barge and truck. All coal from our Belle Ayr Mine in Wyoming is shipped by two competing railroads, the Burlington Northern Santa Fe Railroad and the Union Pacific Railroad, while output from our Eagle Butte operation moves via the Burlington Northern Santa Fe Railroad. The Wabash Mine in Illinois is serviced by the Norfolk Southern Railroad. The Pioneer, Kingston, Laurel Creek and Rockspring Mines in West Virginia are serviced by a combination of the Norfolk Southern Railroad and the CSX Railroad, as well as by truck and barge. In Pennsylvania, the Emerald Mine is serviced by the Norfolk Southern Railroad and the CSX Railroad and the Cumberland Mine is serviced by barge.
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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 $400 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.
Technological Innovation
We have been active in identifying new technologies to improve productivity, lower unit costs and make operations safer. In addition, we have enlisted our suppliers to assist us in developing these new technologies.
Examples of new technological improvements in both our underground and surface operations include:
Two Meter Wide Shields. Cumberland is the first underground mine in the world to fully utilize 2.0 meter wide shields in place of the industry standard 1.75 meter shields. This has reduced the number of longwall shields by 14%, reduced the number of shields to move and reduced the number of components in the longwall system.
Longwall Face Extension. Our Pennsylvania operations have extended the longwall face from 1,000 feet to 1,250 feet and further extended the Emerald face to 1,450 feet in June 2005. These wider longwall faces improve coal recovery and reduce the ratio of continuous miner development work per unit of longwall coal extracted.
Real-Time Truck Dispatch. Our large western surface mines utilize 240 and 360 ton haul trucks. We were the first operator in the Powder River Basin to utilize a real-time dispatch system. The company estimates that this innovation has improved truck productivity by 10% by more fully utilizing the truck asset through automatically assigning the trucks to the shovels that have the greatest need for additional trucks.
Underground Diesel Equipment. We were the first mining company in Pennsylvania to utilize underground diesel equipment, thereby eliminating battery charging requirements and facilitating a continuous duty cycle.
Pumpable Cribs. Roof support is critical in any underground mine to maintain entry stability and safety. We pioneered the use of pumpable cribs which replaced the traditional wooden cribs in certain secondary support areas. The pumpable crib utilizes a low-density concrete that is mixed on the surface and then pumped underground into pre-fabricated forms. The hardened concrete has greater roof support density and a more uniform support base than wooden cribs. This process eliminated the need to haul wood blocks underground to build the cribs and has reduced accident exposure for our employees.
Real-Time Monitoring. The large surface mines use on-line equipment monitoring to increase haul truck payloads by 6%. Maintenance personnel can monitor equipment performance real time and detect problems early, thereby reducing maintenance costs and improving availability. The equipment operators also get immediate feedback on the performance characteristics of their equipment and operating conditions and thus can adjust their management of the equipment to maximize productivity and minimize costs and downtime.
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Employees
As of December 31, 2005, we and our subsidiaries had approximately 2,900 employees. As of December 31, 2005, the UMWA represented approximately 40% of our employees, who produced approximately 23% of our coal sales volume during the fiscal year ended December 31, 2005. Relations with organized labor are important to our success and we believe our relations with our employees are satisfactory. Three mining operations (Cumberland, Emerald and Wabash) are signatories to the UMWA collective wage agreement negotiated between the Bituminous Coal Operators Association (the “BCOA”) and the UMWA in 2002. While our operations are not part of the BCOA, we have historically executed collective wage agreements patterned after the industry negotiated collective wage agreement with additional memoranda of understanding to handle local issues. The three wage agreements with the UMWA expire in early 2007, approximately three months after the industry-negotiated collective wage agreement expiration date of December 31, 2006.
ENVIRONMENTAL AND OTHER REGULATORY MATTERS
Federal, state and local authorities regulate the United States coal mining industry with respect to matters such as: employee health and safety; permitting and licensing requirements; emissions to air and discharges to water; plant and wildlife protection; the reclamation and restoration of mining properties after mining has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, surface and groundwater; surface subsidence from underground mining; and the effects of mining on surface and groundwater quality and availability, and competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, pipelines, roads and public facilities. These 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. As a result, future legislation, regulations, interpretations or enforcement may adversely affect our mining operations, cost structure or the ability of our customers to use coal.
We endeavor to conduct our mining operations in compliance with all applicable federal, state, and local laws and regulations. However, 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 permits, may be imposed under the laws described below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.
Mine Safety and Health
The Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977 impose stringent safety and health standards on all aspects of mining operations.
Also, most of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. Regulation has a significant effect on our operating costs.
In early 2006, as a result of the Sago mine incident in West Virginia and other incidents in the coal mining industry, legislative and regulatory bodies at the state and federal levels as well as MSHA have promulgated or proposed various new statutes, rules and regulations relating to mine safety and rescue issues. At this time it is not possible to predict the effect that the new or proposed statutes, rules and regulations will have on our operating costs.
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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 awards.
As of December 31, 2005, 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 Fund into which employers who are “signatory operators” are obligated to pay annual premiums for beneficiaries. The Combined Fund covers a fixed group of individuals who retired before July, 1 1976, and the average age of the retirees in this fund is approximately 80 years of age. Our premium obligations to the Combined Fund are approximately $1,500,000 per year. The Coal Act also created a second benefit fund, the 1992 Plan, for miners who retired between July 1, 1976 and September 30, 1994, and whose former employers are no longer in business to provide them retiree medical benefits. Companies with 1992 Plan liabilities also pay premiums into this plan. Our payment obligations to the 1992 Plan are approximately $1,000,000 per year. These per beneficiary premiums for both the Combined Fund and the 1992 Plan are adjusted annually based on various criteria such as the number of beneficiaries and the anticipated health benefit costs.
Environmental Laws
We and our customers are subject to various federal, state and local environmental laws. Some of the more material of these laws, discussed below, place stringent requirements on our coal mining operations. Federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance.
Mining Permits and Necessary Approvals
Numerous governmental permits, licenses or approvals are required for mining and related operations. When we apply for these permits and approvals, we may be required to present data to federal, state or local authorities pertaining to the effect or impact our operations may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. These requirements may also be added to, modified or re-interpreted from time to time. Regulations also provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding mining permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.
In order to obtain mining permits and approvals from state regulatory authorities we must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit our necessary permit applications several months, or even years, before we plan to begin mining a new area. In the past, we have generally obtained our mining permits in time so as to be able to run our operations as planned. However, we cannot be sure that we will not experience difficulty or delays in obtaining mining permits in the future.
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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. 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 coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. The permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology, and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, the state programs, and the complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land.
Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given that also provides for a comment period before a permit can be issued. Some SMCRA mine permits may take six months to two years or even longer to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.
Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed prior to 1977. The current fee is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. There are proposals to modify this fee and the administration of the Abandoned Mine Land Fund, but any change is not expected to have a material adverse impact on our financial results.
Surety Bonds
Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations including mine closure or reclamation costs, federal and state workers’ compensation costs, obligations under federal coal leases and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis. In recent years, surety bond premium costs have increased and the market terms of surety bonds have generally become more unfavorable. In addition, the number of companies willing to issue surety bonds has decreased. We cannot predict the ability to obtain or the cost of bonds in the future.
Clean Air Act
The Clean Air Act, the Clean Air Act Amendments and the corresponding state laws that regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds emitted by coal-fueled electricity generating plants. Power plants will likely have to continue to install pollution control technology and upgrades. Power plants may be able to recover the costs for these upgrades
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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:
| • | 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. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. At this time, we believe that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur eastern coals, and more demand for western coals, as coal-fired power plants continue to comply with the more stringent restrictions of Title IV. |
| • | Fine Particulate Matter and Ozone. The Clean Air Act requires the Environmental Protection Agency (“EPA”) to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. In 1997, the EPA revised the NAAQS for particulate matter and ozone. Although previously subject to legal challenge, these revisions were subsequently upheld but implementation was delayed for several years. For ozone, these changes include replacement of the existing one-hour average standard with a more stringent eight-hour average standard 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. In December 2005, 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. The EPA expects to finalize these standards by September 2006 and would make the final designations for attainment of PM2.5 standards by 2009 and PM10 standards by 2013. Designated states would have to meet the new standards by 2015 for PM2.5 and 2018 for PM10. Meeting the new PM2.5 standard may require reductions of nitrogen oxide and sulfur dioxide emissions. Future regulation and enforcement of these new ozone and PM2.5 standards will affect many power plants, especially coal-fired plants and all plants in “non-attainment” areas. |
| • | Ozone. Significant additional emissions control expenditures 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. |
| • | 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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| • | Clear Skies Initiative. The Clear Skies Act of 2005, a revised version of the Clear Skies Acts of 2002 and 2003, was introduced in early 2005. Similar to its predecessors, the Clear Skies Act of 2005 sought to further reduce emissions of sulfur dioxide, nitrogen oxides, and mercury via reduced emissions caps and a revised emission allowance trading system on a national level. The Clear Skies Act of 2005 is still pending in the Senate Committee on Environment and Public Works. It is currently not possible to predict what, if any, new regulatory requirements will ultimately evolve out of these initiatives during the current Congress or in the future. |
| • | Clean Air Interstate Rule. In January 2004, the EPA proposed new rules for reducing emissions of sulfur dioxide and nitrogen oxides. The final Clean Air Interstate Rule (CAIR) was issued by the EPA in March 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. CAIR does not apply on a national basis as would the Clear Skies Act. 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 may be more stringent than 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. |
| • | Clean Air Mercury Rule. In January 2004, the EPA also proposed a mercury reduction rule for controlling mercury emissions from power plants. The proposal sought comments on two approaches for reducing mercury currently emitted each year by coal-fired power plants in the United States. EPA issued its final Clean Air Mercury Rule in March 2005. The EPA has rejected one approach which would require coal-fired power plants to install pollution controls known as “maximum achievable control technologies,” or “MACT,” under section 112 of the Clean Air Act. The approach adopted uses other provisions of the Clean Air Act and sets a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide. This “cap-and-trade” approach is similar to the approach under the CAIR rule discussed above. This approach, which allows mercury emissions trading, when combined with the CAIR regulations, will reduce mercury emissions by nearly 70% from current levels once facilities reach a final mercury cap which takes effect in 2018. Current mercury emissions from United States power plants are about 48 tons per year. The first phase cap is 38 tons beginning in 2010. EPA estimates that much of this reduction will come as a “co-benefit” of the pollution control devices installed under the CAIR regulations. The final cap is set at 15 tons per year beginning in 2018. Each state has been allocated a budget of mercury emissions and must submit a plan on meeting its budget for mercury reductions. The states are not required to adopt the cap-and-trade approach, but EPA expects most to take that approach. Alternatively, a state can elect to meet a specific state emissions budget through measures of the state’s choosing. The stringency of the caps may require many coal-fired sources to install additional pollution control equipment to comply. This increased mercury emission removal capability caused by the proposed rule could result in decreased demand for certain coals either due to higher mercury levels or more difficulty in removing the inherent mercury. |
| • | Carbon Dioxide. In 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. However, Congress, or one or more states, may, at some point, 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. 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 is carbon dioxide, which is considered a greenhouse gas and is a major source of concern with respect to global warming. In November 2004, Russia ratified the Kyoto Protocol to the 1992 Framework Convention on Global Climate Change (the “Protocol”), which establishes a binding set of emission targets for greenhouse gases. With Russia’s 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.
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 February 2006, Senators Domenici and Bingaman released a white paper that is to serve as a platform for discussion of a U.S. policy on greenhouse gas emissions and the possible development of a market-based program to limit emissions. Senators McCain and Lieberman have proposed legislation that would create a national carbon dioxide cap and trade program. This legislation has not been passed but they or others may propose such legislation again in the future. Some states, such as Massachusetts, have already issued regulations regulating greenhouse gas emissions from large power plants. Further, in 2002, the Conference of New England Governors and Eastern Canadian Premiers adopted a Climate Change Action Plan, calling for reduction in regional greenhouse emissions to 1990 levels by 2010, and a further reduction of at least 10% below 1990 levels by 2020. Seven northeastern states adopted the Regional Greenhouse Gas Initiative, which is endeavoring to create a regional cap-and trade program for greenhouse gas emissions for power plants in those states. Three western states are working on a plan that would create a similar greenhouse gas cap-and-trade program. In addition, six states in the Midwest have recently announced that they are working on a plan to address climate and energy issues. There are a number of uncertainties regarding these initiatives, including the applicable baseline of emissions to be permitted, initial allocations, required emissions reductions, availability of offsets, the extent to which additional states will adopt the programs, whether they will be linked with programs in other states or in Canadian provinces, and the timing for implementation of the programs. Increased efforts to control greenhouse gas emissions, including the future ratification of the Protocol by the United States could result in reduced demand for coal.
Clean Water Act
The Clean Water Act of 1972 (the “CWA”) and corresponding state laws affect coal mining operations by imposing restrictions on the discharge of certain pollutants into water and on dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water.
Permits under Section 404 of the CWA are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. Jurisdictional waters typically include ephemeral, intermittent, and perennial streams and may in certain instances include man-made conveyances that have a hydrologic connection to a stream or wetland. Presently, under the Stream Buffer Zone Rule, mining disturbances are prohibited within 100 feet of streams if
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negative effects on water quality are expected. OSM has proposed changes to this rule, which would make exemptions available if mine operators take steps to reduce the amount of waste and its effect on nearby waters. Legislation in Congress has been introduced in the past and may be introduced in the future in an attempt to preclude placing any mining material in streams. Such legislation would have a material adverse impact on future ability to conduct certain types of mining.
The Corps of Engineers (the “COE”) is empowered to issue nationwide permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued the COE in the United States District Court for the Southern District of West Virginia seeking to invalidate nationwide permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs sought to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed individual permits. On July 8, 2004, the court issued an order enjoining the further issuance of Nationwide 21 permits and rescinded certain listed permits where construction of valley fills and surface impoundments had not commenced. On August 13, 2004, the court extended the ruling to all Nationwide 21 permits within the Southern District of West Virginia. The United States Department of Justice appealed the decision to the United States Court of Appeals for the Fourth Circuit. In November 2005, the 4th Circuit Court of Appeals overturned the July 2004 decision allowing the continued use of the NWP 21 permitting process. 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.
Total Maximum Daily Load (“TMDL”) regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL effluent standards for these stream segments. Some of our operations currently discharge effluents into stream segments that have been designated as impaired. The adoption of new TMDL related effluent limitations for our coal mines could require more costly water treatment and could adversely affect our coal production.
Under the CWA, states must conduct an anti-degradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality. A state’s anti-degradation regulations would prohibit the diminution of water quality in these streams. Several environmental groups and individuals recently challenged, and in part successfully, West Virginia’s anti-degradation policy. In general, waters discharged from coal mines to high quality streams will be required to meet or exceed new “high quality” standards. This could cause increases in the costs, time and difficulty associated with obtaining and complying with NPDES permits, and could aversely affect our coal production.
Federal and state laws and regulations can also impose measures to be taken to minimize and\or avoid altogether stream impacts caused by both surface and underground mining. Temporary stream impacts from mining are not uncommon, but when such impacts occur there are procedures we follow to remedy any such impacts. These procedures have generally been effective and we work closely with applicable agencies to implement them. Our inability to remedy any temporary stream impacts in the future, and the application of existing or new laws and regulations to disallow any stream impacts, could adversely affect our operating and financial results.
Endangered Species Act
The Federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.
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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 a consideration 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, proxy statement and other information with the United States Securities and Exchange Commission (“SEC”). You may access and read our SEC filings through our website, atwww.foundationcoal.com, or the SEC’s website atwww.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.
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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.
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.
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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 60% of total U.S. coal production comes from surface mines.
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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 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 40% of annual U.S. coal production.
Unit train. A train of 100 or more cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.
Western Bituminous Region. Coal producing area in western Colorado and eastern Utah.
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RISK FACTORS
Risks Relating to Our Business
A substantial or extended decline in coal prices could reduce our revenues and the value of our coal reserves.
The prices we charge for coal depend upon factors beyond our control, including, but not limited to:
| • | the supply of, and demand for, domestic and foreign coal; |
| • | the demand for electricity; |
| • | domestic and foreign demand for steel and the continued financial viability of the domestic and/or foreign steel industry; |
| • | the proximity to, capacity of, and cost of transportation facilities; |
| • | domestic and foreign governmental regulations and taxes; |
| • | air emission and other regulatory standards for coal-fired power plants; |
| • | costs of transportation of our coal relative to our competitors; |
| • | regulatory, administrative and court decisions; |
| • | the price and availability of alternative fuels, including the effects of technological developments; and |
| • | the effect of worldwide energy conservation measures. |
Our results of operations are dependent upon the prices we charge for our coal as well as our ability to improve productivity and control costs. Any decreased demand would cause spot prices to decline and require us to increase productivity and decrease costs in order to maintain our margins. If we are not able to maintain our margins, our operating results could be adversely affected. Therefore, price declines may adversely affect operating results for future periods and our ability to generate cash flows necessary to improve productivity and invest in operations.
Any adverse change in coal consumption patterns by North American electric power generators or steel producers could result in weaker demand and possibly lower prices for our production, which would reduce our revenues.
