raw_content: PEABODY ENERGY CORP
  e10vk
  Commission File Number 1-16463
  Peabody Energy Corporation
  (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.)
  701 Market Street, St. Louis, Missouri
  Registrant’s telephone number, including area code
  Title of Each Class Name of Each Exchange on Which Registered
  Preferred Share Purchase Rights New York Stock Exchange
  Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act Yes þ No o
  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 o No þ
  Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
  Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
  Indicate by check mark whether the registrant is a 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 þ Accelerated filer o Non-accelerated filer o
  Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the of the Exchange Act) Yes o No þ
  Aggregate market value of the voting stock held by non-affiliates (shareholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2006: Common Stock, par value $0.01 per share, $14.6 billion.
  Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 16, 2007: Common Stock, par value $0.01 per share, 264,685,954 shares outstanding.
  Portions of the Company’s Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company’s Annual Meeting of Stockholders to be held on May 1, 2007 (the “Company’s 2007 Proxy Statement”) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.
  CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
  This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook.” We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “will” or other similar words to identify forward-looking statements.
  Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ materially are:
  • ability to renew sales contracts;
  • reductions of purchases by major customers;
  • transportation performance and costs, including demurrage;
  • geology, equipment and other risks inherent to mining;
  • weather;
  • legislation, regulations and court decisions;
  • new environmental requirements affecting the use of coal including mercury and carbon dioxide related limitations;
  • changes in postretirement benefit and pension obligations;
  • changes to contribution requirements to multi-employer benefit funds;
  • availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;
  • replacement of coal reserves;
  • price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses;
  • performance of contractors, third-party coal suppliers or major suppliers of mining equipment or supplies;
  • negotiation of labor contracts, employee relations and workforce availability;
  • availability and costs of credit, surety bonds and letters of credit;
  • risks associated with customer contracts, including credit and performance risk;
  • the effects of acquisitions or divestitures, including integration of new acquisitions;
  • economic strength and political stability of countries in which we have operations or serve customers;
  • risks associated with our Btu conversion or generation development initiatives;
  • risks associated with the conversion of our current information systems;
  • growth of domestic and international coal and power markets;
  • coal’s market share of electricity generation;
  • prices of fuels which compete with or impact coal usage, such as oil or natural gas;
  • future worldwide economic conditions;
  • successful implementation of business strategies;
  • variation in revenues related to synthetic fuel production due to expiration of related tax credits at the end of 2007;
  • the effects of changes in currency exchange rates, primarily the Australian dollar;
  • inflationary trends, including those impacting materials used in our business;
  • interest rate changes;
  • litigation, including claims not yet asserted;
  • terrorist attacks or threats;
  • impacts of pandemic illnesses;
  • other factors, including those discussed in Legal Proceedings, set forth in Item 3 of this report and Risk Factors, set forth in Item 1A of this report.
  When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (“SEC”) filings. We do not undertake any obligation to update these statements, except as required by federal securities laws.
  PART I.
  Risk Factors 31
  Unresolved Staff Comments 41
  Properties 41
  Legal Proceedings 48
  Submission of Matters to a Vote of Security Holders 52
  Executive Officers of the Company 52
  PART II.
  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 54
  Selected Financial Data 56
  Management’s Discussion and Analysis of Financial Condition and Results of Operations 59
  Quantitative and Qualitative Disclosures About Market Risk 82
  Financial Statements and Supplementary Data 85
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 85
  Controls and Procedures 85
  Other Information 89
  PART III.
  Directors, Executive Officers and Corporate Governance 89
  Executive Compensation 89
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 89
  Certain Relationships and Related Transactions, and Director Independence 89
  Principal Accounting Fees and Services 90
  PART IV.
  Exhibits and Financial Statement Schedules 90
  Senior Notes Due 2013 Twelfth Supplemental Indenture
  Senior Notes Due 2013 Thirteenth Supplemental Indenture
  Senior Notes Due 2016 Fifteenth Supplemental Indenture
  Senior Notes due 2016 Sixteenth Supplemental Indenture
  Senior Notes due 2026 Fourteenth Supplemental Indenture
  Senior Notes due 2026 Seventeenth Supplemental Indenture
  List of Subsidiaries
  Consent of Ernst & Young LLP
  Certification of CEO
  Certification of CFO
  Section 1350 Certification of CEO
  Section 1350 Certification of CFO
  Note: The words “we,” “our,” “Peabody” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries.
  Item 1. Business.
  We are the largest private-sector coal company in the world. During the year ended December 31, 2006, we sold 247.6 million tons of coal. During this period, we sold coal to over 400 electricity generating and industrial plants in 20 countries. Our coal products fuel approximately 10% of all U.S. electricity generation and 2% of worldwide electricity generation. At December 31, 2006, we had 10.2 billion tons of proven and probable coal reserves.
  We own majority interests in 40 coal operations located throughout all major U.S. coal producing regions and in Australia. Additionally, we own a minority interest in one Venezuelan mine through a joint venture arrangement. We shipped 75% of our U.S. mining operations’ coal sales from the western United States during the year ended December 31, 2006 and the remaining 25% from the eastern United States. Most of our production in the western United States is low-sulfur coal from the Powder River Basin. Our overall western U.S. coal production has increased from 127.0 million tons in 2001, the year of our initial public offering, to 160.5 million tons during 2006, representing a compounded annual growth rate of 5%. In the West, we own and operate mines in Arizona, Colorado, New Mexico and Wyoming. In the East, we own and operate mines in Illinois, Indiana, Kentucky and West Virginia. We own six mines, including one late development-stage mine in Queensland, Australia, and five mines, including one late development-stage mine and one development-stage mine in New South Wales, Australia. Our Australian production includes both low-sulfur thermal coal and high Btu metallurgical coal. We generated 86% of our production for the year ended December 31, 2006 from non-union mines.
  For the year ended December 31, 2006, 87% of our sales (by volume) were to U.S. electricity generators, 9% were to customers outside the United States and 4% were to the U.S. industrial sector. Approximately 90% of our coal sales during the year ended December 31, 2006 were under long-term (one year or greater) contracts. Our sales backlog, including backlog subject to price reopener and/or extension provisions, was over one billion tons as of December 31, 2006. The average volume-weighted remaining term of our long-term contracts was approximately 5 years, with remaining terms ranging from one to 19 years. We are targeting 2007 production of 240 to 260 million tons and total sales volume of 265 to 285 tons, including 15 to 18 million tons of metallurgical coal. As of December 31, 2006, our unpriced 2007 volumes for planned produced tonnage were 5 to 15 million U.S. tons and 14 million Australia tons. Our total unpriced planned production for 2008 is approximately 70 to 80 million tons in the United States and 20 to 22 million tons in Australia.
  In addition to our mining operations, we market, broker and trade coal. Our total tons traded were 79.1 million for the year ended December 31, 2006. In response to growing international markets, we established an international trading group in 2006 and added another operations office in Europe in early 2007. We also have a business development, sales and marketing office in Beijing, China to pursue potential long-term growth opportunities in this market. Our other energy related commercial activities include the development of mine-mouth coal-fueled generating plants, the management of our vast coal reserve and real estate holdings, coalbed methane production, and Btu Conversion technologies, which are designed to convert coal to natural gas and transportation fuels.
  Peabody, Daniels and Co. was founded in 1883 as a retail coal supplier, entering the mining business in 1888 as Peabody & Co. with the opening of our first coal mine in Illinois. In 1926, Peabody Coal
  Company was listed on the Chicago Stock Exchange and, beginning in 1949, on the New York Stock Exchange.
  In 1955, Peabody Coal Company, primarily an underground mine operator, merged with Sinclair Coal Company, a major surface mining company. Peabody Coal Company was acquired by Kennecott Copper Company in 1968. The company was then sold to Peabody Holding Company in 1977, which was formed by a consortium of companies.
  During the 1980s, Peabody grew through expansion and acquisition, opening the North Antelope Mine in Wyoming’s coal-rich Powder River Basin in 1983 and the Rochelle Mine in 1985, and completing the acquisitions of the West Virginia coal properties of ARMCO Steel and Eastern Associated Coal Corp., which included seven operating mines and substantial low-sulfur coal reserves in West Virginia.
  In July 1990, Hanson, PLC acquired Peabody Holding Company. In the 1990s, Peabody continued to grow through expansion and acquisitions. In February 1997, Hanson spun off its energy-related businesses, including Eastern Group and Peabody Holding Company, into The Energy Group, plc. The Energy Group was a publicly traded company in the United Kingdom and its American Depository Receipts (ADRs) were publicly traded on the New York Stock Exchange.
  In May 1998, Lehman Brothers Merchant Banking Partners II L.P. and affiliates (“Merchant Banking Fund”), an affiliate of Lehman Brothers Inc. (“Lehman Brothers”), purchased Peabody Holding Company and its affiliates, Peabody Resources Limited and Citizens Power LLC in a leveraged buyout transaction that coincided with the purchase by Texas Utilities of the remainder of The Energy Group. In August 2000, Citizens Power, our subsidiary that marketed and traded electric power and energy-related commodity risk management products, was sold to Edison Mission Energy and in January 2001, we sold our Peabody Resources Limited (in Australia) operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto Limited.
  In April 2001, we changed our name to Peabody Energy Corporation, reflecting our position as a premier energy supplier. In May 2001, we completed an initial public offering of common stock, and our shares began trading on the New York Stock Exchange under the ticker symbol “BTU,” the globally recognized symbol for energy.
  In April 2004, we acquired coal operations from RAG Coal International AG, expanding our presence in both Australia and Colorado. In December 2004, we completed the purchase of a 25.5% equity interest in Carbones del Guasare from RAG Coal International, S.A. Carbones del Guasare, a joint venture with Anglo American plc and a Venezuelan governmental partner, operates Venezuela’s largest coal mine, the Paso Diablo mine in northwestern Venezuela.
  In October 2006, we acquired Excel Coal Limited (“Excel”), an independent coal company in Australia. The Excel acquisition included three operating mines, two late development-stage mines and a development-stage mine, along with estimated proven and probable coal reserves in excess of 500 million tons.
  Peabody has grown significantly in recent years through both organic growth and acquisitions while transforming itself from a high sulfur, high-cost coal company to a predominately low sulfur, low-cost coal producer, marketer/ trader of coal and manager of vast natural resources. Peabody remains focused on areas identified as necessary for achieving future growth: 1) executing the basics of best-in-class safety, operations and marketing; 2) capitalizing on organic growth opportunities; 3) expanding in high-growth global markets; and 4) participating in new generation and Btu Conversion technologies that convert coal into natural gas, liquids and hydrogen.
  We conduct business through three principal mining operating segments: Western U.S. Mining, Eastern U.S. Mining, and Australian Mining. Our Western U.S. Mining Operations consist of our Powder River Basin, Southwest and Colorado operations, and our Eastern U.S. Mining Operations consist of our
  Appalachia and Midwest operations. The principal business of the Western U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities. The principal business of the Eastern U.S. Mining segment is the mining, preparation and sales of steam coal, sold primarily to electric utilities, as well as the mining of some metallurgical coal, sold to steel and coke producers. Internationally, we operate mines in Queensland, Australia and New South Wales, Australia and have a 25.5% investment in a Venezuelan mine. All of our operating segments are discussed in Note 25 to our consolidated financial statements.
  The following describes the operating characteristics of the principal mines and reserves of each of our business units and affiliates. The maps below show mine locations as of December 31, 2006. Included in the descriptions of our mining operations are discussions of the subsidiaries which manage the respective mining operation. The subsidiary that manages a particular mining operation is not necessarily the same as the subsidiary or subsidiaries which own the assets utilized in that mining operation. Unless otherwise indicated, we own 100% of the respective mining operations and related assets.
  U.S. Mining Operations
  Powder River Basin Operations
  We control approximately 3.5 billion tons of proven and probable coal reserves in the Southern Powder River Basin, the largest and fastest growing major U.S. coal-producing region. Our subsidiaries, Powder River Coal, LLC and Caballo Coal Company, manage three low-sulfur, non-union surface mining complexes in Wyoming that sold 138.4 million tons of coal during the year ended December 31, 2006, or approximately 56% of our total coal sales volume. The North Antelope Rochelle and Caballo mines are serviced by both major western railroads, the Burlington Northern Santa Fe (“BNSF”) Railway and the Union Pacific Railroad. The Rawhide Mine is serviced by the BNSF Railway.
  Our Wyoming Powder River Basin reserves are classified as surface mineable, subbituminous coal with seam thickness varying from 60 to 115 feet. The sulfur content of the coal in current production ranges from 0.2% to 0.4% and the heat value ranges from 8,300 to 8,900 Btu’s per pound.
  North Antelope Rochelle Mine
  The North Antelope Rochelle Mine is located 65 miles south of Gillette, Wyoming. This mine is one of the largest in North America, selling 88.5 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu) during 2006. The North Antelope Rochelle facility is capable of loading its production in up to 20 unit trains per day (a unit train generally consists of 100 to 150 cars, each of which holds 100 to 120 tons of coal). The North Antelope Rochelle Mine produces premium quality coal with a sulfur content averaging 0.2% and a heat value ranging from 8,500 to 8,900 Btu per pound. The North Antelope Rochelle Mine produces the lowest sulfur coal in the United States, using two draglines along with six truck-and-shovel fleets. A third dragline is under construction and is scheduled for completion in mid-2007.
  Caballo Mine
  The Caballo Mine is located 20 miles south of Gillette, Wyoming. During 2006, it sold 32.8 million tons of compliance coal. Caballo is a cast/dozer/truck-and-shovel assist operation with a coal handling system that includes two 12,000-ton silos and two 11,000-ton silos. The Caballo Mine is capable of loading its production in up to nine unit trains per day. The Caballo Mine produces compliance coal with a sulfur content averaging 0.36% and a heat value averaging 8,500 Btu per pound.
  Rawhide Mine
  The Rawhide Mine is located ten miles north of Gillette, Wyoming and uses truck-and-shovel mining methods. During 2006, it sold 17.1 million tons of compliance coal. Rawhide is a cast/dozer-push/truck-and-shovel assist operation with a coal handling system that includes two 12,000-ton silos and four 11,000-ton silos. The Rawhide Mine is capable of loading its production in up to six unit trains per day. The Rawhide Mine produces compliance coal with a sulfur content averaging 0.38% and a heat value averaging 8,300 Btu per pound.
  Southwest Operations
  We own three mines in our Southwest operations, and we are currently operating two of these mines, one in Arizona and one in New Mexico. The third mine in Arizona suspended operations as of December 31, 2005. The Arizona mines are managed by our Peabody Western Coal Company subsidiary. In New Mexico, we own and manage, through our Peabody Natural Resources Company subsidiary, the Lee Ranch Mine, which mines and produces subbituminous medium sulfur coal. Together, these two mines sold 13.2 million tons of coal during 2006. We control 1.0 billion tons of proven and probable coal reserves in our Southwest operations.
  Kayenta Mine
  The Kayenta Mine, located on the Navajo Nation and Hopi Tribe lands in Arizona, uses four draglines in three mining areas. It sold approximately 8.0 million tons of coal during 2006 and supplies primarily bituminous compliance coal under a long-term coal supply agreement to an electricity generating station in the region. The Kayenta Mine coal is crushed, then carried 17 miles by conveyor belt to storage silos where it is loaded onto a private rail line and transported 83 miles to the Navajo Generating Station, operated by the Salt River Project near Page, Arizona. The mine and railroad were designed to deliver coal exclusively to the power plant, which has no other source of coal. The Navajo coal supply agreement extends until 2011. Hourly workers at this mine are members of the United Mine Workers of America (“UMWA”).
  Lee Ranch Mine
  The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 5.2 million tons of medium sulfur coal during 2006. Lee Ranch shipped the majority of its coal to two customers in Arizona and New Mexico under coal supply agreements extending until 2020 and 2014, respectively. Lee Ranch is
  a non-union surface mine that uses a combination of dragline and truck-and-shovel mining techniques and ships coal to its customers via the BNSF Railway.
  Colorado Operations
  We control approximately 0.2 billion tons of proven and probable coal reserves and currently have one operating mine in the Colorado Region. Our Twentymile underground mine is managed by our Twentymile Coal Company subsidiary. Our Seneca surface mine is managed by our Seneca Coal Company subsidiary and ceased mining operations at the end of 2005.
  Twentymile Mine
  The Twentymile Mine is located in Routt County, Colorado, and sold 8.8 million tons of compliance, low-sulfur, steam coal of above average heat content for the region to customers throughout the United States during 2006. This mine uses both longwall and continuous mining equipment. Our Twentymile Mine is non-union and has been one of the largest and most productive underground mines in the United States. Approximately 78% of all coal shipped is loaded on the Union Pacific railroad; the remainder is hauled by truck. This mine also provides coal to the nearby Hayden Generating Station, operated by the Public Service of Colorado, under a coal supply agreement that extends until 2011.
  Appalachia/ Highland Operations
  The Appalachia/ Highland Operations consist of five wholly-owned business units and related facilities, a joint venture in West Virginia and one business unit in western Kentucky. Our subsidiary, Pine Ridge Coal Company, LLC, manages the Big Mountain Business Unit, and our subsidiary, Rivers Edge Mining, Inc. manages our Rivers Edge Mine in our Wells Business Unit. Our Eastern Associated Coal, LLC subsidiary manages the remaining wholly-owned West Virginia facilities. In addition, Highland Mining manages the Highland No. 9 Mine in western Kentucky. During 2006, these operations sold approximately 18.8 million tons of compliance, medium-sulfur and high-sulfur steam and metallurgical coal to customers in the United States and abroad. Metallurgical coal from these operations accounted for 5.6 million tons of total sales for the year. In addition to our wholly-owned facilities, we own a 73.9% interest in KE Ventures LLC, a joint venture which owns and manages underground mining operations. We control approximately 0.6 billion tons of proven and probable coal reserves in our Appalachia operations. Our Appalachia Operations also own a 30% interest in a partnership that leases a coal export terminal from the Peninsula Port Authority of Virginia and utilizes the terminal for exports.
  Big Mountain Business Unit and Contract Mines
  The Big Mountain Business Unit is based near Prenter, West Virginia. This business unit’s primary source of coal (approximately 55% of total shipments) is the Big Mountain No. 16 operation with the remainder from contract mine production from coal reserves we control. All production is processed at the business unit’s preparation facility. During 2006, the Big Mountain Business Unit sold approximately 2.0 million tons of steam coal. Big Mountain No. 16 is an underground mine using continuous mining equipment. Processed coal is loaded on the CSX railroad. Our hourly employees at the Big Mountain Business Unit are represented by the UMWA.
  Harris Business Unit
  The Harris Business Unit is based near Bald Knob, West Virginia. The business unit’s primary source of coal is the Harris No. 1 Mine. The business unit also has a small amount of contract mine production from a mine also located near Bald Knob, West Virginia. The Harris Business Unit sold approximately 1.5 million tons of primarily metallurgical product during 2006. This mine uses both longwall and continuous mining equipment. In 2006, the Harris Business Unit transitioned to the James Creek reserves, allowing it to access additional metallurgical coal. Hourly employees at the Harris Business Unit are represented by the UMWA.
  Rocklick Business Unit and Contract Mines
  The Rocklick preparation plant, located near Wharton, West Virginia, processes metallurgical coal produced by the Harris Business Unit and steam coal produced from contract mining operations. This preparation plant shipped approximately 2.2 million tons of contract mine steam coal during 2006. Processed coal is loaded at the plant site on the CSX railroad or transferred via conveyor to our Kopperston loadout facility and loaded on the Norfolk Southern railroad. Hourly employees at the Rocklick preparation plant are represented by the UMWA.
  Wells Business Unit
  The Wells Business Unit, located near Wharton, West Virginia, sold approximately 3.1 million tons of metallurgical and steam coal during 2006. Wells operates a preparation plant and processes coal production from the Rivers Edge Mine and contract mines that use continuous mining equipment. The processed coal is loaded on the CSX railroad. Hourly employees at the Wells preparation plant and Rivers Edge Mine are represented by the UMWA.
  Federal Business Unit
  The Federal Business Unit consists of the Federal No. 2 Mine, near Fairview, West Virginia, and uses longwall and continuous mining equipment to extract coal. The business unit operates a preparation plant which processed and shipped approximately 4.5 million tons of steam coal during 2006. Coal shipped from the Federal No. 2 Mine has sulfur content only slightly above that of medium sulfur coal and has above average heating content for the region. As a result, it is more marketable than some other medium sulfur coals. The CSX and Norfolk Southern railroads jointly serve the mine. Hourly employees at the Federal Business Unit are represented by the UMWA.
  Highland Business Unit
  The Highland No. 9 Mine, which uses continuous mining equipment, is managed by our Highland Mining Company, LLC subsidiary and is located near Waverly, Kentucky. The mine sold 3.5 million tons of steam coal during 2006. This business unit also operates a preparation plant and barge loading facility. Hourly employees at the Highland No. 9 Mine are represented by the UMWA.
  KE Ventures Joint Venture
  We own a 73.9% interest in KE Ventures LLC, a joint venture which owns and manages underground mining operations, a preparation plant and barge-and-rail loading facilities near Marmet, West Virginia. The mines are non-union and use continuous mining equipment. The joint venture shipped 2.0 million tons during 2006.
  Midwest Operations
  Our Midwest Operations consist of 14 wholly-owned mines in the Illinois Basin and are comprised of our Midwest Coal Resources II, LLC, Indian Hill Company, Coulterville Coal Company, LLC, Black Beauty Holding Company, LLC and Arclar LLC subsidiaries. We control approximately 4.2 billion tons of proven and probable coal reserves in the Midwest. In 2006, these operations collectively sold 35.9 million tons of coal, more than any other Midwestern coal producer. We ship coal from these mines primarily to electricity generators in the Midwestern United States and to industrial customers for power generation.
  Midwest Coal Resources II, LLC
  Midwest Coal Resources II, LLC owns and manages three mines in western Kentucky. Patriot, a surface mine, and Freedom, an underground mine, are located in Henderson County, Kentucky, and sold 1.4 million tons and 1.3 million tons of steam coal, respectively, in 2006. The Big Run underground mine, located in Ohio County, Kentucky, closed in December 2006 due to loss of the mine’s sole customer. The
  mine sold 1.3 million tons of steam coal in 2006. The two underground mines use continuous mining equipment and the surface mine uses truck and shovel equipment. Midwest Coal Resources II, LLC also owns and operates a preparation plant and a coal loading dock. All Midwest Coal Resources II, LLC employees are non-union.
  Indian Hill Company
  Indian Hill Company, our wholly-owned subsidiary, owns Dodge Hill Holding JV, LLC, which manages Dodge Hill No. 1, an underground mine located in Union County, Kentucky. Dodge Hill No. 1 has non-union employees and sold 1.1 million tons of steam coal in 2006.
  Coulterville Coal Company
  Coulterville Coal Company, LLC owns the Gateway Mine in Randolph County, located in southwestern Illinois. During 2006, the Gateway Mine sold 2.4 million tons of steam coal. The mine, which has non-union employees, is managed and operated by our wholly-owned subsidiary, Black Beauty Coal Company.
  Black Beauty Coal Company
  The Black Beauty Coal Company, LLC mines sold 22.5 million tons of compliance, medium sulfur and high sulfur steam coal during 2006. Black Beauty’s principal Indiana mines include Air Quality, Farmersburg, Francisco and Somerville. Air Quality is an underground coal mine located near Monroe City, Indiana that sold 2.2 million tons of compliance coal during 2006. Farmersburg is a surface mine located in Vigo and Sullivan counties in Indiana that sold 3.8 million tons of medium sulfur coal during 2006. The Francisco Mine Complex, located in Gibson County, Indiana mines coal by utilizing both surface mining and underground mining methods and sold 3.1 million tons of medium sulfur coal during 2006. The Somerville Mine Complex, also located in Gibson County, sold a total of 8.6 million tons of medium sulfur coal in 2006. Two other surface mines located in Indiana, Viking and Miller Creek, collectively sold 3.1 million tons of medium sulfur coal during 2006.
  Black Beauty’s Riola Mine Complex is an underground mining facility in eastern central Illinois. The Riola Mine Complex sold 1.7 million tons of medium sulfur coal during 2006. Due to unforeseen geologic conditions, and for the safety of our employees, Black Beauty reoriented its mine plan in 2006 resulting in the closure of the Riola Portal, with all subsequent production coming from the Vermilion Grove Portal. All Black Beauty Coal Company employees are non-union.
  Black Beauty owns a 75% interest in United Minerals Company, LLC. United Minerals, which utilizes a non-union workforce, currently acts as a contract miner for Black Beauty on a portion of the Somerville Mine Complex reserves and is a contract operator for Black Beauty at the Evansville River Terminal coal dock located on the Ohio River.
  Arclar Company LLC
  We operate the Wildcat Hills surface mine and Willow Lake underground mining complex located in Gallatin and Saline counties in southern Illinois. During 2006, these mines sold 2.4 million tons and 3.5 million tons, respectively, of medium sulfur coal that is primarily shipped by barge to downriver utility plants. An underground portal was added to the Wildcat Hills operation in mid-2006. Black Beauty provides a non-union contract workforce to mine the surface reserves at Wildcat Hills. The hourly workforce at the Willow Lake underground mine, which is represented under an International Brotherhood of Boilermakers labor agreement, is supplied by our Big Ridge, Inc. subsidiary. This labor agreement expired in October 2006 and negotiations are continuing for a new labor agreement. The hourly workforce is working under the provisions of the previous labor agreement.