During 2005, sales of steam coal accounted for approximately 97% of our total coal sales volume and 92% of our coal sales revenue, respectively, and the vast majority of our sales of steam coal were to U.S. electric power generators. Based on preliminary estimates, domestic electric power generation accounted for approximately 92% of all U.S. coal consumption in 2005, according to the EIA. The amount of coal consumed for U.S. electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power, technological developments and environmental and other governmental regulations. Many of the recently constructed electric power sources have been gas-fired, by virtue of lower construction costs and reduced environmental risks. Gas-based generation from existing and newly constructed gas-based facilities has the potential to displace coal-based generation, particularly from older, less efficient coal generators. In addition, the increasingly stringent requirements of the Clean Air 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.
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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, depending on the time frame of contract execution or initiation. As a consequence of the substantial volume of our sales that are subject to these long-term agreements, we have less coal available with which to capitalize on higher coal prices if and when they arise. In addition, in some cases, our ability to realize the higher prices that may be available in the spot market may be restricted when customers elect to purchase higher volumes allowable under some contracts.
When our current contracts with customers expire or are otherwise renegotiated, our customers may decide not to extend or enter into new long-term contracts or, in the absence of long-term contracts, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including under different pricing terms. For additional information relating to these contracts, see “Business—Long-Term Coal Supply Agreements”.
As electric utilities adjust to the regulations of the Clean Air Act, the Clean Air Mercury Rule, the Clean Air Interstate Rule, possible regulation of greenhouse gas 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 long-term supply contracts may provide limited protection during adverse economic conditions or may result in economic penalties upon the failure to meet specifications.
Price adjustment, “price reopener” and other similar provisions in long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by such contracts. Some of our coal supply contracts contain provisions that allow for the purchase price to be renegotiated at periodic intervals. These price reopener provisions may automatically set a new price based on the prevailing market price or, in some instances,
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require the parties to agree on a new price, sometimes between a pre-set “floor” and “ceiling”. In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions.
Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or our customers for the duration of specified events beyond the control of the affected party. Most of our coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, hardness and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or, in the extreme, termination of the contracts. 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. In addition, we may not be able to successfully convert these sales commitments into long-term contracts.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
We derived 53% of our total coal revenues from sales to our 10 largest customers for the year ended December 31, 2005, with no single customer accounting for more than 14% of our coal revenues for that year. At December 31, 2005, we had 28 coal supply agreements with those 10 customers that expire at various times from 2006 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 2005, less than one percent of the coal we produced was mined by contract miners.
Competition within the coal industry may adversely affect our ability to sell coal.
Coal with lower production costs shipped east from Western coal mines and from offshore sources has resulted in increased competition for coal sales in the Appalachian region. This competition could result in a decrease in our market share in this region and a decrease in our revenues.
Demand for our high sulfur coal and the price that we can obtain for it is impacted by, among other things, the changing laws with respect to allowable emissions and the price of emission allowances. Significant increases in the price of those allowances could reduce the competitiveness of high sulfur coal at plants not equipped to reduce sulfur dioxide emissions. Competition from low sulfur coal and possibly natural gas could result in a decrease in our high-sulfur coal market share and revenues from those operations.
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
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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 mining properties after mining has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, surface and groundwater; surface subsidence from underground mining; and the effects of mining on surface water and groundwater quality and availability. In addition, we are subject to significant legislation mandating certain benefits for current and retired coal miners. We incur substantial costs to comply with government laws and regulations that apply to our operations.
Numerous governmental permits and approvals are required under these laws and regulations for mining operations. Many of our permits are subject to renewal from time to time, and renewed permits may contain more restrictive conditions than our existing permits. Many of our permits governing discharges to or impacts upon surface streams will be subject to new and more stringent conditions to address various new water quality requirements that permitting authorities are now required to address when those permits are renewed over the next several years. Although we have no estimates at this time, our costs to satisfy such conditions could be substantial. We may also be required under certain permits to provide authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment. In recent years, the permitting required under the Clean Water Act to address filling streams and other valleys with wastes from mountaintop coal mining operations and preparation plant refuse disposal has been the subject of extensive litigation by environmental groups against coal mining companies and environmental regulatory authorities, as well as regulatory changes by the U.S. 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, 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 during mining operations 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.
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Our operations may substantially impact the environment or cause exposure to hazardous substances, and our properties may have significant environmental contamination, any of which could result in material liabilities to us.
We use, and in the past have used, hazardous materials and generate, and in the past have generated, hazardous wastes. In addition, many of the locations that we own or operate were used for coal mining and/or involved hazardous materials usage before we were involved with those locations as well as after. We may be subject to claims under federal and state statutes, and/or common law doctrines, for toxic torts, natural resource damages, and other damages as well as the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of current or former conditions at sites that we own or operate currently, as well as at sites that we or predecessor entities owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire share. We have from time to time been subject to claims arising out of contamination at our own and other facilities and may incur such liabilities in the future.
Mining operations can also impact flows and water quality in surface water bodies and remedial measures may be required, such as grouting in 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 coal-fired power plants to attain applicable ambient air quality standards. In addition, state regulatory schemes for electricity pricing are increasingly 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 Clean Air Interstate Rule was issued by the Environmental Protection Agency (the “EPA”) in May 2005 imposing new regulations regarding further reductions of sulfur dioxide and nitrogen oxide emissions from coal-fired power plants. In December 2005, the EPA announced a decision to reconsider specific issues and asked for comments. The outcome of this reconsideration is not known at this time. Installation of additional pollution control equipment required by this rule could result in a decrease in the demand for low sulfur coal,
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potentially driving down prices for low sulfur coal. Also, in March 2005, the EPA finalized a Clean Air Mercury Rule (originally proposed as the Utility Mercury Reductions 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. These standards and future standards could have the effect of making coal-fired plants unprofitable, thereby decreasing demand for coal. Some of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition 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 air pollutants. If such initiatives are enacted into law, power plant operators could choose other fuel sources to meet their requirements, thereby reducing the demand for coal. 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 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 has received sufficient support from enough nations to enter into force and will become binding on all those countries that have ratified it. Although the Protocol is still not binding on the United States, and no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. Countries that have to reduce emissions may use less coal affecting demand for United States export coal. There could be pressure on companies in the United States to reduce emissions if they want to trade with countries that are part of the Protocol. 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. Future regulation of greenhouse gas emissions may be implemented as part of or distinct from the Protocol. Any of these measures could affect coal demand at utilities in the United States. See “Business—Environmental and Other Regulatory Matters” for a discussion of environmental and other regulations affecting our business.
Fluctuations in transportation costs and the availability or reliability of transportation could reduce revenues by causing us to reduce our production or impairing our ability to supply coal to our customers.
Transportation costs represent a significant portion of the total cost of coal for our customers and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make our coal production less competitive than coal produced from other sources.
On the other hand, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, coordination of the many eastern loading facilities, the large number of small shipments, the steeper average grades of the terrain and a more unionized workforce are all issues that combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, high coal transportation rates from the western coal producing areas into Central Appalachian markets limited the use of western coal in those markets. More recently, however, lower rail rates from the western coal producing areas to markets served by eastern U.S.
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producers have created major competitive challenges for eastern producers. The increased competition could have a material adverse effect on the business, financial condition and results of operations of our Pennsylvania, West Virginia and Illinois operations.
Some of our mines depend on a single transportation carrier or a single mode of transportation. Disruption of any of these transportation services due to weather-related problems, flooding, drought, accidents, mechanical difficulties, strikes, lockouts, bottlenecks, and other events could temporarily impair our ability to supply coal to our customers. Our transportation providers may face difficulties in the future that may impair our ability to supply coal to our customers, resulting in decreased revenues.
If there are disruptions of the transportation services provided by our primary rail or barge carriers that transport our produced coal and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.
West Virginia legislation, which raised coal truck weight limits, 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 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
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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 coal reserves through acquisitions of businesses and assets, mergers, joint ventures or other transactions. Such transactions involve various inherent risks, such as:
| • | uncertainties in assessing the value, strengths and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of, acquisition or other transaction candidates; |
| • | the potential loss of key customers, management and employees of an acquired business; |
| • | the inability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction; |
| • | problems that could arise from the integration of the acquired business; and |
| • | unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction rationale. |
Any one or more of these and other factors could cause us not to realize the benefits anticipated to result from the acquisition of businesses or assets or could result in unexpected liabilities associated with the acquired businesses.
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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 Notes 12, 13 and 14 to our consolidated financial statements at December 31, 2005, included $563.8 million of postretirement obligations, $57.2 million of defined benefit pension obligations, $28.8 million of workers’ compensation obligations and $10.0 million of self insured pneumoconiosis obligations. These obligations have been estimated based on assumptions including actuarial estimates, assumed discount rates, estimates of mine lives, expected returns on pension plan assets and changes in health care costs. We could be required to expend greater amounts than anticipated. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse affect on our financial results. Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us.
The inability of the sellers of companies we have acquired to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations and financial position.
In our acquisition and disposition agreements, the respective sellers and buyers, and in some cases, their parent companies, agreed to retain responsibility for and indemnify us against damages resulting from certain third-party claims or other liabilities. These third-party claims and other liabilities include, without limitation, employee liabilities, costs associated with various litigation matters related to the mines involved, and certain environmental liabilities. The failure of any seller or buyer and, if applicable, its parent company, to satisfy its obligations with respect to claims and retained liabilities covered by the relevant agreements could have an adverse effect on our results of operations and financial position because claimants may successfully assert that we are liable for those claims and /or retained liabilities. In addition, certain obligations of the sellers to indemnify us will terminate or have already terminated upon expiration of the applicable indemnification period and will not cover damages in excess of the applicable coverage limit. The assertion of third-party claims after the expiration of the applicable indemnification period or in excess of the applicable coverage limit, or the failure of any seller to satisfy its indemnification obligations with respect to breaches of its representations and warranties, could have an adverse effect on our results of operations and financial position.
Our 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, 2005, our total indebtedness was $635.0 million. In addition, as of December 31, 2005, we had $185.8 million of letters of credit outstanding and additional borrowings available under our new revolving credit facility of $164.2 million. We may also incur additional indebtedness in the future.
The degree to which we are leveraged could have important consequences, including, but not limited to:
| • | making it more difficult to self-insure and obtain surety bonds or letters of credit; |
| • | limiting our ability to enter into new long-term sales contracts; |
| • | increasing our vulnerability to general adverse economic and industry conditions; |
| • | requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal of, and interest on, our indebtedness, thereby reducing the availability of the cash flow to fund working capital, capital expenditures, research and development or other general corporate uses; |
| • | limiting our ability to obtain additional financing to fund future working capital, capital expenditures, research and development, debt service requirements or other general corporate requirements; |
| • | making it more difficult for us to pay interest and satisfy our debt obligations; |
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| • | limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; and |
| • | placing us at a competitive disadvantage compared to less leveraged competitors. |
In addition, our indebtedness subjects us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us. Furthermore, substantially all of our material assets secure our indebtedness under our Senior Credit Facilities.
If our cash flows and capital resources are insufficient to fund our debt service obligations or our requirements under our other long-term liabilities, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations or our requirements under our other long term liabilities. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our Senior Credit Facilities and the indenture under which our 7 1/4% 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 Holdings, Inc. or our subsidiaries from doing so. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.
The covenants in our Senior Credit Facilities and our indenture impose restrictions that may limit our operating and financial flexibility.
The Senior Credit Facilities, our indenture governing the 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 Credit Facilities. If we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
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Failure to maintain required surety bonds could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease the coal. Failure to maintain capacity for required letters of credit could limit our available borrowing capacity under our Senior Credit Facilities and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements.
We are required to provide financial assurance to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation benefits, to secure coal lease obligations and to satisfy other miscellaneous obligations. We generally use surety bonds to secure reclamation and coal lease obligations. We generally use letters of credit to assure workers’ compensation benefits, 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, 2005, we had outstanding surety bonds of $257.1 million, which includes $234.6 million secured reclamation obligations, $10.7 million secured coal lease obligations and $9.6 million secured self-insured workers’ compensation obligations. The premium rates and terms of the surety bonds are subject to annual renewals. It has become increasingly difficult for us to secure new surety bonds or renew bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would affect our ability to secure reclamation 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:
| • | lack of availability, higher expense or unfavorable market terms of new surety bonds; and |
| • | restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of the indenture or new credit facilities. |
In addition, as of December 31, 2005, we had $185.8 million of letters of credit in place for the following purposes: $34.1 million for workers’ compensation, including collateral for workers compensation bonds; $23.4 million for UMWA retiree health care obligations; $121.5 million for collateral for reclamation surety bonds; $3.0 million for minimum royalty payment obligations for a closed mine in Utah; and $3.8 million for other miscellaneous obligations. Obligations secured by letters of credit may increase in the future. Any such increase would limit our available borrowing capacity under the Senior Credit Facilities and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements.
Due to our participation in multi-employer pension plans, we may have exposure under those plans that extends 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 2005, our total contributions to these plans and other contractual payments under our UMWA wage agreement were approximately $1.9 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.
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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 2005, we contributed $7.5 million to our pension plans. We currently expect to make contributions in 2006 of approximately $15.2 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 September 30, 2005, our annual measurement date, our pension plans were underfunded by $57.2 million (based on the actuarial assumptions used for FAS 87 purposes). Our pension plans are subject to the Employee Retirement Income Security Act of 1974 (“ERISA”). Under ERISA, the Pension Benefit Guaranty Corporation, or PBGC, has the authority to terminate an underfunded pension plan under limited circumstances. In the event our 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, 2005, the UMWA represented approximately 40% of our employees, who produced approximately 23% of our coal sales volume during the fiscal year ended December 31, 2005. Because of the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our non-unionized competitors may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. Our existing collective bargaining agreements with the UMWA expire in 2007. If some or all of the affected employees strike, it could adversely affect our productivity, increase our costs and disrupt shipments.
In November 2003, the UMWA held an election at our Rockspring mining facility in West Virginia. The UMWA challenged nine unopened ballots as being improperly cast by supervisors. The outcome of the election will depend on the decision of the 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, and we are currently awaiting a decision. If it is ultimately determined that the UMWA was validly elected, 255 employees, or approximately 10% of our total workforce, will become UMWA members. In the event the Rockspring mining facility becomes unionized, we will bargain in good faith towards an acceptable collective bargaining agreement. If we are unable to do so, there could be strikes or other work stoppages detrimental to the normal operation of the Rockspring mining facility.
A shortage of skilled labor in the mining industry could pose a risk to achieving improved labor productivity and competitive costs, which could adversely affect our profitability.
Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. In the event the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal.
Our ability to operate our company effectively could be impaired if we lose key personnel.
We manage our business with a number of key personnel. We do not have “key person” life insurance to cover our executive officers. The loss of certain of these key individuals could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. Key personnel may not continue to be employed by us or we may not be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have a material adverse effect on us.
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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 certificate of incorporation and bylaws may discourage a takeover attempt even if doing so might be beneficial to our shareholders.
Provisions contained in our certificate of incorporation and bylaws could make it more difficult for a third party to acquire us. Provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for shareholders to effect certain corporate actions. For example, our certificate of incorporation authorizes our board of directors to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock, without any vote or action by our shareholders. Thus, our board 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 common stock. These rights may have the effect of delaying or deterring a change of control of our company. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock.
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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 1.7 billion tons as of December 31, 2005.
Of the 1.7 billion tons, approximately 1 billion tons are assigned reserves that we expect to be mined at operations that were active as of December 31, 2005. Approximately .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.
Approximately 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 42% of our reserves are classified as compliance coal which meets the 1.2 lb SO2/mmBtu standard of Phase II of the Clean Air Act. Our compliance reserves are located in Wyoming and West Virginia.
The table below summarizes the locations, coal reserves in millions of tons and primary ownership of the coal reserves. Tonnage is on an as-received wet basis and the quality figures represent an approximate reserve average.
Operating Segments | Proven and Probable Reserves(1) | Assigned Reserves | Unassigned Reserves | Average Btu/lb | Average Sulfur Content (lbs SO2/mmBtu) | Ownership | ||||||
| (Tons in millions) | ||||||||||||
Powder River Basin | 676.8 | 676.8 | — | 8,400 | 0.8 | Primarily Leased | ||||||
Northern Appalachia | 764.5 | 200.5 | 564.0 | 12,825 | 3.3 | Primarily Owned | ||||||
Central Appalachia | 201.2 | 76.7 | 124.5 | 12,900 | 1.4 | Primarily Leased | ||||||
Other | 65.1 | 27.7 | 37.4 | 11,450 | 3.8 | Primarily Leased | ||||||
Total | 1,707.6 | 981.7 | 725.9 | |||||||||
| (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 has a maximum term of 100 years and requires diligent development of the lease within the first 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
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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 royalty payments to Wyoming after deducting administrative expenses.
Certain of our mines in Pennsylvania, West Virginia and Illinois are subject to private coal leases. Private coal leases normally have a stated term and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and 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.
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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
Overview
We are the fifth largest coal company in the United States operating nine mining complexes that consist of thirteen individual coal mines. Our mining operations are located in southwest Pennsylvania, southern West Virginia, southern Illinois and the southern Powder River Basin region of Wyoming. Three of our mining complexes are surface mines, two of our complexes are underground mines using highly efficient longwall mining technology and the remaining four complexes are underground mines that utilize continuous miners. In addition to mining coal, we also purchase coal from other producers and utilize it with our own production in coal brokering and trading activities.
Our primary product is steam coal, sold primarily to electric power generators located in the United States. Approximately 9% and 8%, respectively, of our 2005 coal sales revenues and our non-GAAP combined 2004 coal sales revenues were made from the sale of metallurgical coal to the domestic and export metallurgical coal markets where it is used to make coke for steel production.
While the majority of our revenues are derived from the sale of coal, we also realize revenues from coal production royalties, override royalty payments from a coal supply agreement now fulfilled by another producer, fees from the processing of our production by a synfuel facility, fees to transload coal through our Rivereagle facility on the Big Sandy River and revenues from the sale of coalbed methane.
From July 1, 1999 through July 29, 2004, we were a stand-alone wholly owned subsidiary of RAG Coal International AG (“RAG”) headquartered in Essen, Germany. In October 2003, RAG announced its intention to divest its international mining subsidiaries. In addition to RAG American Coal Holding, Inc., these international mining subsidiaries consisted of operations in Australia and Venezuela. On February 29, 2004, RAG announced the sale of four of our subsidiaries, collectively known as the RAG Colorado Business Unit, to a third party. The subsidiaries comprising the RAG Colorado Business Unit owned an underground longwall mine located in Routt County, Colorado, an idled underground longwall mine located in Moffat County, Colorado and surface lands located in northwest Colorado and southern Wyoming. The transaction closed on April 15, 2004. In the financial statements of the Predecessor for the period from January 1, 2004 through July 29, 2004 and for the twelve months ended December 31, 2003, the RAG Colorado Business Unit was classified as a discontinued operation.
On May 24, 2004, RAG entered into a definitive agreement with Foundation Coal Corporation, which was owned by affiliates of First Reserve, Blackstone and AMCI, to sell all of its operations except the Colorado Business Unit which was sold on April 15, 2004. The Acquisition closed on July 30, 2004.
Results of Continuing Operations
Basis of Presentation:
RAG American Coal Holding, Inc. and its subsidiaries, excluding the subsidiaries comprising the Colorado Business Unit which were sold on April 15, 2004, were acquired by a subsidiary of Foundation Coal Holdings, Inc. on July 30, 2004. Due to the change in ownership, and the resultant application of purchase accounting, the historical financial statements of the Predecessor and the Successor included in this Form 10-K have been prepared on different bases for the periods presented and are not comparable.
The following provides a description of the basis of presentation during all periods presented:
Successor—Represents the consolidated financial position of Foundation Coal Holdings, Inc. as of December 31, 2005 and 2004 and our consolidated results of operations and cash flows for the twelve months ended December 31, 2005 and for the period from February 9 through December 31, 2004. Foundation Coal Holdings, Inc. had no significant activities until the acquisition of RAG American Coal Holding, Inc. on July 30, 2004. Hereinafter, the period from February 9 through December 31, 2004 is referred to as the “five month operating period ended
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December 31, 2004.” Our consolidated financial position at December 31, 2005 and our consolidated results of operations for the twelve months then ended reflect the final purchase price allocation based on appraisals prepared by independent valuation specialists, employee benefit valuations prepared by independent actuaries and other internal analysis. Deferred income taxes have been provided in the consolidated balance sheet based on the tax versus book basis of the assets acquired and liabilities assumed. During the twelve months ended December 31, 2005, we completed the purchase price allocation, and recorded final purchase accounting adjustments that reduced the fair value of the total assets acquired by approximately $105.9 million, or approximately 5%, of the preliminary value assigned to the assets acquired. The most significant component of this decrease related to a revision in deferred income tax liabilities associated with projected post-retirement benefit obligations resulting from changes in the assumptions regarding the impact on these obligations of the Medicare Part D prescription drug benefits. The reduction in deferred income tax liabilities resulted in corresponding changes to the values assigned to owned and leased mineral rights and coal supply agreements. The preliminary valuation of deferred income taxes assumed that Medicare Part D would be coordinated with the Company’s health care plans. Additional information obtained and analysis performed prior to the finalization of purchase accounting caused this assumption to change to an expectation that the Company will utilize the income tax free subsidy offered under Medicare Part D. Our consolidated financial position at December 31, 2004 reflected our preliminary estimates of purchase price allocation before the final purchase accounting adjustments described above. The application of purchase accounting to the acquired assets of RAG American Coal Holding, Inc. resulted in increases to owned and leased mineral rights, surface lands, coal inventories, and the asset arising from recognition of asset retirement obligations. It resulted in decreases to plant and equipment and current deferred taxes. In addition, the historical cost assigned to deferred overburden in the acquired asset balance sheet was eliminated. The values assigned to uncovered and partially covered coal lands considered the stage of the mining process in which these two groups of coal lands were at the acquisition date. The application of purchase accounting to the acquired liabilities of RAG American Coal Holding, Inc. resulted in increases to postretirement health care obligations, pension obligations, black lung obligations, asset retirement obligations and noncurrent deferred taxes. Separate assets or liabilities were established to reflect the valuation of above or below market coal supply agreements in relation to market price curves. With regard to consolidated results of operations for the five month operating period ended December 31, 2004 and the twelve months ended December 31, 2005, the principal effects of the application of purchase accounting, in comparison to reporting for historical periods, were to decrease the cost of coal sold due to lower expenses for postretirement health care and pensions, to decrease the cost of coal sold for net deferrals of deferred overburden costs, to decrease net amortization expense for coal supply agreements which is now a credit because our contracts at acquisition represented a net liability and to increase the cost of depletion expense for owned and leased mineral rights. During the five month operating period ended December 31, 2004, cost of coal sold was increased for the increase in value of coal inventories from cost to market at the acquisition date.
Predecessor—Represents the consolidated financial position, results of operations and cash flows for RAG American Coal Holding, Inc. for the twelve months ended December 31, 2003, and for the period from January 1, 2004 through July 29, 2004, respectively. These consolidated financial statements are based on the historical assets, liabilities, sales and expenses of the Predecessor for these periods.
Non-GAAP Combined —To facilitate trend analysis, in management’s discussion and analysis for thetwelve months ended December 31, 2005 – Successor compared to the period from January 1, 2004 through July 29, 2004 – Predecessor and the period from February 9, 2004 (date of formation) through December 31, 2004 (five month operating period) – Successor and the period from January 1, 2004 through July 29, 2004 compared to the twelve months ended December 31, 2003 for RAG American Coal Holding, Inc. plus comments and comparisons to the five month operating period ended December 31, 2004 for Foundation Coal Holdings, Inc., we discuss “non-GAAP combined” results. Non-GAAP combined amounts are determined by adding the historical amounts of the Predecessor for the period from January 1, 2004 through July 29, 2004 with the corresponding amounts of the Successor for the five month operating period ended December 31, 2004. Non-GAAP combined amounts are not recognized measures under GAAP and do not purport to be alternatives to GAAP operating measures. Non-GAAP combined amounts are not indicative of the operating results of Foundation Coal Holdings, Inc. because of the significant difference in basis between the Successor and Predecessor caused by the acquisition on July 30, 2004 and its impact on income from operations. Management believes that the discussion of non-GAAP combined operating results is important to the readers of the financial statements to understand key operating trends over the normal operating cycle years 2005, 2004 and 2003. Non-GAAP combined amounts are reconciled to the underlying historical GAAP basis financial statements on page 47.
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Twelve months ended December 31, 2005—Successor compared to period from January 1, 2004 through July 29, 2004—Predecessor and period from February 9, 2004 (date of formation) through December 31, 2004 (five month operating period)—Successor
As previously described there are significant differences in the basis of financial reporting between the Successor and Predecessor periods as a result of the purchase of RAG American Coal Holding, Inc. by Foundation Coal Corporation on July 30, 2004, and the resultant application of purchase accounting to the assets and liabilities acquired. The Successor reported income from continuing operations of $88.9 million and $14.5 million, respectively, for the twelve months ended December 31, 2005 and for the five month operating period ended December 31, 2004, whereas the Predecessor reported a loss from continuing operations of $90.6 million for the period from January 1, 2004 through July 29, 2004.
During the period from January 1, 2004 through July 29, 2004 the Predecessor incurred approximately $27.4 million, net of income taxes, of non-cash charges related to termination of hedge accounting for interest rate swaps, partly offset by a net mark-to-market gain on the interest rate swaps. The Predecessor also incurred charges for early extinguishment of debt of $13.8 million, net of income taxes, and a coal contract settlement of $16.5 million, net of income taxes. These one-time charges total $57.7 million, net of income taxes. These charges in combination with below normal coal production from our Northern Appalachia mines were the primary reason for the significant loss from continuing operations.
During the twelve months ended December 31, 2005, the Successor achieved stronger production and tons sold, enjoyed significantly higher per ton sales realizations and received the benefit of a net credit from amortization of coal supply agreements, reflecting amortization of a liability established for below market contracts in purchase accounting. Period-over-period increases in cost of coal sales, selling, general and administrative expenses and depreciation, depletion and amortization were more than absorbed by higher coal sales revenues. The operating trends discussed in the following section,Twelve months ended December 31, 2005 compared to non-GAAP combined twelve months ended December 31, 2004, also apply to comparisons of the Successor periods and the Predecessor period from January 1, 2004 through July 29, 2004.
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Historical and Non-GAAP Combined
Consolidated Condensed Statements of Operations
(dollars in millions, except per share)
| Successor | Predecessor | Non-GAAP Combined | ||||||||||||||
Twelve Months Ended December 31, 2005 | Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | |||||||||||||
| (unaudited) | ||||||||||||||||
Revenues | $ | 1,316.9 | $ | 444.6 | $ | 551.0 | $ | 995.6 | ||||||||
Cost of coal sales | 936.2 | 345.8 | 484.5 | 830.3 | ||||||||||||
Selling, general & administrative expense | 50.7 | 24.6 | 27.4 | 52.0 | ||||||||||||
Accretion on asset retirement obligations | 8.5 | 3.3 | 4.0 | 7.3 | ||||||||||||
Write-down of long-lived asset | 1.6 | — | — | — | ||||||||||||
Depreciation, depletion & amortization | 211.2 | 84.8 | 61.2 | 146.0 | ||||||||||||
Amortization of coal supply agreements | (84.9 | ) | (67.2 | ) | 8.8 | (58.4 | ) | |||||||||
Income (loss) from operations | 193.6 | 53.3 | (34.9 | ) | 18.4 | |||||||||||
Interest expense | (59.5 | ) | (26.7 | ) | (18.0 | ) | (44.7 | ) | ||||||||
Interest income | 1.3 | 1.0 | 1.3 | 2.3 | ||||||||||||
Loss on termination of hedge accounting for interest rate swaps | — | — | (48.9 | ) | (48.9 | ) | ||||||||||
Loss on early debt extinguishment | — | — | (21.7 | ) | (21.7 | ) | ||||||||||
Contract settlement | — | — | (26.0 | ) | (26.0 | ) | ||||||||||
Mark-to-market gain (loss) on interest rate swaps | — | 0.5 | 5.8 | 6.3 | ||||||||||||
Income (loss) before income taxes | 135.4 | 28.1 | (142.4 | ) | (114.3 | ) | ||||||||||
Income tax (expense) benefit | (46.5 | ) | (13.6 | ) | 51.8 | 38.2 | ||||||||||
Income (loss) from continuing operations | 88.9 | 14.5 | (90.6 | ) | (76.1 | ) | ||||||||||
Income from discontinued operations, net of income tax expense | — | — | 23.1 | 23.1 | ||||||||||||
Net income (loss) | $ | 88.9 | $ | 14.5 | $ | (67.5 | ) | $ | (53.0 | ) | ||||||
Earnings per share: | ||||||||||||||||
Net income (loss), basic | $ | 1.99 | $ | 0.60 | $ | (492.38 | ) | |||||||||
Net income (loss), diluted | $ | 1.92 | $ | 0.58 | $ | (492.38 | ) | |||||||||
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Twelve months ended December 31, 2005 compared to non-GAAP combined twelve months ended December 31, 2004
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
| Successor | Predecessor | Non-GAAP Combined | ||||||||||
Twelve Months Ended December 31, 2005 | Five Month Operating Period Ended December 31, | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, | |||||||||
| (unaudited) | ||||||||||||
| (in millions, except per ton data) | ||||||||||||
Coal sales | $ | 1,292.4 | $ | 436.0 | $ | 544.9 | $ | 980.9 | ||||
Other revenue | 24.5 | 8.6 | 6.1 | 14.7 | ||||||||
Total revenues | $ | 1,316.9 | $ | 444.6 | $ | 551.0 | 995.6 | |||||
Tons sold | 68.8 | 27.6 | 35.9 | 63.5 | ||||||||
Coal sales realization per ton sold | $ | 18.79 | $ | 15.80 | $ | 15.18 | $ | 15.47 | ||||
Coal sales revenues for the twelve months ended December 31, 2005 increased by $311.5 million (32)% compared to the non-GAAP combined coal sales revenues for the twelve months ended December 31, 2004 as a result of an 8% increase in tons sold and a 22% increase in average coal sales realization per ton.
Coal sales volumes in Northern Appalachia increased by 3.0 million tons (28%) as a result of increased shipments from both the Emerald (1.2 million tons) and Cumberland (1.8 million tons) mines. Combined production from the two mines and from Cumberland alone set annual records. Coal sales volumes in Northern Appalachia during 2004 were decreased by interruptions to operations caused by: (a) the idling of the Cumberland Mine longwall for approximately eleven weeks as explained below, (b) an extended duration longwall move at the Emerald Mine during the first quarter of 2004, and (c) adverse mining conditions at Emerald during the third quarter of 2004. Including the extended duration longwall move mentioned above, Emerald had two longwall moves in 2004 compared with only one in 2005. Cumberland had one longwall move in each year. From February 17 through May 7, 2004, the longwall mining equipment at the Cumberland Mine was idled due to alleged violations resulting from a revised interpretation of regulations issued by MSHA regarding the ventilation system at the Mine. In response, we revised the ventilation system to minimize any future business disruption and on May 7, 2004 we resumed longwall operations at the Cumberland Mine. There were no interruptions of production due to ventilation issues during 2005.
Coal sales volumes in Central Appalachia increased by 1.0 million tons (13%) due to increased sales of purchased coal in 2005 plus higher production at the Kingston and Pioneer/Pax mines, which was partly offset by lower production from the Laurel Creek complex. Production capacity at Kingston was expanded in early 2005 by the addition of a continuous miner unit. Production from the Pioneer/Pax surface mine complex increased in comparison to 2004 as the closure of the Simmons Fork Mine was more than offset by production from the developing Pax Mine. The Pax Mine produced 0.6 million tons during 2005. When fully developed in 2006, it is expected to produce approximately one million tons of coal per year. Coal sales volumes in the Powder River Basin increased by 1.9 million tons (5%), to an annual record level of 43.6 million tons. A higher level of committed sales was partly offset by worse than expected levels of rail service brought on by unusually inclement weather during May and resultant repairs to the rail lines, particularly the UP/BNSF joint line south of Gillette. During the second half of 2005, our Powder River Basin mines shipped at an annualized rate of 45.4 million tons, approximately equal to our expected total year 2005 shipments prior to the disruptions to rail service. Coal sales volumes from the Illinois Basin increased by 0.1 million tons (5%) reflecting shipments made to fulfill new contract obligations. Purchased coal activities by our trading group decreased by approximately 0.7 million tons compared to the prior year due to the timing of purchased coal transactions.
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Coal sales realization per ton sold in Northern and Central Appalachia increased by 31% and 29%, respectively, in 2005 due to substitution of higher priced contracts, which took effect in late 2004 and during 2005, for lower priced contracts that rolled off. An additional factor in Northern Appalachia was higher coal quality premiums for sulfur content as a result of record prices for sulfur dioxide allowances and lower sulfur content of shipped coal. In the Powder River Basin, coal sales realizations per ton declined by 2% due to the expiration at the end of 2004 of higher priced contracts signed during the 2001 market increase, partly offset by higher sulfur premiums. The weighted average coal sales realization per ton sold of $18.79 for 2005 also benefited from a larger proportion of higher priced Northern Appalachia and Central Appalachia tons sold relative to the lower priced tons from the Powder River Basin.
As of January 24, 2006, uncommitted and unpriced tonnage was 4%, 25%, 50% and 63% of planned production in 2006, 2007, 2008 and 2009, respectively. Eastern coals account for the majority of uncommitted tonnage, representing 12%, 36%, 62% and 87% of the Company’s planned eastern production, remains uncommitted and unpriced in 2006, 2007, 2008 and 2009, respectively.
In 2006 through 2009, Foundation Coal expects coal production within the following ranges:
Expected Coal Production (Millions of Tons)
| 2006 | 2007 | 2008 | 2009 | |||||
East | 21.5–23.5 | 21.5–23.5 | 21.5–23.5 | 21.5–23.5 | ||||
West | 49.0–51.0 | 49.0–51.0 | 54.0–56.0 | 54.0–56.0 | ||||
Total Consolidated | 70.5–74.5 | 70.5–74.5 | 75.5–79.5 | 75.5–79.5 |
Based on its committed and priced planned production as of January 24, 2006, the Company expects its committed and priced production from its Eastern mines, encompassing Northern Appalachia, Central Appalachia and the Illinois Basin, to realize in the range of $40.20 to $40.60 per ton in 2006. The Company also expects its committed and priced production from the Powder River Basin to realize in the range of $8.05 to $8.25 per ton in 2006. These ranges of expected per ton average realizations include forecast sulfur dioxide and btu premiums based on contract terms, projected coal qualities and historical realized premiums. The above tonnages and expected per ton average realizations exclude coal that may be purchased and resold during 2006.