  Australian Mining Operations
  In October 2006, we acquired Excel Coal Limited, an independent coal company in Australia, which added three operating mines (Wambo Open-Cut, Metropolitan and Chain Valley), two late development-stage mines (Wilpinjong and Millennium) and a development-stage mine (North Wambo Underground) to our Australia operations. Following the acquisition, we manage six mines in Queensland, Australia, and five mines in New South Wales, Australia, through our wholly-owned subsidiary, Peabody Pacific Pty Limited. During 2006, our Australian operations sold 11.0 million tons of coal, 6.5 millions tons of which were metallurgical coal. Coal from the Queensland mines is shipped via rail and truck from the mine to the Dalrymple Bay Coal Terminal and the Ports of Gladstone and Brisbane, where the coal is loaded onto ocean-going vessels while coal from the New South Wales mines is shipped via rail and truck from the mine to domestic customers and to the Ports of Newcastle and Kembla. The majority of sales from our Australian mines are denominated in U.S. dollars. Our Australian mines operate with site-specific collective bargaining labor agreements. Our Australian operations control 0.8 billion tons of proven and probable coal reserves.
  Wilkie Creek Mine
  The Wilkie Creek Coal Mine, located in Queensland, Australia, is a surface, truck-and-shovel operation. In 2006, the Wilkie Creek Mine sold 2.0 million tons of steam coal, all of which was sold to the Asia export market through the Port of Brisbane.
  Burton Mine
  The Burton Mine, located in Queensland, Australia, is a surface mine using the truck-and-shovel terrace mining technique. We own 95% of the Burton operation and the remaining 5% interest is owned by the contract miner that operates on reserves we control. During 2006, we sold 3.5 million tons of metallurgical coal and 0.6 million tons of steam coal from the Burton Mine through the Dalrymple Bay Coal Terminal.
  Millennium Mine
  The Millennium Mine, located in Queensland, Australia, is a surface operation utilizing truck-and-shovel mining methods. This mine is expected to begin shipments of metallurgical coal through the Dalrymple Bay Coal Terminal in early 2007, with production targeted at 1.6 million tons. We own an 84.6% interest in the Millennium Mine and manage the operations utilizing a contract miner.
  North Goonyella Mine
  The North Goonyella Mine, located in Queensland, Australia, is a longwall underground operation. The North Goonyella Mine operates in a difficult geologic environment and produces a high-quality metallurgical coal product. During 2006, the North Goonyella Mine sold 1.2 million tons of metallurgical coal through the Dalrymple Bay Coal Terminal.
  Eaglefield Mine
  The Eaglefield Mine, located in Queensland, Australia, is a surface operation utilizing truck-and-shovel mining methods. It is adjacent to, and fulfills contract tonnages in conjunction with the North Goonyella underground mine. Coal is mined by a contractor from reserves that we control. During 2006, the Eaglefield mine sold 1.4 million tons of metallurgical coal through the Dalrymple Bay Coal Terminal.
  Baralaba Mine
  The Baralaba Mine, located in Queensland, Australia, is a surface operation utilizing truck-and-shovel mining methods. The mine produces steam coal and a pulverized coal injection (“PCI”) product, a substitute for metallurgical coal used primarily by steel makers. Shipments through the Port of Gladstone commenced in the first quarter of 2006. During 2006, the Baralaba Mine sold 0.1 million tons of steam coal and 0.1 million tons of PCI product. We own a 62.5% interest in the Baralaba Mine and manage the operations, utilizing a contract miner.
  Wambo Open-Cut Mine
  The Wambo Open-Cut Mine, located in New South Wales, Australia, is a surface operation utilizing truck-and-shovel mining methods. In 2006, the Wambo Open-Cut Mine sold 4.6 million tons of steam coal for the full year and sold 1.3 million tons of steam coal since the acquisition. The coal from this mine was shipped the through the Port of Newcastle. We own a 75% interest in the Wambo Open-Cut Mine and manage the operations utilizing a contract miner.
  North Wambo Underground Mine
  The North Wambo Underground Mine, located in New South Wales, Australia, is under development and is expected to begin shipments in mid to late 2007, with production targeted for approximately 3 million tons per year over the next several years. This longwall mining operation plans to produce steam coal and semi-soft metallurgical coal for shipment to customers through the Port of Newcastle. We own a 75% interest in the Wambo Underground Mine.
  Metropolitan Mine
  The Metropolitan Mine, located in New South Wales, Australia, is a longwall underground operation. In 2006, the Metropolitan Mine sold 1.7 million tons of hard and semi-hard metallurgical coal for the full year and sold 0.5 million tons of this coal since the acquisition. Coal shipments from this mine are to export customers through Port Kembla and to an Australian domestic customer.
  Wilpinjong Mine
  The Wilpinjong Mine, located in New South Wales, Australia, is a new open-cut mine that was under development until late 2006. The mine is expected to produce 6-7 million tons of thermal coal in 2007 for
  shipment to export customers through the Port of Newcastle in addition to serving a domestic electricity generator. Coal is mined by a contractor from reserves that we control.
  Chain Valley Mine
  The Chain Valley Mine located in New South Wales, Australia, is a room and pillar underground operation. The Chain Valley Mine produces thermal coal which is sold locally to power authorities and to export customers through the Port of Newcastle. The mine sold 0.8 million tons of thermal coal for the full year and sold 0.3 million tons of thermal coal since it was acquired in October 2006. We own 80% of the Chain Valley Mine.
  Venezuelan Mining Operations
  Our Venezuelan Operations consist of two joint ventures, including one operating mine and one coal mine development project.
  Carbones del Guasare, S.A.
  We own a 25.5% interest in Carbones del Guasare, S.A., a joint venture that includes Anglo American plc and a Venezuelan governmental partner. Carbones del Guasare operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine is a surface operation in northwestern Venezuela that produces approximately 6 to 8 million tons of steam coal annually for export primarily to the United States and Europe. We are responsible for our pro-rata share of sales from Paso Diablo; the joint venture is responsible for production, processing and transportation of coal to ocean-going vessels for delivery to customers.
  Las Carmelitas Coal Project
  We own a 51.0% interest in Excelven Pty Ltd., which holds a 96.7% interest in Cosila Complejo Siderurgico Del Lago S.A. (“Cosila”) and all of Transportes Coal-Sea de Venezuela C.A. Cosila owns the Las Carmelitas coal mine development project, which has approximately 30 million tons of reserves in Venezuela. The other partners in this project include Alpha Natural Resources and Triangle Resource Fund. This project is currently in the exploratory stage. This interest was obtained through the Excel acquisition in October 2006.
  We hold approximately 10.2 billion tons of proven and probable coal reserves and more than 350,000 acres of surface property. Our resource development group constantly reviews these reserves for opportunities to generate revenues through the sale of non-strategic coal reserves and surface land. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties, coalbed methane production and farm income from surface land under third-party contracts.
  Our sales, trading, brokerage and marketing operations include COALSALES, LLC; COALSALES II, LLC; COALTRADE, LLC and COALTRADE International, LLC. Through our sales, trading, brokerage and marketing departments, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers both as principal and agent, trade coal and emission allowances and provide transportation-related services. As of December 31, 2006, we had 85 employees in our sales, trading, brokerage, marketing and transportation operations, including personnel dedicated to performing market research, contract administration and risk management activities.
  In response to growing international markets, we established an international trading group in 2006. This group began trading in international markets in May 2006 and added another operations office in Europe in early 2007. The sales and marketing operations also include our COALTRADE Australia operation that brokers coal in the Australia and Pacific Rim markets, and is based in Newcastle, Australia. We also have a business development, sales and marketing office in Beijing, China to pursue potential long-term growth opportunities in this market. In 2006, Shenhua Group Corporation Limited and Peabody announced that the two companies have signed a memorandum of understanding to pursue business development opportunities of mutual interest. The agreement formalizes the parties’ mutual interest in working together in coal and coal-related projects and initiatives. Shenhua Group Corporation Limited is the wholly-state owned parent company of the Hong Kong stock exchange-listed China Shenhua Energy Company Limited.
  Long-Term Coal Supply Agreements
  We currently have a sales backlog in excess of one billion tons of coal, including backlog subject to price reopener and/or extension provisions, and our coal supply agreements have remaining terms ranging from one to 19 years and an average volume-weighted remaining term of approximately 5 years. For 2006, we sold approximately 90% of our sales volume under long-term coal supply agreements. In 2006, we sold coal to over 400 electricity generating and industrial plants in 20 countries. Our primary customer base is in the United States, although customers in the Pacific Rim and other international locations represent an increasing portion of our revenue stream. One of our largest coal supply agreements is the subject of ongoing litigation and arbitration, as discussed in Item 3. Legal Proceedings.
  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 coal supply contracts when we can do so at prices we believe are favorable. Long-term contracts are attractive for regions where market prices are expected to remain stable, for cost-plus arrangements serving captive electricity generating plants and for the sale of high-sulfur coal to “scrubbed” generating plants. To the extent we do not renew or replace expiring long-term coal supply agreements, our future sales will be subject to market fluctuations.
  In January 2006, we signed a 19-year, 65-million-ton coal supply agreement with Arizona Public Service Company (“APS”). The contract is expected to generate revenue in excess of $1 billion. When our planned 6 million ton per year El Segundo Mine begins production in 2008, it will serve APS’s Cholla Generating Station near Joseph City, Arizona, and other customers. In December 2006, we signed a 10-year coal supply agreement with Tennessee Valley Authority to supply 6 million tons per year of Illinois Basin coal. Coal sales under the first five years of the agreement are expected to be in excess of $1 billion. Assumed as part of the Excel Coal Limited acquisition, we have a 19-year coal supply agreement with Macquarie Generation, which runs through 2025 and will supply approximately 127 million tons in total.
  Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices, while we seek stable sources of revenue to support the investments required to open, expand and maintain or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the
  terms of these contracts vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure, and termination and assignment provisions.
  Each contract sets a base price. Some contracts provide for a predetermined adjustment to the base price at times specified in the agreement. Base prices may also be adjusted quarterly, annually or at other periodic intervals for changes in production costs and/or changes due to inflation or deflation. Changes in production costs may be measured by defined formulas that may include actual cost experience at the mine as part of the formula. The inflation/deflation adjustments are measured by public indices, the most common of which is the implicit price deflator for the gross domestic product as published by the U.S. Department of Commerce. In most cases, the components of the base price represented by taxes, fees and royalties which are based on a percentage of the selling price are also adjusted for any changes in the base price and passed through to the customer. Some contracts allow the base price to be adjusted to reflect the cost of capital.
  Most contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that impact our cost of performance under the agreement. Additionally, some contracts contain provisions that allow for the recovery of costs impacted by the modifications or changes in the interpretation or application of any existing statute by local, state or federal government authorities. Some agreements provide that if the parties fail to agree on a price adjustment caused by cost increases due to changes in applicable laws and regulations, either party may terminate the agreement.
  Price reopener provisions are present in many of our multi-year coal contracts. These provisions may allow either party to commence a renegotiation of the contract price at various intervals. In a limited number of agreements, if the parties do not agree on a new price, the purchaser or seller has an option to terminate the contract. Under some 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 limited instances buyers have the option to vary annual or monthly volumes if necessary. Variations to the quality and volumes of coal may lead to adjustments in the contract price. Most coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat (Btu), sulfur, and ash content, and for grindability and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Coal supply agreements typically stipulate procedures for quality control, sampling and weighing. In the eastern United States, approximately half of our customers require that the coal is sampled and weighed at the destination, whereas in the western United States, samples and weights are usually taken at the shipping source.
  Contract provisions in some cases 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 or serious transportation problems that affect the seller or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement. Buyers often negotiate similar clauses covering changes in environmental laws. We often negotiate the right to supply coal that complies with a new environmental requirement to avoid contract termination. Coal supply agreements typically contain termination clauses if either party fails to comply with the terms and conditions of the contract, although most termination provisions provide the opportunity to cure defaults.
  In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines, including third-party production, as long as the replacement coal meets the contracted quality specifications and will be sold at the same delivered cost.
  Usually coal consumed domestically is sold at the mine and transportation costs are 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, including any demurrage costs.
  The majority of our sales volume is shipped by rail, but a portion of our production is shipped by other modes of transportation, including barge, truck and ocean-going vessels. Our transportation department manages the loading of coal via these transportation modes.
  Approximately 12,000 unit trains are loaded each year to accommodate the coal shipped by our mines overall. A unit train generally consists of 100 to 150 cars, each of which can hold 100 to 120 tons of coal. We believe we have good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators.
  The main types of goods we purchase are mining equipment and replacement parts, explosives, fuel, tires, steel-related (including roof control) products and lubricants. Although we have many well-established, strategic relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers, except as noted below. The supplier base providing mining materials has been relatively consistent in recent years, although there continues to be some consolidation. Consolidation of suppliers of explosives has limited the number of sources for these materials. Although our current supply of explosives is concentrated with one supplier, some alternative sources are available to us in the regions where we operate. Further consolidation of underground equipment suppliers has resulted in a situation where purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop. In recent years, demand for certain surface and underground mining equipment and off-the-road tires has increased. As a result, lead times for certain items have generally increased, although no material impact is currently expected to our financial condition, results of operations or cash flows.
  To support the continued growth and globalization of our businesses, our Board of Directors approved a project to convert our existing information systems across the major business processes to an integrated information technology system provided by SAP AG. This project will establish a single global information platform for Peabody and will enable standard processes and real-time capabilities in Finance, Materials, Maintenance, Human Resources, Sales, Production, Transportation and Quality across all of our domestic and Australia operations. The project began in the first half of 2006 with development activities, and implementation is targeted to occur mid-2007 in the U.S. and late 2007 to early 2008 for Australia.
  We continue to place great emphasis on the application of technical innovation to improve new and existing equipment performance. This research and development effort is typically undertaken and funded by equipment manufacturers using our input and expertise. Our engineering, maintenance and purchasing personnel work together with manufacturers to design and produce equipment that we believe will add value to the business.
  We are continuing a major effort to improve the performance of our dragline systems. The dragline improvement effort includes more efficient bucket design, faster cycle times, improved swing motion controls to increase component life and better monitors to enable increased payloads. A dragline is being refurbished and upgraded in Wyoming with many new design features including a new trapezoidal boom, larger bucket, larger hoist motors and additional drag and swing motors. The upgrade modifications are expected to increase the dragline system capacity by 20% over the original capacity. The dragline is expected to be commissioned near the end of the first quarter of 2007. A large dragline in Arizona was upgraded with many of the same improvements in 2006. All draglines are equipped with stress and performance monitoring equipment.
  Technology to quickly capture, analyze and transfer information regarding safety, performance and maintenance conditions at our operations is a priority. A wireless data acquisition system has been installed at the North Antelope Rochelle Mine to more efficiently dispatch mobile equipment and monitor performance and condition of all major mining equipment on a real-time basis. There are plans to rollout the system to other mining operations. Proprietary software for hand-held Personal Digital Assistant (“PDA”) devices was developed, and is being used, for safety observations, audits and front-line supervisor reports.
  World-class maintenance standards based on condition-based maintenance practices are being implemented at all operations. Use of these techniques is expected to allow us to increase equipment utilization and reduce capital spending by extending the equipment life, while minimizing the risk of premature failures. Lubrication is replaced and work is scheduled on condition rather than time. Benefits from sophisticated lubrication analysis and quality-control include lower lubrication consumption, optimum equipment performance and extended component life. Specialized maintenance reliability software is currently being installed, on a phased schedule, to better predict equipment condition in order to optimize component replacement timing.
  Our mines use sophisticated software to schedule and monitor trains, mine and pit blending, quality and customer shipments. The integrated software was developed in-house and provides a competitive tool to differentiate our reliability and product consistency. We are one of the largest users of advanced coal quality analyzers among coal producers, according to the manufacturer of this equipment. These analyzers allow continuous analysis of certain coal quality parameters, such as sulfur content. Their use helps ensure consistent product quality and helps customers meet stringent air emission requirements.
  We are also involved in the commercial development and advancement of Btu Conversion technologies (See the Btu Conversion discussion that follows for more details).
  The markets in which we sell our coal are highly competitive. According to the National Mining Association’s “2005 Coal Producer Survey,” the top 10 coal companies in the United States produced approximately 67% of total domestic coal in 2005. Our principal U.S. competitors are other large coal producers, including Arch Coal, Inc., Rio Tinto Energy America, CONSOL Energy Inc, Foundation Coal Corporation and Massey Energy Company, which collectively accounted for approximately 39% of total U.S. coal production in 2005. Major international competitors include Rio Tinto, Anglo-American PLC and BHP Billiton.
  A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on the coal consumption patterns of the electricity and steel industries in the United States, China, India and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear and hydroelectric. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations, and technological developments. We compete on the basis of coal quality, delivered price, customer service and support, and reliability.
  Generation Development
  To maximize our coal assets and land holdings for long-term growth, we continue to pursue the development of coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. The projects involve mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal lessor. The projects we are currently pursuing, as further detailed below, include the 1,600 plus-megawatt Prairie State Energy Campus in Washington County, Illinois and the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky.
  We are continuing to progress on the permitting processes, transmission access agreements and contractor-related activities for developing clean, low-cost mine-mouth generating plants using our surface lands and coal reserves. Because coal costs just a fraction of natural gas, mine-mouth generating plants can provide low-cost electricity to satisfy growing baseload generation demand. The plants will be designed to comply with all current clean air standards using advanced emissions control technologies. The plants, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, could be operational following a four-year construction phase.
  Prairie State Energy Campus
  Our Prairie State Energy Campus (“Prairie State”) is a planned 1,600 plus-megawatt coal-fueled electricity generation project located in Washington County, Illinois. Prairie State would be fueled by over six million tons of coal each year produced from adjacent underground mining operations. In February 2005, a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire approximately 47% of the project. This group of investors is comprised of Soyland Power Cooperative, Inc. (“SPCI”) (subsequently assigned to Prairie Power, Inc.), Kentucky Municipal Power Agency (“KMPA”), Wolverine Power Cooperative, Northern Illinois Municipal Power Agency, Indiana Municipal Power Agency and the Missouri Joint Municipal Electric Utility Commission (“MJMEUC”). In October 2006, Prairie State entered into agreements with the KMPA, the MJMEUC and the SPCI for the right to purchase an additional 6% equity share of the project. Also in October 2006, we entered an agreement with CMS Enterprises to equally share an expected 30% equity interest in Prairie State and to oversee development and operation of the generating plant. We also signed a letter of intent with Bechtel Power Corporation in October 2006 to provide engineering and procurement services for development of the power-related facilities at Prairie State. The above are all key milestones in the development of Prairie State.
  In January 2005, the State of Illinois issued the final air permit for the electric generating station and adjoining coal mine. After an initial appeal, the Illinois Environmental Protection Agency reissued the air permit on April 28, 2005. The same parties who filed the earlier permit challenge filed a new appeal on June 8, 2005. In the third quarter of 2006, the Prairie State Energy Campus received affirmation of the air quality permit from the Environmental Appeals Board of the U.S. Environmental Protection Agency; however, in the fourth quarter of 2006, parties that had previously challenged the permit filed a new appeal with the United States 7th Circuit Court of Appeals.
  Thoroughbred Energy Campus
  In 2003, the 1,500-megawatt Thoroughbred Energy Campus (“Thoroughbred”) in Muhlenberg County, Kentucky received a conditional Certificate to Construct from the Commonwealth of Kentucky. We and the Commonwealth of Kentucky defended the air permit granted to Thoroughbred in 2002 as certain environmental groups challenged the permit, and in April 2006, we received a decision affirming the air permit for our Thoroughbred Energy Campus. This milestone allows us to continue advancing the development of that campus. Certain parties subsequently challenged the favorable decision in Kentucky state court. If successfully completed, the Thoroughbred Energy project is expected to utilize approximately six million tons of coal each year.
  FutureGen Industrial Alliance
  We are a founding member of the FutureGen Industrial Alliance (“FutureGen”), a non-profit company that is partnering with the U.S. Department of Energy (“DOE”) to facilitate the design, construction and operation of the world’s first near-zero emission coal-fueled power plant. FutureGen is intended to demonstrate advanced coal-based technologies to generate electricity and also produce hydrogen to power fuel cells for transportation and other energy needs. The technology is expected to 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 cooperative agreement with the DOE 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. Four candidate sites (two in Texas and two in Illinois) are finalists to host FutureGen. The DOE will review the candidate sites in accordance with the National Environmental Policy Act prior to the Alliance’s selection of a final site by late-summer 2007.
  Btu Conversion
  With the increase in domestic demand for natural gas and oil based commodities, we have placed significant attention on determining how we can participate in technologies to economically convert our coal resources. Technology has advanced over the last twenty years to convert coal to natural gas as well as liquids, such as diesel fuel, gasoline and jet fuel.
  In October 2005, we reached an agreement to acquire a 30% interest in Econo-Power International Corporation (“EPIC™”). We will invest up to $6 million for the 30% interest and will assist in developing coal supply options for customers of that technology. As of December 31, 2006, we have funded $4.1 million under this agreement and hold a 25.35% interest. EPIC™ systems use air-blown gasifiers to convert coal into a synthetic gas that is ideal for industrial applications.
  In July 2006, we announced that we had entered into a joint development agreement with Rentech, Inc. to evaluate sites in the Midwest and Montana for coal-to-liquids projects that would transform coal into diesel and jet fuel. Projects would be sited where we have large reserves and would be designed using Rentech’s proprietary Fischer-Tropsch coal-to-liquids process. Plant production could range from 10,000 to 30,000 barrels of fuel per day (“bpd”). A 10,000 bpd plant would use 2 to 3 million tons of coal annually and a 30,000 bpd plant would use 6 to 9 million tons of coal annually, dependent on the quality of coal. With more than 10.2 billion tons of reserves, we have numerous sites in the United States that have potential for Btu Conversion projects.
  Coalbed Methane and Oil and Gas Properties
  We continue to evaluate the potential of the coalbed methane business and will make acquisitions, develop our properties, enter into joint operating agreements and ventures with other companies or make property sales as appropriate. Our subsidiary, Peabody Natural Gas, LLC, produces coalbed methane and conventional gas and oil from its operations in the Southern Powder River Basin near the Caballo Mine and North Antelope Rochelle Mine. As of December 31, 2006, we operated 62 coalbed methane and conventional gas and oil wells with net production of approximately 1.7 million cubic feet per day. We are evaluating coalbed methane resources in several deep coal seams in the Powder River Basin and continue to evaluate coalbed methane and shale gas opportunities in southern Illinois and Indiana, western Kentucky, and West Virginia.
  Certain Liabilities
  We have significant long-term liabilities for reclamation (also called asset retirement obligations), work-related injuries and illnesses, pensions and retiree health care. In addition, labor contracts with the UMWA and voluntary arrangements with non-union employees include long-term benefits, notably health care coverage for retired employees and future retirees and their dependents. The majority of our existing liabilities relate to our past operations.
  Asset Retirement Obligations. Asset retirement obligations primarily represent the present value of future anticipated costs to restore surface lands to productivity levels equal to or greater than pre-mining conditions, as required by the Surface Mining Control and Reclamation Act. Expense (which includes liability accretion and asset amortization) for the years ended December 31, 2006, 2005 and 2004 was $40.1 million, $35.9 million, and $42.4 million, respectively. As of December 31, 2006, our asset retirement obligations of $423.0 million included $354.0 million related to locations with active mining operations and $69.0 million related to locations that are closed or inactive.
  Workers’ Compensation. These liabilities represent the actuarial estimates for compensable, work-related injuries (traumatic claims) and occupational disease, primarily black lung disease (pneumoconiosis). The Federal Black Lung Benefits Act requires employers to pay black lung awards to current and former employees who filed claims after June 1973. Workers’ compensation liabilities were $264.4 million as of December 31, 2006, $31.0 million of which was a current liability. The adoption of the Financial Accounting Standards Board’s recently issued Statement of Financial Accounting Standard (“SFAS”) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”) on December 31, 2006 resulted in a decrease to our workers’ compensation liability of $4.5 million and a decrease to accumulated other comprehensive loss of $2.7 million, net of tax. Therefore, in accordance with SFAS No. 158, the $264.4 million liability as of December 31, 2006 represented the accumulated obligation related to our workers’ compensation plans, including unrecognized actuarial gains. Expense for the years ended December 31, 2006, 2005 and 2004 was $44.0 million, $56.1 million and $59.2 million, respectively.
  Pension-Related Provisions. Pension-related costs represent the actuarially-estimated cost of pension benefits. Annual minimum contributions to the pension plans are determined by consulting actuaries based on the minimum funding standards of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and an agreement with the Pension Benefit Guaranty Corporation. Beginning on January 1, 2008, new minimum funding standards will be required by the Pension Protection Act of 2006. Pension-related liabilities were $128.6 million as of December 31, 2006, $1.3 million of which was a current liability. The adoption of SFAS No. 158 on December 31, 2006 resulted in an increase to our pension-related liability of $14.9 million and an increase to accumulated other comprehensive loss of $8.0 million, net of tax. Therefore, in accordance with SFAS No. 158, the $128.6 million liability as of December 31, 2006 represented the projected benefit obligation associated with our pension plans, including unrecognized actuarial losses and prior service cost, less the fair value of pension plan assets. Expense for the years ended December 31, 2006, 2005 and 2004 was $26.3 million, $38.7 million and $28.5 million, respectively.
  Retiree Health Care. Consistent with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” we record a liability representing the estimated cost of providing retiree health care benefits to current retirees and active employees who will retire in the future. Provisions for active employees represent the amount recognized to date, based on their service to date; additional amounts are accrued periodically so that the total estimated liability is accrued when the employee retires.
  Our retiree health care liabilities were $1.45 billion as of December 31, 2006, $82.6 million of which was a current liability. The adoption of SFAS No. 158 on December 31, 2006 resulted in an increase to our retiree health care liabilities of $395.5 million and an increase to accumulated other comprehensive loss of $237.3 million, net of tax. Therefore, in accordance with SFAS No. 158, the $1.45 billion liability as of December 31, 2006 represented the accumulated benefit obligations of our retiree health care liabilities, including any unrecognized actuarial losses and prior service cost. Expense for the years ended December 31, 2006, 2005 and 2004 was $108.4 million, $99.0 million and $58.4 million, respectively.