Other revenues for the twelve months ended December 31, 2005 increased by $9.8 million (67%) compared to the non-GAAP combined other revenues for the twelve months ended December 31, 2004. The increase was partly due to charges totaling $8.4 million during the 2004 period for settlement of future coal sales commitments compared to $3.6 million of such charges in 2005, combined with higher revenues for synfuel fees ($3.0 million) and higher coal bed methane sales and coal bed methane royalties ($1.9 million) during the 2005 period.
Costs and Expenses
| Successor | Predecessor | Non-GAAP Combined | |||||||||||||
Twelve Months Ended December 31, 2005 | Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | ||||||||||||
| (unaudited) | |||||||||||||||
| (in millions) | |||||||||||||||
Cost of coal sales (excludes depreciation, depletion and amortization) | $ | 936.2 | $ | 345.8 | $ | 484.5 | $ | 830.3 | |||||||
Selling, general and administrative expenses (excludes depreciation, depletion and amortization) | 50.7 | 24.6 | 27.4 | 52.0 | |||||||||||
Accretion on asset retirement obligations | 8.5 | 3.3 | 4.0 | 7.3 | |||||||||||
Write-down of long-lived asset | 1.6 | — | — | — | |||||||||||
Depreciation, depletion and amortization | 211.2 | 84.8 | 61.2 | 146.0 | |||||||||||
Amortization of coal supply agreements | (84.9 | ) | (67.2 | ) | 8.8 | (58.4 | ) | ||||||||
Total costs and expenses | $ | 1,123.3 | $ | 391.3 | $ | 585.9 | $ | 977.2 | |||||||
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Cost of coal sales. The cost of coal sales for the twelve months ended December 31, 2005 increased from the non-GAAP combined cost of coal sales for the twelve months ended December 31, 2004 primarily due to: (a) increases in labor costs as a result of both compensation increases and hiring of additional personnel ($38.0 million); (b) increases in many categories of materials and services as a result of significantly higher commodity prices particularly for steel products and diesel fuel ($86.0 million); (c) increases in royalties and coal production taxes as a result of higher revenues ($17.8 million), partly offset by reduced purchased coal costs ($4.9 million); (d) reduced pension and other postretirement net periodic benefit costs due to elimination of amortization of actuarial losses as a result of purchase accounting ($9.9 million); and (e) reduced overburden removal costs reflected in depreciation, depletion and amortization as a result of purchase accounting ($21.4 million). Cost of coal sales per ton were $13.61 for the twelve months ended December 31, 2005 compared to a non-GAAP combined figure of $13.08 for the twelve months ended December 31, 2004, an increase of 4%.
Selling, general and administrative expenses. Selling, general and administrative expenses for the twelve months ended December 31, 2005 totaled $50.7 million compared to the non-GAAP combined expense of $52.0 million for the twelve months ended December 31, 2004. Period-over-period decreases in 2005 are primarily due to additional expenses incurred in the areas of: (a) directors and officers’ insurance premiums ($1.1 million); (b) audit fees, including Sarbanes Oxley 404 compliance ($2.9 million); (c) information technology costs ($0.9 million); (d) salaries and cash incentive compensation ($1.7 million); (e) non-cash stock compensation expense ($0.7 million); (f) various professional services fees ($2.2 million), including fees associated with the secondary stock offering completed in September 2005 ($1.2 million) and office rent ($0.3 million), offset by lower legal fees ($1.6 million); reduced health care and pension costs ($2.3 million); reduced sales commissions ($0.8 million); elimination of the sponsor monitoring fee in 2005 ($2.0 million); expenses incurred in 2004 by the predecessor representing management incentive plan expenses ($2.4 million), a one-time bonus awarded to certain employees in 2004 in connection with the sale of RAG American Coal Holding, Inc. ($1.8 million); and amortization of actuarial losses on pensions, other postretirement benefits and black lung benefits included in 2004, but not in 2005 as a result of purchase accounting ($0.4 million).
Accretion on asset retirement obligation. Accretion on asset retirement obligation is a component of accounting for asset retirement obligations under SFAS No. 143. Accretion represents the increase in the asset retirement liability to reflect the change in the liability for the passage of time. Higher accretion expense period-over-period is to be expected as the imputed interest factor is applied to an increasing obligation.
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. Expense increased in the twelve months ended December 31, 2005 compared to the non-GAAP combined expense for the year ended December 31, 2004, primarily due to a full year of depreciation, depletion and amortization in 2005 of the increased asset values assigned in purchase accounting, as well as depreciation of capital additions made during 2005.
Coal supply agreement amortization. Application of purchase accounting resulted in recognition of a significant liability for below market priced coal supply agreements as well as a significant asset for above market priced coal supply agreements, both in relation to market prices at the acquisition date. Amortization of the liability for below market priced coal supply agreements during the twelve months ended December 31, 2005 and the five month operating period ended December 31, 2004 totaled $109.9 million and $88.2 million of credits to expense, respectively. Amortization of the asset for above market priced coal supply agreements during the same periods totaled $25.0 million and $21.0 million of charges to expense, respectively. The increase in net credit from amortization of coal supply agreements for the year ended December 31, 2005 compared to the non-GAAP combined net credit for the twelve months ended December 31, 2004 is due to a full year of post purchase accounting amortization in 2005.
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Segment Analysis
Utilizing data published by Argus Media, the following graph sets forth representative steam coal prices in various U.S. markets for the period from January 1, 2004 through December 31, 2005. 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 statements.
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| Successor | Predecessor | Non-GAAP Combined | |||||||||||
| Twelve Months Ended December 31, 2005 | Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | ||||||||||
| (unaudited) | |||||||||||||
| (in millions, except per ton data) | |||||||||||||
Powder River Basin | |||||||||||||
Tons sold | 43.6 | 17.9 | 23.8 | 41.7 | |||||||||
Average sales realization per ton | $ | 7.47 | $ | 7.80 | $ | 7.51 | $ | 7.64 | |||||
Revenues | $ | 327.6 | $ | 140.2 | $ | 179.8 | $ | 320.0 | |||||
Income from operations | $ | 23.6 | $ | 3.5 | $ | 30.7 | $ | 34.2 | |||||
Northern Appalachia | |||||||||||||
Tons sold | 13.7 | 4.8 | 5.8 | 10.7 | |||||||||
Average sales realization per ton | $ | 35.00 | $ | 26.33 | $ | 27.07 | $ | 26.74 | |||||
Revenues | $ | 483.5 | $ | 128.1 | $ | 160.5 | $ | 288.6 | |||||
Income (loss) from operations | $ | 174.6 | $ | 49.4 | $ | (10.4 | ) | $ | 39.0 | ||||
Central Appalachia | |||||||||||||
Tons sold | 8.9 | 3.4 | 4.4 | 7.9 | |||||||||
Average sales realization per ton | $ | 45.37 | $ | 36.38 | $ | 35.02 | $ | 35.61 | |||||
Revenues | $ | 417.0 | $ | 122.1 | $ | 159.0 | $ | 281.1 | |||||
Income (loss) from operations | $ | 49.6 | $ | 21.8 | $ | (9.8 | ) | $ | 12.0 | ||||
Powder River Basin—Income from operations for the twelve months ended December 31, 2005 was $23.6 million compared to non-GAAP combined income from operations of $34.2 million for the twelve months ended December 31, 2004. The decrease in operating income is primarily due to higher depreciation, depletion and amortization (“DD&A”) expense of $24.3 million in 2005 as a result of increased values assigned to plant, equipment and owned and leased mineral rights in purchase accounting as of July 30, 2004. The increase in DD&A is partly offset by higher revenues ($7.6 million), reflecting increased coal shipments and higher coal quality premiums partly offset by lower sales realizations per ton, and a lower charge for amortization of coal supply agreements ($7.1 million), reflecting the expiration of several above market coal supply agreements at year end 2004. Cost of coal sales for the twelve months ended December 31, 2005 were comparable to non-GAAP combined cost of coal sales for the twelve months ended December 31, 2004. Increases in 2005 in labor costs ($3.3 million), materials, supplies and repair expenses ($14.1 million), mainly due to higher commodity prices, and royalties and production taxes ($2.5 million), due to higher sales revenues, were offset by an increased expense credit for deferral of overburden removal costs into work-in-process inventory ($21.0 million).
Northern Appalachia—Income from operations for the twelve months ended December 31, 2005 was $174.6 million compared to non-GAAP combined income from operations of $39.0 million for the twelve months ended December 31, 2004. The significant improvement is primarily due to increased revenues of $194.9 million resulting from a 28% increase in tons sold and a 31% increase in average sales realization per ton. Production from the Cumberland Mine increased substantially during 2005. During the first half of 2004, Cumberland’s longwall was idle from February 17 to May 7 for reasons previously described. Production at Emerald also increased period-over-period due to one longwall move in 2005 compared to two longwall moves in 2004 and improved mining conditions in 2005. Higher revenues and a $9.9 million larger credit from amortization of coal supply agreements valued in purchase accounting were partly offset by increases in labor and employee benefit expenses ($16.3 million), materials and supplies ($26.5 million), coal production taxes ($2.2 million), depreciation, depletion and
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amortization ($22.8 million) and write-off of deferred longwall development costs ($1.6 million) in 2005. These expense increases were due to a combination of higher tons sold and increased prices for labor, fringe benefits and materials and supplies. Cost of coal sales per ton decreased approximately 6% period-over-period.
Central Appalachia—Income from operations for the twelve months ended December 31, 2005 was $49.6 million compared to non-GAAP combined income from operations of $12.0 million for the twelve months ended December 31, 2004. Revenues increased by $135.9 million mainly due to a 13% increase in tons sold, driven by higher sales of purchased coal and increased production at the Kingston and Pax mines, and a 29% increase in average sales realizations per ton. The credit for expense from amortization coal supply agreements valued in purchase accounting was $6.7 million higher in 2005. Higher revenues were partly offset by increased expenses for: (a) labor and fringe benefits ($10.4 million); (b) materials and supplies, led by increases for roof control materials and diesel fuel ($24.5 million); (c) purchased coal ($43.3 million); (d) royalties and severance taxes driven by higher sales revenues ($8.0 million); (e) depreciation, depletion and amortization ($17.1 million); and (f) increased other expenses ($1.5 million). Cost of coal sales in both periods included charges of approximately $1.5 million each year for litigation settlements. These expense increases were due to a combination of higher tons sold and increased prices for labor, fringe benefits, materials and supplies and purchase coal. Cost of coal sales per ton increased approximately 22% period-over-period.
Other—Includes the Company’s Illinois Basin operation, the Wabash mine, 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 and Central Appalachia mine. During the twelve months ended December 31, 2005, the Other segment reported a loss from operations of $54.1 million compared to a non-GAAP combined loss from operations of $66.9 million in the twelve months ended December 31, 2004. The reduced period-over-period loss from operations of $12.8 million was mainly due to a combination of: (a) reduced pension and retiree medical expenses in 2005 as a result of the elimination of amortization of actuarial losses and prior service costs in purchase accounting ($5.5 million); (b) increased tons sold and higher average sales realizations per ton at the Wabash mine in 2005 partly offset by higher cash operating costs and depreciation, depletion and amortization expenses ($0.9 million); increased credit to expense from amortization of coal supply agreements in 2005 ($2.8 million) and reduced selling, general and administrative expenses in 2005 ($3.7 million).
Interest Expense, Net
| Successor | Predecessor | Non-GAAP Combined | ||||||||||||||
| Twelve Months Ended December 31, 2005 | Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | |||||||||||||
| (unaudited) | ||||||||||||||||
| (in millions) | ||||||||||||||||
Interest expense—debt related | $ | (44.5 | ) | $ | (17.9 | ) | $ | (16.2 | ) | $ | (34.1 | ) | ||||
Interest expense—amortization of deferred financing fees | (4.8 | ) | (4.4 | ) | — | (4.4 | ) | |||||||||
Interest expense—surety bond and letter of credit fees | (10.2 | ) | (4.4 | ) | (1.8 | ) | (6.2 | ) | ||||||||
Interest income | 1.3 | 1.0 | 1.3 | 2.3 | ||||||||||||
Interest expense, net | $ | (58.2 | ) | $ | (25.7 | ) | $ | (16.7 | ) | $ | (42.4 | ) | ||||
Debt related interest expense for the twelve months ended December 31, 2005 was higher than the non-GAAP combined debt related interest expense for twelve months ended December 31, 2004 due to: (a) a larger balance of debt outstanding after July 30, 2004 due to the transaction; (b) imputed interest charges that began in the second half of 2004; and (c) greater utilization of the revolving credit agreement. Non-GAAP combined amortization of deferred financing fees for the twelve months ended December 30, 2004 includes $3.0 million of accelerated amortization from the repayment of variable rate debt with IPO proceeds and cash on hand at year end 2004; there is $1.6 million of accelerated amortization from repayment of variable rate debt in the year ended December 31, 2005.
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The increase in surety bond and letter of credit fees for the twelve months ended December 31, 2005 compared to the non-GAAP combined expense for the twelve months ended December 31, 2004 is due to higher balances of financial assurance instruments from the transaction date forward. The reduction in interest income between the years is primarily due to lower cash balances available for investment in 2005; $444.1 million of cash from the December 8, 2004 IPO earned interest for approximately one month in 2004 before being paid as a dividend to the pre-IPO shareholders on January 4, 2005.
Income Tax (Expense)
| Successor | Predecessor | Non-GAAP Combined | ||||||||||||
| Twelve Months Ended December 31, 2005 | Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | |||||||||||
| (unaudited) | ||||||||||||||
| (in millions) | ||||||||||||||
Income tax (expense) benefit | $ | (46.5 | ) | $ | (13.6 | ) | $ | 51.8 | $ | 38.2 | ||||
For the twelve months ended December 31, 2005, income taxes are provided at an effective rate of 34.3%. Current tax expense, which represents taxes currently payable on operations, was approximately 14.5% of pre-tax income. We provided a full valuation allowance against deferred tax assets attributable to alternative minimum tax credits in both successor periods. Management has determined that the Company does not meet the more likely than not criteria with regard to future utilization of these alternative minimum tax credits. For the five month operating period ended December 31, 2004, income tax expense was accrued at a blended federal and state income tax rate of 48.4%. This effective income tax rate exceeds the federal statutory income tax rate of 35% primarily due to the establishment of a valuation allowance against alternative minimum tax credits. In the period from January 1, 2004 through July 29, 2004, a deferred income tax benefit was recognized at a blended federal and state income tax rate of 36%, and substantially all of the net operating losses were realized as a result of the Acquisition. The valuation allowance of $4.6 million previously established against the deferred tax assets associated with certain net operating loss carryforwards was released as a credit to income tax expense in this predecessor period.
Period from January 1, 2004 through July 29, 2004 compared to the twelve months ended December 31, 2003 for RAG American Coal Holding, Inc. plus comments and comparisons to the five month operating period ended December 31, 2004 for Foundation Coal Holdings, Inc.
Coal sales realization per ton sold represents the average revenue realized on each ton of coal sold. It is calculated by dividing coal sales revenues by tons sold.
Revenues
| Successor | Predecessor | Non-GAAP Combined | Predecessor | |||||||||
| Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | Twelve Months Ended December 31, 2003 | |||||||||
| (unaudited) | ||||||||||||
| (in millions, except per ton data) | ||||||||||||
Coal sales | $ | 436.0 | $ | 544.9 | $ | 980.9 | $ | 976.0 | ||||
Other revenues | 8.6 | 6.1 | 14.7 | 18.3 | ||||||||
Total revenues | $ | 444.6 | $ | 551.0 | $ | 995.6 | $ | 994.3 | ||||
Tons sold | 27.6 | 35.9 | 63.5 | 67.2 | ||||||||
Coal sales realization per ton sold | $ | 15.80 | $ | 15.18 | $ | 15.47 | $ | 14.52 | ||||
Coal sales volumes and coal sales revenues reported for the period from January 1, 2004 through July 29, 2004 and the five month operating period ended December 31, 2004 are reported on a comparable basis, and represent, in
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combination, the non-GAAP combined results for the year ended December 31, 2004. The combined tons sold by the successor and predecessor during the twelve months ended December 31, 2004 and coal sales revenues on a non-GAAP combined basis for 2004 were 63.5 million tons and $980.9 million, respectively, compared with 67.2 million tons and $976.0 million in the twelve months ended December 31, 2003. The decrease in tons sold in 2004 as compared to 2003 is primarily due to lower production and sales from the Cumberland and Emerald mines in Northern Appalachia. From February 17 through May 7, the longwall mining equipment at the Cumberland mine was idled due to alleged violations resulting from a revised interpretation of regulations issued by MSHA regarding the ventilation system in the mine. In response, we revised the ventilation system to minimize any future business disruption, and on May 7, 2004, we resumed longwall operations at the Cumberland mine. Mainly as a result of the idle period for its longwall coupled with reduced shipments due to high water conditions from the hurricanes in September and October 2004, Cumberland’s combined tons sold by the successor and predecessor during the twelve months ended December 31, 2004 and non-GAAP combined coal sales revenues were 1.2 million tons and $28.7 million, respectively, lower in 2004 compared to the corresponding period of 2003. Emerald sold 1.3 million tons less in 2004 compared to the corresponding period of 2003 primarily due to mining delays attributable to adverse geological problems consisting of sandstone intrusions from the roof into the coal seam in the longwall panel mined during the period February through October 2004, which slowed mining by forcing the machinery to cut harder material and causing less stable roof conditions. While Emerald achieved record production in the month of December 2004, shipments for that month did not keep pace with production due to constrained rail capacity. The coal sales revenue effect of these lower 2004 shipments from Emerald were partly offset by increased average realizations per ton.