  A second category of retiree health care obligations represents the liability for future contributions to certain multi-employer health funds. The United Mine Workers of America Combined Fund was created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of retirees including our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the 1992 law. No new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan created by the same federal law in 1992, provides benefits to qualifying retired former employees of bankrupt companies who have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers default in providing their former employees with retiree medical benefits, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Fund, was established through collective bargaining and provides benefits to qualifying retired
  former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business.
  On December 20, 2006, President Bush signed the Surface Mining Control and Reclamation Act Amendments of 2006 (the “2006 Act”). Prior to the enactment of this new law, federal statutes required certain Peabody subsidiaries to make contributions to two coal industry retiree health funds for costs of “orphans” who are retirees and their dependents of bankrupt companies that defaulted in providing their health care benefits. These orphan benefits will be the responsibility of the federal government on a phased-in basis. The legislation authorizes $490 million per year in general fund revenues to pay for these and other benefits under the bill. In addition, future interest from the federal Abandoned Mine Land (“AML”) trust fund and previous unused interest from the AML trust fund will be available to offset orphan retiree health care costs. Under current projections from the health funds, these available resources are more than adequate to cover all anticipated costs of orphan retirees. These amounts are also in addition to any amounts that may be appropriated by Congress at its discretion. The legislation also reduces AML fees currently paid by us on coal production. Beginning in October 2007, those fees will be reduced by ten percent from current levels for five years, and then twenty percent from current levels for ten years, at which point the authority to collect fees will expire.
  The 2006 Act specifically amended the federal laws establishing the Combined Fund, the 1992 Benefit Plan and the 1993 Benefit Plan. The 2006 Act provides new and additional funding to all three programs, subject to the limitations described below. The 2006 Act guarantees full funding of all beneficiaries in the Combined Fund by supplementing the annual transfers of interest earned on the AML trust fund. The 2006 Act further provides funding for the annual orphan health costs under the 1992 Benefit Plan on a phased-in basis: 25%, 50% and 75% in the years 2008, 2009 and 2010, respectively. Thereafter, federal funding will pay for 100% of the orphan health costs. The coal producers that signed the 1988 labor agreement, including some of our subsidiaries, remain responsible for the costs of the 1992 Benefit Plan in 2007. The 2006 Act also included the 1993 Benefit Plan as one of the statutory funds and authorizes the trustees of the 1993 Benefit Plan to determine the contribution rates through 2010 for pre-2007 beneficiaries. During calendar years 2008 through 2010, federal funding will pay a portion of the 1993 Benefit Plan’s annual health costs on a phased-in basis; 25%, 50% and 75% in the years 2008, 2009 and 2010, respectively. The 1993 Benefit Plan trustees have set a $2.00 per hour statutory contribution rate for 2007. Under the 2006 Act, these new and additional federal expenditures to the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million. To the extent that (i) the annual funding of the programs exceeds this amount (plus the amount of interest from the AML trust fund paid with respect to the Combined Benefit Fund), and (ii) Congress does not allocate additional funds to cover the shortfall, contributing employers and affiliates, including some of our subsidiaries, would be responsible for the additional costs. Those of our subsidiaries that have agreed to the 2007 National Bituminous Coal Wage Agreement will pay $0.50 per hour worked to the 1993 Benefit Plan to provide benefits for post 2006 beneficiaries. To the extent the $0.50 per hour payment exceeds the amount needed for this purpose, the difference will be credited against the $2.00 per hour statutory payment.
  Obligations to the United Mine Workers of America Combined Fund were $30.8 million as of December 31, 2006, $5.2 million of which was a current liability. Expense for the years ended December 31, 2006, 2005 and 2004 was $2.5 million, $0.9 million and $4.9 million, respectively. The 1992 Benefit Fund and the 1993 Benefit Fund are expensed as payments are made and no liability is recorded other than amounts due and unpaid. Expense related to these funds was $5.7 million, $4.0 million and $4.4 million for the years ended December 31, 2006, 2005 and 2004, respectively.
  As of December 31, 2006, we had approximately 9,200 employees. Approximately 60% of our hourly employees were non-union as of December 31, 2006 and they generated 86% of our 2006 coal production. Relations with our employees and, where applicable, organized labor are important to our success.
  We opened training centers in the eastern, midwest and western regions of the United States under our “Workforce of the Future” initiative. Due to our current employee demographics, a significant portion of our current hourly employees will retire over the next decade. Our training centers are educating our workforce, particularly our most recent hires, in our rigorous safety standards, the latest in mining techniques and equipment, and the centers serve as centers for dissemination of mining best practices across all of our operations. Our training efforts exceed minimum government standards for safety and technical expertise with the intent of developing and retaining a world-class workforce. Additionally, we are implementing a supervisor training program through our training centers to develop both new and current supervisors, in an effort to ensure the replenishment of our operating management workforce over the next decade.
  United States Labor Relations
  Approximately 66% of our U.S. miners are non-union and are employed in the states of Wyoming, Colorado, Indiana, New Mexico, Illinois and Kentucky. The UMWA represented approximately 26% of our subsidiaries’ hourly employees, who generated 11% of our U.S. production during the year ended December 31, 2006. An additional 5% of our hourly employees are represented by labor unions other than the UMWA. These employees generated 1% of our production during the year ended December 31, 2006. Hourly workers at our mine in Arizona are represented by the UMWA under the Western Surface Agreement of 2000, which is effective through September 1, 2007. Our union workforce east of the Mississippi River is primarily represented by the UMWA. The UMWA-represented workers at one of our eastern mines operate under a contract that expires on December 31, 2007. The remainder of our UMWA-represented workers in the east operate under a recently signed, five-year labor agreement expiring December 31, 2011. This contract replaced a contract that had expired on December 31, 2006 and mirrors the 2007 National Bituminous Coal Wage Agreement.
  Australia Labor Relations
  The Australian coal mining industry is unionized and the majority of workers employed at our Australian Mining Operations are members of trade unions. The Construction Forestry Mining and Energy Union represents our hourly production employees. As of December 31, 2006, our Australian hourly employees were approximately 9% of our hourly workforce and generated 2% of our total production in the year then ended. The labor agreement at our Wilkie Creek Mine was renewed in June 2006 and that agreement expires in June 2009. The North Goonyella Mine operates under an agreement due to expire in 2008, and the Metropolitan Mine operates under an agreement that expires in June 2007.
  Regulatory Matters — United States
  Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations.
  We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of the violations to date or the monetary penalties assessed has been material.
  Mine Safety and Health
  Our goal is to achieve excellent safety and health performance. We measure our progress in this area primarily through the use of accident frequency rates. We believe that it is our responsibility to our employees to provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in the establishment of safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence. A portion of the annual performance incentives for our operating units is tied to their safety record.
  Our safety performance in 2006, as measured by accident frequency rates, was 38% better than the U.S. average for our industry. During 2006, we achieved our vision of zero accidents at 12 of our facilities, which contributed to our second best year ever in safety. We received multiple safety awards during the year, including our third consecutive Holmes Safety Association’s Green River Council award at our Big Run Mine in Ohio County, Kentucky; our second consecutive Safe Sam award at our North Antelope Rochelle Mine, Wyoming’s safest mine and our most productive; and the Mountaineer Guardian Award from the West Virginia Office of Miners’ Health, Safety and Training and the West Virginia Coal Association for outstanding safety achievement at our Federal No. 2 underground mine. Our training centers educate our employees in safety best practices and reinforce our company-wide belief that productivity and profitability follow when safety is a cornerstone of all of our operations. See the “Employees” section above for a discussion of our Workforce of the Future initiative.
  Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations. Congress enacted The Mine Improvement and New Emergency Response Act of 2006 (“The Miner Act”) as a result of the increase in fatal accidents primarily at U.S. underground mines. Among the new requirements, each miner must have at least two, one-hour Self Contained Self Rescue (“SCSR”) devices for their use in the event of an emergency (each miner had at least one SCSR device prior to The Miner Act) and additional caches of rescuers in the escape routes leading to the surface. Our cost for the additional SCSR devices, storage boxes, training units and lifelines to assist miners in potentially dangerous escape routes has exceeded $10 million. Our evacuation training programs have been expanded to include more comprehensive training with the SCSR devices and frequent tours of the escape routes in their entirety. The Miner Act also requires installation of two-way communications systems that allows communication between rescue workers and trapped miners following an accident as mine operators must have the ability to locate each miner’s last known position immediately before and after a disaster occurs. Since these technologies are not yet available, our underground mines currently locate miners with existing mine communications telephone systems and we are working with the National Institute for Occupational Safety and Health and several manufacturers to develop new communications and location systems. The projected costs for a new system are approximately $10 million. We are also constructing rescue chambers for trapped miners who are unable to use escape routes due to fires or obstructions and providing at least two mine rescue teams located within thirty minutes of each mine. See risks inherent to mining in Item 1A. Risk Factors.
  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. As a result of the increase in fatal accidents primarily at U.S. underground mines, several states have adopted new safety regulations and the Mine Safety and Health Administration has passed numerous emergency regulations including emergency notification and response plans, increased fines for violations and added mine rescue coverage requirements. While these changes have had a significant effect on our operating costs, our U.S. competitors with underground mines are subject to the same degree of regulation.
  In the United States, under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator must pay federal black lung benefits and medical expenses to claimants who are current and former employees and last worked for the operator after July 1, 1973. Coal mine operators must also make payments 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. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits. The trust fund is funded by an excise tax on U.S. 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.
  Coal Industry Retiree Health Benefit Act of 1992
  The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) provides for the funding of health benefits for certain UMWA retirees. The Coal Act established the Combined Fund into which “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. The Coal Act also created a second benefit fund, the 1992 Benefit Plan, for miners who retired between July 21, 1992, and September 30, 1994, and whose former employers are no longer in business. Annual payments made by certain of our subsidiaries under the Coal Act totaled $13.5 million, $6.3 million $19.3 million, respectively, during the years ended December 31, 2006, 2005 and 2004.
  Our subsidiaries have been billed a retroactive assessment in the amount of $7.4 million for periods prior to October 1, 2003 as well as an increase of $0.7 million for the period from October 1, 2003 through September 30, 2004 and $0.6 million from October 2004 through August 15, 2005 as a result of the Social Security Administration’s premium recalculation. These amounts were paid as required by the Combined Fund Trustees, but were paid under protest. In August 2005, a federal district court in Maryland ruled in favor of our subsidiaries, and we suspended payments to the Combined Fund to recoup our overpayment. On December 2, 2005, the same federal court granted a stay of payment recoupment, and we paid to the Combined Fund the amount we recouped. In December 2006, the Fourth Circuit Court of Appeals upheld the Maryland district court’s finding that the Social Security Administration’s premium calculation was
  unlawful. Our subsidiaries are pursuing a refund of the $8 million overpayment made to the Combined Fund.
  Environmental Laws
  We are subject to various federal, state and foreign environmental laws. Some of these laws, discussed below, place many requirements on our coal mining operations. Federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance.
  Surface Mining Control and Reclamation Act
  In the United States, the Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of U.S. surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under the act, the state becomes the regulatory authority. Except for Arizona, states in which we have active mining operations have achieved primary control of enforcement through federal authorization. In Arizona, we mine on tribal lands and are regulated by OSM because the tribes do not have SMCRA authorization.
  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 U.S. mining 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 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 mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact 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 and documents required of the OSM’s Applicant Violator System.
  Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts.
  Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund. The fee is $0.35 per ton of surface-mined coal and $0.15 per ton of deep-mined coal, effective through September 30, 2007. Pursuant to the Tax Relief and Health Care Act of 2006, from October 1, 2007 through September 30, 2012, the fee will be $0.315 per ton of surface-mined coal and $0.135 per ton of underground mined coal. From October 1, 2012 through September 30, 2021, the fee will be $0.28 per ton of surface-mined coal and $0.12 per ton of underground mined coal.
  SMCRA stipulates compliance with many other major environmental programs. These programs include the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (“RCRA”); and Comprehensive Environmental Response, Compensation, and Liability Acts (“CERCLA”, commonly known as “Superfund”). Besides OSM, other Federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The U.S. Environmental Protection Agency (“EPA”) is the lead agency for States or Tribes with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers regulates activities affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms (“ATF”) regulates the use of explosive blasting.
  We do not believe there are any substantial matters that pose a risk to maintaining our existing mining permits or hinder our ability to acquire future mining permits. It is our policy to comply in all material respects with the requirements of the Surface Mining Control and Reclamation Act and the state and tribal laws and regulations governing mine reclamation.
  The Clean Air Act and the corresponding state laws that regulate the emissions of materials into the air affect U.S. 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. The Clean Air Act indirectly, but more significantly, affects the coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxide, mercury and other compounds emitted by coal-based electricity generating plants.
  Title IV of the Clean Air Act places limits on sulfur dioxide emissions from electric power generation plants. The limits set baseline emission standards for these facilities. Reductions in emissions occurred in Phase I in 1995 and in Phase II in 2000 and apply to all coal-based power plants. The affected electricity generators have been able to meet these requirements by, among other ways, switching to lower sulfur fuels; installing pollution control devices, such as flue gas desulfurization systems, which are known as “scrubbers;” reducing electricity generating levels; or purchasing sulfur dioxide emission allowances. Emission sources receive these sulfur dioxide emission allowances, which can be traded or sold to allow other units to emit higher levels of sulfur dioxide. Title IV also required that certain categories of coal-based electric generating stations install certain types of nitrogen oxide controls. Major changes in Title IV were recently promulgated in the Clean Air Interstate Rule (“CAIR”) discussed below.
  In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for very fine particulate matter (PM2.5) and ozone. As a result, some states will be required to change their existing implementation plans to attain and maintain compliance with the new air quality standards. Our mining operations and electricity generating customers are likely to be directly affected when the revisions to the air quality standards are implemented by the states. State and federal regulations relating to implementation of the new air quality standards may restrict our ability to develop new mines or could require us to modify our existing operations.
  In December 2003, the EPA proposed the CAIR, which is designed to help bring the eastern half of the United States into compliance with the National Ambient Air Quality Standards for fine particulates and ozone. The rule became final in March 2005 and will require further reduction of sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 28 states and the District of Columbia although it is being challenged. Once fully implemented, the rule will reduce sulfur dioxide from power plants by approximately 73% from 2003 levels and, by 2015, nitrogen oxide emissions by approximately 61% from 2003 levels. CAIR is currently under review in court on a number of grounds, including the assertion that the regulation is insufficiently stringent.
  On September 21, 2006, EPA promulgated new National Ambient Air Quality Standards revising and updating the 1997 particulate matter standards. The new regulations made the 24-hour standard for PM2.5 more stringent but left the annual PM2.5 standard unchanged. It also left the 24-hour standard for PM10 (particulate matter equal to 10 microns or more) unchanged and terminated the annual PM10 standard. The change to the 24-hour PM2.5 standard is expected to have an effect on the use of coal for electric
  generation, but it is impossible at this time to quantify that effect. Lawsuits seeking to compel EPA to adopt more stringent standards both for PM2.5 and PM10 have been filed and are pending in court. It is not possible to determine the chances of success for those lawsuits.
  The Clean Air Act also requires electricity generators that currently are major sources of nitrogen oxide in moderate or higher ozone non-attainment areas (areas where the air quality does not meet acceptable standards) to install reasonably available control technology for nitrogen oxide, which is a precursor of ozone. In 1997, the EPA promulgated the final “NOx SIP Call” rules that require coal-fueled power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions. These states were required to submit their Phase II SIPs by April 2005. Two additional states, Georgia and Missouri, were required to submit a complete NOx SIP by April 2005 to address affected portions of their states. In August 2005, EPA stayed the applicability of the NOx SIP Call to Georgia, although the stay may be reconsidered. Installation of additional control measures required under the final rules has made and will continue to make it more costly to operate coal-based electricity generating plants.
  The Justice Department, on behalf of the EPA, has filed a number of lawsuits since November 1999, alleging that 12 electricity generators violated the new source review provisions of the Clean Air Act Amendments at power plants in the midwestern and southern United States. Six electricity generators have announced settlements with the Justice Department requiring the installation of additional control equipment on selected generating units, and at least one generator has received a favorable court decision. If the remaining electricity generators are found to be in violation, they could be subject to civil penalties and be required to install the required control equipment or cease operations. One of the currently pending enforcement cases is now before the U.S. Supreme Court, with a decision expected shortly. Another of these cases was recently decided adversely to the utility, and the utility has asked the Supreme Court to review the case. Our customers are among the electricity generators subject to enforcement actions and if found not to be in compliance, our customers could be required to install additional control equipment at the affected plants or they could decide to close some or all of those plants. If our customers decide to install additional pollution control equipment at the affected plants, we have the ability to supply coal from various regions to meet any new coal requirements.
  In 2002 and again in 2003, EPA promulgated new regulations clarifying and modifying its new source review regulations, including with respect to electric generation sources that utilize coal. These regulations have been litigated and partially remanded to EPA, which has proposed new regulations and is considering proposing others. There is also ongoing litigation concerning aspects of the regulations. These regulations could affect the pending new source review enforcement cases, whether additional cases are brought, and the extent to which other existing coal-based electric generating units may undertake repairs, replacements and modifications without triggering a requirement to install new pollution control equipment. It is difficult to determine at this point the exact configuration of the final new source review regulations that ultimately will emerge and the impact they will have on the utilization of coal for electric generation.
  The Clean Air Act set a national goal of the prevention of any future, and the remedying of any existing, impairment of visibility in 156 national parks and wilderness areas across the U.S. Under regulations issued by the EPA in 1999, states were required to consider setting a goal of restoring natural visibility conditions in Class I areas in their states by 2064 and to explain their reasons to the extent they determine not to adopt this goal. The state plans must require the application of “Best Available Retrofit Technology” (“BART”) after 2010 on certain electric generating stations reasonably anticipated to cause or contribute to regional haze which impairs visibility in these areas. The extent and nature of these BART requirements have been the subject of litigation. As a result of the litigation, EPA finalized amendments to the 1999 BART regulations in June 2005. EPA included in the amendments guidelines for states to use in determining which facilities must install controls and the types of controls the facilities must use. States are required to develop their implementation plans by December 2007. For electric generating units subject to CAIR in states that adopt the CAIR cap and trade program for sulfur dioxide and NOx, the state is allowed to apply CAIR controls as a substitute for those required by BART. The EPA regional haze regulations may affect other (non-BART) sources to the extent determined necessary to make reasonable progress towards the national visibility improvement goal. Also, five western states
  have elected an option offered by the EPA of regulating visibility-impairing emissions through a regional rather than a source-by-source approach. However, this option was litigated and the states’ rules were invalidated. On October 13, 2006, EPA promulgated new regulations that may allow these western states and possibly others to adopt a regional approach. The EPA’s regional haze regulations could cause our customers to install equipment to control sulfur dioxide and nitrogen oxide emissions. The requirement to install control equipment could affect the amount of coal supplied to those customers if they decide to switch to other sources of fuel to lower emission of sulfur dioxide and nitrogen oxide.
  In 2005, the EPA adopted the Clean Air Mercury Rule (“CAMR”) to permanently cap and reduce nationwide mercury emissions from coal-fired power plants. When fully implemented, and after the appeals have been resolved, the rule will reduce mercury emissions by nearly 70%. CAMR establishes standards of performance limiting mercury emissions from new and existing power plants and creates a cap-and-trade program, which will reduce emissions in two phases. When fully implemented, the cap on mercury emissions will be 15 tons per year. Some states have adopted rules that are more stringent than the federal program and other states are considering such rules. Implementation of the federal program or the more stringent state programs could cause our customers to switch to other fuels to the extent it would be economically preferable for them to do so, and could impact the completion or success of our generation development projects. CAMR is currently under review in court on a number of grounds, including the assertion by a number of states and environmental groups that the regulation is insufficiently stringent.
  Legislation that would reduce emissions of sulfur dioxide, nitrogen oxide and mercury and other greenhouse gases in phases has been introduced in Congress. No such legislation has passed either house of Congress. If this type of legislation were enacted into law, it could impact the amount of coal supplied to electricity generating customers if they decide to switch to other sources of fuel whose use would result in lower emission of sulfur dioxide, nitrogen oxide, mercury and carbon dioxide.
  A small number of states have either proposed or adopted legislation or regulations limiting emissions of sulfur dioxide, nitrogen oxide and mercury from electric generating stations. A smaller number of states have also proposed to limit emissions of carbon dioxide from electric generating stations, with California recently having adopted legislation and regulations requiring that all fossil-fueled generation in the state or sold into the state meet a greenhouse gas performance standard that coal-based generation cannot meet without capturing and sequestering a significant amount of carbon dioxide emissions. Limitations imposed by states on emissions of any of these four substances from electric generating stations could result in fuel switching by the generators if they determined it to be economically preferable to do so.
  The U.S. Supreme Court in November 2006 heard oral arguments in a case seeking to establish that EPA has authority to regulate carbon dioxide emissions as a “pollutant” under the Clean Air Act. A decision is expected early this year. It is too soon to speculate on whether a decision in that case could cause EPA to issue carbon dioxide regulations and, if so, the character of those regulations.
  The Clean Water Act of 1972 affects U.S. coal mining operations by requiring effluent limitations and treatment standards for waste water discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water.
  States are empowered to develop and enforce “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the Clean Water Act section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with its water quality standards and other applicable requirements in deciding whether or not to certify the activity.
  Section 404 under the Clean Water Act requires mining companies to obtain U.S. Army Corps of Engineers permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. These permits have been the subject of multiple recent court cases, the results of which may affect permitting costs or result in permitting delays.
  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, may be required to meet new TMDL effluent standards for these stream segments. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality/exceptional use.” These regulations would restrict the diminution of water quality in these streams. Waters discharged from coal mines to high quality/exceptional use streams may be required to meet additional conditions or provide additional demonstrations and/or justification. In general, these Clean Water Act requirements could result in higher water treatment and permitting costs or permit delays, which could adversely affect our coal production costs or efforts.
  RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous materials found on a mine site are those contained in products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous waste materials under RCRA.
  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 materials generated at electric utility and independent power producing facilities. In May 2000, the EPA concluded that coal combustion materials do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these materials. The EPA is evaluating national non-hazardous waste guidelines for coal combustion materials placed at a mine. National guidelines for mine-fills may affect the cost of ash placement at mines.
  CERCLA (Superfund)
  CERCLA affects U.S. 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. Under the EPA’s Toxic Release Inventory process, companies are required annually to report the use, manufacture or processing of listed toxic materials that exceed defined thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.
  The Energy Policy Act of 2005
  The Domenici-Barton Energy Policy Act of 2005 (“EPACT”) was signed by President Bush in August 2005. EPACT contains tax incentives and directed spending totaling an estimated $14.1 billion intended to stimulate supply-side energy growth and increased efficiency. In addition to rules affecting the leasing process of federal coal properties, EPACT programs and incentives include funding to demonstrate advanced coal technologies, including coal gasification; grants and a loan guarantee program to encourage deployment of advanced clean coal-based power generation technologies, including integrated gasification combined cycle (“IGCC”); a federal loan guarantee program for the cost of advanced fossil energy projects, including coal gasification; funding for energy research, development, demonstration and commercial application programs relating to coal and power systems; and tax incentives for IGCC, industrial gasification and other advanced coal-based generation projects, as well as for coal sold from Indian lands. Finally, certain sections of EPACT are potentially applicable to the area of Btu Conversion,
  such as the aforementioned fossil energy project loan guarantee program as well as a provision allowing taxpayers to capitalize 50% of the cost of refinery investments which increase the total throughput of qualified fuels — including synthetic fuels produced from coal — by at least 25%. In addition, EPACT requires the Secretary of Defense to develop a strategy to use fuel produced from coal, oil shale and tar sands (“covered fuel”) to assist in meeting the fuel requirements of the U.S. Department of Defense (“DOD”). The law authorizes the DOD to enter into multi-year contracts to procure a covered fuel to meet one or more of its fuel requirements and to carry out an assessment of potential locations for covered fuel sources.
  Regulatory Matters — Australia
  The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines), and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed.
  Mining and exploration in Australia is generally carried on under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.
  COAL21 Fund
  Our subsidiary, Peabody Pacific, has committed to pay up to a maximum of A$0.20/tonne (approximately US$0.15/tonne) of coal sales for a period of five years to the Australian COAL21 Fund. The COAL21 Fund is a voluntary coal industry fund to support clean coal technology demonstration projects and research in Australia. All major coal companies in Australia have committed to this fund. The commitment to pay starts on April 1, 2007 with a levy of A$0.10/tonne of coal sales. This levy is expected to rise to A$0.20/tonne on July 1, 2007.
  Native Title and Cultural Heritage
  Since 1992, the Australian courts have recognized that native title to lands, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the Federal Native Title Act (“NTA”) which recognizes and protects native title, and under which a national register of native title claims has been established.
  Native title rights do not extend to minerals; however, native title rights can be affected by the mining process unless those rights have previously been extinguished. Native title rights can be extinguished either by a valid act of Government (as set out in the NTA) or by the loss of connection between the land and the group of Aboriginal peoples concerned.
  The NTA provides that where native title rights still exist and the mining project will affect those native title rights, it will be necessary to consult with the relevant Aboriginal group and to come to an agreement on issues such as the preservation of sacred or important sites, the employment of members of the group by the mine operator, and the payment of compensation for the effect on native title of the mining project. In the absence of agreement with the relevant Aboriginal group, there is an arbitration provision in the NTA.
  There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archeological sites. The NTA and laws protecting Aboriginal cultural heritage and archeological sites have had no impact on our current operations.
  The federal system requires that approval is obtained for any activity which will have a significant impact on a matter of national environmental significance. Matters of national environmental significance include listed endangered species, nuclear actions, World Heritage areas, National Heritage areas, and migratory species. An application for such an approval may require public consultation and may be approved, refused or granted subject to conditions. Otherwise, responsibility for environmental regulation in Australia is primarily vested in the states.
  Each state and territory in Australia has its own environmental and planning regime for the development of mines. In addition, each state and territory also has a specific act dealing with mining in particular, regulating the granting of mining licenses and leases. The mining legislation in each state and territory operates concurrently with environmental and planning legislation. The mining legislation governs mining licenses and leases, including the restoration of land following the completion of mining activities. Apart from the grant of rights to mine (which are covered by the mining statutes), all licensing, permitting, consent and approval requirements are contained in the various state and territory environmental and planning statutes.
  The particular provisions of the various state and territory environmental and planning statutes vary depending upon the jurisdiction. Despite variation in details, each state and territory has a system involving at least two major phases. First, obtaining the developmental application and, if that is granted, obtaining the detailed operational pollution control licenses, which authorize emissions up to a maximum level; and second, obtaining pollution control approvals, which authorize the installation of pollution control equipment and devices. In the first regulatory phase, an application to a regulatory authority is filed. The relevant authority will either grant a conditional consent, an unconditional consent, or deny the application based on the details of the application and on any submissions or objections lodged by members of the public. If the developmental application is granted, the detailed pollution control license may then be issued and such license may regulate emissions to the atmosphere; emissions in waters; noise impacts, including impacts from blasting; dust impacts; the generation, handling, storage and transportation of waste; and requirements for the rehabilitation and restoration of land.
  Each state and territory in Australia also has either a specific statute or certain sections in other environmental and planning statutes relating to the contamination of land and vesting powers in the various regulatory authorities in respect of the remediation of contaminated land. Those statutes are based on varying policies — the primary difference between the statutes is that in certain states and territories, liability for remediation is placed upon the occupier of the land, regardless of the culpability of that occupier for the contamination. In other states and territories, primary liability for remediation is placed on the original polluter, whether or not the polluter still occupies the land. If the original polluter cannot itself carry out the remediation, then a number of the statutes contain provisions which enable recovery of the costs of remediation from the polluter as a debt.
  Many of the environmental planning statutes across the states and territories contain “third-party” appeal rights in relation, particularly, to the first regulatory phase. This means that any party has a right to take proceedings for a threatened or actual breach of the statute, without first having to establish that any particular interest of that person (other than as a member of the public) stands to be affected by the threatened or actual breach.
  Accordingly, in most states and territories throughout Australia, mining activities involve a number of regulatory phases. Following exploratory investigations pursuant to a mining lease, the activity proposed to be carried out must be the subject of an application for the activity or development. This phase of the regulatory process, as noted above, usually involves the preparation of extensive documents to constitute the application, addressing all of the environmental impacts of the proposed activity. It also generally
  involves extensive notification and consultation with other relevant statutory authorities and members of the public. Once a decision is made to allow a mine to be developed by the grant of a development consent, permit or other approval, then a formal mining lease can be obtained under the mining statute. In addition, operational licenses and approvals can then be applied for and obtained in relation to pollution control devices and emissions to the atmosphere, to waters and for noise. The obtaining of licenses and approvals, during the operational phase, generally does not involve any extensive notification or consultation with members of the public, as most of these issues are anticipated to be resolved in the first regulatory phase.
  The combined effect of various state and federal statutes requires an employer to ensure that persons employed in a mine are safe from injury by providing a safe working environment and systems of work; safety machinery; equipment, plant and substances; and appropriate information, instruction, training and supervision.
  In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation that deals specifically with the coal mining industry. Mining employers, owners, directors and managers, persons in control of work places, mine managers, supervisors and employees are all subject to these duties.
  It is mandatory for an employer to have insurance coverage with respect to the compensation of injured workers; similar coverage is in effect throughout Australia which is of a no fault nature and which provide for benefits up to a prescribed level. The specific benefits vary from jurisdiction to jurisdiction, but generally include the payment of weekly compensation to an incapacitated employee, together with payment of medical, hospital and related expenses. The injured employee has a right to sue his or her employer for further damages if a case of negligence can be established.
  Legislation was introduced in Congress in 2006 to reduce greenhouse gas emissions in the United States. Such or similar federal legislative action could be taken in 2007 or later years. In addition, a number of states in the United States have taken steps to regulate greenhouse gas emissions. For example, seven northeastern states (New York, Vermont, New Hampshire, Maine, Connecticut, Delaware and New Jersey) entered into the Regional Greenhouse Gas Initiative (RGGI) agreement in December 2005 to reduce carbon dioxide emissions from power plants, and in August 2006 finalized a model rule to help implement the agreement; Maryland has approved legislation that may result in inclusion in the RGGI in 2007; in August 2006, the California legislature approved legislation allowing the imposition of statewide caps on, and cuts in, carbon dioxide emissions; and Arizona’s governor signed an executive order in September 2006 that calls for the state to reduce carbon dioxide emissions. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. Passage of regulations regarding greenhouse gas emissions by the United States or other actions to limit carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by electric generators.
  In December 1997, in Kyoto, Japan, the signatories to the 1992 Framework Convention on Climate Change, which addresses emissions of greenhouse gases, established a binding set of emission targets for developed nations. The Australian Federal Government has not signed the Kyoto Protocol but has indicated interest in meeting the emissions reduction requirements of the protocol. No legislation currently exists that restricts or requires reduction in greenhouse emissions within Australia. The Australian Federal Government has created significant incentives for companies that are large energy users. The New South Wales State Government requires certain businesses to prepare an Energy Reduction Plan and is considering introducing mandatory emissions reporting for all coal mines. None of these programs mandate any greenhouse gas emission or energy usage reduction, but seek disclosure of current emissions and voluntary reduction.
  We file annual, quarterly and current reports, and our amendments to those reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings free of charge through our website, at www.peabodyenergy.com, or the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
  You may also request copies of our filings, free of charge, by telephone at (314) 342-3400 or by mail at: Peabody Energy Corporation, 701 Market Street, Suite 900, St. Louis, Missouri 63101, attention: Investor Relations.
  If a substantial portion of our long-term coal supply agreements terminate, our revenues and operating profits could suffer if we were unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts.
  Most of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. For the year ended December 31, 2006, 90% of our sales volume was sold under long-term coal supply agreements. At December 31, 2006, our coal supply agreements had remaining terms ranging from one to 19 years and an average volume-weighted remaining term of approximately 5 years.
  Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We may adjust these contract prices based on inflation or deflation and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. We sometimes experience a reduction in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements permit the customer to terminate the contract if transportation costs, which our customers typically bear, increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.
  The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Market prices for coal vary by mining region and country. As a result, we cannot predict the future strength of the coal market overall or by mining region and cannot assure you that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, one of our largest coal supply agreements is the subject of ongoing litigation and arbitration.
  The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
  For the year ended December 31, 2006, we derived 22% of our total coal revenues from sales to our five largest customers. At December 31, 2006, we had 123 coal supply agreements with these customers expiring at various times from 2007 to 2016. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and those customers may not continue to purchase coal from us under long-term coal supply agreements. If a number of these customers significantly reduce their purchases of coal from us, or if we are unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.
  If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer.
  Transportation costs represent a significant portion of the total cost of coal and the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs and the lack of sufficient rail and port capacity could lead to reduced coal sales. As of December 31, 2006, certain coal supply agreements, which account for less than 5% of our tons sold, permit the customer to terminate the contract if the cost of transportation increases by an amount over specified levels in any given 12-month period.
  Coal producers depend upon rail, barge, trucking, overland conveyor and ocean-going vessels to deliver coal to markets. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations. For example, two primary railroads serve the Powder River Basin mines. Due to the high volume of coal shipped from all Powder River Basin mines, the loss of access to rail capacity could create temporary congestion on the rail systems servicing that region. We are also susceptible to port congestion and demurrage fees. In Australia, we export our Queensland production from Dalrymple Bay Coal Terminal and the Ports of Gladstone and Brisbane. We export our New South Wales production from the Ports of Newcastle and Kembla.
  Risks inherent to mining could increase the cost of operating our business.
  Our mining operations are subject to conditions that can impact the safety of our workforce, or delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include fires and explosions from methane gas or coal dust; accidental minewater discharges; weather, flooding and natural disasters; unexpected maintenance problems; key equipment failures; variations in coal seam thickness; variations in the amount of rock and soil overlying the coal deposit; variations in rock and other natural materials and variations in geologic conditions. We maintain insurance policies that provide limited coverage for some of these risks, although there can be no assurance that these risks would be fully covered by our insurance policies. Despite our efforts, significant mine accidents could occur and have a substantial impact.
  Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations and developments could increase those costs or limit our ability to produce coal.
  Federal, state and local authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. Numerous governmental permits
  and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production. The possibility exists that new legislation and/or regulations and orders related to the environment or employee health and safety may be adopted and may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or judicial interpretations of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. The majority 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.
  According to the Department of Energy’s Energy Information Administration, “Emissions of Greenhouse Gases in the United States 2003,” coal accounts for 31% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. Legislation was introduced in Congress in 2006 to reduce greenhouse gas emissions in the United States. Such or similar federal legislative action could be taken in 2007 or later years (see additional discussion in Item 1 under the heading “Global Climate Change”). Further developments in connection with legislation, regulations or other limits on greenhouse emissions, both in the United States and in other countries where we sell coal, could have a material adverse effect on our financial condition or results of operations.
  A number of laws, including in the U.S. the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA” or “Superfund”), impose liability relating to contamination by hazardous substances. Such liability may involve the costs of investigating or remediating contamination and damages to natural resources, as well as claims seeking to recover for property damage or personal injury caused by hazardous substances. Such liability may arise from conditions at formerly as well as currently owned or operated properties, and at properties to which hazardous substances have been sent for treatment, disposal, or other handling. Liability under CERCLA and similar state statutes is without regard to fault, and typically is joint and several, meaning that a person may be held responsible for more than its share, or even all of, the liability involved. Our mining operations involve some use of hazardous materials. In addition, we have accrued for liability arising out of contamination associated with Gold Fields Mining, LLC (“Gold Fields”), a dormant, non-coal-producing subsidiary of ours that was previously managed and owned by Hanson PLC, or with Gold Fields’ former affiliates. A predecessor owner of ours, Hanson PLC transferred ownership of Gold Fields to us in the February 1997 spin-off of its energy business. Gold Fields is currently a defendant in several lawsuits and has received notices of several other potential claims arising out of lead contamination from mining and milling operations it conducted in northeastern Oklahoma. Gold Fields is also involved in investigating or remediating a number of other contaminated sites. Although we have accrued for many of these liabilities known to us, the amounts of other potential losses cannot be estimated. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than our accrual. Although we believe many of these liabilities are likely to be resolved without a material adverse effect on us, future developments, such as new information concerning areas known to be or suspected of being contaminated for which we may be responsible, the discovery of new contamination for which we may be responsible, or the inability to share costs with other parties that may be responsible for the contamination, could have a material adverse effect on our financial condition or results of operations.
  Our expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.
  We provide postretirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” which we estimate had a present value of $1.45 billion as of December 31, 2006, $82.6 million of which was a current liability. We have estimated these unfunded obligations based on assumptions described in the notes to our consolidated financial statements. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher. Moreover, regulatory changes could increase our obligations to provide these or additional benefits.
  We are party to an agreement with the Pension Benefit Guaranty Corporation (the “PBGC”) and TXU Europe Limited, an affiliate of our former parent corporation, under which we are required to make specified contributions to two of our defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If we or the PBGC give notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if we fail to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employment Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guaranty in place from TXU Europe Limited in favor of the PBGC before it draws on our letter of credit. On November 19, 2002, TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the United States) and continues under this process as of December 31, 2006.
  In addition, certain of our subsidiaries participate in two defined benefit multi-employer pension funds that were established as a result of collective bargaining with the UMWA pursuant to the National Bituminous Coal Wage Agreement as periodically negotiated. The UMWA 1950 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked prior to January 1, 1976. This is a closed group of beneficiaries with no new entrants. The UMWA 1974 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked after December 31, 1975. In December 2006, the 2007 National Bituminous Coal Wage Agreement was signed, which required funding of the 1974 Pension Plan through 2011 under a phased funding schedule. The funding is based on an hourly rate for certain UMWA workers. Under the labor contract, the per hour funding rate increased from zero to $2.00 in 2007 and increased each year thereafter until reaching $5.50 in 2011. Although our subsidiaries are not a party to that labor agreement, they are required to contribute to the 1974 Pension Plan at the new hourly rates. During 2006, represented employees subject to the new rate worked a total of approximately four million hours.
  Contributions to these funds could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to these funds, lower than expected returns on pension fund assets, higher medical and drug costs or other funding deficiencies.
  The United Mine Workers of America Combined Fund was created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of retirees including our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the 1992 law. No new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan created by the same federal law in 1992, provides benefits to qualifying retired former employees of bankrupt companies who have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers default in providing their former employees with retiree medical benefits, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Plan, was established
  through collective bargaining and provides benefits to qualifying retired former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business.
  The Surface Mining Control and Reclamation Act Amendments of 2006 (the “2006 Act”), which was enacted in December 2006, amended the federal laws establishing the Combined Fund, 1992 Benefit Plan and the 1993 Benefit Plan. Among other things, the 2006 Act guarantees full funding of all beneficiaries in the Combined Fund, provides funds on a phased-in basis for the 1992 Benefit Plan, and authorizes the trustees of the 1993 Benefit Plan to determine the contribution rates through 2010 for pre-2007 beneficiaries. The new and additional federal expenditures to the Combined Fund, 1992 Benefit Plan, 1993 Benefit Plan and certain Abandoned Mine Land payments to the states and Indian tribes are collectively limited by an aggregate annual cap of $490 million. To the extent that (i) the annual funding of the programs exceeds this amount (plus the amount of interest from the AML trust fund paid with respect to the Combined Benefit Fund), and (ii) Congress does not allocate additional funds to cover the shortfall, contributing employers and affiliates, including some of our subsidiaries, would be responsible for the additional costs.
  Based upon the enactment of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, we estimated future cash savings which allowed us to reduce our projected postretirement benefit obligations and related expense. Failure to achieve these assumed future savings under all benefit plans could adversely affect our financial condition, results of operations and cash flows.
  A decrease in the availability or increase in costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires could decrease our anticipated profitability.
  Our mining operations require a reliable supply of replacement parts, explosives, fuel, tires, steel-related products (including roof control) and lubricants. If the cost of any of these inputs increased significantly, or if a source for these supplies or mining equipment were unavailable to meet our replacement demands, our profitability could be reduced from our current expectations. Recent consolidation of suppliers of explosives has limited the number of sources for these materials, and our current supply of explosives is concentrated with one supplier. Further, our purchases of some items of underground mining equipment are concentrated with one principal supplier. Over the past few years, industry-wide demand growth has exceeded supply growth for certain surface and underground mining equipment and other capital equipment as well as off-the-road tires. As a result, lead times for some items have increased significantly.
  Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable.
  Our recoverable reserves decline as we produce coal. We have not yet applied for 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 future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties. The federal government also leases natural gas and coalbed methane reserves in the West, including in the Powder River Basin. Some of these natural gas and coalbed methane reserves are located on, or adjacent to, some of our Powder River Basin reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2006, we leased a total of 63,463 acres from the federal government. The limit could restrict
  our ability to lease additional federal lands. For additional discussion of our federal leases see Item 2. Properties.
  Our planned mine development projects and acquisition activities may not result in significant additional reserves, and we may not have continuing success developing additional mines. 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 are 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 cannot predict whether we will continue to receive the permits necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties, obtain mining contracts for properties containing additional reserves or maintain our leasehold interest in properties on which mining operations are not commenced during the term of the lease. From time to time, we have experienced litigation with lessors of our coal properties and with royalty holders.
  A decrease in the price or our production of metallurgical coal could decrease our anticipated profitability.
  We have annual capacity to produce approximately 15 to 18 million tons of metallurgical coal. Prices for metallurgical coal at the end of 2005 and during 2006 were near historically high levels. As a result, our margins from these sales have increased significantly, and represented a larger percentage of our overall revenues and profits and are expected to continue to favorably contribute in the future. To the extent we experience either production or transportation difficulties that impair our ability to ship metallurgical coal to our customers at anticipated levels, our profitability will be reduced in 2007.
  The majority of our 2007 metallurgical coal production will be priced during the first quarter of 2007; however, early indications are that prices will be down from historical highs. As a result, a decrease in metallurgical coal prices could decrease our profitability.
  Our financial performance could be adversely affected by our debt.
  Our financial performance could be affected by our indebtedness. As of December 31, 2006, our total indebtedness was $3.26 billion, and we had $1.29 billion of available borrowing capacity under our revolving credit facility. The indentures governing the convertible debentures and senior notes do not limit the amount of indebtedness that we may issue, and the indentures governing our other senior notes permit the incurrence of additional indebtedness.
  The degree to which we are leveraged could have important consequences, including, but not limited to:
  • making it more difficult for us to pay interest and satisfy our debt obligations;
  • 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 or other general corporate requirements;
  • 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 that, if not cured or waived, could have a material adverse effect on us.
  If our cash flows and capital resources are insufficient to fund our debt service obligations, 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. 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. The senior unsecured credit facility and indentures governing certain of our notes 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.
  The covenants in our senior unsecured credit facility and the indentures governing our senior notes and convertible debentures impose restrictions that may limit our operating and financial flexibility.
  Our senior unsecured credit facility, the indentures governing our senior notes and convertible debentures and the instruments governing our other indebtedness contain certain restrictions and covenants which restrict our ability to incur liens and debt or provide guarantees in respect of obligations of any other person. Under our senior unsecured credit facility, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio, as defined. The financial covenants also place limitations on our investments in joint ventures, unrestricted subsidiaries, indebtedness of non-loan parties and the imposition of liens on our assets. These covenants and restrictions are reasonable and customary and have not impacted our business in the past.
  Operating results below current levels or other adverse factors, including a significant increase in interest rates, could result in our inability to comply with the financial covenants contained in our senior unsecured credit facility. If we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may also cause us to take actions that are not favorable to holders of our other debt or equity securities and may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.
  Our operations could be adversely affected if we fail to appropriately secure our obligations.
  U.S. federal and state laws and Australian laws require us to secure certain of our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. The primary method for us to meet those obligations is to post a corporate guarantee (i.e. self bond), provide a third-party surety bond or provide a letter of credit. As of December 31, 2006, we had $685.2 million of self bonds in place primarily for our reclamation obligations. As of December 31, 2006, we also had outstanding surety bonds with third parties and letters of credit of $1.09 billion, of which $445.6 million was for post-mining reclamation, $188.5 million related to workers’ compensation obligations, $119.4 was for retiree healthcare obligations, $104.2 million was for coal lease obligations, and $236.0 million was for other obligations, including collateral for surety companies and bank guarantees, road maintenance, and performance guarantees. Surety bonds are typically renewable on a yearly basis. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. Letters of credit are subject to our successful renewal of our bank revolving credit facilities, which are currently set to expire in 2011. Our failure to maintain, or inability to acquire, surety bonds, or letters of credit, or to provide a suitable
  alternative would have a material adverse effect on us. 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;
  • restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures or senior unsecured credit facility;
  • the exercise by third-party surety bond issuers of their right to refuse to renew the surety; and
  • inability to renew our credit facility.
  Our ability to self bond reduces our costs of providing financial assurances. To the extent we are unable to maintain our current level of self bonding, due to legislative or regulatory changes or changes in our financial condition, our costs would increase.
  The conversion of our outstanding convertible debentures may result in the dilution of the ownership interests of our existing stockholders.
  If the conditions permitting the conversion of our convertible debentures are met and holders of the convertible debentures exercise their conversion rights, any conversion value in excess of the principal amount will be delivered in shares of our common stock. If any common stock is issued in connection with a conversion of our convertible debentures, our existing stockholders will experience dilution in the voting power of their common stock and earnings per share could be negatively impacted.
  Provisions of our convertible debentures could discourage an acquisition of us by a third-party.
  Certain provisions of our convertible debentures could make it more difficult or more expensive for a third-party to acquire us. Upon the occurrence of certain transactions constituting a “change of control” as defined in the indenture relating to our convertible debentures, holders of our convertible debentures will have the right, at their option, to convert their convertible debentures and thereby require us to pay the principal amount of such converted debentures in cash.
  An inability of contract miner or brokerage sources to fulfill the delivery terms of their contracts with us could reduce our profitability.
  In conducting our trading, brokerage and mining operations, we utilize third-party sources of coal production, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. In Australia, the majority of our mines utilize contract miners. Employee relations at mines that use contract miners is the responsibility of the contractor.
  Recently, certain of our brokerage sources and contract miners in the United States have experienced adverse geologic mining, escalated operating costs and/or financial difficulties that have made their delivery of coal to us at the contracted price difficult or uncertain. In some instances, the contract miners and third-party suppliers have suspended mining operations, and it has become increasing difficult to identify and retain contract workers. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon the reliability (including financial viability) and price of the third-party supply, our obligation to supply coal to customers in the event that adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market, and other factors.
  If the coal industry experiences overcapacity in the future, our profitability could be impaired.
  During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in production capacity in excess of market demand throughout the industry. Similarly, increases in future coal
  prices could encourage the development of expanded capacity by new or existing coal producers. Recently, the coal industry experienced lower demand as electricity usage was at lower than historical growth levels. Therefore, as of December 2006, total coal inventories of 130 to 140 million tons at generators were above the five-year average.
  We could be negatively affected if we fail to maintain satisfactory labor relations.
  As of December 31, 2006, we had approximately 9,200 employees. As of December 31, 2006, approximately 40% of our hourly employees were represented by unions and they generated approximately 14% of our 2006 coal production. Relations with our employees and, where applicable, organized labor are important to our success.
  Due to 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 competitors who operate without union labor 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.
  The Australian coal mining industry is unionized and the majority of workers employed at our Australian Mining Operations are members of trade unions. The Construction Forestry Mining and Energy Union represents our hourly production employees. As of December 31, 2006, our Australian hourly employees were approximately 9% or our hourly workforce and generated 2% of our total production in the year then ended. The labor agreement at our Wilkie Creek Mine was renewed in June 2006 and that agreement expires in June 2009. The North Goonyella Mine operates under an agreement due to expire in 2008, and the Metropolitan Mine operates under an agreement that expires in June 2007.
  Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.
  We manage our business with a number of key personnel, the loss of a number of whom 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. We cannot assure you that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. We do not have “key person” life insurance to cover our executive officers. Failure to retain or attract key personnel could have a material adverse effect on us.
  Due to the current demographics of our mining workforce, a high portion of our current hourly employees are eligible to retire over the next decade. Additionally, many of our mine sites are in more
  secluded areas of the United States, such as the Native American reservations of Arizona and the Southern Powder River Basin of Wyoming. These geographic locations provide limited pools of qualified resources, and it is challenging to locate resources interested in working in some of these regions. Failure to attract new employees to the mining workforce could have a material adverse effect on us.
  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 has changed with deregulation as utilities have sold their power plants to their non-regulated affiliates or third parties. These new power plant owners or other customers may have credit ratings that are below investment grade. If deterioration of the creditworthiness of our customers occurs, our $225.0 million accounts receivable securitization program and our business could be adversely affected.
  Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
  Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third-party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. For example, a change of control of our Company may be delayed or deterred as a result of the stockholders’ rights plan adopted by our Board of Directors. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.
  The extent to which we are able to successfully integrate the newly acquired Excel operations and successfully complete the development of the new mine sites acquired from Excel will have a bearing on our future financial results.
  The process of integrating the operations of the Excel coal mines could cause an interruption of, or loss of momentum in, the activities of the business or the development of new mines. We will need to make significant capital expenditures to utilize and maintain the assets we acquired in the Excel acquisition. There are currently three development-stage mines, two of which are scheduled to begin production in early 2007. Delays in optimizing the operations of the development-stage mines, and to a lesser extent the existing Excel operations, could impact our future financial results. Additionally, our ability to integrate and manage the Excel operations will have a direct bearing on the realization of anticipated cost savings and synergies. Further, we may encounter unanticipated risks associated with the Excel acquisition.
  Growth in our global operations increases our risks unique to international mining and trading operations.
  We currently have international mining operations in Australia and Venezuela. We have recently opened a business development, sales and marketing office in Beijing, China and an international trading group in our trading and brokerage operations. The international expansion of our operations increases our exposure to country and currency risks. Some of our international activities include expansion into developing countries where business practices and counterparty reputations may not be as well developed as in our domestic or Australian operations. We are also challenged by political risks, including expropriation and the inability to repatriate earnings on our investment. In particular, the Venezuelan government has suggested its desire to increase government ownership in Venezuelan energy assets and natural resources. Actions to nationalize Venezuelan coal properties could be detrimental to our investments in the Paso Diablo Mine and Cosila development project. During 2006, the Paso Diablo Mine contributed $28.0 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA”
  (see Item 7) and paid a dividend of $18.2 million. At December 31, 2006, our investment in Paso Diablo was $60.1 million, recorded in “Investment and other assets” on the consolidated balance sheet.
  As we continue to pursue development of Generation Development and Btu Conversion activities, we face challenges and risks that differ from those in our mining business.
  We continue to pursue the development of coal-fueled generating projects in the U.S., including mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal sales. The projects we are currently pursuing include the 1,600 plus-megawatt Prairie State Energy Campus in Washington County, Illinois and the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky. We also continue to pursue opportunities to participate in technologies to economically convert our coal resources to natural gas and liquids, such as diesel fuel, gasoline and jet fuel (Btu conversion).
  As we move forward with all of these projects, we are exposed to risks related to the performance of our partners, securing required financing, obtaining necessary permits, meeting stringent regulatory laws, maintaining strong supplier relationships and managing (along with our partners) large projects, including managing through long lead times for ordering and obtaining capital equipment. Our work in new or recently commercialized technologies could expose us to unanticipated risks, evolving legislation and uncertainty regarding the extent of future government support and funding.