The Powder River Basin and Central Appalachia also had reduced combined tons sold by the successor and predecessor during the twelve months ended December 31, 2004 compared with 2003 totaling 1.2 million tons. In Central Appalachia, the Pioneer mine complex produced and sold less tons as the Simmons Fork surface mine completed mining and began the transition to the Pax surface mine. In the Powder River Basin, Eagle Butte produced and sold less tons due to a combination of poor rail service and limited attractively priced short term sales opportunities. Non-GAAP combined 2004 coal sales revenues in both the Powder River Basin and Central Appalachia increased from 2003 as higher average realizations more than offset the lower tons sold.
Total non-GAAP combined coal sales revenues increased 0.5% period-over-period due to a 6.5% increase in average realizations from improved pricing in all regions in which the Company operates. This increase was largely offset by a 5.5% decrease in tons sold, largely as a result of reduced production from our Northern Appalachia longwall mines as described above.
Other revenues reported for the period from January 1, 2004 through July 29, 2004 and the five month operating period ended December 31, 2004 were reported on a comparable basis, and represent, in combination, the non-GAAP combined results for the twelve months ended December 31, 2004. On a non-GAAP combined basis, other revenues in 2004 are $3.6 million less than 2003. An additional $3.7 million of losses on settlement of coal sales contracts and $4.2 million less from gains on asset sales in 2004 plus a $1.4 million gain from settlement of an asset retirement obligation in 2003 were partly offset by increased 2004 synfuel fees of $2.7 million and increased 2004 coalbed methane revenues of $3.9 million.
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Costs and Expenses
| Successor | Predecessor | Non-GAAP Combined | Predecessor | |||||||||||
| Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | Twelve Months Ended December 31, 2003 | |||||||||||
| (unaudited) | ||||||||||||||
Cost of coal sales (excludes depreciation, depletion and amortization) | $ | 345.8 | $ | 484.5 | $ | 830.3 | $ | 798.3 | ||||||
Selling, general and administrative expenses (excludes depreciation, depletion and amortization) | 24.6 | 27.4 | 52.0 | 45.3 | ||||||||||
Accretion on asset retirement obligations | 3.3 | 4.0 | 7.3 | 7.0 | ||||||||||
Depreciation, depletion and amortization | 84.8 | 61.2 | 146.0 | 99.8 | ||||||||||
Amortization of coal supply agreements | (67.2 | ) | 8.8 | (58.4 | ) | 17.9 | ||||||||
Total costs and expenses | $ | 391.3 | $ | 585.9 | $ | 977.2 | $ | 968.3 | ||||||
Cost of coal sales. The cost of coal sales for the five month operating period ended December 31, 2004 (which represents operations from July 30 through December 31, 2004) included approximately $15.3 million less in deferred overburden charges and $8.8 million less in postretirement medical, pension and black lung benefit expenses as a result of purchase accounting compared with a comparable length period of the Predecessor. In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially and fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to preacquisition overburden removal efforts, is included in depreciation, depletion and amortization. Subsequent to the acquisition date, the costs associated with removal of overburden to uncover coal reserves is inventoried as work-in-process until the related coal is mined and the inventoried cost charged to cost of coal sales when the coal is sold. Until coal valued as partially or fully uncovered at the acquisition date is fully depleted, depreciation, depletion and amortization will include the value of overburden removal performed prior to the acquisition date which if incurred subsequent to the acquisition date would have been included in cost of coal sales. As a result of revaluing pension and post-employment benefit liabilities at the acquisition date under purchase accounting, unamortized actuarial losses which were being amortized in expense by the Predecessor were eliminated. As a result, pension and post retirement benefit costs of the Successor are expected to be lower than that of the Predecessor. Cost of coal sales for the five month operating period ended December 31, 2004 also included approximately $3.8 million of additional charges from sale of inventories revalued to market in purchase accounting than for a comparable length period of the Predecessor. These effects from the application of purchase accounting to the Successor basis of reporting cost of coal sales net to $20.3 million of reduced expense. Otherwise, the cost of coal sales are reported on a comparable basis for the period from January 1, 2004 through July 29, 2004 and for the five month operating period ended December 31, 2004. The non-GAAP combined 2004 cost of coal sales was $830.3 million compared to $798.3 million in 2003.
This increase is the net impact of the $15.3 million less in deferred overburden charges as a result of purchase accounting, the elimination of $8.8 million in amortization of actuarial losses in pension and post retirement medical expenses, the additional cost of sales of $3.8 million relating to inventory revalued at the acquisition date and an increase of $52.2 million, or 6.5%, mainly due to higher mine operating costs in the areas of retiree health care, workers’ compensation, repairs and maintenance, mine operating supplies, wages, salaries, contract labor and coal trucking, along with increased costs for purchased coal. The increased costs of mine operating supplies and repair and maintenance parts is largely attributable to commodity price increases, particularly for steel products and diesel fuel.
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Selling, general and administrative expenses. Selling, general and administrative expenses for the period from January 1, 2004 through July 29, 2004 included $1.8 million in bonus expenses related to the sale of RAG American Coal Holding, Inc. The five month operating period ended December 31, 2004 included $1.7 million of bonus expenses paid to senior management related to the IPO, $2.0 million of sponsor monitoring fees, and $1.3 million of expenses arising from adjustment of the incurred-but-not-reported (IBNR) medical benefits liability. Non-GAAP combined selling, general and administrative expenses for 2004 were $52.1 million compared to $45.3 million for the Predecessor in 2003. The increase is primarily due to the IPO and acquisition related costs discussed above. Increases in compensation, employee relocation expenses and professional service fees in the non-GAAP combined 2004 period are offset by lower sales commissions and reduced consulting expenses compared to 2003.
Accretion on asset retirement obligation. Accretion on asset retirement obligation is a component of accounting for asset retirement obligations under SFAS No. 143. Accretion represents the increase in the asset retirement liability to reflect the change in the liability for the passage of time. We adopted SFAS No. 143, effective January 1, 2003. The impact of adopting SFAS No. 143 is discussed below. Application of purchase accounting increased accretion of asset retirement obligations by approximately $0.4 million in the five month operating period ended December 31, 2004, compared with a comparable length period of the Predecessor. Non-GAAP combined accretion in asset retirement obligation for 2004 was $7.3 million, compared with $7.0 million for the Predecessor for 2003.
Depreciation, depletion and amortization. In comparison to historical reporting of the Predecessor, depreciation, depletion and amortization for the five month operating period ended December 31, 2004 reflects increased cost depletion of owned and leased mineral rights as a result of the purchase accounting in which higher values have been assigned to owned and leased mineral rights. In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially and fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to pre-acquisition overburden removal efforts, is included in depreciation, depletion and amortization. Subsequent to the acquisition date, the costs associated with removal of overburden to uncover coal reserves is inventoried as work-in-progress until the related coal is mined and the inventoried cost is 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. Cost depletion for the five month operating period includes $23.5 million related to the production of fully and partially uncovered coal which received a higher value than other owned and leased mineral rights at the acquisition date. Absent this application of purchase accounting the amortization of costs associated with fully and partially uncovered coal would have been included in and increased the cost of coal sales. Non-GAAP combined depreciation, depletion and amortization for 2004 was $146.0 million compared with $99.8 million for the Predecessor in 2003. The increase is the result of the higher basis in assets subject to depreciation, depletion and amortization. The higher basis assets are primarily coal reserves recorded at fair value at the acquisition date. The Successor expects that depreciation, depletion and amortization in future years will continue to be higher than that of the Predecessor due to the higher asset bases.
Coal supply agreement amortization. Application of purchase accounting resulted in recognition of a significant liability for below market priced coal supply agreements as well as a significant asset for above market priced coal supply agreements, both in relation to market prices at the acquisition date. Amortization of the liability for below market priced coal supply agreements during the five month operating period ended December 31, 2004 totaled $88.2 million of credit to expense. Amortization of the asset for above market priced coal supply agreements during the same period totaled $21.0 million of charges to expense. Coal supply agreement amortization of the Predecessor was only related to above market coal supply agreements in existence at the time of the acquisition of certain mining properties in 1999.
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Segment Analysis
Utilizing data published by Argus Media, the following graph sets forth representative steam coal prices in various U.S. markets for the period from January 1, 2003 through December 31, 2004. 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 statements.
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| Successor | Predecessor | Non-GAAP Combined | Predecessor | ||||||||||
Five Month Operating Period | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | Twelve Months Ended December 31, 2003 | ||||||||||
| (unaudited) | |||||||||||||
| (in millions, except per ton data) | |||||||||||||
Powder River Basin | |||||||||||||
Tons sold | 17.9 | 23.8 | 41.7 | 42.6 | |||||||||
Average sales realization per ton | $ | 7.80 | $ | 7.51 | $ | 7.64 | $ | 7.12 | |||||
Revenues | $ | 140.2 | $ | 179.8 | $ | 320.0 | $ | 305.6 | |||||
Income from operations | $ | 3.5 | $ | 30.7 | $ | 34.2 | $ | 47.7 | |||||
Northern Appalachia | |||||||||||||
Tons sold | 4.8 | 5.8 | 10.7 | 13.2 | |||||||||
Average sales realization per ton | $ | 26.33 | $ | 27.07 | $ | 26.74 | $ | 24.80 | |||||
Revenues | $ | 128.1 | $ | 160.5 | $ | 288.6 | $ | 330.0 | |||||
Income (loss) from operations | $ | 49.4 | $ | (10.4 | ) | $ | 39.0 | $ | 29.0 | ||||
Central Appalachia | |||||||||||||
Tons sold | 3.4 | 4.4 | 7.9 | 8.2 | |||||||||
Average sales realization per ton | $ | 36.38 | $ | 35.02 | $ | 35.61 | $ | 31.92 | |||||
Revenues | $ | 122.1 | $ | 159.0 | $ | 281.1 | $ | 263.8 | |||||
Income (loss) from operations | $ | 21.8 | $ | (9.8 | ) | $ | 12.0 | $ | 5.7 | ||||
Powder River Basin—Income from operations for the period from January 1, 2004 through July 29, 2004 was $30.7 million. Income from operations for the five month operating period ended December 31, 2004 was $3.5 million, and was reduced by approximately $20 million from the application of purchase accounting. The application of purchase accounting resulted in higher cost depletion and amortization of coal supply agreements partially offset by a reduction in cost of coal sales arising from the deferral of overburden removal costs. Non-GAAP combined income from operations for the Powder River Basin for 2004 was $34.2 million compared to $47.7 million for the Predecessor in 2003. This decrease is due to the net of the impact of purchase accounting previously discussed and higher average sales realizations, partly offset by lower tons sold and increases in mine operating expenses.
Northern Appalachia—Losses from operations for the period from January 1, 2004 through July 29, 2004 were $10.4 million primarily due to the previously described idling of the longwall at the Cumberland mine from February 17 through May 7, 2004. Income from operations for the five month operating period ended December 31, 2004, was $49.4 million which benefited by approximately $38 million from the application of purchase accounting. This benefit was primarily from amortization of a liability established for below term market priced coal supply agreements, which is reported as a credit in amortization of coal supply agreements, partly offset by increased cost depletion and additional cost of coal sales from recording coal inventories at fair value at the acquisition date. Non-GAAP combined income from operations for Northern Appalachia for 2004 was $39.0 million compared to $29.0 million for the Predecessor in 2003. The net impact of the effects of purchase accounting, the idle period for the Cumberland longwall and lower production from Emerald as a result of longwall mining delays from periodic adverse geological problems encountered in mining the first longwall panel of a new mining district between February and October 2004 account for this change. Though it is uncertain, we expect to encounter similar geological conditions in future panels to be mined at Emerald. In response to these conditions, we have made changes to our equipment and operating plan at Emerald that we believe will mitigate the impact of these adverse geologic conditions.
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Central Appalachia—Losses from operations for the period from January 1, 2004 through July 29, 2004 were $9.8 million primarily due to production shortfalls associated with adverse geological problems at the Kingston and Rockspring mines, the depletion of reserves at one of the Pioneer surface mines, significant increases in operating costs in the areas of health care, mine operating supplies, workers’ compensation, wages, salaries, contract labor, equipment repairs and maintenance and coal trucking coupled with litigation settlement charges of $2.7 million. Higher average sales realizations at all mines partly offset the reduced production and higher costs. Income from operations for the five month operating period ended December 31, 2004 was $21.8 million. Income for this five month operating period was benefited by approximately $22.0 million from the application of purchase accounting. This benefit from the application of purchase accounting was primarily from amortization of a liability established for below term market priced coal supply agreements which is reported as a credit in amortization of coal supply agreements, partly offset by higher cost depletion and additional cost of coal sales from recording coal inventories at fair value at the acquisition date. Non-GAAP combined income from operations for Central Appalachia for 2004 was $12.0 million compared to $5.7 million for the Predecessor in 2003. This change in income from operations was the net impact of the effects of purchase accounting combined with the same factors cited above for the period from January 1, 2004 through July 29, 2004.
Other—Includes the Company’s Illinois Basin operation, the Wabash mine, 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 and Central Appalachia mine. During the twelve months ended December 31, 2004, the Other segment reported a non-GAAP combined loss from operations of $66.9 million compared to a loss from operations of $56.3 million in the twelve months ended December 31, 2003. The increased period-over-period loss from operations of $10.6 million was mainly due to: (a) lower other revenues in 2004 as explained previously; and (b) higher selling, general and administrative expenses for 2004 on a non-GAAP combined basis as discussed previously.
Other Income (Loss)
| Successor | Predecessor | Non-GAAP Combined | Predecessor | |||||||||||
| Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, | Twelve Months Ended December 31, | |||||||||||
| (unaudited) | ||||||||||||||
| (in millions) | ||||||||||||||
Litigation settlements | $ | — | $ | — | $ | — | $ | 43.5 | ||||||
Contract settlement | — | (26.0 | ) | (26.0 | ) | — | ||||||||
Loss on termination of hedge accounting for interest rate swaps | — | (48.9 | ) | (48.9 | ) | — | ||||||||
Unrealized gain on interest rate swap | 0.5 | 5.8 | 6.3 | — | ||||||||||
Early debt extinguishment costs | — | (21.7 | ) | (21.7 | ) | — | ||||||||
Litigation settlements. In February 2003, we received a cash settlement from a litigation claim arising from inaccuracies in financial statements represented as correct by Cyprus Amax Minerals Company, in connection with the sale to RAG of Cyprus Amax Coal Company in June 1999.
Contract Settlement. In July 2004, the Predecessor reached a settlement agreement with South Carolina Public Service Authority (“Santee Cooper”) in which Santee Cooper agreed to relinquish any claims under a guarantee in exchange for a multi-year coal supply agreement from our Pennsylvania operations at prices below then prevailing market prices for new contracts of similar duration. The guarantee related to a multi-year supply agreement between Santee Cooper and a former subsidiary that the Predecessor sold to Horizon NR LLC in 1998. The Predecessor recorded a non-cash charge of $26.0 million in the period from January 1, 2004 through July 29, 2004 based on the present value of the difference between the agreed upon contract prices and market prices for new contracts of similar duration.
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Expense resulting from termination of hedge accounting for interest rate swaps and unrealized gain (loss) on interest rate swaps. As a result of the execution of a definitive stock purchase agreement to sell the RAG Colorado Business Unit during the first quarter of 2004, it became probable that the Predecessor’s variable rate bank debt would be repaid early rather than held to maturity. Therefore, pay-fixed, receive-variable interest rate swaps that had previously been designated as a hedge against the variable interest payments on this debt no longer qualified for hedge accounting under SFAS No. 133 Accounting for Derivative Financial Instruments and Hedging Activities (“SFAS No. 133”). The fair value of the interest rate swaps on the date it became probable that the future variable interest payments being hedged by the swap would no longer be made was charged to “Loss on termination of hedge accounting for interest rate swaps” with a corresponding gain reported in other comprehensive income. The amount of the mark-to-market change in the fair value of the interest rate swaps for the portion of the year following the determination that they did not qualify for hedge accounting was recorded as an unrealized gain. The interest rate swaps were settled when the variable rate bank debt was repaid on April 27, 2004.
On September 30, 2004, we entered into receive variable, pay fixed interest rate swap agreements on a notional amount of $85.0 million for three years. Under these swaps, we receive a variable rate of 3 month US dollar LIBOR and pay a fixed rate of 3.26%. For the five month operating period ended December 31, 2004, we recorded a gain on these swaps of $0.5 million. Upon completion of the effectiveness testing and related documentation, these interest rate swaps were designated as cash flow hedges of the variable interest payments due on $85.0 million of our variable rate debt through September 2007 under SFAS No. 133 at December 31, 2004.