  The extent of our success in converting our current information systems to our new enterprise resource planning system will directly impact our ability to perform functions critical to our day-to-day business.
  To support the continued growth and globalization of our businesses, we are converting our existing information systems across major business processes to an integrated information technology system provided by SAP AG. The project began in the first quarter of 2006 and certain phases of implementation are expected to be completed in 2007. The successful conversion of our information technology systems will have direct bearing on our ability to perform certain day-to-day functions critical to our business, including billing, processing invoices, certain Treasury functions, recordkeeping and financial reporting.
  Item 1B. Unresolved Staff Comments.
  Item 2. Properties.
  Coal Reserves
  We had an estimated 10.2 billion tons of proven and probable coal reserves as of December 31, 2006. An estimated 9.4 billion tons of our proven and probable coal reserves are in the United States and 0.8 billion tons are in Australia. Forty-three percent of our reserves, or 4.4 billion tons, are compliance coal and 57% are non-compliance coal. We own approximately 42% of these reserves and lease property containing the remaining 58%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
  Below is a table summarizing the locations and reserves of our major operating regions.
  Proven and Probable
  Reserves as of
  December 31, 2006(1)
  Owned Leased Total
  Operating Regions Locations Tons Tons Tons
  (Tons in millions)
  Illinois, Indiana and Kentucky 3,270 900 4,170
  Powder River Basin
  Wyoming and Montana 67 3,400 3,467
  Arizona and New Mexico 617 363 980
  West Virginia and Ohio 249 306 555
  Colorado 43 184 227
  Total United States
  New South Wales — 466 466
  Queensland — 337 337
  Total Proven and Probable Coal Reserves
  (1) Reserves have been adjusted to take into account estimated losses involved in producing a saleable product.
  Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:
  Proven (Measured) 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 close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
  Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) 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 (measured) reserves, is high enough to assume continuity between points of observation.
  Our estimates of proven and probable coal reserves are established within these guidelines. Proven reserves require the coal to lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas. Estimates of probable reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density. Active surface reserves generally have points of observation as close as 330 feet to 660 feet.
  Our reserve estimates are prepared by our staff of geologists, whose experience ranges from 10 to 30 years. We also have a chief geologist of reserve reporting whose primary responsibility is to track changes in reserve estimates, supervise our other geologists and coordinate periodic third-party reviews of our reserve estimates by qualified mining consultants.
  Our reserve estimates are predicated on information obtained from our ongoing drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the
  quality of the coal are determined. The density of the drill pattern determines whether the reserves will be classified as proven or probable. The reserve estimates are then input into our computerized land management system, which overlays the geological data with data on ownership or control of the mineral and surface interests to determine the extent of our reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserves and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.
  Our estimate of the economic recoverability of our reserves is based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to existing market prices for the quality of coal expected to be mined and taking into consideration typical contractual sales agreements for the region and product. Where possible, we also review production by competitors in similar mining areas. Only reserves expected to be mined economically are included in our reserve estimates. Finally, our reserve estimates include reductions for recoverability factors to estimate a saleable product.
  We periodically engage independent mining and geological consultants to review estimates of our coal reserves. The most recent of these audits, which was completed in January 2007, included a review of the procedures used by us to prepare our internal estimates, verification of the accuracy of selected property reserve estimates and retabulation of reserve groups according to standard classifications of reliability. This audit confirmed that we controlled approximately 10.2 billion tons of proven and probable reserves as of December 31, 2006.
  With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification. On a regional basis, the expected degree of variance from reserve estimate to tons produced is lower in the Powder River Basin, Southwest and Illinois Basin due to the continuity of the coal seams as confirmed by the mining history. Appalachia, however, has a higher degree of risk due to the mountainous nature of the topography which makes exploration drilling more difficult. Our recovered reserves in Appalachia are less predictable and may vary by an additional one to two percent above the threshold discussed above.
  We have numerous federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2006, we leased 11,103 acres of federal land in Colorado, 11,254 acres in Montana and 41,106 acres in Wyoming, for a total of 63,463 nationwide.
  Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 65,000 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments.
  Private coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to
  the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease bonus 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. With a portfolio of approximately 10.2 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our significant reserve holdings is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.
  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.
  The following chart provides a summary, by mining complex, of production for the years ended December 31, 2006 and 2005 and 2004, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities.
  PRODUCTION AND ASSIGNED RESERVES(1)
  Sulfur Content(2) As of December 31, 2006
  <1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. As Assigned
  Year Ended Year Ended Year Ended sulfur dioxide sulfur dioxide sulfur dioxide Received Proven and
  Geographic Region/Mining Dec. 31, Dec. 31, Dec. 31, Type of per per per Btu per Probable
  Complex 2006 2005 2004 Coal Million Btu Million Btu Million Btu pound(3) Reserves Owned Leased Surface Underground
  Appalachia:
  4.6 4.1 4.9 Steam — — 31 13,300 31 11 20 — 31
  2.0 1.9 1.9 Steam 4 30 — 12,300 34 — 34 — 34
  Kanawha Eagle(4)
  1.9 — — Steam/Met. 31 22 — 13,100 53 — 53 — 53
  1.6 2.0 3.0 Steam/Met. 5 3 — 13,800 8 — 8 — 8
  Rocklick
  2.2 2.6 2.0 Steam/Met. 5 7 1 13,100 13 — 13 3 10
  2.3 2.6 2.6 Steam/Met. 20 29 — 12,800 49 — 49 — 49
  14.6 13.2 14.4 65 91 32 188 11 177 3 185
  Midwest:
  3.9 4.2 4.1 Steam — — 41 10,800 41 4 37 3 38
  2.2 2.1 1.8 Steam — 25 33 10,700 58 5 53 — 58
  Riola/ Vermilion Grove
  1.7 2.3 2.3 Steam — — 19 10,500 19 — 19 — 19
  Miller Creek
  1.6 1.0 0.9 Steam — 2 28 10,000 30 29 1 30 —
  Francisco Surface
  2.0 1.8 2.1 Steam — — 6 10,500 6 2 4 6 —
  Francisco Underground
  1.1 1.2 0.9 Steam — — 22 10,600 22 3 18 — 22
  Farmersburg
  3.8 3.8 4.2 Steam 1 11 95 10,300 107 93 14 107 —
  Somerville Central
  Somerville — North
  Somerville — South
  2.5 2.4 2.0 Steam — — 14 10,000 14 8 6 14 —
  1.5 1.5 1.5 Steam — 1 7 10,700 8 — 8 8 —
  Wildcat Hills Surface/Underground
  Willow Lake
  2.6 0.5 — Steam — — 20 10,300 20 20 — — 20
  Dodge Hill
  1.1 1.2 1.2 Steam — — 8 11,100 8 3 5 — 8
  39.6 37.9 35.6 1 39 466 506 259 247 189 317
  Powder River Basin:
  North Antelope/ Rochelle
  88.6 82.7 82.5 Steam 1,171 — — 8,800 1,171 — 1,171 1,171 —
  32.8 30.5 26.5 Steam 787 122 22 8,600 931 — 931 931 —
  17.0 12.4 6.9 Steam 290 62 55 8,600 407 — 407 407 —
  138.4 125.6 115.9 2,248 184 77 2,509 — 2,509 2,509 —
  Southwest/ Colorado:
  — 3.9 4.8 Steam 10 1 — 10,600 11 — 11 11 —
  8.2 8.2 8.2 Steam 185 82 3 11,000 270 — 270 270 —
  Lee Ranch
  5.5 5.3 5.8 Steam 20 123 12 10,000 155 88 67 155 —
  Twentymile
  8.6 9.4 6.4 Steam 73 — — 10,800 73 14 59 — 73
  — 1.1 1.5 Steam — — — NA — — — — —
  22.3 27.9 26.7 288 206 15 509 102 407 436 73
  North Goonyella/ Eaglefield
  2.2 2.1 1.7 Met. 48 — — 12,800 48 — 48 2 46
  0.4 — — Met. 40 — — 12,700 40 — 40 — 40
  Wilkie Creek
  2.0 1.9 1.4 Steam 223 — — 10,800 223 — 223 223 —
  Chain Valley (80.0%)(5)
  0.2 — — Steam 17 — — 11,900 17 — 17 — 17
  Wambo Open Cut(4)
  1.2 — — Steam 106 — — 12,400 106 — 106 106 —
  Burton (95.0%)(5)
  4.3 4.4 3.2 Steam/Met. 38 — — 12,400 38 — 38 38 —
  Baralaba(4)
  0.2 — — Steam/Met. — 2 — 12,200 2 — 2 2 —
  Wilpinjong
  0.3 — — Steam — 165 — 9,900 165 — 165 165 —
  Millennium(4)
  0.1 — — Met. 26 — — 12,800 26 — 26 26 —
  10.9 8.4 6.3 498 167 — 665 — 665 562 103
  225.8 213.0 198.9 4,377 4,377 4,377 4,377 4,377 4,377 4,377 4,377
  The following chart provides a summary of the amount of our proven and probable coal reserves in each U.S. state and Australia state, the predominant type of coal mined in the applicable location, our property interest in the reserves and other characteristics of the facilities.
  ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES
  As of December 31, 2006
  Sulfur Content(2)
  <1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. As
  Total Tons Proven and sulfur dioxide sulfur dioxide sulfur dioxide Received Reserve Control Mining Method
  Probable Type of per per per Btu per
  Coal Seam Location Assigned Unassigned Reserves(6) Proven Probable Coal Million Btu Million Btu Million Btu pound(3) Owned Leased Surface Underground
  — 25 25 19 6 Steam — — 25 11,300 25 — — 25
  188 342 530 310 220 Steam/Met. 141 190 199 13,000 224 306 15 515
  188 367 555 329 226 141 190 224 249 306 15 540
  113 2,292 2,405 1,190 1,215 Steam 5 38 2,362 10,400 2,195 210 78 2,327
  255 353 608 410 198 Steam 1 40 567 10,300 402 206 258 350
  138 1,019 1,157 622 535 Steam — 1 1,156 10,800 673 484 105 1,052
  506 3,664 4,170 2,222 1,948 6 79 4,085 3,270 900 441 3,729
  — 162 162 158 4 Steam 15 117 30 8,600 67 95 162 —
  2,509 796 3,305 3,226 79 Steam 3,020 183 102 8,700 — 3,305 3,305 —
  2,509 958 3,467 3,384 83 3,035 300 132 67 3,400 3,467 —
  281 — 281 281 — Steam 195 83 3 10,900 — 281 281 —
  73 154 227 165 62 Steam 139 — 88 10,600 43 184 — 227
  155 544 699 636 63 Steam 91 344 264 9,200 617 82 699 —
  509 698 1,207 1,082 125 425 427 355 660 547 980 227
  328 138 466 253 213 Steam/Met. 466 — — 12,400 — 466 271 195
  337 — 337 104 233 Steam/Met. 335 2 — 11,200 — 337 291 46
  665 138 803 357 446 801 2 — — 803 562 241
  Total Proven and Probable
  10,202 10,202 10,202 10,202 10,202 4,408 998 4,796 10,202 10,202 10,202 10,202
  (1) Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2006. Unassigned reserves represent coal at suspended locations and coal that has not been committed. These reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property.
  (2) Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.
  (3) As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The following table reflects the average moisture content used in the determination of as-received Btu by region:
  Missouri/ Oklahoma
  (4) These joint ventures are consolidated in our results and their proven and probable coal reserves are reflected at 100%. Our effective percentage interest in each operation is as follows: Kanawha Eagle — 73.9%; Wambo Open-Cut — 75.0%; Baralaba — 62.5% and Millennium — 84.6%.
  (5) Proven and probable coal reserves for these joint ventures reflect our proportional ownership as indicated parenthetically.
  (6) Proven and probable reserves exclude approximately 30 million tons located in Zulia State, Venezuela, related to the Las Carmelitas Project, which is held through our 51% interest in Excelven Pty Ltd.
  From time to time, we or our subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. We believe we have recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on our financial condition, results of operations or cash flows. We discuss our significant legal proceedings below.
  Litigation Relating to Continuing Operations
  Navajo Nation Litigation
  On June 18, 1999, the Navajo Nation served three of our subsidiaries, including Peabody Western Coal Company (“Peabody Western”), with a complaint that had been filed in the U.S. District Court for the District of Columbia. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act (“RICO”) violations and fraud. The complaint alleges that the defendants
  jointly participated in unlawful activity to obtain favorable coal lease amendments. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases have terminated due to Peabody Western’s breach of these leases and a reformation of these leases to adjust the royalty rate to 20%. Subsequently, the court allowed the Hopi Tribe to intervene in this lawsuit and the Hopi Tribe is also seeking unspecified actual damages, punitive damages and reformation of its coal lease. On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States rejecting the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments. On February 9, 2005, the U.S. District Court for the District of Columbia granted a consent motion to stay the litigation until further order of the court. Peabody Western, the Navajo Nation, the Hopi Tribe and the owners of the power plants served by the suspended Black Mesa mine and the Kayenta mine are in mediation with respect to this litigation and other business issues.
  The outcome of this litigation, or the current mediation, is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
  Salt River Project Agricultural Improvement and Power District — Mine Closing and Retiree Health Care
  Salt River Project and the other owners of the Navajo Generating Station filed a lawsuit on September 27, 1996, in the Superior Court of Maricopa County in Arizona seeking a declaratory judgment that certain costs relating to final reclamation, environmental monitoring work and mine decommissioning and costs primarily relating to retiree health care benefits are not recoverable by our subsidiary, Peabody Western, under the terms of a coal supply agreement dated February 18, 1977. The contract expires in 2011. The trial court subsequently ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. We have recorded a receivable for mine decommissioning costs of $76.8 million and $74.2 million included in “Investments and other assets” in the consolidated balance sheets as of December 31, 2006 and 2005, respectively.
  The outcome of this litigation and arbitration is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
  Gulf Power Company Litigation
  On June 21, 2006, our subsidiary filed a complaint in the U.S. District Court, Southern District of Illinois, seeking a declaratory judgment upholding its declaration of a permanent force majeure under a coal supply agreement with Gulf Power Company. On June 22, 2006, Gulf Power Company filed a breach of contract lawsuit against our subsidiary in the U.S. District Court, Northern District of Florida, contesting the force majeure declaration and seeking damages for alleged past and future tonnage shortfalls of nearly 5 million tons under the coal supply agreement, which would have expired on December 31, 2007. The parties have filed motions to determine which court will hear the lawsuits. On October 6, 2006, the Florida District Court stayed Gulf Power’s lawsuit until the Illinois court decides whether it has jurisdiction.
  The outcome of this litigation is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot reasonably be estimated. However, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
  Claims and Litigation relating to Indemnities or Historical Operations
  Citizens Power
  In connection with the August 2000 sale of our former subsidiary, Citizens Power LLC (“Citizens Power”), we have indemnified the buyer, Edison Mission Energy, from certain losses resulting from specified power contracts and guarantees. During the period that Citizens Power was owned by us, Citizens Power guaranteed the obligations of two affiliates to make payments to third parties for power delivered under fixed-priced power sales agreements with terms that extend through 2008. Edison Mission Energy has stated and we believe there will be sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. There is no pending litigation with respect to these indemnities at this time.
  Oklahoma Lead Litigation
  Gold Fields Mining, LLC (“Gold Fields”) is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, our predecessor owner. In a February 1997 spin-off, Hanson PLC transferred ownership of Gold Fields to us, despite the fact that Gold Fields had no ongoing operations and we had no prior involvement in its past operations. Today Gold Fields is one of our subsidiaries. We indemnified TXU Group with respect to certain claims relating to a former affiliate of Gold Fields. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950s and mined, in accordance with lease agreements and permits, approximately 0.15% of the total amount of the crude ore mined in the county.
  Gold Fields and two other companies are defendants in two class action lawsuits. The plaintiffs have asserted claims predicated on allegations of intentional lead exposure by the defendants and are seeking compensatory damages, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. Gold Fields is also a defendant, along with other companies, in several personal injury lawsuits involving over 50 children, arising out of the same lead mill operations. Plaintiffs in these actions are seeking compensatory and punitive damages for alleged personal injuries from lead exposure. The first personal injury trial has been scheduled for March 2007 and Gold Fields along with the former affiliate will be the only defendants. In December 2003, the Quapaw Indian tribe and certain Quapaw land owners filed a class action lawsuit against Gold Fields and five other companies. The plaintiffs are seeking compensatory and punitive damages based on a variety of theories. Gold Fields has filed a third-party complaint against the United States, and other parties. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other companies regarding a possible natural resources damage claim. All of the lawsuits are pending in the U.S. District Court for the Northern District of Oklahoma.
  The outcome of litigation and these claims are subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
  Environmental Claims and Litigation
  We are subject to applicable federal, state and local environmental laws and regulations in those countries where we conduct operations. Current and past mining operations in the United States are primarily covered by the Surface Mining Control and Reclamation Act of 1977, the Clean Water Act and the Clean Air Act but also include the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA” or “Superfund”), the Superfund Amendments and Reauthorization Act of 1986 and the Resource Conservation and Recovery Act of 1976. Superfund and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under that legislation and many state Superfund statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These regulations could require us to do some or all of the
  following: (i) remove or mitigate the effects on the environment at various sites from the disposal or release of certain substances; (ii) perform remediation work at such sites; and (iii) pay damages for loss of use and non-use values.
  Our policy is to accrue environmental cleanup-related costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures requires an assessment of many factors, including the nature and extent of contamination, the timing, extent and method of the remedial action, changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. We also assess the financial capability and proportional share of costs of other PRPs and, where allegations are based on tentative findings, the reasonableness of our apportionment. We have not anticipated any recoveries from insurance carriers in the estimation of liabilities recorded in our consolidated balance sheets.
  Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of Superfund and similar legislation and are generally covered by the Surface Mining Control and Reclamation Act of 1977, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed by the Superfund statute. Thus, coal mines currently or previously owned or operated by us, and sites to which we have sent waste materials, may be subject to liability under Superfund and similar state laws.
  Environmental claims have been asserted against Gold Fields related to activities of Gold Fields or a former affiliate. Gold Fields or the former affiliate has been named a potentially responsible party (“PRP”) based on CERCLA at five sites, and claims have been asserted at 18 other sites. The number of PRP sites in and of itself is not a relevant measure of liability, because the nature and extent of environmental concerns varies by site, as does the estimated share of responsibility for Gold Fields or the former affiliate. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above were $43.0 million as of December 31, 2006 and $42.5 million as of December 31, 2005, $14.4 million and $23.6 million of which was reflected as a current liability, respectively. These amounts represent those costs that we believe are probable and reasonably estimable. In September 2005, Gold Fields and other PRPs received a letter from the U.S. Department of Justice alleging that the PRPs’ mining operations caused the Environmental Protection Agency (“EPA”) to incur approximately $125 million in residential yard remediation costs at Picher, Oklahoma and will cause the EPA to incur additional remediation costs relating to historical mining sites. Gold Fields has participated in the ongoing settlement discussions. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950s and mined, in accordance with lease agreements and permits, approximately 0.15% of the total amount of the crude ore mined in the county. Gold Fields believes it has meritorious defenses to these claims. Gold Fields is involved in other litigation in the Picher area, and we indemnified TXU Group with respect to a defendant as is more fully discussed under the “Oklahoma Lead Litigation” caption above. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than this provision.
  In addition, at times we become a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. Management believes that the ultimate resolution of such other pending or threatened proceedings is not reasonably likely to have a material adverse effect on our financial position, results of operations or liquidity.
  Item 4. Submission of Matters to a Vote of Security Holders.
  No matters were submitted to a vote of security holders during the quarter ended December 31, 2006.
  Executive Officers of the Company
  Set forth below are the names, ages as of February 16, 2007 and current positions of our executive officers. Executive officers are appointed by, and hold office at, the discretion of our Board of Directors.
  Name Age Position
  Gregory H. Boyce
  52 President and Chief Executive Officer, Director
  Sharon D. Fiehler
  50 Executive Vice President — Human Resources and Administration
  Richard A. Navarre
  46 Chief Financial Officer and Executive Vice President of Corporate Development
  Alexander C. Schoch
  52 Executive Vice President Law and Chief Legal Officer
  Roger B. Walcott, Jr.
  50 Executive Vice President — Strategy and Business Services
  Richard M. Whiting
  52 Executive Vice President and Chief Marketing Officer
  Rick Bowen
  51 President, Generation and Btu Conversion
  Ian S. Craig
  53 Managing Director — Australia Operations
  Jiri Nemec
  50 Group Vice President — U.S. Eastern Operations
  Kemal Williamson
  47 Group Vice President — U.S. Western Operations
  Gregory H. Boyce has been a director of the Company since March 2005. Mr. Boyce was named Chief Executive Officer Elect of the Company in March 2005, and assumed the position of Chief Executive Officer in January 2006. He also serves as President of the Company, a position he has held since October 2003. He was Chief Operating Officer of the Company from October 2003 to December 2005. He previously served as Chief Executive — Energy of Rio Tinto plc (an international natural resource company) from 2000 to 2003. Other prior positions include President and Chief Executive Officer of Kennecott Energy Company from 1994 to 1999 and President of Kennecott Minerals Company from 1993 to 1994. He has extensive engineering and operating experience with Kennecott and also served as Executive Assistant to the Vice Chairman of Standard Oil of Ohio from 1983 to 1984. Mr. Boyce is Co-Chairman of the Coal Based Generation Stakeholders Group, and a member of the Coal Industry Advisory Board of the International Energy Agency, the Advisory Council of the University of Arizona’s Department of Mining and Geological Engineering and the National Council of the School of Engineering and Applied Science at Washington University in St. Louis. He is a board member of the Center for Energy and Economic Development, the National Mining Association and the National Coal Council, and a past board member of the Western Regional Council, Mountain States Employers Council and Wyoming Business Council.
  Sharon D. Fiehler has been our Executive Vice President of Human Resources and Administration since April 2002, with executive responsibility for employee development, benefits, compensation, employee relations, affirmative action programs, information services, flight services and facilities management. She joined us in 1981 as Manager — Salary Administration and has held a series of employee relations, compensation and salaried benefits positions. Ms. Fiehler holds degrees in social work and psychology and an MBA, and prior to joining Peabody was a personnel representative for Ford Motor Company. Ms. Fiehler is a member of the Executive Committee and Board of Directors of Junior Achievement of St. Louis and a Board member of the Chancellor’s Council of the University of Missouri at St. Louis. She is also a member of the Women’s Advisory Council of the University of Missouri at St. Louis Executive Leadership Institute and the St. Louis Women’s Forum.
  Richard A. Navarre is our Chief Financial Officer and Executive Vice President of Corporate Development. He has served as Chief Financial Officer since October 1999. He also previously served as President of Peabody’s COALSALES, LLC affiliate, President of Peabody Energy Solutions, Inc., Vice President of Finance and Vice President and Controller. He joined our predecessor company in 1993. Prior to joining us, Mr. Navarre was a senior manager with KPMG Peat Marwick. Mr. Navarre is former Chairman of the Bituminous Coal Operators’ Association. He serves on the Board of Advisors to the College of Business for Southern Illinois University at Carbondale and is a member of the International Business Advisory Board, University of Missouri-St. Louis, College of Business Administration. He is a member of Financial Executives International. Mr. Navarre is on the Board of Directors of the Missouri Historical Society.
  Alexander C. Schoch was named our Executive Vice President Law and Chief Legal Officer in October 2006, with responsibility for all of our legal and corporate secretary functions. Prior to joining us, Mr. Schoch served as Vice President and General Counsel for Emerson Process Management, an operating segment of Emerson Electric Company and leading supplier of process-automation products. Mr. Schoch also served in several legal positions with Goodrich Corporation, a global supplier to the aerospace and defense industries, from 1987 to 2004, including Vice President, Associate General Counsel and Secretary. Prior to that, he worked for Marathon Oil Company as an attorney in its international exploration and production division. Mr. Schoch holds a Juris Doctorate from Case Western Reserve University in Ohio, as well as a Bachelor of Arts in Economics from Kenyon College in Ohio. He is admitted to practice law in several states, and is a member of the American and International Bar Associations.
  Roger B. Walcott, Jr. became Executive Vice President — Strategy and Business Services in May 2006. Prior to that he was our Executive Vice President — Resource Management and Strategic Planning since July 2005 and our Executive Vice President — Corporate Development since February 2001. He joined us in June 1998 as Executive Vice President. From 1987 to 1998, he was a Senior Vice President and a director with The Boston Consulting Group, where he served a variety of clients in strategy and operational assignments. He joined Boston Consulting Group in 1981, and was Chairman of The Boston Consulting Group’s Human Resource Capabilities Committee. Mr. Walcott holds a MBA with high distinction from the Harvard Business School.
  Richard M. Whiting became Executive Vice President and Chief Marketing Officer in May 2006. Prior to that he was our Executive Vice President — Sales, Marketing and Trading since October 2002. Previously, Mr. Whiting served as our President and Chief Operating Officer and President of Peabody’s COALSALES, LLC affiliate. He joined our predecessor company in 1976 and has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Mr. Whiting is the former Chairman of the National Mining Association’s Safety and Health Committee, the former Chairman of the Bituminous Coal Operators’ Association, a past board member of the National Coal Council and is a member of the Visiting Committee of West Virginia University College of Engineering and Mineral Resources.
  Rick Bowen became President of Generation and Btu Conversion in July 2006, with responsibility for project and business development for planned electric generating initiatives and projects for technologies to transform the energy in coal into other high-demand energy forms. He joined us in September 2004 as Corporate Senior Vice President and President of Generation. Prior to joining us, Mr. Bowen served for 20 years with Dynegy Inc. and its predecessor companies. Mr. Bowen is a member of the Board of Directors of the Western Electric Coordinating Council and the Industry Advisory Board, Consortium for Electric Reliability Technology Solutions. He holds a Bachelor of Science in Business Administration and a Master of Business Administration from the University of Houston.
  Ian S. Craig was named our Managing Director — Australia Operations in September 2004. From May 2004 to August 2004, Mr. Craig served as Group Executive — Technical Services. He was Group Executive — Powder River Basin Operations from July 2001 to April 2004. Prior to that, he was Managing Director of a former Peabody subsidiary in Australia. Mr. Craig also held a number of management
  positions within the subsidiary company and other Australian mining organizations. He holds a Bachelor of Applied Science Degree in Mineral Engineering from the South Australian Institute of Technology. Mr. Craig is a Fellow of The Australasian Institute of Mining and Metallurgy.
  Jiri Nemec has been our Group Vice President — U.S. Eastern Operations since July 2005. Previously, Mr. Nemec was Group Executive of Appalachia and Highland Operations from April 2004 to July 2005; Appalachia Operations from January 2001 to April 2004; Midwest Operations from August 1999 to January 2001; and Northern Appalachia Operations from July 1998 to August 1999. He has extensive experience in mining engineering and operations, primarily with a Peabody subsidiary in West Virginia. He holds a Bachelor of Science Degree in Engineering from Pennsylvania State University and an MBA from Washington University.
  Kemal Williamson became our Group Vice President — U.S. Western Operations in July 2005. After joining us in September 2000, Mr. Williamson served as Group Executive — Midwest Operations until April 2004, and then was Group Executive — Powder River Basin Operations until July 2005. He has extensive mining engineering and operations experience in the United States and Australia. Mr. Williamson holds a Bachelor of Science Degree in Mining Engineering from Pennsylvania State University and an MBA from Kellogg Graduate School of Management, Northwestern University.
  Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
  Our common stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 16, 2007, there were 952 holders of record of our common stock.
  The table below sets forth the range of quarterly high and low sales prices for our common stock (after giving retroactive effect to the two-for-one stock split effective February 22, 2006) on the New York Stock Exchange during the calendar quarters indicated.
  The quarterly dividend rate for Common Stock was increased 26% by the Board of Directors to $0.06 per share (from $0.0475 per share) on January 23, 2006, when a dividend of $0.06 per share was declared on Common Stock, payable on February 22, 2006, to stockholders of record on February 7, 2006. We paid quarterly dividends totaling $0.24 per share during the year ended December 31, 2006, and $0.17 per share during the year ended December 31, 2005. Most recently, our Board of Directors declared a dividend of $0.06 per share of Common Stock on January 23, 2007, payable on February 27, 2007, to stockholders of record on February 6, 2007. The declaration and payment of dividends and the amount of dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt instruments and other factors deemed relevant by our Board of
  Directors; however, we presently expect that dividends will continue to be paid. Limitations on our ability to pay dividends imposed by our debt instruments are discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
  On February 22, 2006, we effected a two-for-one stock split on all shares of our common stock. Shareholders of record at the close of business on February 7, 2006, received a dividend of one share of stock for every share held. The stock began trading ex-split on February 23, 2006. On March 30, 2005, we effected a two-for-one stock split on all shares of our common stock. Shareholders of record at the close of business on March 16, 2005 received a dividend of one share of stock for every share held. The stock began trading ex-split on March 31, 2005. All share and per share amounts in this Annual Report on Form 10-K reflect both two-for-one stock splits.
  Share Repurchase Program
  In July 2005, our Board of Directors authorized a share repurchase program of up to 5% of the then outstanding shares of our common stock, approximately 13.1 million shares. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. As of December 31, 2006, there were approximately 10.9 million shares available for repurchase. There were no share repurchases made in the three months ended December 31, 2006.
  Stock Performance Graph
  The following performance graph compares the cumulative total return on our common stock with the cumulative total return of the following indices: (i) the S&P© 400 MidCap Stock Index; (ii) the S&P© 500 Stock Index; (iii) a peer group comprised of Arch Coal Inc., Massey Energy Company, CONSOL Energy, Inc. and Westmoreland Coal Company (“Peer Group 1”) and (iv) a peer group comprised of Arch Coal Inc., Massey Energy Company, CONSOL Energy, Inc., Foundation Coal Holdings Inc., Alpha Natural Resources, Inc. and International Coal Group, Inc. (“Peer Group 2”). The companies included in Peer Group 2 are listed in the Bloomberg U.S. Coal Index as of December 31, 2006. In November 2006, we were added to the S&P© 500 Stock Index and we have accordingly changed our equity market index to the S&P© 500 Stock Index from the S&P© 400 MidCap Stock Index. The graph assumes that the value of the investment in our common stock and each index was $100 at December 31, 2001. The graph also assumes that all dividends were reinvested and that investments were held through December 31, 2006. These indices are included for comparative purposes only and do not necessarily reflect management’s opinion that such indices are an appropriate measure of the relative performance of the stock involved, and are not intended to forecast or be indicative of possible future performance of the common stock.
  Dec-01 Dec-02 Dec-03 Dec-04 Dec-05 Dec-06
  $ 100 $ 105 $ 153 $ 299 $ 614 $ 605
  S&P© 500 Stock Index
  $ 100 $ 78 $ 100 $ 111 $ 117 $ 135
  S&P© MidCap 400 Stock Index
  Peer Group 1
  Item 6. Selected Financial Data.
  The following table presents selected financial and other data about us for the most recent five fiscal years. The following table and the discussion of our results of operations in 2006 and 2005 in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations includes references to, and analysis of, our Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization.
  Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.
  In October 2006, we acquired Excel Coal Limited and our results of operations for the year ended December 31, 2006 included the results of operations of the three operating mines and three development-stage mines in New South Wales, Australia and Queensland, Australia from the date of acquisition.
  On April 15, 2004, we acquired three coal operations from RAG Coal International AG. Our results of operations for the year ended December 31, 2004 include the results of operations of the two mines in Queensland, Australia and the results of operations of the Twentymile Mine in Colorado from the April 15, 2004 purchase date.
  Results of operations for the year ended December 31, 2003 include early debt extinguishment costs of $53.5 million pursuant to our debt refinancing in the first half of 2003. In addition, results included expense relating to the cumulative effect of accounting changes, net of income taxes, of $10.1 million. This amount represents the aggregate amount of the recognition of accounting changes pursuant to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations,” the change in method of amortization of actuarial gains and losses related to net periodic postretirement benefit costs and the effect of the rescission of Emerging Issues Task Force No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.”
  We have derived the selected historical financial data as of and for the years ended December 31, 2006, 2005, 2004, 2003 and 2002 from our audited financial statements. All share and per share amounts included in the following consolidated financial data have been retroactively adjusted to reflect the two-for-one stock splits, effective February 22, 2006, and March 30, 2005. You should read the following table in conjunction with the financial statements, the related notes to those financial statements and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
  The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, the Risk Factors section of Item 1A of this report includes a discussion of risk factors that could impact our future results of operations.
  (Dollars in thousands, except share and per share data)
  Results of Operations Data
  $ 5,144,925 $ 4,545,323 $ 3,545,027 $ 2,729,323 $ 2,630,371
  111,390 99,130 86,555 85,973 89,267
  5,256,315 4,644,453 3,631,582 2,815,296 2,719,638
  Operating costs and expenses
  377,210 316,114 270,159 234,336 232,413
  Asset retirement obligation expense
  40,112 35,901 42,387 31,156 —
  Selling and administrative expenses
  Other operating income:
  Net gain on disposal of assets
  (132,162 ) (101,487 ) (23,829 ) (32,772 ) (15,763 )
  (23,852 ) (30,096 ) (12,399 ) (2,872 ) 2,540
  143,450 102,939 96,793 98,540 102,458
  Early debt extinguishment costs
  1,396 — 1,751 53,513 —
  (12,726 ) (10,641 ) (4,917 ) (4,086 ) (7,574 )
  Income (loss) before income taxes and minority interests
  530,962 426,085 153,071 (3,181 ) 78,804
  Income tax provision (benefit)
  (81,515 ) 960 (26,437 ) (47,708 ) (40,007 )
  Minority interests
  11,780 2,472 1,282 3,035 13,292
  Income from continuing operations
  600,697 422,653 178,226 41,492 105,519
  Loss from discontinued operations
  — — (2,839 ) — —
  Income before accounting changes
  Cumulative effect of accounting changes
  — — — (10,144 ) —
  $ 600,697 $ 422,653 $ 175,387 $ 31,348 $ 105,519
  Basic earnings per share from continuing operations
  $ 2.28 $ 1.62 $ 0.72 $ 0.19 $ 0.51
  Diluted earnings per share from continuing operations
  Weighted average shares used in calculating basic earnings per share
  263,419,344 261,519,424 248,732,744 213,638,084 208,662,940
  Weighted average shares used in calculating diluted earnings per share
  Dividends declared per share
  Tons sold (in millions)
  247.6 239.9 227.2 203.2 197.9
  Net cash provided by (used in):
  $ 595,726 $ 702,759 $ 283,760 $ 188,861 $ 234,804
  (2,143,818 ) (584,202 ) (705,030 ) (192,280 ) (144,078 )
  1,371,325 (4,915 ) 693,404 48,598 (58,398 )
  1,080,404 870,398 559,244 410,278 406,101
  Additions to property, plant, equipment & mine development
  Federal coal lease expenditures
  178,193 118,364 114,653 — —
  Purchase of mining and related assets
  — 141,195 — — —
  Acquisitions, net
  1,552,313 — 429,061 90,000 46,012
  Balance Sheet Data (at period end)
  (1) Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated
  identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.
  Adjusted EBITDA is calculated as follows (unaudited):
  $ 1,080,404 $ 870,398 $ 559,244 $ 410,278 $ 406,101
  We are the largest private sector coal company in the world, with majority interests in 40 coal operations located throughout all major U.S. coal producing regions and internationally in Australia and Venezuela. In 2006, we sold 247.6 million tons of coal, which was approximately 38% greater than the sales of our closest competitor. Our domestic sales represented 22% of all U.S. coal sales and was approximately 80% greater than the sales of our closest domestic competitor. Based on Energy Information Administration (“EIA”) estimates, demand for coal in the United States was approximately 1.1 billion tons in 2006. Domestic coal consumption is expected to grow at an average rate of 1.8% per year through 2030 when U.S. coal demand is forecasted to be 1.8 billion tons. The EIA expects demand for coal use at coal-to-liquids (“CTL”) plants to grow to 112 million tons by 2030. Coal-fueled generation is used in most cases to meet baseload electricity requirements, and coal use generally grows at the approximate rate of electricity growth, which is expected to average 1.5% annually through 2030. Coal production located west of the Mississippi River is projected to provide most of the incremental growth as Western production increases to an estimated 68% share of total production in 2030. In 2005, coal’s share of electricity generation was approximately 50%, a share that the EIA projects will grow to 57% by 2030.
  Our primary customers are U.S. utilities, which accounted for 87% of our sales in 2006. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2006, approximately 90% of our sales were under long-term contracts. As of December 31, 2006, production totaled 226.2 million tons and sales totaled 247.6 million tons. As discussed more fully in Item 1A. Risk Factors, our results of operations in the near-term could be negatively impacted by poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations, and by the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections.
  We conduct business through four principal operating segments: Western U.S. Mining, Eastern U.S. Mining, Australian Mining, and Trading and Brokerage. Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations, and our Eastern U.S. Mining operations
  consist of our Appalachia and Midwest operations. The principal business of the Western U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities. The principal business of the Eastern U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities, as well as the mining of metallurgical coal, sold to steel and coke producers.
  Geologically, Western operations mine bituminous and subbituminous coal deposits and Eastern operations mine bituminous coal deposits. Our Western U.S. Mining operations are characterized by predominantly surface extraction processes, lower sulfur content and Btu of coal, and higher customer transportation costs (due to longer shipping distances). Our Eastern U.S. Mining operations are characterized by predominantly underground extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances).
  Australian Mining operations are characterized by both surface and underground extraction processes, mining various qualities of low-sulfur, high Btu coal (metallurgical coal) as well as steam coal primarily sold to an international customer base with a small portion sold to Australian steel producers and power generators. In the second half of 2006, through two separate transactions, we acquired Excel Coal Limited (“Excel”), an independent coal company in Australia for a total acquisition price of US$1.51 billion, net of cash received, plus approximately US$293.0 million in assumed debt. See Liquidity and Capital Resources for information on the financing of the Excel transaction. Assets acquired include three operating mines and three development-stage mines, along with more than 500 million tons of proven and probable coal reserves.
  We own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine produces approximately 6 to 8 million tons of steam coal annually for export to the United States and Europe. During 2006, the Paso Diablo Mine contributed $28.0 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA” and paid a dividend of $18.2 million. At December 31, 2006, our investment in Paso Diablo was $60.1 million.
  Metallurgical coal is produced primarily from four of our Australian mines (two of which were acquired in the Excel transaction) and two of our U.S. mines. Metallurgical coal is approximately 5% of our total sales volume and approximately 3% of U.S. sales volume.
  In addition to our mining operations, which comprised 87% of revenues in 2006, our trading and brokerage operations (13% of revenues), transactions utilizing our vast natural resource position (selling non-core land holdings and mineral interests) and other ventures generate revenues and additional cash flows.
  We continue to pursue the development of coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. The projects involve mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal sales. The projects we are currently pursuing include the 1,600-megawatt Prairie State Energy Campus in Washington County, Illinois and the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky. The plants, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, could be operational following a four-year construction phase. In October 2006, we entered an agreement with CMS Enterprises to share equally an expected 30% equity interest in the Prairie State Energy Campus and to oversee development and operation of the generating plant and coal mine. In the third quarter of 2006, the Prairie State Energy Campus received affirmation of the air quality permit from the U.S. Environmental Protection Agency, and in the fourth quarter of 2006, parties that had previously challenged the permit filed a new appeal.
  The EIA projects that the high price of oil will lead to an increase in demand for unconventional sources of transportation fuel, including Btu conversion technologies, and that coal will increase its share as a fuel for generation of electricity. We are exploring several Btu conversion projects, which are designed to
  expand the uses of coal through various technologies, and we are continuing to explore options particularly as they relate to Btu conversion technologies such as coal-to-liquids and coal gasification.
  Effective February 22, 2006, we implemented a two-for-one stock split on all shares of our common stock. All share and per share amounts in this annual report on Form 10-K reflect this split. In July 2005, our Board of Directors authorized a share repurchase program of up to 5% of the outstanding shares of our common stock. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. In 2006, we repurchased 2.2 million of our common shares for $99.8 million under this repurchase program.
  The discussion of our results of operations below includes references to and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under generally accepted accounting principles, in Note 25 to our consolidated financial statements.
  Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
  Higher average sales prices and increased volumes in the Eastern U.S., Powder River Basin and Australian mining operations, including the October 2006 acquisition of three mines in Australia, contributed to a 13.2% increase in revenues to $5.26 billion compared to 2005. Segment Adjusted EBITDA increased 13.8% to $1.23 billion primarily on growth in international volumes and higher sales prices from our Australian mining operations and increased results from Trading and Brokerage operations. Increases in sales volumes and prices in our U.S. mining operations were partially offset by operational challenges experienced during the period such as ongoing shipping constraints from rail performance in the Powder River Basin and port congestion in Australia; geologic, equipment and third-party supply issues as well as mine closures in our Western U.S. mining operations in late 2005. Net income was $600.7 million in 2006, or $2.23 per diluted share, an increase of 42.1% over 2005 net income of $422.7 million, or $1.58 per diluted share.
  Tons Sold
  The following table presents tons sold by operating segment for the year ended December 31, 2006 and 2005:
  Year Ended Increase
  December 31, (Decrease)
  2006 2005 Tons %
  Western U.S. Mining Operations
  160.5 154.3 6.2 4.0 %
  Eastern U.S. Mining Operations
  54.7 52.5 2.2 4.2 %
  11.0 8.3 2.7 32.5 %
  Trading and Brokerage Operations
  21.4 24.8 (3.4 ) (13.7 )%
  Total tons sold
  The following table presents revenues for the year ended December 31, 2006 and 2005:
  Increase to
  Year Ended December 31, Revenues
  2006 2005 $ %
  $ 5,144,925 $ 4,545,323 $ 599,602 13.2 %
  111,390 99,130 12,260 12.4 %
  In 2006, our total revenues were $5.26 billion, an increase of $611.9 million, or 13.2%, compared to prior year, which resulted from sales price increases in all regions, particularly in our Eastern and Australian operations and demand-driven sales volume increases in the Powder River Basin, Midwest and Australian operations. Volumes related to the October 2006 Excel acquisition accounted for 2.1 million tons of the increase to tons sold and approximately 43% of the increase to sales in Australia. Partially offsetting sales price increases were lower regional sales due to late 2005 mine closures in the Western U.S. Mining operations and lower brokerage volumes.
  Sales increased $599.6 million, or 13.2%, to $5.14 billion in 2006, which included increases of $91.9 million in Western U.S. Mining sales, $318.1 million in Eastern U.S. Mining sales and $245.1 million in Australian Mining sales, partially offset by a decrease of $55.5 million in our brokerage operations. Overall, prices and volumes in our Western U.S. Mining operations increased, mainly reflecting increases to sales prices of over $0.70 per ton and volumes of 12.7 million tons in the Powder River Basin. These increases at our Powder River Basin operations resulted from strong demand for the mines’ low-sulfur products and improved rail conditions compared to 2005, when the region was dealing with major railroad maintenance. Despite rail performance improvements relative to 2005, constrained rail capacity continued to limit growth in the region in 2006. Offsetting this increase was lower production due to the cessation of mining operations at our Seneca and Black Mesa mines in late 2005 and unfavorable geologic conditions and equipment issues at our Twentymile Mine. On average, per ton sales prices in our Eastern U.S. Mining operations increased, driven by increases in metallurgical and steam coal prices. Sales volumes increased due to a newly developed mine, which began operation in late 2005, and the expansion of several existing mines, partially offset by lower production at one of our mines and at contract miner operations, as both managed geologic, equipment and, in certain locations, supplier issues. Sales from our Australian Mining operations were $245.1 million, or 41.0%, higher than in 2005, primarily due to higher international metallurgical coal prices, higher production at our underground mine following installation of a new longwall in the second quarter of 2006 and additional volumes from our newly acquired mines ($105.1 million). A higher per ton sales price reflected higher contract prices in 2006 for metallurgical coal as well as the slower realization of metallurgical coal price increases in 2005 when we operated under some lower priced carry-over contracts from 2004 through most of the first nine months of 2005. Brokerage operations’ sales decreased $55.5 million in 2006 compared to prior year due to lower sales volumes, partially offset by higher sales prices.
  Other revenues increased $12.3 million, or 12.4%, compared to prior year. The increase includes proceeds of $28.2 million from settlement of commitments by a third-party coal producer following a brokerage contract restructuring. Offsetting this increase were lower revenues related to synthetic fuel facilities as customers idled their synthetic fuel plants due to high crude oil prices.
  Segment Adjusted EBITDA
  Our total segment Adjusted EBITDA was $1.23 billion for the year ended 2006, compared with $1.08 billion in the prior year. Details were as follows:
  Increase to Segment
  Year Ended December 31, Adjusted EBITDA
  $ 473,074 $ 459,039 $ 14,035 3.1 %
  384,107 374,628 9,479 2.5 %
  278,411 202,582 75,829 37.4 %
  92,604 43,058 49,546 115.1 %
  Total Segment Adjusted EBITDA
  Adjusted EBITDA from our Western U.S. Mining operations increased $14.0 million, or 3.1%, during 2006 primarily reflecting an increase in sales volumes of 12.7 million tons at our Powder River Basin operations, which resulted from continued strong demand and improved rail performance relative to 2005. Western U.S. Mining operations sales price per ton increased moderately due to mix changes resulting from ceasing operations at our Black Mesa and Seneca mines. Western U.S. Mining operations cost increases were driven by higher fuel costs, an increase in revenue-based royalties and production taxes, and the timing of major repairs. In addition, we experienced unfavorable geologic conditions and equipment issues related to the new longwall system at our Twentymile Mine; however, a recovery of certain costs associated with the equipment difficulties lessened the impact of these issues on our 2006 results. The Western U.S. Mining operations were also negatively impacted by the cessation of operations at the Black Mesa mine in late 2005.
  Eastern U.S. Mining operations’ Adjusted EBITDA increased $9.5 million, or 2.5%, compared to prior year primarily due to higher sales volumes partially offset by a decrease in margin per ton. Results improved compared to prior year as benefits of higher volumes, product mix and sales prices were partially offset by higher costs. The Eastern U.S. Mining operations experienced higher costs per ton due to fuel costs, revenue-based royalties and production taxes as well as higher costs associated with equipment, geologic and contract miner issues. The 2006 results were also negatively impacted by lower revenues from synthetic fuel facilities of $10.1 million as customers idled their synthetic fuel plants. Also impacting Eastern U.S. Mining results was $8.9 million of income from a settlement related to customer billings regarding coal quality.
  Our Australian Mining operations’ Adjusted EBITDA increased $75.8 million, or 37.4%, compared to prior year primarily due to increased sales volumes following increased production from the second quarter installation of a new longwall system at our underground mine, higher metallurgical coal sales prices, and a $19.7 million contribution from our newly acquired mines.
  Trading and Brokerage operations’ Adjusted EBITDA increased $49.5 million from the prior year, as 2006 results included proceeds from restructuring the brokerage contract mentioned above, improved brokerage margins and contribution from the newly established international operation, partially offset by lower domestic trading results.
  Income Before Income Taxes and Minority Interests
  The following table presents income before income taxes and minority interests for the years ended December 31, 2006 and 2005:
  Increase (Decrease)
  Year Ended December 31, to Income
  Corporate and Other Adjusted EBITDA
  (147,792 ) (208,909 ) 61,117 29.3 %
  (377,210 ) (316,114 ) (61,096 ) (19.3 )%
  (40,112 ) (35,901 ) (4,211 ) (11.7 )%
  Interest expense and early debt extinguishment costs
  12,726 10,641 2,085 19.6 %
  $ 530,962 $ 426,085 $ 104,877 24.6 %
  Income before income taxes and minority interests of $531.0 million for 2006 is $104.9 million, or 24.6%, higher than 2005 primarily due to improved segment Adjusted EBITDA as discussed above.
  Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our joint ventures, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development, Btu conversion and resource management. The $61.1 million improvement in Corporate and Other Adjusted EBITDA (net expense) in 2006 compared to 2005 includes the following:
  • Higher gains on asset disposals and exchanges of $30.7 million. The 2006 activity included sales with a combined gain of $66.3 million from the sale of non-strategic coal reserves and surface lands located in Kentucky and West Virginia, a $39.2 million gain on an exchange with the Bureau of Land Management of approximately 63 million tons of leased coal reserves at our Caballo mining operation for approximately 46 million tons of coal reserves contiguous with our North Antelope Rochelle mining operation and other gains on asset disposals totaling $26.7 million. In comparison, activity in 2005 included a $37.4 million gain on exchange of coal reserves as part of a dispute settlement with a third-party supplier, a $31.1 million gain from sale of our remaining 0.838 million units of Penn Virginia Resource Partners, L.P., a $12.5 million gain from the sale of non-strategic coal reserves and properties, a $6.2 million gain on an asset exchange from which we received Illinois Basin coal and other gains on asset disposals of $14.3 million;
  • Lower selling and administrative expenses of $13.9 million primarily associated with lower performance-based incentive costs, partially offset by increases to share-based compensation expense as a result of the new requirement to expense stock options, costs to support corporate and international growth initiatives and costs for the development and installation of a new enterprise resource planning system. The lower costs associated with the performance-based incentive plan related to a long-term, executive incentive plan that is driven by shareholder return and reflected lower stock price appreciation in 2006 than in the prior year;
  • Higher equity income of $8.0 million from our 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela; and
  • Lower net expenses of $4.7 million related to the development of the Prairie State Energy Campus due to a higher rate of cost reimbursement from the partners in 2006.
  Depreciation, depletion and amortization increased $61.1 million in 2006 due to higher production volume, acquisitions and the impact of escalating costs and new capital, including two new longwall installations and new mine development. Also, 2005 depreciation, depletion and amortization was net of amortization of acquired contract liabilities.
  Interest expense and early debt extinguishment costs increased $41.9 million primarily due to approximately $1.7 billion in new debt issuances in the second half of 2006 to finance the Excel acquisition. See Liquidity and Capital Resources for more details of the debt issued.
  The following table presents net income for the year ended December 31, 2006 and 2005:
  Income tax benefit (provision)
  81,515 (960 ) 82,475 n/a
  (11,780 ) (2,472 ) (9,308 ) (376.5 )%
  Net income increased $178.0 million in 2006 compared to prior year due to the increase in income before income taxes and minority interests discussed above and an income tax benefit compared to an income tax provision in 2005. The income tax benefit for the year ended 2006 related primarily to a reduction in tax reserves no longer required due to the finalization of various federal and state returns and expiration of applicable statute of limitations, and a reduction in a portion of the valuation allowance related to net operating loss (“NOL”) carry-forwards. The reduction to the valuation allowance resulted from an increase to estimated future taxable income primarily resulting from long-term contracts signed in late 2006 which increased our ability to realize these benefits in the future. Minority interests increased primarily as a result of acquiring an additional interest in a joint venture near the end of the first quarter of 2006.
  Our 2005 revenues of $4.64 billion increased 27.9% over the prior year. Revenues were driven higher by improved pricing in all of our mining operations and increased sales volume with 239.9 million tons sold compared to 227.2 million tons in 2004. Segment Adjusted EBITDA of $1.08 billion was a 39.5% increase over the prior year due to increases in sales volumes and prices at our U.S. and Australian Mining Operations. Results in our Western U.S. Mining Operations segment include amounts for our April 15, 2004, acquisition of the Twentymile Mine in Colorado. Results in our Australian Mining Operations segment include amounts for our April 15, 2004, acquisition of the Burton and North Goonyella Mines as well as the opening of the Eaglefield Mine adjacent to the North Goonyella Mine in the fourth quarter of 2004. Our Corporate and Other segment includes results from our December 2004 acquisition of a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. In addition, higher gains on property transactions contributed to higher year over year results. Net income was $422.7 million in 2005, or $1.58 per diluted share, an increase of 141.0% over 2004 net income of $175.4 million, or $0.69 per diluted share.