Early debt extinguishment costs. In July 2004, the Predecessor incurred cash prepayment penalties of $21.7 million in connection with prepayment of substantially all remaining long-term indebtedness as required under the terms of the stock purchase agreement between Foundation Coal Corporation and RAG Coal International AG.
Interest Expense, Net
| Successor | Predecessor | Non-GAAP Combined | Predecessor | |||||||||||||
Five Month Ended | Period From January 1 | Twelve Months Ended | Twelve Months Ended | |||||||||||||
| (unaudited) | ||||||||||||||||
| (in millions) | ||||||||||||||||
Interest expense | $ | (26.7 | ) | $ | (18.0 | ) | $ | (44.7 | ) | $ | (46.9 | ) | ||||
Interest income | 1.0 | 1.3 | 2.3 | 3.2 | ||||||||||||
Interest expense, net | $ | (25.7 | ) | $ | (16.7 | ) | $ | (42.4 | ) | $ | (43.7 | ) | ||||
In addition to the abbreviated length of the period from January 1, 2004 through July 29, 2004, the decline in net interest expense between the two Predecessor periods was a result of lower outstanding bank debt levels in 2004 due to repayment of two bank term loans in April of 2004. The interest expense for the Successor period reflects approximately five months of interest expense on the $470.0 million senior secured term loan B and the $300.0 million senior unsecured 10-year 7.25% Senior Notes, $4.4 million of non-cash amortization of deferred financing costs and $4.4 million of surety bond and letter of credit fees. We incurred this indebtedness to purchase RAG American Coal Holding, Inc. and subsidiaries.
Income Tax (Expense) Benefit
| Successor | Predecessor | Non-GAAP Combined | Predecessor | ||||||||||
| Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | Twelve Months Ended December 31, 2003 | ||||||||||
| (unaudited) | |||||||||||||
| (in millions) | |||||||||||||
Income tax (expense) benefit | $ | (13.6 | ) | $ | 51.8 | $ | 38.2 | $ | 0.2 | ||||
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In the period from January 1, 2004 through July 29, 2004, a deferred income tax benefit was recognized at a blended federal and state income tax rate of 36.4%, and substantially all of the net operating losses carryforwards were realized as a result of the Acquisition. The valuation allowance of $4.6 million previously established against the deferred tax assets associated with certain net operating loss carryforwards was released as a credit to income tax expense in the period January 1, 2004 through July 29, 2004. The remaining valuation allowance of $1.0 million was eliminated at the July 30, 2004 acquisition date. In the five month operating period ended December 31, 2004, income tax expense was accrued at a blended federal and state income tax rate of 48.4%. This effective income tax rate exceeds the federal statutory tax rate of 35% primarily due to the establishment of a valuation allowance against alternative minimum tax credits. Management has determined that the Company does not meet the more likely than not criteria with regard to future utilization of these alternative minimum tax credits. In the twelve months ended December 31, 2003, the income from the litigation settlement allowed the recognition of percentage depletion benefits that reduced the blended federal and state income tax rate applied to income from continuing operations to approximately 0%.
Income from Discontinued Operations After Income Taxes
| Successor | Predecessor | Non-GAAP Combined | Predecessor | ||||||||||||
| Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2004 | Twelve Months Ended December 31, 2003 | ||||||||||||
| (unaudited) | |||||||||||||||
| (in millions) | |||||||||||||||
Income from discontinued operations before income taxes | $ | — | $ | 2.9 | $ | 2.9 | $ | 16.1 | |||||||
Gain from sale of discontinued operations | — | 25.7 | 25.7 | — | |||||||||||
Income tax expense | — | (5.5 | ) | (5.5 | ) | (6.0 | ) | ||||||||
Income from discontinued operations after income taxes | $ | — | $ | 23.1 | $ | 23.1 | $ | 10.1 | |||||||
Income from discontinued operations consists of income from the RAG Colorado Business Unit, which primarily includes the results of operations of the Twentymile mine located in Routt County, Colorado. The increase in income from discontinued operations before income taxes in the period from January 1, 2004 through July 29, 2004 was mainly due to the gain from sale of this business unit on April 15, 2004. Income from the discontinued operations, excluding the gain, was lower in the period from January 1, 2004 through July 29, 2004 as compared to 2003 as a direct result of the sale timing which occurred three and one-half months into 2004.
Cumulative Effect of Accounting Change
Effective January 1, 2003, we adopted SFAS No. 143, which requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time obligations are incurred. Upon initial recognition of a liability, that cost is capitalized to the related long-lived asset and allocated to expense over the useful life of the asset. The asset retirement obligations are initially recorded at their present value and accreted to reflect the increase in the liability for the passage of time. Application of SFAS No. 143 resulted in a non-cash charge due to the cumulative effect of an accounting change as of January 1, 2003 of $3.6 million, net of tax. Prior to the adoption of SFAS No. 143, we utilized a cost accumulation method that accrued the expected mine closure expense over the coal reserves that each property was expected to mine.
Liquidity and Capital Resources
Our primary sources of cash have been sales of our coal production and purchased coal to customers, plus cash from sales of non-core assets.
Our primary uses of cash have been our cash costs of coal production, the cash cost of purchased coal, capital expenditures, interest costs, cash payments for employee benefit obligations such as defined benefit pensions and
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retiree health care benefits, cash outlays related to post mining asset retirement obligations and support of working capital requirements such as coal inventories and trade accounts receivable. Our ability to service our debt (principal and interest) and acquire new productive assets for use in our operations has been and will be dependent upon our ability to generate cash from our operations. We normally fund all of our capital expenditure requirements with cash generated from operations. During the past three years, we have engaged in minimal financing of assets such as through operating leases.
In the Predecessor periods, cash balances in excess of our day-to-day operating requirements were placed on deposit with RAG where cash balances could be aggregated to earn better investment returns. This cash on deposit was available to us on a one day turn-around. Increases in the cash on deposit with RAG have been classified under financing activities as uses of cash in the consolidated cash flow statements. Decreases in cash on deposit with RAG have been classified under financing activities as cash provided.
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, 2005, five month operating period ended December 31, 2004 and for the period from January 1, 2004 through July 29, 2004:
| Successor | Predecessor | |||||||||||
Twelve Months Ended December 31, | Five Month Operating Period Ended December 31, | Period From January 1 Through July 29, 2004 | ||||||||||
| (in millions) | ||||||||||||
Cash provided by (used in): | ||||||||||||
Operating activities—continuing operations | $ | 184.2 | $ | 62.2 | $ | (8.0 | ) | |||||
Operating activities—discontinued operations | — | — | 7.0 | |||||||||
Investing activities—continuing operations(1) | (130.4 | ) | (934.9 | ) | (50.7 | ) | ||||||
Investing activities—discontinued operations | — | — | 185.0 | |||||||||
Financing activities—borrowings(2) | 76.0 | 830.0 | 306.0 | |||||||||
Financing activities—repayments(2) | (126.0 | ) | (145.1 | ) | (686.9 | ) | ||||||
Financing activities—sales of equity securities | 0.6 | 693.5 | — | |||||||||
Financing activities—dividends on common stock | (452.1 | ) | (1.0 | ) | — | |||||||
Financing activities—other | (0.2 | ) | (34.4 | ) | — | |||||||
Financing activities—pledged cash | — | — | 20.0 | |||||||||
Financing activities—on deposit with RAG(3) | — | — | 233.0 | |||||||||
Change in cash and cash equivalents | $ | (447.9 | ) | $ | 470.3 | $ | 5.4 | |||||
| (1) | Cash used in investing activities by the Successor for the five month operating period ended December 31, 2004 include $904.9 million, net of cash acquired to acquire RAG American Coal Holding, Inc. and subsidiaries from RAG Coal International AG. |
| (2) | The borrowings and repayments during the twelve months ended December 31, 2005 in the amount of $76.0 million represent use of the Revolving Credit facility to maintain day-to-day liquidity and a $50.0 million prepayment of long term bank debt in advance of maturity. |
| (3) | Represents the decrease in the balance of cash on deposit with RAG. |
Cash provided by operating activities from continuing operations increased in the twelve months ended December 31, 2005 as compared to the non-GAAP combined results of the Successor for the five month operating period ended December 31, 2004 and the Predecessor for the period from January 1, 2004 through July 29, 2004, primarily due to higher net income from continuing operations, partly offset by increases in working capital, mainly trade accounts receivable and inventories.
Cash used in investing activities for continuing operations, excluding the purchase of RAG American Coal Holding, Inc., increased in the twelve months ended December 31, 2005 as compared to the non-GAAP combined results of the Successor for the five month operating period ended December 31, 2004 and the Predecessor for the period from January 1, 2004 through July 29, 2004 due to higher capital expenditures in the 2005 period. Capital
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expenditures for the twelve months ended December 31, 2005 totaled $140.2 million, including $49.8 million of expenditures related to the expansion of the Belle Ayr Mine in the Powder River Basin, development of the Pax surface mine and related rail loading facility in Central Appalachia, addition of a continuous mining unit to the Kingston Mine in Central Appalachia, the widening of the Emerald Mine longwall face to 1,450 feet from 1,250 feet and upgrades to the rail loading facility at Emerald. Non-GAAP combined capital expenditures of the Successor for the five month operating period ended December 31, 2004 and for the Predecessor for the period from January 1, 2004 through July 29, 2004 of $86.3 million were mainly for replacement of equipment and other expenditures necessary to sustain mine operations.
Cash used in financing activities by the Successor for the twelve months ended December 31, 2005 includes the payment of $452.1 million of cash dividends, including $444.1 million of cash dividends related to the IPO that were accrued as of December 31, 2004 and paid on January 4, 2005. The remaining $8.0 million in cash dividends were a quarterly dividend of $.04 per share paid in March and June 2005 and a quarterly dividend of $0.05 per share paid in September and December 2005. Cash used in financing activities by the Successor for the twelve months ended December 31, 2005 also includes $50.0 million in prepayments of our senior secured term Loan B. These payments were voluntary and consistent with management’s strategy to deleverage the Company as funds are available from cash flows generated by the business.
Cash used in financing activities of the Predecessor for the period from January 1, 2004 through July 29, 2004 represents repayment of all long-term debt of the Predecessor including cash prepayment penalties coupled with the settlement of the Predecessor’s interest rate swaps. These repayments utilized the proceeds from the sale of the RAG Colorado Business Unit, cash previously reported as cash on deposit with Parent, cash pledged and $306.0 million of cash advanced by RAG Coal International AG that the Predecessor repaid from a portion of the cash acquisition price that Foundation Coal paid to RAG.
The cash acquisition price, including transaction costs, of $904.9 million paid by Foundation for RAG American Coal Holding, Inc and subsidiaries, net of cash acquired, was funded by $830.0 million of Successor long-term debt, consisting of $470.0 million of senior secured term Loan B, $300.0 million of senior unsecured long-term notes, $60.0 million of drawings under the $350.0 million revolving credit facility and $196.0 million of cash equity contributed by the shareholders. The $60.0 million of drawings under the revolving credit facility were fully repaid on the first business day after the Acquisitions utilizing cash of the acquired subsidiaries. The $34.4 million other cash used in financing activities consists of $28.6 million for costs associated with arranging the long-term debt used to fund the acquisition, which are accounted for as deferred financing fees and amortized over the lives of the senior secured Loan B and the senior unsecured long-term notes, and $5.8 million for cash expenses of the IPO.
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The following is a summary of cash provided by or used in each of the indicated categories of activities during the five month operating period ended December 31, 2004, the period from January 1, 2004 through July 29, 2004 and the twelve months ended December 31, 2003:
| Successor | Predecessor | |||||||||||
| Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2003 | ||||||||||
| (in millions) | ||||||||||||
Cash provided by (used in): | ||||||||||||
Operating activities—continuing operations | $ | 62.2 | $ | (8.0 | ) | $ | 197.7 | |||||
Operating activities—discontinued operations | — | 7.0 | 35.4 | |||||||||
Investing activities—continuing operations | (934.9 | ) | (50.7 | ) | (92.7 | ) | ||||||
Investing activities—discontinued operations | — | 185.0 | (2.8 | ) | ||||||||
Financing activities—borrowings(1) | 830.0 | 306.0 | — | |||||||||
Financing activities—repayments | (145.1 | ) | (686.9 | ) | (40.3 | ) | ||||||
Financing activities—sales of equity securities | 693.5 | — | — | |||||||||
Financing activities—dividends on common stock | (1.0 | ) | — | — | ||||||||
Financing activities—other | (34.4 | ) | — | — | ||||||||
Financing activities—pledged cash | — | 20.0 | 55.1 | |||||||||
Financing activities—on deposit with RAG(2) | — | 233.0 | (166.5 | ) | ||||||||
Change in cash and cash equivalents | $ | 470.3 | $ | 5.4 | $ | (14.1 | ) | |||||
| (1) | The borrowing in the period from January 1, 2004 through July 29, 2004 represented a short-term advance from RAG that was repaid from a portion of $904.9 million that Foundation Coal paid to RAG to acquire RAG American Coal Holdings, Inc. and subsidiaries. |
| (2) | Represents the decrease in the balance of cash on deposit with RAG. |
Cash provided by operating activities from continuing operations in the period from January 1, 2004 through July 29, 2004 decreased as compared to 2003 due to reduced production and sales at the Cumberland mine as previously discussed along with significant payments of accrued interest associated with repayment of the Predecessor’s long-term debt. The 2004 period was also approximately five months shorter in duration. The cash provided by operating activities in 2003 included $43.5 million from a cash litigation settlement previously discussed. Cash provided by operating activities for the five month operating period ended December 31, 2004 increased in comparison to the period from January 1, 2004 through July 29, 2004, primarily due to improved operating performance, lower interest payments and the timing of accounts receivable collections.
Cash used in investing activities for continuing operations decreased in the period January 1, 2004 through July 29, 2004 from the twelve months ended December 31, 2003 mainly due to lower capital expenditures, attributable to the abbreviated 2004 reporting period. Capital expenditures during the five month operating period ended December 31, 2004 were approximately 12% less on an annualized basis than capital expenditures during the period from January 1, 2004 through July 29, 2004. This reduction is due to lower capital expenditures in the Powder River Basin, Northern Appalachia and Central Appalachia partly offset by increased capital expenditures at the Wabash Mine during the five month operating period ended December 31, 2004.
Cash used in financing activities primarily represents repayment of all long-term debt of the Predecessor, including cash prepayment penalties coupled with settlement of the interest rate swaps. These repayments utilized the proceeds from the sale of the Colorado Business Unit, cash previously reported as cash on deposit with Predecessor, cash pledged and $306.0 million of cash advanced by RAG that we repaid from a portion of the cash acquisition price that Foundation Coal paid to RAG.
The sale of the RAG Colorado Business Unit to a third party closed on April 15, 2004. The cash proceeds from the sale, prior to final purchase price adjustments, were $182.7 million. Purchase price adjustments totaled $0.5 million. With this receipt, we realized a pre-tax gain on sale of the discontinued operation of $25.7 million. The proceeds were deposited into an escrow account at DZ Bank. In addition, $221.4 million of our cash on deposit with
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RAG was also deposited into this escrow account. On April 27, 2004, the escrow account balance of $404.2 million, including interest earned on the account of $0.1 million, was used to: (a) repay the Tranche A Notes due to DZ Bank and Dresdner in the combined amount of $358.0 million; (b) pay accrued interest on these notes in the amount of $1.5 million; and (c) settle the pay-fixed, receive-variable interest rate swaps for a payment of $44.7 million as mentioned above.
The remaining Predecessor long-term debt, accrued interest and related prepayment penalties, totaling approximately $305.9 million, were repaid on July 28, 2004 utilizing $306.0 million of cash advanced by RAG. This advance was repaid using a portion of the cash acquisition price that Foundation Coal Corporation paid to RAG.
The cash acquisition price, including transaction costs of $904.9 million paid by us for RAG American Coal Holding, Inc. and subsidiaries, net of cash acquired, was funded by $830.0 million of Successor long-term debt, consisting of $470.0 million of senior secured term Loan B, $300.0 million of 7.25% Senior Notes, and $60.0 million of drawings under the $350.0 million revolving credit facility, and $196.0 million of cash equity contributed by the shareholders. The $60 million drawing under the revolving credit facility was fully repaid on the first business day after the acquisition utilizing cash of the acquired subsidiaries. The $28.6 million of costs associated with arranging the long term debt used to fund the acquisition is included in the cash outflows for “Financing Activities—Other.”
On December 8, 2004, Foundation Coal Holdings, Inc. sold 23.6 million common shares in an IPO resulting in proceeds net of underwriting discount of $486.9 million. Cash expenses of the IPO in the amount of $5.8 million are included in the cash outlays for “Financing Activities—Other” in the above table. On December 21, 2004, an additional 0.5 million common shares were issued pursuant to the underwriters’ exercise of a portion of their overallotment option resulting in proceeds net of underwriting discount of $10.5 million. Approximately $47.1 million of IPO proceeds along with cash on hand were used to prepay $85.0 million of the senior secured term loan in December 2004.