  The following table presents tons sold by operating segment for the years ended December 31, 2005 and 2004:
  154.3 142.2 12.1 8.5 %
  8.3 6.1 2.2 36.1 %
  24.8 27.2 (2.4 ) (8.8 )%
  The table below presents revenues for the years ended December 31, 2005 and 2004:
  Year Ended December 31, Increase to Revenues
  $ 4,545,323 $ 3,545,027 $ 1,000,296 28.2 %
  99,130 86,555 12,575 14.5 %
  Our revenues increased by $1.01 billion, or 27.9%, to $4.64 billion compared to prior year. The three mines we acquired in the second quarter of 2004 contributed $365.2 million of revenue growth due to the additional 105 days of operations in 2005 compared to the prior year. The remaining $647.7 million of revenue growth was driven by higher sales prices and volumes across all mining segments and improved volumes in our brokerage operations.
  Sales increased 28.2% to $4.55 billion in 2005, reflecting increases in every operating segment. Western U.S. Mining sales increased $222.2 million, Eastern U.S. Mining sales were $224.0 million higher, sales in Australia Mining improved $328.0 million and sales from our brokerage operations increased $226.0 million. Sales in every segment increased on improved pricing, and volumes were higher in every segment other than Trading and Brokerage. Our average sales price per ton increased 17.4% during 2005 due to increased demand for all of our coal products, which drove pricing higher, particularly in the regions where we produce metallurgical coal. Prices for metallurgical coal and our ultra-low sulfur Powder River Basin coal have been the subject of increasing demand. We sell metallurgical coal from our Eastern U.S. and Australian Mining operations. We sell ultra-low sulfur Powder River Basin coal from our Western U.S. Mining operations. The sales mix also improved due to an increase in sales from our Australian Mining segment, where per ton prices are higher than in domestic markets due primarily to a higher proportion of metallurgical coal production in the Australian segment sales mix.
  The increase in Eastern U.S. Mining operations sales was primarily due to improved pricing for both steam and metallurgical coal from the region. On average, prices in our Eastern U.S. Mining operations increased 14.1% to $33.10 per ton. Sales increased in our Western U.S. Mining operations due to higher demand-driven volumes and prices, particularly in the Powder River Basin. Overall, prices in our Western U.S. Mining operations increased 6.6% to $10.45 per ton. Powder River Basin production and sales volumes were up as a result of increasingly strong demand for the mines’ low-sulfur product, which continues to expand its market area geographically. Powder River Basin operations were able to ship record volumes during 2005 by overcoming train derailments, weather and track maintenance disruptions on the main shipping line out of the basin. Our Twentymile Mine, acquired in April of 2004, contributed to higher sales in 2005 due to an additional four months of ownership, higher prices and increased mine
  productivity. Sales from our Australian Mining operations were $328.0 million, or 122.1%, higher than in 2004. The increase in Australian sales was due primarily to a 63.3% increase in per ton sales prices largely due to higher international metallurgical coal prices, an increase in volumes which included the opening of our Eaglefield surface mine at the end of 2004, and $197.6 million of incremental sales from the two mines we acquired in April 2004 due to 105 additional days of operations in 2005 compared to 2004. Our Trading and Brokerage operations sales increased $226.0 million in 2005 compared to prior year due to an increase in average per ton prices and higher eastern U.S. and international brokerage volumes.
  Other revenues increased $12.6 million, or 14.5%, compared to prior year primarily due to proceeds from a purchase contract restructuring and higher synthetic fuel revenues in the Midwest.
  Our total segment Adjusted EBITDA of $1.08 billion for 2005 was $305.5 million higher than 2004 segment Adjusted EBITDA of $773.8 million, and was composed of the following:
  $ 459,039 $ 402,052 $ 56,987 14.2 %
  202,582 50,372 152,210 302.2 %
  43,058 41,039 2,019 4.9 %
  $ 1,079,307 $ 773,820 $ 305,487 39.5 %
  Adjusted EBITDA from our Western U.S. Mining operations increased $57.0 million during 2005 due to a margin per ton increase of $0.15, or 5.3%, and a sales volume increase of 12.1 million tons. Results in the Powder River Basin operations contributed to the increase in Western U.S. Mining operations as it earned 12.3% higher per ton margins while increasing volumes 8.5% in response to greater demand for our low-sulfur products. Improved revenues overcame increased unit costs that resulted from higher fuel and explosives costs, lower than anticipated volume due to rail difficulties and an increase in revenue-based royalties and production taxes. The Twentymile Mine, acquired in April of 2004, contributed $25.4 million more to Adjusted EBITDA in 2005 than in 2004, due to four months of incremental ownership and a 22.2% increase in per ton margin.
  Eastern U.S. Mining operations’ Adjusted EBITDA increased $94.3 million, or 33.6%, compared to prior year primarily due to an increase in margin per ton of $1.71, or 31.5%. Our Eastern U.S. Mining operations’ Adjusted EBITDA increased as a result of sales price increases, partially offset by lower production at two of our mines and higher costs related to geologic issues, contract mining, fuel, repair and maintenance and the impact of heavy rainfall on surface operations early in the year.
  Our Australian Mining operations’ Adjusted EBITDA increased $152.2 million in the current year, a 302.2% increase compared to prior year due to an increase of $16.23, or 197.4%, in margin per ton and 2.2 million additional tons shipped. Our Australian operations produce mostly (75% to 85%) high margin metallurgical coal. The two mines we acquired in April 2004 added $87.4 million to Adjusted EBITDA compared to eight months of ownership in 2004. The remaining increase of $64.8 million was primarily due to an increase in volume, including tonnage from our surface operation opened at the end of the prior year, and an increase of 63.3% in average per ton sale price. While current year margins benefited from strong sales prices, margin growth was limited by the impact of port congestion, related demurrage costs and higher costs due to geological problems at the underground mine.
  Trading and Brokerage operations’ Adjusted EBITDA increased $2.0 million from the prior year primarily due to higher brokerage results. Results in 2005 included a net charge of $4.0 million, primarily related to the breach of a coal supply contract by a producer.
  Reconciliation of Segment Adjusted EBITDA to Income Before Income Taxes and Minority Interests
  (208,909 ) (214,576 ) 5,667 2.6 %
  (35,901 ) (42,387 ) 6,486 15.3 %
  (102,939 ) (98,544 ) (4,395 ) (4.5 )%
  10,641 4,917 5,724 116.4 %
  $ 426,085 $ 153,071 $ 273,014 178.4 %
  Income before income taxes and minority interest of $426.1 million for the current year is $273.0 million, or 178.4%, higher than prior year primarily due to improved segment Adjusted EBITDA as discussed above. Increases in depreciation, depletion and amortization expense and interest expense offset improvements in Corporate and Other Adjusted EBITDA, asset retirement obligation expense, debt extinguishment costs and interest income.
  Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our Venezuelan joint venture, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development and resource management. The $5.7 million improvement in Corporate and Other Adjusted EBITDA (net expense) in 2005 compared to 2004 included:
  • net gains on asset sales that were $77.7 million higher than prior year primarily due to a $37.4 million gain from a property exchange related to settlement of a contract dispute with a third-party coal supplier (see Note 3 to our consolidated financial statements), sales of Penn Virginia Resource Partners, L.P. (“PVR”) units ($31.1 million) (see Note 9 to our consolidated financial statements), resource sales involving non-strategic coal assets and properties ($12.5 million), and an asset exchange in which we acquired Illinois Basin coal reserves ($6.2 million). The gain from PVR unit sales in 2005 was from the sale of all of our remaining 0.838 million units compared to a gain of $15.8 million on the sale of 0.775 million units in two separate transactions during 2004. All other gains on asset disposals in 2005 and 2004 were $14.3 million and $8.0 million, respectively;
  • higher equity income of $18.7 million from our 25.5% interest in Carbones del Guasare (acquired in December 2004), which owns and operates the Paso Diablo Mine in Venezuela, and;
  • lower net expenses related to generation development of $5.1 million, primarily due to reimbursements from the Prairie State Energy Campus partnership group.
  These improvements were partially offset by:
  • a $36.0 million increase in past mining obligations expense, primarily related to higher retiree health care costs. The increase in retiree health care costs was actuarially driven by higher trend rates, and lower interest discount assumptions and higher amortization of actuarial losses in 2005, and;
  • an increase of $46.8 million in selling and administrative expenses primarily related to accruals for higher short-term and long-term performance-based incentive plans ($32.2 million). These incentives are principally long-term plans that are driven by total shareholder returns. Our share price increased 104% during 2005, significantly outperforming industrial benchmarks and our coal
  peer group average. The remaining increase in selling and administrative expenses was due to higher personnel and outside services costs needed to advance our growth initiatives in areas such as China and BTU conversion, acquisitions and regulatory costs (e.g. Sarbanes-Oxley), and an increase in advertising costs related to an industry awareness campaign launched in late 2005.
  Depreciation, depletion and amortization increased $46.0 million during 2005. Approximately 56% of the increase was due to acquisitions completed during 2004 and the remainder was from increased volumes at existing mines and operations opened during 2005. Asset retirement obligation expense decreased $6.5 million in 2005 due to additional expenses incurred in 2004 to accelerate the planned reclamation of certain closed mine sites. Interest expense increased $6.1 million primarily related to a full year of interest in 2005 on $250 million of 5.875% Senior Notes issued in late March of 2004 and increases in the cost of floating rate debt due to higher interest rates. Interest income improved $5.7 million due to higher yields on short-term interest rates and an increase in invested balances due to improved cash flows during 2005.
  $ 426,085 $ 153,071 $ 273,014 178.4%
  (960 ) 26,437 (27,397 ) (103.6 )%
  (2,472 ) (1,282 ) (1,190 ) (92.8 )%
  422,653 178,226 244,427 (137.1 )%
  — (2,839 ) 2,839 n/a
  Net income increased $247.3 million, or 141.0%, compared to the prior year due to the increase in income before income taxes and minority interests discussed above, partially offset by increases in our income tax provision. The income tax benefit in 2004 included a $25.9 million reduction in the valuation allowance on net operating loss carry-forwards and alternative minimum tax credits. The income tax provision in 2005 was higher based on the increase in pretax income which was partially offset by the higher permanent benefit of percentage depletion and the partial benefit of tax loss from a deemed liquidation of a subsidiary arising as an indirect consequence of a comprehensive and strategic internal restructuring we completed during 2005. This restructuring resulted from efforts to better align corporate ownership of subsidiaries on a geographic and functional basis.
  Events Impacting Near-Term Operations
  In October 2006, we acquired Excel Coal Limited, which included three operating mines, two late development-stage mines and a development-stage mine. These development-stage mines are expected to begin shipments in 2007, and our 2007 results will be impacted to the extent we complete ramp up activities at these development-stage mines on time and at expected capacity. Furthermore, our two primary Australian shipping points, Dalrymple Bay Coal Terminal and Port of Newcastle, are experiencing significant queues of vessels, which could result in delayed shipments and demurrage charges.
  Currently depressed Central Appalachian coal prices combined with escalating costs of our third-party contractors could adversely impact our saleable production as it becomes uneconomic to mine.
  Although we expect that the Twentymile longwall system will allow for expanded capacity over the next several years, we continue to manage equipment and lower coal quality issues at our Twentymile mine.
  Shipments from our Powder River Basin mines improved in 2006, but were still impacted by rail service disruptions. Rail carriers are expected to continue improvements in 2007. Although we currently expect to increase our shipment levels from our Powder River Basin operations in 2007 compared with 2006, our ability to reach these targeted shipment levels is dependent upon the performance of the rail carriers.
  Our union workforce east of the Mississippi River is primarily represented by the UMWA. The UMWA-represented workers at one of our eastern mines operate under a contract that expires on December 31, 2007. The remainder of our UMWA-represented workers in the east operate under a recently signed, five-year labor agreement expiring December 31, 2011. The new contract mirrors the 2007 National Bituminous Coal Wage Agreement and stipulates a $1.50 per hour increase to wages effective January 1, 2007 and a total wage increase of $4.00 per hour over the life of the agreement. The contract also calls for a $1,000 bonus for each of our UMWA-represented employees.
  Long-Term Outlook
  Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as growth continues in the U.S., Asia and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. Approximately 115 gigawatts of new coal-fueled electricity generating capacity is scheduled to come on line around the world over the next three years, and the EIA projects an additional 156 gigawatts of new U.S. coal-fueled generation by 2030, which by itself represents more than 500 million tons of additional coal demand.
  Global coal markets continued to grow, driven by increased demand from growing economies. The U.S. economy grew at an annual rate of 3.5% based on fourth quarter 2006 data as reported by the U.S. Commerce Department, while China’s economy grew 10.7% in 2006 as published by the National Bureau of Statistics of China. Metallurgical coal continued to sell at a significant premium to steam coal. Metallurgical markets, while off record levels, remain strong as seaborne metallurgical coal prices for the upcoming fiscal year were settling from a reference price near $100 per metric ton and as China steel production shows signs of continued growth over 2005 levels. We expect to capitalize on the strong global market for metallurgical coal primarily through production and sales of metallurgical coal from our Appalachia and Australian operations. In response to growing international markets, we established an international trading group in 2006, and added another operations office in Europe in early 2007.
  Coal-to-gas and coal-to-liquids (“CTL”) plants represent a significant avenue for long-term industry growth. The EIA continues to project an increase in demand for unconventional sources of transportation fuel, including coal-to-liquids, and in the U.S. coal-to-liquid technologies are receiving growing bipartisan support as demonstrated by the newly introduced CTL bills such as the “Coal-to-Liquid Fuel Promotion Act” within the Senate. China and India are developing coal-to-gas and coal-to-liquids facilities.
  Demand for Powder River Basin coal remains strong, particularly for our ultra-low sulfur products. The Powder River Basin represents more than half of our production. We control approximately 3.5 billion tons of proven and probable reserves in the Southern Powder River Basin, and we sold 138.4 million tons of coal from this region during 2006, an increase of 10.1% over the prior year.
  We are targeting 2007 production of 240 to 260 million tons and total sales volume of 265 to 285 tons, including 15 to 18 million tons of metallurgical coal. As of December 31, 2006, our unpriced 2007 volumes for planned produced tonnage were 5 to 15 million U.S. tons and 14 million Australia tons. Our total unpriced planned production for 2008 is approximately 70 to 80 million tons in the United States and 20 to 22 million tons in Australia.
  Management plans to aggressively control costs and operating performance to mitigate external cost pressures, geologic conditions and potentially adverse port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel, tires, contract mining and healthcare, and have taken measures to mitigate the increases in these costs, including a company-wide initiative to instill best
  practices at all operations. In addition, historically low long-term interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage source performance or unforeseen equipment problems that 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 “Cautionary Notice Regarding Forward-Looking Statements” and Item 1A. Risk Factors for additional considerations regarding our outlook.
  Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.
  Employee-Related Liabilities
  We have significant long-term liabilities for our employees’ postretirement benefit costs, workers’ compensation obligations and defined benefit pension plans. Detailed information related to these liabilities is included in Notes 14, 15 and 16 to our consolidated financial statements. The adoption of SFAS No. 158 on December 31, 2006 resulted in each of these liabilities recorded on the consolidated balance sheet as of December 31, 2006 being equal to the funded status of the plans. Liabilities for postretirement benefit costs and workers’ compensation obligations are not funded. Our pension obligations are funded in accordance with the provisions of federal law. Expense for the year ended December 31, 2006, for these liabilities totaled $178.7 million, while payments were $146.2 million.
  Each of these liabilities are actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities.
  We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injuries and illnesses obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data. In addition, we make assumptions related to future compensation increases and rates of return on plan assets in the estimates of pension obligations.
  If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. Our most significant employee liability is postretirement health care, and assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for health care plans.
  Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.
  Health care cost trend rate:
  One-Percentage- One-Percentage-
  Point Increase Point Decrease
  Effect on total service and interest cost components(1)
  $ 9,501 $ (7,989 )
  Effect on total postretirement benefit obligation(1)
  $ 179,264 $ (150,765 )
  Discount rate:
  $ (78,243 ) $ 82,702
  (1) In addition to the effect on total service and interest cost components of expense, changes in trend and discount rates would also increase or decrease the actuarial gain or loss amortization expense component. The gain or loss amortization would approximate the increase or decrease in the obligation divided by 8.47 years at December 31, 2006.
  Asset Retirement Obligations
  Our asset retirement obligations primarily consist of spending estimates for surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mining permit. Asset retirement obligations are determined for each mine using various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted, risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the obligation and asset are revised to reflect the new estimate after applying the appropriate credit-adjusted, risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2006, was $40.1 million, and payments totaled $36.6 million. See detailed information regarding our asset retirement obligations in Note 13 to our consolidated financial statements.
  We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis 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 our annual evaluation of 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 actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made.
  We establish reserves for tax contingencies when, despite the belief that our tax return positions are fully supported, certain positions are likely to be challenged and may not be fully sustained. The tax contingency reserves are analyzed on a quarterly basis and adjusted based upon changes in facts and circumstances, such as the progress of federal and state audits, case law and emerging legislation. Our effective tax rate includes the impact of tax contingency reserves and changes to the reserves, including
  related interest. We establish the reserves based upon management’s assessment of exposure associated with permanent tax differences (i.e. tax depletion expense, etc.) and certain tax sharing agreements. We are subject to federal audits for several open years due to our previous inclusion in multiple consolidated groups and the various parties involved in finalizing those years. Additional details regarding the effect of income taxes on our consolidated financial statements is available in Note 11.
  Interpretation No. 48 “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (“FIN No. 48”) prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006 (January 1, 2007 for the Company).
  In general, we recognize revenues when they are realizable and earned. We generated 98% of our revenue in 2006 from the sale of coal to our customers. Revenue from coal sales is realized and earned when risk of loss passes to the customer. Coal sales are made to our customers under the terms of coal supply agreements, most of which are long-term (greater than one year). Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the mine or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source(s) that delivers coal to its destination.
  With respect to other revenues, other operating income, or gains on asset sales recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and apply the relevant accounting literature as appropriate, and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller’s price to the buyer is fixed or determinable; and collectibility is reasonably assured.
  Trading Activities
  We engage in the buying and selling of coal in over-the-counter markets. Our coal trading contracts are accounted for on a fair value basis under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” To establish fair values for our trading contracts, we use bid/ask price quotations obtained from multiple, independent third-party brokers to value coal and emission allowance positions. Prices from these sources are then averaged to obtain trading position values. We could experience difficulty in valuing our market positions if the number of third-party brokers should decrease or market liquidity is reduced.
  All of the contracts in our trading portfolio as of December 31, 2006 were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials. As of December 31, 2006, 41% of the estimated future value of our trading portfolio was scheduled to be realized by the end of 2007 and 80% within 24 months. See Note 5 to our consolidated financial statements for additional details regarding assets and liabilities from our coal trading activities.
  Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities, sales of non-core assets and financing transactions, including the sale of our accounts receivable (through our securitization program). Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs and costs related to past mining obligations as well as planned acquisitions. Our ability to pay dividends, service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. Future dividends,
  among other things, are subject to limitations imposed by our Senior Notes and Debenture covenants. We expect to fund all of our capital expenditure requirements with cash generated from operations.
  Net cash provided by operating activities was $595.7 million for the year ended December 31, 2006, a decrease of $107.1 million compared to $702.8 million provided by operating activities in the prior year. The decrease was primarily related to the timing of working capital needs. The decrease in cash from operating activities would have been $30.4 million lower had 2006 and 2005 operating cash flows been shown on a comparable basis. The 2006 operating cash flows include a required reclassification of the excess tax benefit related to stock option exercises ($33.2 million) from operating to financing activities.
  Net cash used in investing activities was $2.14 billion for the year ended December 31, 2006 compared to $584.2 million used in the prior year. The increase reflects the acquisition of Excel for $1.51 billion, net of cash acquired, higher capital expenditures of $93.4 million, higher federal coal lease expenditures of $59.8 million, the acquisition of an additional interest in a joint venture for $44.5 million, and the receipt of notes in lieu of payments on asset sales of $45.6 million, partially offset by higher proceeds from asset disposals of $46.9 million in 2006 and the purchase of mining and related assets of $141.2 million in 2005. Capital expenditures included longwall equipment and mine development at our Australian mines (including our recently acquired Excel operations), the opening of new mines and the purchase of equipment for expansion. The $141.2 million purchase of mining and related assets in 2005 included 70 million tons of Illinois and Indiana coal reserves, surface properties and equipment from Lexington Coal Company ($56.5 million) and rail, loadout and surface facilities as well as other mining assets for $84.7 million from another major coal producer.
  Net cash provided by financing activities was $1.37 billion during the year ended December 31, 2006, compared to a use of $4.9 million in 2005. In 2006, we issued net borrowings of $1.74 billion, which were utilized to fund the $1.51 billion Excel acquisition, the repayment of Excel’s bank facility and a portion of its outstanding bonds, and other corporate purposes. See the detailed discussion of our Senior Unsecured Credit Facility, Convertible Junior Subordinated Debentures, Senior Notes offerings and borrowings under our Senior Unsecured Credit Facility below. In addition to the net issuance of debt related to the Excel acquisition, we repaid $23.8 million of debt held by a majority-owned joint venture, purchased $7.7 million of our 5.875% Senior Notes in the open market, and made scheduled debt repayments of $11.1 million on our 5% Subordinated Note and other notes payable.
  The 2006 activity compared to 2005 also reflected payments for common stock repurchases of $99.8 million, debt issuance costs of $40.6 million and higher dividends of $18.9 million. During the year ended December 31, 2006, we repurchased 2.2 million of our common shares at a cost of $99.8 million under our share repurchase program as authorized by the Board of Directors. The 2006 activity included a decrease in the usage of our accounts receivable securitization program of $5.8 million compared to an increase of $25.0 million in 2005. The 2006 activity compared to 2005 also reflected $7.0 million lower proceeds from the exercise of stock options as well as a $33.2 million tax benefit related to stock option exercises included in financing activity based on the newly adopted accounting standard for share-based compensation (see “Newly Adopted Accounting Pronouncements” below for more discussion about the adoption of this standard). In 2005, the tax benefit related to stock option exercises (totaling $30.4 million) was included in operating activities.
  Our total indebtedness as of December 31, 2006 and 2005 consisted of the following:
  Term Loan under Senior Unsecured Credit Facility
  $ 547,000 $ —
  Term Loan under Senior Secured Credit Facility
  — 442,500
  Convertible Junior Subordinated Debentures due 2066
  732,500 —
  7.375% Senior Notes due 2016
  5.0% Subordinated Note
  6.84% Series C Bonds due 2016
  6.34% Series B Bonds due 2014
  6.84% Series A Bonds due 2014
  Fair value of interest rate swaps
  (13,784 ) (8,879 )
  Senior Unsecured Credit Facility
  In September 2006, we entered into a Third Amended and Restated Credit Agreement, which established a $2.75 billion Senior Unsecured Credit Facility and which amended and restated in full our then existing $1.35 billion Senior Secured Credit Facility. The Senior Unsecured Credit Facility provides a $1.8 billion Revolving Credit Facility and a $950.0 million Term Loan Facility. The Revolving Credit Facility replaced our previous $900.0 million revolving credit facility and the increased capacity is intended to accommodate working capital needs, letters of credit, the funding of capital expenditures and other general corporate purposes. The Revolving Credit Facility also includes a $50.0 million sub-facility available for same-day swingline loan borrowings. In September 2006, we borrowed $312.0 million under the Revolver in conjunction with the Excel acquisition and repaid this $312.0 million outstanding balance in December 2006 with net proceeds from the Debentures.
  The Term Loan Facility consisted of an unsecured $440.0 million portion, which was drawn at closing to replace the previous term loan ($437.5 million balance at time of replacement; $442.5 million at December 31, 2005) issued under the Senior Secured Credit Facility. The Term Loan Facility also included a Delayed Draw Term Loan Sub-Facility of up to $510.0 million, which was fully drawn in October 2006 in connection with the Excel acquisition. In December 2006, $403.0 million of the outstanding balance of the Term Loan Facility ($950.0 million was outstanding at time of repayment) was repaid with the net proceeds from the Debentures. In conjunction with the establishment of the Senior Unsecured Credit Facility, we incurred $8.6 million in financing costs, of which $5.6 million related to the Revolving Credit Facility and $3.0 million related to the Term Loan Facility. These debt issuance costs will be amortized to interest expense over five years, the term of the Senior Unsecured Credit Facility.
  Loans under the facility are available in U.S. dollars, with a sub-facility under the Revolving Credit Facility available in Australian dollars, pounds sterling and Euros. Letters of credit under the Revolving Credit Facility are available to us in U.S. dollars with a sub-facility available in Australian dollars, pounds sterling and Euros. The interest rate payable on the Revolving Credit Facility and the Term Loan Facility under the Senior Unsecured Credit Facility is LIBOR plus 1.0% with step-downs to LIBOR plus 0.50% based on improvement in the leverage ratio, as defined in the Third Amended and Restated Credit Agreement. The rate applicable to the Term Loan Facility was 6.35% at December 31, 2006.
  Under the Senior Unsecured Credit Facility, we must comply with certain financial covenants on a quarterly basis including a minimum interest coverage ratio and a maximum leverage ratio, as defined in the Third Amended and Restated Credit Agreement. The financial covenants also place limitations on our investments in joint ventures, unrestricted subsidiaries, indebtedness of non-loan parties, and the imposition of liens on our assets. The new facility is less restrictive with respect to limitations on our dividend payments, capital expenditures, asset sales or stock repurchases. The Senior Unsecured Credit Facility matures on September 15, 2011.