On December 8, 2004, Foundation Coal Holdings, Inc. declared dividends on common stock totaling $439.0 million to the pre-IPO shareholders, including members of Foundation Coal Holdings, Inc.’s senior management. The members of senior management elected to take their portion of the dividend, totaling $5.1 million, in shares of common stock. Dividends of $1.0 million were paid in December 2004. The remaining $432.9 million of cash dividends were paid in January 2005. The stock dividend was declared on December 8, 2004 and was distributed to senior management on January 4, 2005. The Company paid an additional dividend of $11.1 million to the pre-IPO shareholders from the proceeds of the underwriters’ exercise of a portion of the overallotment option plus cash on hand. This dividend was also declared on December 8, 2004 and was paid on January 4, 2005.
The portion of the underwriters’ overallotment option that was not exercised, consisting of 3.0 million common shares, was distributed to the pre-IPO shareholders as a stock dividend in January 2005.
Our primary source of liquidity will continue to be cash from sales of our coal production and purchased coal to customers. We have availability under our revolving credit facility, subject to certain conditions.
As of December 31, 2005, we have outstanding $635.0 million in aggregate indebtedness, with an additional $164.2 million of available borrowings under our revolving credit facility (after giving effect to $185.8 million of letters of credit outstanding as of December 31, 2005). Our liquidity requirements will be significant, primarily due to debt service requirements. Of the $59.5 million of interest expense for the year ended December 31, 2005, approximately $52.7 million has or will be paid in cash.
Based on our current levels of operations, we believe that remaining cash on hand, cash flow from operations and available borrowings under the revolving credit portion of our Senior Credit Facility will enable us to meet our working capital, capital expenditure, debt service and other funding requirements for at least the next twelve months.
Our Senior Credit Facility consists of a revolving credit facility and a term loan facility. Our revolving credit facility provides for loans in a total principal amount of up to $350.0 million, less outstanding letters of credit, which will be available for general corporate purposes, subject to certain conditions, and will mature in five years. The term loan facility consists of a $470.0 million term loan facility with a maturity of seven years.
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Borrowings under our Senior Credit Facility bear interest at a floating base rate plus an applicable margin. The initial applicable margin for borrowings under the revolving credit facility is 1.50% with respect to base rate borrowings and 2.50% with respect to LIBOR borrowings. Based on our leverage ratio as of December 31, 2005, the margins on our revolving credit facility have been reduced to 1.00% and 2.00%, respectively. The initial applicable margin for borrowings under the term loan facility is 1.00% with respect to base rate borrowings and 2.00% with respect to LIBOR borrowings. Based on our leverage ratio as of December 31, 2005, the margins under our term loan facility have been reduced to 0.75% and 1.75%, respectively. The above cited reductions in the margins on our revolving credit facility and our term loan facility bring those respective margins to the minimum levels provided in our credit agreement.
In addition to paying interest on outstanding principal under the Senior Credit Facility, we will be required to pay a commitment fee to the lenders under the revolving credit facility in respect of the unutilized commitments, at a rate equal to 0.375% per annum, based on our leverage ratio as of December 31, 2005. We will also pay customary letter of credit fees.
The Senior Credit Facility requires us to prepay outstanding term loans, subject to certain exceptions, in certain situations. Any mandatory prepayments other than from excess cash flow would be applied to the remaining installments of the term loan facility on a pro rata basis. Mandatory prepayments from excess cash flow would be applied to the term loan facility at our direction. If pre-paid, there would be a charge for unamortized deferred issuance costs.
At the inception of the Senior Credit Facility, we were required to repay installments on the loans in quarterly principal amounts of 0.25% of their funded total principal amount for the first six years and nine months, with the remaining amount payable on the date that is seven years from the date of the closing of the senior secured credit facility. In prepaying $85.0 million in December 2004, we eliminated quarterly principal installments for the life of the loan. In reducing our leverage ratio below 2.5 to 1 as of December 31, 2005, we are not required to make mandatory prepayments from excess cash flows.
Principal amounts outstanding under the revolving credit facility will be due and payable in full at maturity, five years from the date of the closing of the senior secured credit facility.
The Senior Credit 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.
We have amended our credit agreement to permit the payment of certain dividends. Our credit agreement now permits the payment to us by our subsidiary, FC2 Corp., for use by us to pay dividends on our common stock after the IPO in an amount not to exceed $12.5 million in any consecutive four quarter period, which amount may increase to $30.0 million and $45.0 million upon reaching leverage ratios, as set forth in the credit agreement, of 3.0 to 1.0 and 2.0 to 1.0, respectively. Accordingly, we expect that the terms of our credit agreement will permit us to pay dividends at a quarterly dividend rate of at least $0.05 per share for the foreseeable future.
In addition, the Senior Credit Facility requires FC2 Corp. to maintain the following financial covenants: a maximum total leverage ratio, a minimum interest coverage ratio and a maximum capital expenditures limitation.
The indenture governing our outstanding 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 FC2 Corp. by Foundation Coal Corporation of $25.0 million, plus an amount up to 5% per calendar year of the net proceeds received by Foundation Coal Corporation from the IPO. Foundation Coal Corporation will also have the ability to pay dividends over time using a formula based on 50% of consolidated net income, as set forth in the indenture, if it meets certain conditions, including having greater than a 2.0 to 1.0 fixed charge coverage ratio.
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Subject to certain exceptions, the indenture governing our outstanding 7.25% Senior Notes permits us and our restricted subsidiaries to incur additional indebtedness, including secured indebtedness.
As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition of coal mining assets, including LBA bids, and acquisitions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our growth plans and our acquisition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements, which may be binding or nonbinding, that are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreements if, among other things, we are not satisfied with the results of our due diligence investigation. Any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both.
Covenant Compliance
We believe that our Senior Credit Facility and the indenture governing our outstanding 7.25% Senior Notes are material agreements, that the covenants are material terms of these agreements and that information about the covenants is material to an investor’s understanding of our financial condition and liquidity. The breach of covenants in the Senior Credit Facility that are tied to ratios based on Adjusted EBITDA, as defined below, could result in a default under the Senior 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 Credit Facility and indenture, our ability to engage in activities such as incurring additional indebtedness, making investments and paying dividends is also tied to ratios based on Adjusted EBITDA.
Covenant levels and ratios for the four quarters ended December 31, 2005 are as follows:
| Covenant Level | December 31, 2005 Ratios | |||
Senior Credit Facilities(1) | ||||
Minimum Adjusted EBITDA to cash interest ratio | 2.0x | 6.3x | ||
Maximum total debt to Adjusted EBITDA ratio | 5.5x | 2.1x | ||
Indenture(2) | ||||
Minimum Adjusted EBITDA to fixed charge ratio required to incur additional debt pursuant to ratio provisions | 2.0x | 6.3x | ||
| (1) | The Senior Credit Facility require us to maintain an Adjusted EBITDA to cash interest ratio starting at a minimum of 1.75x and a total debt to Adjusted EBITDA ratio starting at a maximum of 6.0x in each case for the most recent four quarter period. Failure to satisfy these ratio requirements would constitute a default under the Senior Credit Facility. If lenders under the Senior Credit Facility failed to waive any such default, repayment obligations under the Senior Credit Facility could be accelerated, which would also constitute a default under the indenture. |
| (2) | Our ability to incur additional debt and make certain restricted payments under our indenture, subject to specified exceptions, is tied to an Adjusted EBITDA to fixed charge ratio of at least 2.0 to 1. |
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Adjusted EBITDA is defined as EBITDA further adjusted to exclude non-recurring items, non-cash items and other adjustments permitted in calculating covenant compliance under the indenture, and the Senior Credit Facilities, as shown in the table below. We believe that the inclusion of supplementary adjustments to EBITDA applied in presenting Adjusted EBITDA is appropriate to provide additional information to investors to demonstrate compliance with financing covenants.
| Twelve Months Ended December 31, 2005 | Four Quarters Ended December 31, 2004 | Five Month Operating Period Ended December 31, 2004 | Period From January 1 Through July 29, 2004 | Twelve Months | ||||||||||||||||
| (unaudited) (in millions) | ||||||||||||||||||||
EBITDA(1) | $ | 319.9 | $ | 15.7 | $ | 71.4 | $ | (55.7 | ) | $ | 187.2 | |||||||||
Non-cash charges (income)(2) | (10.9 | ) | 70.4 | (8.7 | ) | 79.1 | 18.4 | |||||||||||||
Unusual or non-recurring items(3) | — | 35.9 | 3.8 | 32.1 | (42.8 | ) | ||||||||||||||
Cumberland mine force majeure(4) | — | 31.1 | — | 31.1 | — | |||||||||||||||
Other adjustments(5) | 0.7 | (0.5 | ) | 0.9 | (1.4 | ) | (2.4 | ) | ||||||||||||
Adjusted EBITDA | $ | 309.7 | $ | 152.6 | $ | 67.4 | $ | 85.2 | $ | 160.4 | ||||||||||
| (1) | EBITDA is calculated in the table below: |
| Twelve Months Ended December 31, 2005 | Four Quarters | Five Month | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2003 | ||||||||||||||||
| (unaudited) (in millions) | ||||||||||||||||||||
Income (loss) from continuing operations | $ | 88.9 | $ | (76.1 | ) | $ | 14.5 | $ | (90.6 | ) | $ | 26.0 | ||||||||
Interest expense | 59.5 | 44.7 | 26.7 | 18.0 | 46.9 | |||||||||||||||
Interest income | (1.3 | ) | (2.3 | ) | (1.0 | ) | (1.3 | ) | (3.2 | ) | ||||||||||
Income tax expense (benefit) | 46.5 | (38.2 | ) | 13.6 | (51.8 | ) | (0.2 | ) | ||||||||||||
Depreciation, depletion and amortization | 211.2 | 146.0 | 84.8 | 61.2 | 99.8 | |||||||||||||||
Amortization of above market coal supply agreements | (84.9 | ) | (58.4 | ) | (67.2 | ) | 8.8 | 17.9 | ||||||||||||
EBITDA | $ | 319.9 | $ | 15.7 | $ | 71.4 | $ | (55.7 | ) | $ | 187.2 | |||||||||
| (2) | We are required to adjust EBITDA, as defined above, for the following non-cash charges (income): |
| Twelve Months Ended December 31, 2005 | Four Quarters Ended December 31, 2004 | Five Month | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2003 | ||||||||||||||
| (unaudited) (in millions) | ||||||||||||||||||
Interest rate swaps(a) | $ | — | $ | 42.6 | $ | (0.5 | ) | $ | 43.1 | $ | — | |||||||
Early extinguishment of debt | — | 21.7 | — | 21.7 | — | |||||||||||||
Profit in inventory(b) | — | 3.8 | 3.8 | — | — | |||||||||||||
Overburden removal included in depreciation, depletion and amortization(c) | (22.6 | ) | (15.3 | ) | (15.3 | ) | — | — | ||||||||||
Accretion on asset retirement obligations | 8.5 | 7.3 | 3.3 | 4.0 | 7.0 | |||||||||||||
Stock based compensation expense(d) | 1.6 | — | — | — | — | |||||||||||||
Write-down of long lived asset | 1.6 | — | — | — | — | |||||||||||||
Amortization included in benefits expense(e) | — | 10.3 | — | 10.3 | 11.4 | |||||||||||||
Total | $ | (10.9 | ) | $ | 70.4 | $ | (8.7 | ) | $ | 79.1 | $ | 18.4 | ||||||
| (a) | Includes $48.9 million of expense resulting in the period from January 1, 2004 to July 29, 2004 from loss on termination of hedge accounting for interest rate swaps less $5.8 million mark-to-market adjustment. Under the terms of the stock purchase agreement, we did not assume any existing interest rate swaps. For the five month operating period ended December 31, 2004 includes the mark-to-market gain on interest rate swaps not yet designated as cash flow hedges. |
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| (b) | Represents incremental cost of sales recorded in the period arising from the manufacturing profit added to inventory in purchase accounting. |
| (c) | In purchase accounting, the fair value of partially and fully uncovered coal included consideration of the effort spent prior to the purchase date to remove overburden and get the coal to its partially or fully uncovered state. Therefore, the fair value assigned to partially or fully uncovered coal reserves was higher than that assigned to other coal reserves. Depletion of coal reserves, including the incremental fair value related to pre-acquisition overburden removal efforts, is included in depreciation, depletion and amortization. Subsequent to the acquisition date, the costs associated with removal of overburden to uncover coal reserves is inventoried as work-in-process until the related coal is mined and the inventoried cost charged to cost of coal sales when the coal is sold. Until coal valued as partially or fully uncovered at the acquisition date is fully depleted, depreciation, depletion and amortization will include the value of overburden removal performed prior to the acquisition date; overburden removal, if incurred subsequent to the acquisition date, would have been included in cost of coal sales. |
| (d) | Represents an accrual for compensation expense attributable to restricted stock performance units and restricted stock awarded to certain directors. |
| (e) | Represents the portion of pension, other post retirement and black lung expense resulting from the amortization of unrecognized actuarial losses, prior service costs and transition obligations. Unrecognized actuarial losses, prior service costs and transition obligations were eliminated when the pension, other post retirement and black lung obligations were fair valued in purchase accounting. |
| (3) | We are also required to adjust EBITDA, as defined above, for the following unusual (income) expense: |
| Twelve Months Ended December 31, 2005 | Four Quarters Ended December 31, 2004 | Five Month | Period From January 1 Through July 29, 2004 | Twelve Months Ended December 31, 2003 | ||||||||||||||
| (unaudited) (in millions) | ||||||||||||||||||
Litigation/arbitration/contract settlements, net(a) | $ | — | $ | 28.9 | $ | — | $ | 28.9 | $ | (41.9 | ) | |||||||
Transaction bonus(b) | — | 1.8 | — | 1.8 | — | |||||||||||||
Long-term incentive plan expense(c) | — | 2.4 | — | 2.4 | 3.9 | |||||||||||||
Gain on asset sales and sale of affiliates | — | (1.0 | ) | — | (1.0 | ) | (4.8 | ) | ||||||||||
Other(d) | — | 3.8 | 3.8 | — | — | |||||||||||||
Total | $ | — | $ | 35.9 | $ | 3.8 | $ | 32.1 | $ | (42.8 | ) | |||||||
| (a) | Represents arbitration awards, litigation and contract settlements, net of related legal and tax fees. |
| (b) | Represents the cost of a one-time bonus awarded to certain employees in connection with the sale of RAG American Coal Holding, Inc. |
| (c) | Represents the cost of a long-term incentive plan instituted by the Seller in 2001 that was terminated prior to closing as required by the change in control provisions in the plan agreement. We have implemented a management equity program that will not result in a cash cost to us. |
| (d) | Represents $2.0 million from a sponsor monitoring fee and $1.8 million from a tax allowance related to the IPO in the period July 30 to December 31, 2004. In addition, other items that are permitted adjustments in calculating covenant compliance under the indenture governing the 7.25% Senior Notes and the Senior Credit Facilities, including directors’ fees, reimbursements of certain union dues by the Seller, black lung settlement charges and costs related to moving our human resources organization from Colorado to Maryland, incurred primarily in the year ended December 31, 2003 and in the period from January 1, 2004 through July 29, 2004, net to an immaterial amount. |
| (4) | Represents the adjustment required for the estimated impact of the temporary idling of our Cumberland mine in the first half of 2004 as a result of a revised interpretation of mine ventilation laws by MSHA. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information. |
| (5) | We are also required to make adjustments to EBITDA for items such as incremental insurance costs and franchise taxes not included in income tax expense. |
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Cash interest for the twelve months ended December 31, 2005 is calculated as follows:
| (unaudited) (in millions) | |||
Interest expense for twelve months ended December 31, 2005 | $ | 57.3 | |
Less: Amortization of deferred financing costs for the twelve months ended December 31, 2005 | 4.8 | ||
Less: Cash interest income for the twelve months ended December 31, 2005 | 1.3 | ||
Less: Other non cash interest expense for the twelve months ended December 31, 2005 | 2.0 | ||
| $ | 49.2 | ||
In future periods, adjustments to EBITDA that could be used to calculate compliance with the debt covenants are: (a) accretion on asset retirement obligations, (b) credits from deferral of overburden removal costs, (c) any non-cash expenses or charges arising as a result of the application of purchase accounting in acquisitions, (d) business optimization expenses or other restructuring charges, (e) non-cash impairment charges resulting from the application of SFAS No. 142 or SFAS No. 144, (f) amortization of intangibles pursuant to SFAS No. 141, and (g) any long term incentive plan accruals or any non-cash compensation expense realized from grants of stock appreciation or similar rights, stock options or other rights to officers, directors and employees.
In future periods, cash interest is expected to be calculated by adding back amortization of deferred debt issuance costs and deducting cash interest income from the interest expense reported in the Statement of Operations. 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, 2005:
| 2006 | 2007-2008 | 2009-2010 | After 2010 | Total | |||||||||||
| (unaudited, in millions) | |||||||||||||||
Long-term debt and capital leases | $ | — | $ | — | $ | — | $ | 635.0 | $ | 635.0 | |||||
Cash interest on long term debt | 42.3 | 86.1 | 87.1 | 90.6 | 306.1 | ||||||||||
Cash payments for asset retirement obligations | 3.2 | 1.1 | 7.0 | 214.6 | 225.9 | ||||||||||
Unconditional purchase commitments | 103.5 | 42.6 | — | — | 146.1 | ||||||||||
Operating leases | 5.9 | 5.5 | 3.8 | 4.6 | 19.8 | ||||||||||
Minimum royalties | 1.0 | — | — | — | 1.0 | ||||||||||
Total | $ | 155.9 | $ | 135.3 | $ | 97.9 | $ | 944.8 | $ | 1,333.9 | |||||
We expect to use cash flows provided by operating activities to invest in the range of $150.0 million to $170.0 million in capital expenditures during calendar year 2006 of which $100.0 million to $110.0 million is to maintain production and replace mining equipment. The additional $50.0 million to $60.0 million is expected to be directed toward selective expansions of production and improvements in productivity. Approximately $40.3 million of expected 2006 capital expenditures are included in unconditional purchase commitments shown above. The remaining 2006 unconditional purchase commitments consist of $28.4 million for purchased coal and $34.8 million pertaining to forward contracts to purchase diesel fuel and explosives in normal quantities for use at our surface mines. The remaining unconditional purchase commitments, totaling $42.6 million in 2007-2008 consists of $20.6 million for purchased coal and a $22.0 million commitment to purchase underground mining equipment. We expect to contribute approximately $15.2 million to our defined benefit retirement plans and to pay approximately $23.5 million of retiree health care benefits in calendar year 2006. We also expect to incur approximately $8.0 million per year for surety bond premiums and letters of credit fees. We believe that cash balances plus cash generated by operations will be sufficient to meet these obligations plus fund requirements for working capital and capital expenditures without incurring additional borrowings.
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Off-Balance Sheet Arrangements
In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in our consolidated balance sheets. However, the underlying obligations that they secure, such as asset retirement obligations, self-insured workers’ compensation liabilities, royalty obligations and certain retiree medical obligations, are reflected in our consolidated balance sheets.
We are required to provide financial assurance in order to perform the post-mining reclamation required by our mining permits, pay our federal production royalties, pay workers’ compensation claims under self-insured workers’ compensation laws in the various states, pay federal black lung benefits, pay retiree health care benefits to certain retired UMWA employees and perform certain other obligations.
In order to provide the required financial assurance, we generally use surety bonds for post-mining reclamation and royalty payment obligations and bank letters of credit for self-insured workers’ compensation obligations and UMWA retiree health care obligations. Federal black lung benefits are paid from a dedicated trust fund that has sufficient assets to fund these obligations for the next several years. Bank letters of credit are also used to collateralize a portion of the surety bonds.
We had outstanding surety bonds with a total face amount of $257.1 million as of December 31, 2005, of which $234.6 million secured reclamation obligations, $10.7 million secured coal lease obligations, $9.6 million secured self-insured workers’ compensation obligations and $2.2 million secured miscellaneous obligations. In addition, we had $185.8 million of letters of credit in place for the following purposes: $34.1 million for workers’ compensation, including collateral for workers’ compensation bonds; $23.4 million for UMWA retiree health care obligations; $121.5 million for collateral for reclamation surety bonds, $3.0 million for minimum royalty payment obligations for a closed mine in Utah; and $3.8 million for other miscellaneous obligations. Recently, surety bond costs have increased, while the market terms under which surety bonds can be obtained have generally become less favorable to all mining companies. In the event that additional surety bonds become unavailable, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral.
Certain Trends and Uncertainties
Our outlook for the coal markets in the United States remains positive. The U. S. economy grew at an annual rate of 3.5% in 2005 as reported by the U.S. Commerce Department. U. S. electricity generation increased by 1.7% during 2005 as reported by the Energy Information Agency. Strong demand for coal and coal-based electricity generation in the U. S. is being driven by the growing economy, low customer stockpiles compared to historical norms, weather conditions and high prices for alternative fuels for electricity generation. The high price of natural gas during 2005 caused some coal-fired generating plants to operate at increased levels. U. S. coal inventories at year end 2005 were at levels below the five year averages.
Our revenues depend on the price at which we are able to sell our coal. The current pricing environment for United States coal is strong relative to historical pricing levels. Any decrease in coal prices due to, among other reasons, the supply of domestic and foreign coal, the demand for electricity and the price and availability of alternative fuels for electricity generation could adversely affect our revenues and our ability to generate cash flows. In addition, our results of operations depend on the cost of coal production. We are experiencing increased operating costs for fuel and explosives, steel products, tires, health care, wages, salaries, and contract labor. In addition, historically low interest rates have had a negative impact on expenses related to our actuarially determined employee-related liabilities.
We may also experience difficult geologic conditions, 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 exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See “Item 1A. Risk Factors” for additional considerations regarding our outlook.
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Critical Accounting Estimates
Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management evaluates its estimates on an on-going basis. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Actual results may differ from the estimates used. Note 3 to the Consolidated Financial Statements 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:
| • | Discount rate—SFAS No. 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of SFAS No. 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives adjusted for our credit standing. |
| • | Third party margin—SFAS No. 143 requires the measurement of an obligation to be based on the amount a third party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of performing these activities with internal resources. This margin was estimated based upon discussion with contractors that perform reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is settled. |
On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revision to cost estimates and productivity assumptions, in each case to reflect current experience.
At December 31, 2005, we had recorded asset retirement obligation liabilities of $116.2 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 $225.9 million at December 31, 2005 payable through 2032.
Employee Benefit Plans
We have two non-contributory defined benefit retirement plans covering certain of our salaried and non-union hourly employees. We also have an unfunded non-qualified Supplemental Executive Retirement Plan (SERP) 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, 2005, 2004 and 2003, we contributed $7.5 million, $18.0 million and $20.0 million, respectively, into the plans. We account for our defined benefit retirement plans in accordance with SFAS No. 87,Employer’s Accounting for Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis. For the twelve months ended December 31, 2005, we recorded pension expense of
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$5.2 million. For the five month operating period ended December 31, 2004, after applying purchase accounting, we recorded pension expense of approximately $2.6 million. For the period from January 1, 2004 through July 29, 2004, we recorded pension expense of $7.1 million. For the twelve months ended December 31, 2003, we recorded pension expense of $11.7 million.
The calculation of the net periodic benefits costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pension plans requires the use of a number of assumptions that we deem to be “critical accounting estimates.” These assumptions are used by our independent actuaries to make the underlying calculations. Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions.
| • | The expected long-term rate of return on plan assets is an assumption of the rate of return on plan assets reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The pension plan’s investment targets are 55% equity, 22% fixed income, 5% private equity, 8% absolute return funds and 10% real estate mutual funds. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine pension expense was 8.5% for the twelve months ended December 31, 2005, for the five month operating period ended December 31, 2004 and for the period from January 1, 2004 through July 29, 2004, and 9.0% for the twelve months ended December 31, 2003. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into the future. |
| • | The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic pension cost. In estimating that rate, SFAS No. 87 requires rates of return on high quality, fixed income investments. The discount rate used to determine pension expense was 6.00% for the twelve months ended December 31, 2005, 6.25% for the five month operating period ended December 31, 2004 and for the period from January 1, 2004 through July 29, 2004, and 7.00% for the twelve months ended December 31, 2003. The discount rate was reduced to 5.60% at the September 30, 2005 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, 2005 by approximately $0.2 million and decrease the projected benefit obligation at December 31, 2005 by approximately $11.9 million. The corresponding effects of a one half of one percentage-point decrease in the discount rate would be approximately a $0.1 million increase in the net periodic pension cost and approximately a $12.7 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. 106,Employer’s Accounting for Postretirement Benefits Other Than Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis. For the twelve months ended December 31, 2005, we recorded postretirement benefit expense of approximately $37.0 million. In the Successor financial statements for the five month operating period ended December 31, 2004, after applying purchase accounting and incorporating Medicare Part D, we recorded postretirement benefit expense of approximately $14.4 million. For the period from January 1, 2004 through July 29, 2004, we recorded postretirement benefit expense of $25.5 million. For the twelve months ended December 31, 2003, we recorded postretirement benefit expense of $41.7 million.
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Various actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. The differences resulting from actual experience versus actuarial assumptions are deferred as unrecognized actuarial gains or losses and amortized into expense in future periods. These assumptions include the discount rate and the future medical cost trend rate.
| • | The discount rate assumption reflects the rates available on high quality fixed income debt instruments and is calculated in the same manner as discussed above for the defined benefit retirement plans. The discount rate used to calculate the postretirement benefit expense was 6.00% for the twelve months ended December 31, 2005, 6.25% for the five-month operating period ended December 31, 2004 and for the period from January 1, 2004 through July 29, 2004, and 7.00% for the twelve months ended December 31, 2003. The discount rate was reduced to 5.60% at the September 30, 2005 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, 2005 by approximately $0.4 million and decrease the accumulated postretirement benefit obligation at December 31, 2005 by approximately $37.1 million. The corresponding effects of a one-half of one percentage-point decrease in the discount rate would be approximately a $1.7 million increase in the postretirement benefit expense and approximately a $39.7 million increase in the accumulated postretirement benefit obligation. |
| • | The future health care cost trend rate represents the rate at which health care costs are expected to increase over the life of the plan. The health care cost trend rate assumptions are determined primarily based upon our historical rate of change in retiree health care costs. We have implemented many effective retiree health care cost containment measures that have resulted in actual increases in our retiree health care costs to fall far below the double-digit annual increases experienced by many companies and cited in most external studies. The postretirement expense for the twelve months ended December 31, 2005 and the five-month operating period ended December 31, 2004 was based on an assumed heath care inflationary rate of 8.00% in 2004 decreasing to 5.00% in 2010, which represents the ultimate health care cost trend rate for the remainder of the plan life. The postretirement expense for the period from January 1, 2004 through July 29, 2004 and the twelve months ended December 31, 2003 was based on an assumed health care inflationary rate of 5.75% in 2003 decreasing to 4.75% in 2008. A one-percentage point increase in the 5.00% assumed ultimate health care cost trend rate would increase the service and interest cost components of the postretirement benefit expense for the twelve months ended December 31, 2005 by $5.9 million and increase the accumulated postretirement benefit obligation at December 31, 2005 by $69.2 million. A one-percentage point decrease in the 5.00% assumed ultimate health care cost trend rate would decrease the service and interest cost components of the postretirement benefit expense for the twelve months ended December 31, 2005 by $4.7 million and decrease the accumulated postretirement benefit obligation at December 31, 2005 by $56.0 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. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, we may record a change to the valuation allowance through income tax expense in the period such determination is made.
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Mineral Rights
There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves. Many of these uncertainties are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff and independent third party consultants. Some of the factors and assumptions that impact economically recoverable reserve estimates include:
| • | geological and mining conditions; |
| • | historical production from similar areas with similar conditions; |
| • | the assumed effects of regulations and taxes by governmental agencies; |
| • | assumptions governing future prices; |
| • | competing property rights such as surface rights, oil and gas rights, deeper or shallower coal rights and easements; |
| • | ability to permit specific reserves for a particular type of mining; |
| • | future operating, development and reclamation costs; and |
| • | mining technology improvements. |
Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows may vary substantially. Actual production, revenue and expenditures with respect to reserves may materially vary from estimates.
Recent Accounting Pronouncements
New Pronouncements
In December 2004, the FASB issued SFAS No. 123 (revised 2004),Share-Based Payment (“SFAS No. 123R”), which replaces SFAS No. 123, and supersedes APB No. 25. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair value at the grant date. SFAS No. 123R generally requires companies to measure the cost of employee services received in exchange for an award of equity instruments (such as stock options and restricted stock) based on the grant-date fair value of the award, and to recognize that cost over the requisite service period. SFAS No. 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow rather than operating cash flow, as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. SFAS No. 123R allows for adoption using either the modified prospective or modified retrospective method. We expect to adopt SFAS No. 123R in the first quarter of 2006 using the modified prospective method. The impact of adopting SFAS No. 123R is expected to be consistent with the pro forma disclosure under SFAS No. 123.
In March 2005, the Emerging Issues Task Force reached consensus on Issue No. 04-6,Accounting for Stripping Costs in the Mining Industry(“EITF Issue 04-6”) concluding that post-production stripping costs are a component of mineral inventory costs subject to the provisions of the American Institute of Certified Public Accountants Accounting Research Bulletin No. 43,Restatement and Revision of Accounting Research Bulletins,Chapter 4,Inventory Pricing, (“ARB No. 43”). The FASB ratified the EITF consensus. Based upon this consensus, post production stripping costs are considered costs of the extracted minerals under a full absorption costing system and are recognized as a component of inventory to be recognized in cost of coal sales in the same period as the revenue from the sale of the inventory. In addition, capitalization of such costs would be appropriate only to the extent inventory exists at the end of a reporting period. The guidance in this consensus will be effective for financial statements issued for the first reporting period in fiscal years beginning after December 15, 2005, with early adoption permitted. At a June EITF meeting, the Task Force modified the transition provisions of EITF Issue 04-6, indicating that companies adopting beginning after June 29, 2005 may utilize a cumulative effect adjustment approach where the cumulative effect adjustment is recorded directly to retained earnings in the year of adoption. Alternatively, a company may recognize this change in accounting by restatement of prior-period financial
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statements through retrospective application. Historically, the Company recorded stripping costs associated with in-process production as a separate component of inventory described as deferred overburden in Note 5. At December 31, 2005, such stripping costs associated with coal that has not been extracted is $60.4 million. The Company will adopt EITF Issue 04-6 in the first quarter of 2006 using the cumulative effect adjustment approach and record an adjustment directly to retained earnings upon adoption. The effect on the financial statements upon adoption will result in a reduction to retained earnings of $39.3 million, net of tax of $21.1 million, with a corresponding decrease of $60.4 million in inventory. After the adoption of EITF Issue 04-6, the amount of stripping expensed in the period will be dependent on mining and overburden removal activity, inventory levels and the timing of sales.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Commodity Price Risk
We manage our commodity price risk for coal sales through the use of long-term coal supply agreements rather than through the use of derivative instruments. As of December 31, 2005, we had sales commitments for approximately 97% of our planned 2006 production, approximately 78% of our planned 2007 production, approximately 56% of our planned 2008 production, approximately 42% of our planned 2009 production and approximately 23% of our planned 2010 production. Some of the products used in our mining activities, such as diesel fuel, explosives and steel products, are subject to price volatility. Through our suppliers, we utilize forward purchase contracts to manage the exposure related to this volatility.
Credit Risk
Our credit risk is primarily with electric power generators and, to a lesser extent, steel producers. Most electric power generators to whom we sell have investment grade credit ratings. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.
Counterparty risk with respect to interest rate swaps is not considered to be significant based upon the creditworthiness of the participating financial institutions.
Interest Rate Risk
Historically, we have had exposure to changes in interest rates on a portion of our existing level of indebtedness under the Predecessor. This exposure had been completely hedged for the life of the debt using pay-fixed, receive-variable interest rate swaps. From July 30, 2004 forward, we have exposure to changes in interest rates on our bank term loan and our revolving credit facility. As described below, we have used interest rate swaps to manage this risk.
We entered into swap contracts for the purpose of complying with certain financial covenants in our senior secured credit facility that require fixing the interest rate for at least three years on a minimum of 50% of our total outstanding debt. The swap contracts cover $85 million to September 2007. The following table summarizes our outstanding swap contracts at December 31, 2005.
Notional Amount | Term | Floating Rate | Fixed Rate | ||||
| $20 million | September 2004—September 2007 | 3-month LIBOR | 3.26 | % | |||
| $25 million | September 2004—September 2007 | 3-month LIBOR | 3.26 | % | |||
| $20 million | September 2004—September 2007 | 3-month LIBOR | 3.26 | % | |||
| $20 million | September 2004—September 2007 | 3-month LIBOR | 3.26 | % |
As of December 31, 2005, after giving effect to the $85 million of interest rate swaps that were entered into, we had $250 million of variable rate indebtedness, representing approximately 39% of our outstanding indebtedness. A 1% change in interest rates would affect the interest expense on such indebtedness by $2.5 million. At December 31, 2005, the fair value of these swap agreements was an unrealized gain of $1.0 million. During the five month operating period ended December 31, 2004 these swaps were not designated as hedges.
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15(a)(3) Exhibits.
| Exhibit No. | Description of Exhibit | |
| 31.1* | Certification of periodic report by Foundation Coal Holdings, Inc.’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
| 31.2* | Certification of periodic report by Foundation Coal Holdings, Inc.’s Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 | |
| 32.1* | Certification of periodic report by Foundation Coal Holdings, Inc.’s Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| 32.2* | Certification of periodic report by Foundation Coal Holdings, Inc.’s Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 | |
| * | Filed herewith |
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SIGNATURES
Name | Title | |
/s/ JAMES F. ROBERTS James F. Roberts | President, Chief Executive Officer and Director (Principal Executive Officer) | |
/s/ FRANK J. WOOD Frank J. Wood | Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) | |
* David I. Foley | Director | |
* Alex T. Krueger | Director | |
* William E. Macaulay | Chairman of the Board and Director | |
* William J. Crowley, Jr. | Director | |
* Joel Richards, III | Director | |
* P. Michael Giftos | Director | |
* Robert C. Scharp | Director | |
*/s/ GREG A. WALKER Greg A. Walker, Attorney-in-fact | ||
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