  As of December 31, 2006, we had no borrowings outstanding under our Revolving Credit Facility. Our revolving line of credit was primarily used for standby letters of credit until September 2006, when we also used the revolving line of credit to facilitate the Excel acquisition. As discussed above, the $312.0 million outstanding under the revolving line of credit was repaid in December 2006 with net proceeds from the Debentures. The remaining available borrowing capacity ($1.29 billion as of December 31, 2006) will be used to fund strategic acquisitions or meet other financing needs, including standby letters of credit. During 2005, we had no borrowings outstanding under our previous $900.0 million revolving line of credit, which we used primarily for standby letters of credit. We were in compliance with all of the covenants of the Senior Unsecured Credit Facility, the 6.875% Senior Notes, the 5.875% Senior Notes, the 7.375% Senior Notes, the 7.875% Senior Notes, and the Convertible Junior Subordinated Debentures as of December 31, 2006.
  Convertible Junior Subordinated Debentures
  On December 20, 2006, we issued $732.5 million aggregate principal amount of 4.75% Convertible Junior Subordinated Debentures due 2066 (the “Debentures”), including $57.5 million issued pursuant to the underwriters’ exercise of their over-allotment option. Net proceeds from the offering, after deducting underwriting discounts and offering expenses, were $715.0 million and were used to repay indebtedness under our Senior Unsecured Credit Facility. The Debentures will pay interest semiannually at a rate of 4.75% per year. We may elect to, and if and to the extent that a mandatory trigger event (as defined in the indenture governing the Debentures) has occurred and is continuing will be required to, defer interest payments on the Debentures. After five years of deferral at our option, or upon the occurrence of a mandatory trigger event, we generally must sell warrants or preferred stock with specified characteristics and use the funds from that sale to pay deferred interest, subject to certain limitations. In no event may we defer payments of interest on the Debentures for more than ten years.
  The Debentures are convertible at any time on or prior to December 15, 2036 if any of the following conditions occur: (i) our closing common stock price exceeds 140% of the then applicable conversion price for the Debentures (currently $86.73 per share) for at least 20 of the final 30 trading days in any quarter; (ii) a notice of redemption is issued with respect to the Debentures; (iii) a change of control, as defined in the indenture governing the Debentures; (iv) satisfaction of certain trading price conditions; and (v) other specified corporate transactions described in the indenture governing the Debentures. In addition, the Debentures are convertible at any time after December 15, 2036 to December 15, 2041, the scheduled maturity date. In the case of conversion following a notice of redemption or upon a non-stock change of control, as defined in the indenture governing the Debentures, holders may convert their Debentures into cash in the amount of the principal amount of their Debentures and shares of our common stock for any conversion value in excess of the principal amount. In all other conversion circumstances, holders will receive perpetual preferred stock (see Note 17 to our consolidated financial statements) with a liquidation preference equal to the principal amount of their Debentures, and any conversion value in excess of the principal amount will be settled with our common stock. The consideration delivered upon conversion will be based upon an initial conversion rate of 16.1421 shares of common stock per $1,000 principal amount of Debentures, subject to adjustment. This conversion rate represents an initial conversion price of approximately $61.95 per share, a 40% premium over the closing stock price of $44.25 on December 14, 2006, the date of the pricing of the offering of the Debentures.
  The Debentures are unsecured obligations, ranking junior to all existing and future senior and subordinated debt (excluding trade accounts payable or accrued liabilities arising in the ordinary course of
  business) except for any future debt that ranks equal to or junior to the Debentures. The Debentures will rank equal in right of payment with our obligations to trade creditors. Substantially, all of our existing indebtedness is senior to the Debentures. In addition, the Debentures will be effectively subordinated to all indebtedness of our subsidiaries. The indenture governing the Debentures places no limitation on the amount of additional indebtedness that we or any of our subsidiaries may incur (see Note 12 of our consolidated financial statements for additional information on the Debentures).
  7.375% Senior Notes Due November 2016 and 7.875% Senior Notes Due November 2026
  On October 12, 2006, we completed a $650 million offering of 7.375% 10-year Senior Notes due 2016 and $250 million of 7.875% 20-year Senior Notes due 2026. The notes are general unsecured obligations and rank senior in right of payment to any subordinated indebtedness; equally in right of payment with any senior indebtedness; effectively junior in right of payment to our existing and future secured indebtedness, to the extent of the value of the collateral securing that indebtedness; and effectively junior to all the indebtedness and other liabilities of our subsidiaries that do not guarantee the notes. Interest payments are scheduled to occur on May 1 and November 1 of each year, commencing on May 1, 2007.
  The notes are guaranteed by our Subsidiary Guarantors, as defined in the note indenture. The note indenture contains covenants that, among other things, limit our ability to create liens and enter into sale and lease-back transactions. The notes are redeemable at a redemption price equal to 100% of the principal amount of the notes being redeemed plus a make-whole premium, if applicable, and any accrued unpaid interest to the redemption date. Net proceeds from the offering, after deducting underwriting discounts and expenses, were $886.1 million.
  Series Bonds
  As of December 31, 2006, we had $74.0 million in Series Bonds outstanding, which were assumed as part of the Excel acquisition. The 6.84% Series A Bonds have a balloon maturity in December 2014. The 6.34% Series B Bonds mature in December 2014 and are payable in installments beginning December 2008. The 6.84% Series C Bonds mature in December 2016 and are payable in installments beginning December 2012. Interest payments occur in June and December of each year.
  Interest Rate Swaps
  Prior to completion of the Senior Unsecured Credit Facility, we had two $400.0 million interest rate swaps. A $400.0 million notional amount floating-to-fixed interest rate swap was designated as a hedge of changes in expected cash flows on the previous term loan under the Senior Secured Credit Facility. Under this swap, we paid a fixed rate of 6.764% and received a floating rate of LIBOR plus 2.5% that reset each March 15, June 15, September 15 and December 15 based upon the three-month LIBOR rate. A $400.0 million notional amount fixed-to-floating interest rate swap was designated as a hedge of the changes in the fair value of the 6.875% Senior Notes due 2013. Under this swap, we paid a floating rate of LIBOR plus 1.97% that reset each March 15, June 15, September 15 and December 15 based upon the three-month LIBOR rate and received a fixed rate of 6.875%.
  In conjunction with the completion of the new Senior Unsecured Credit Facility, the $400.0 million notional amount floating-to-fixed interest rate swap was terminated and resulted in payment to us of $5.2 million. We recorded the $5.2 million fair value of the swap in “Accumulated other comprehensive loss” on the consolidated balance sheet and will amortize this amount to interest expense over the remaining term of the forecasted interest payments initially hedged. We then entered into a $120.0 million notional amount floating-to-fixed interest rate swap with a fixed rate of 6.25% and a floating rate of LIBOR plus 1.0%. This interest rate swap was designated as a hedge of the variable interest payments on the Term Loan under the new Senior Unsecured Credit Facility.
  We also terminated $280.0 million of our $400.0 million notional amount fixed-to-floating interest rate swap designated as a hedge of the changes in fair value of the 6.875% Senior Notes due 2013. Reducing the notional amount of the interest rate swap to $120.0 million resulted in payment of $5.2 million to the
  counterparty. Reduction of the notional amount of the swap did not affect our floating and fixed rates. The $5.2 million of fair value associated with the termination of the $280.0 million portion of the swap was recorded as an adjustment to the carrying value of long-term debt and will be amortized to interest expense through maturity of the 6.875% Senior Notes due 2013.
  Because the critical terms of the swaps and the respective debt instruments they hedge coincide, there was no hedge ineffectiveness recognized in the consolidated statements of operations during the years ended December 31, 2006 and 2005. At December 31, 2006 there was an unrealized loss related to the cash flow hedge of $2.5 million and at December 31, 2005 there was an unrealized gain related to the cash flow hedge of $2.3 million. As of December 31, 2006 and 2005, the net unrealized loss on the fair value hedges discussed above were $13.8 million and $8.9 million, respectively, which is reflected as an adjustment to the carrying value of the Senior Notes (see table above).
  Third-party Security Ratings
  In 2006, third-party rating agencies performed a comprehensive review of our securities’ ratings based on our entrance into the new senior unsecured credit facility and the issuance of additional debt securities to facilitate the Excel acquisition. The ratings for our senior unsecured credit facility and our senior unsecured notes are as follows: Moody’s issued a Ba1 rating, Standard & Poor’s issued a BB rating and Fitch issued a BB+ rating. The rating on our convertible junior subordinated debentures issued in December 2006 were as follows: Moody’s issued a Ba2 rating, Standard & Poor’s issued a B rating and Fitch issued a BB- rating. These security ratings reflected the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.
  Shelf Registration Statement
  On July 28, 2006, we filed an automatic shelf registration statement on Form S-3 as a well-known seasoned issuer with the Securities and Exchange Commission. The registration was for an indeterminate number of securities and is effective for three years, at which time we can file an automatic shelf registration statement that would become immediately effective for another three-year term. Under this universal shelf registration statement, we have the capacity to offer and sell from time to time securities, including common stock, preferred stock, debt securities, warrants and units. The Debentures, 7.375% Senior Notes due 2016 and 7.875% Senior Notes due 2026 were issued pursuant to the shelf registration statement.
  Excel Transaction
  On July 5, 2006, we signed a merger implementation agreement to acquire Excel Coal Limited (“Excel”), an independent coal company, by means of a scheme of arrangement transaction under Australian law. The merger implementation agreement was amended on September 18, 2006, and we agreed to pay A$9.50 per share (US$7.16 as of the amendment date) for the outstanding shares of Excel. On September 20, 2006, as part of the amended agreement, we acquired 19.99% of the outstanding shares of Excel at A$9.50 per share, resulting in payment of A$408.3 million, or US$307.8 million. In October 2006, we acquired the remaining interest in Excel for A$9.50 per share (US$7.07 per share), a total of A$1.63 billion or US$1.21 billion. The total acquisition price, including the advance purchase of 19.99% and related costs, was US$1.54 billion in cash plus assumed debt of US$293.0 million, less US$30.0 million of cash acquired in the transaction, and was financed with borrowings under our Senior Unsecured Credit Facility and Senior Notes due 2016 and 2026 (see Note 12 of our consolidated financial statements for additional information on the financing of the Excel acquisition). The Excel acquisition includes three operating mines (Wambo Open-Cut Mine, Metropolitan Mine and Chain Valley Mine) and three development-stage mines (North Wambo Underground Mine, Wilpinjong Mine and Millennium Mine), with more than 500 million tons of proven and probable coal reserves. We also acquired a 51.0%
  interest in Excelven Pty Ltd., which owns Transportes Coal-Sea de Venezuela C.A. and a 96.7% interest in Cosila Complejo Siderurgico Del Lago S.A., which owns the Las Carmelitas coal mine development project. The results of operations of Excel are included in our Australian Mining Operations segment from October 2006. The acquisition was accounted for as a purchase in accordance with SFAS No. 141, “Business Combinations” (see Note 4 of our consolidated financial statements for additional information on the Excel acquisition).
  Contractual Obligations
  The following is a summary of our contractual obligations as of December 31, 2006:
  Payments Due By Year
  Within After
  1 Year 2-3 Years 4-5 Years 5 Years
  Long-term debt obligations (principal and interest)
  $ 303,849 $ 481,974 $ 859,965 $ 4,323,807
  Capital lease obligations (principal and interest)
  11,335 21,806 15,686 23,428
  Operating leases obligations
  102,256 152,264 101,386 168,076
  Unconditional purchase obligations(1)
  125,791 — — —
  Coal reserve lease and royalty obligations
  216,996 344,407 25,459 46,611
  Other long-term liabilities(2)
  170,716 337,809 396,113 1,362,711
  Total contractual cash obligations
  $ 930,943 $ 1,338,260 $ 1,398,609 $ 5,924,633
  (1) We have purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material. The commitments in the table above relate to significant capital purchases.
  (2) Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans and mine reclamation and end of mine closure costs.
  As of December 31, 2006, we had $125.8 million of purchase obligations for capital expenditures and $479.8 million of obligations related to federal coal reserve lease payments due over the next three years. Total capital expenditures for 2007 are expected to range from $450 million to $525 million, excluding federal coal reserve lease payments, and relate to replacement, improvement, or expansion of existing mines, particularly in Australia, Appalachia and the Midwest, and growth initiatives such as increasing capacity in the Powder River Basin. Approximately $10 million of the expenditures relate to safety equipment that will be utilized to comply with recently issued federal and state regulations. Capital expenditures were funded primarily through operating cash flow. Despite the acquisition of three development stage mines in 2006, we will exercise capital discipline in 2007, limiting capital expenditures to 2006 levels.
  In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such
  as bank letters of credit and performance or surety bonds and our accounts receivable securitization. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.
  We use a combination of surety bonds, corporate guarantees (i.e. self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement benefits and coal lease obligations as follows as of December 31, 2006:
  Workers’ Retiree
  Reclamation Lease Compensation Healthcare
  Obligations Obligations Obligations Obligations Other(1) Total
  (Dollars in millions)
  Self Bonding
  $ 685.3 $ — $ — $ — $ 2.9 $ 688.2
  441.5 83.9 31.7 — 27.2 584.3
  4.1 20.3 156.8 119.4 208.8 509.4
  $ 1,130.9 $ 104.2 $ 188.5 $ 119.4 $ 238.9 $ 1,781.9
  (1) Includes financial guarantees primarily related to joint venture debt, the Pension Benefit Guarantee Corporation and collateral for surety companies.
  As part of arrangements through which we obtain exclusive sales representation agreements with small coal mining companies (the “Counterparties”), we issued financial guarantees on behalf of the Counterparties. These guarantees facilitate the Counterparties’ efforts to obtain bonding or financing. In July 2006, we issued $5.2 million of financial guarantees, expiring at various dates through July 2013, on behalf of a small coal producer to facilitate its efforts in obtaining financing. In the event of default, we have multiple recourse options, including the ability to assume the loans and procure title and use of the equipment purchased through the loans. If default occurs, we have the ability and intent to exercise our recourse options, so the liability associated with the guarantee has been valued at zero. We have also guaranteed bonding for a partnership in which we formerly held an interest. The aggregate amount guaranteed for all such Counterparties was $12.1 million, and the fair value of the guarantees recognized as a liability was $0.4 million as of December 31, 2006. Our obligations under the guarantees extend to September 2015. In March 2006, we issued a guarantee for certain equipment lease arrangements on behalf of one of the sales representation parties with maximum potential future payments totaling $2.7 million at December 31, 2006, and with lease terms that extend to April 2010. See Note 21 to our consolidated financial statements included in this report for a discussion of our guarantees.
  Under our accounts receivable securitization program, undivided interests in a pool of eligible trade receivables contributed to our wholly-owned, bankruptcy-remote subsidiary are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (“Conduit”). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We utilize proceeds from the sale of our accounts receivable as an alternative to other forms of debt, effectively reducing our overall borrowing costs. The funding cost of the securitization program was $1.9 million and $2.5 million for the years ended December 31, 2006 and 2005, respectively. The securitization program is scheduled to expire in September 2009. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheets. The amount of undivided interests in accounts receivable sold to the Conduit was $219.2 million and $225.0 million as of December 31, 2006 and 2005 (see Note 6 to our consolidated financial statements for additional information on accounts receivable securitization).
  The following is a summary of specified types of commercial commitments available to us as of December 31, 2006:
  Expiration Per Year
  Total Amounts Within Over
  Committed 1 Year 2-3 Years 4-5 Years 5 Years
  Lines of credit and/ or standby letters of credit
  $ 1,800,000 $ — $ — $ 1,800,000 $ —
  Newly Adopted Accounting Pronouncements
  We adopted Emerging Issues Task Force (“EITF”) Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry” (“EITF Issue No. 04-6”) on January 1, 2006 and utilized the cumulative effect adjustment approach whereby a cumulative effect adjustment reduced retained earnings by $150.3 million, net of tax. EITF Issue No. 04-6 states “that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred.” Advance stripping costs include those costs necessary to remove overburden above an unmined coal seam as part of the surface mining process and prior to the adoption were included as the “work-in-process” component of “Inventories” in the consolidated balance sheet. EITF Issue No. 04-6 and its interpretations require stripping costs incurred during a period to be attributed only to the inventory costs of the coal that is extracted during that same period, and therefore, advance stripping costs are no longer separately classified as a component of inventory.
  On January 1, 2006, we adopted SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123(R)”), which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). SFAS No. 123(R) supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB Opinion No. 25”) and amends SFAS No. 95, “Statement of Cash Flows.” Prior to January 1, 2006, we applied APB Opinion No. 25 and related interpretations in accounting for our stock option plans, as permitted under SFAS No. 123 and SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure.” We applied SFAS No. 123(R) through use of the modified prospective method, in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted or modified after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values at the grant date. SFAS No. 123(R) also requires that the excess income tax benefits from stock options exercised be recorded as financing cash inflow on the statements of cash flows. The excess income tax benefit from stock option exercises during 2005 and 2004 are included in operating cash flows, netted in deferred tax activity.
  For share-based payment instruments excluding restricted stock, we recognized $17.7 million (or $0.07 per diluted share), $24.8 million (or $0.09 per diluted share) and $12.8 million (or $0.05 per diluted share) of expense, net of taxes, for the years ended December 31, 2006, 2005 and 2004, respectively. As a result of adopting SFAS No. 123(R), our net income for the year ended December 31, 2006 was $4.4 million (or $0.02 per diluted share) lower than if we had continued to account for share-based compensation under APB Opinion No. 25. Share-based compensation expense is recorded in “Selling and administrative expenses” in the consolidated statements of operations. We used the Black-Scholes option pricing model to determine the fair value of stock options and employee stock purchase plan share-based payments made before and after the adoption of SFAS No. 123(R). We began utilizing restricted stock as part of our equity-based compensation strategy in January 2005. Accounting for restricted stock awards was not changed by the adoption of SFAS No. 123(R). As of December 31, 2006, the total unrecognized compensation cost related to nonvested awards was $24.0 million, net of taxes, which is expected to be
  recognized over 5.0 years with a weighted-average period of 1.3 years. See Note 18 to our consolidated financial statements for further discussion of our share-based compensation plans.
  In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (“SFAS No. 158”). For fiscal years ending after December 15, 2006, SFAS No. 158 requires recognition of the funded status of pension and other postretirement benefit plans (an asset for overfunded status or a liability for underfunded status) in a company’s balance sheet. In addition, the standard requires recognition of actuarial gains and losses, prior service cost, and any remaining transition amounts from the initial application of SFAS No. 87, “Employers’ Accounting for Pensions” (“SFAS No. 87”) and SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“SFAS No. 106”) when determining a plan’s funded status, with a corresponding charge to accumulated other comprehensive income (loss).
  We adopted SFAS No. 158 on December 31, 2006, and as a result, recorded a noncurrent liability of $376.1 million, which reflected the total underfunded status of the pension, retiree healthcare and workers’ compensation plans. The funded status of each plan was measured as the difference between the fair value of the assets and the projected benefit obligation (the “funded status”). SFAS No. 158 did not impact net income. The impact to the balance sheet was as follows (see Notes 14, 15, and 16 to our consolidated financial statements for additional details):
  Before Application of
  of SFAS No. 158 Adjustments SFAS No. 158
  Workers’ compensation obligations
  $ 237,965 $ (4,558 ) $ 233,407
  Accrued postretirement benefit costs
  973,164 395,522 1,368,686
  Other noncurrent liabilities (includes long-term pension and UMWA Combined Fund liabilities)
  375,485 (14,855 ) 360,630
  Deferred income taxes (long-term liability)
  344,712 (149,499 ) 195,213
  6,915,583 226,610 7,142,193
  (22,448 ) (226,610 ) (249,058 )
  2,565,136 (226,610 ) 2,338,526
  Accounting Pronouncements Not Yet Implemented
  In June 2006, the FASB issued FIN No. 48. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. This interpretation is effective for fiscal years beginning after December 15, 2006 (January 1, 2007 for the Company). Any adjustments required upon the adoption of this interpretation must be recorded directly to retained earnings in the year of adoption and reported as a change in accounting principle. We expect the adoption of FIN No. 48 will not have a material impact on our financial position.
  Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
  The potential for changes in the market value of our coal trading, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading portfolio is evaluated using a value at risk analysis (described below). Value at risk analysis is not used to evaluate our non-trading interest rate and currency portfolios. A description of each market risk category is set forth below. We attempt to manage market risks through diversification, controlling position sizes, and executing hedging strategies. Due to lack of quoted market prices and the long term, illiquid nature of the positions, we have not quantified market risk related to our non-trading, long-term coal supply agreement portfolio.
  Coal Trading Activities and Related Commodity Price Risk
  We engage in over-the-counter and direct trading of coal. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure, in value at risk terms, that we may assume at any point in time.
  We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, options and swaps, at market value in our consolidated financial statements. Our trading portfolio included forwards and swaps as of December 31, 2006 and forwards as of December 31, 2005.
  We perform a value at risk analysis on our coal trading portfolio, which includes over-the-counter and brokerage trading of coal. The use of value at risk allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. Value at risk represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon (liquidation period) within a specified confidence level. Our value at risk model is based on the industry standard variance/co-variance approach. This captures our exposure related to both option and forward positions. Our value at risk model assumes a 15-day holding period and a 95% one-tailed confidence interval. This means that there is a one in 20 statistical chance that the portfolio would lose more than the value at risk estimates during the liquidation period.
  The use of value at risk allows management to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. Due to the subjectivity in the choice of the liquidation period, reliance on historical data to calibrate the models and the inherent limitations in the value at risk methodology, we perform regular stress and scenario analysis to estimate the impacts of market changes on the value of the portfolio. Additionally, back-testing is regularly performed to monitor the effectiveness of our value at risk measure. The results of these analyses are used to supplement the value at risk methodology and identify additional market-related risks.
  We use historical data to estimate our value at risk and to better reflect current asset and liability volatilities. Given our reliance on historical data, value at risk is effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. An inherent limitation of value at risk is that past changes in market risk factors may not produce accurate predictions of future market risk. Value at risk should be evaluated in light of this limitation.
  During the year ended December 31, 2006, the actual low, high, and average values at risk for our coal trading portfolio were $0.7 million, $2.7 million, and $1.4 million, respectively. As of December 31, 2006, the timing of the estimated future realization of the value of our trading portfolio was as follows:
  Year of Expiration of Portfolio
  We also monitor other types of risk associated with our coal trading activities, including credit, market liquidity and counterparty nonperformance.
  Our concentration of credit risk is substantially with energy producers and marketers and electric utilities. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into
  transactions and to constantly monitor the credit extended. In the event that we engage in a transaction with a counterparty that does not meet our credit standards, we will protect our position by requiring the counterparty to provide appropriate credit enhancement. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties. Counterparty risk with respect to interest rate swap and foreign currency forwards and options transactions is not considered to be significant based upon the creditworthiness of the participating financial institutions.
  Foreign Currency Risk
  We utilize currency forwards to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2007 targets hedging approximately 70% of our anticipated, non-capital Australian dollar-denominated expenditures. As of December 31, 2006, we had in place forward contracts designated as cash flow hedges with notional amounts outstanding totaling A$1.35 billion of which A$764.2 million, A$359.7 million, A$196.7 million and A$28.8 million will expire in 2007, 2008, 2009, and 2010, respectively. The accounting for these derivatives is discussed in Note 2 to our consolidated financial statements. Our current expectation for 2007 non-capital, Australian dollar-denominated cash expenditures is approximately $1.37 billion. An increase or decrease in the Australian dollar/ U.S. dollar exchange rate of US$0.01 (ignoring the effects of hedging) would result in an increase or decrease, respectively, in our “Operating costs and expenses” of $13.7 million per year.
  Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed-rate debt as a percent of net debt through the use of various hedging instruments, which are discussed in detail in Note 12 to our consolidated financial statements. As of December 31, 2006, after taking into consideration the effects of interest rate swaps, we had $2.61 billion of fixed-rate borrowings and $649.3 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $6.5 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a $0.2 million decrease in the estimated fair value of these borrowings.
  Other Non-trading Activities
  We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 90% of our sales volume under long-term coal supply agreements during 2006 and 2005. As of December 31, 2006, we had 5 to 15 million tons of expected U.S. production unpriced for 2007. We had 14 million tons remaining to be priced in Australia at December 31, 2006. We have approximately 70 to 80 million tons of expected U.S. production unpriced for 2008, with an additional 20 to 22 million tons of expected Australia coal production.
  Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage this risk, we use a combination of forward contracts with our suppliers and financial derivative contracts, primarily swap contracts with financial institutions. As of December 31, 2006, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel and explosives.
  Notional amounts outstanding under fuel-related, derivative swap contracts were 11.6 million gallons of heating oil scheduled to expire through 2007 and 83.2 million gallons of crude oil scheduled to expire through 2009. At December 31, 2006, we had outstanding option contracts designated as a collar of crude oil prices with notional amounts of 43.1 million gallons, expiring through 2007. We expect to consume 100 to 105 million gallons of fuel next year. On a per gallon basis, based on this usage, a change in fuel prices of one cent per gallon (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of approximately $1 million per year. Alternatively, a one dollar per barrel change in the price of crude oil would increase or decrease our annual fuel costs (ignoring the effects of hedging) by approximately $2.4 million.
  Notional amounts outstanding under explosives-related swap contracts, scheduled to expire through 2009, were 5.7 mmbtu of natural gas. We expect to consume 315,000 to 325,000 tons of explosives per year. Through our natural gas hedge contracts, we have fixed prices for approximately 46% of our anticipated explosives requirements for 2007. Based on our expected usage, a change in natural gas prices of ten cents per mmbtu (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of approximately $0.6 million per year.
  Item 8. Financial Statements and Supplementary Data.
  See Part IV, Item 15 of this report for information required by this Item.
  Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
  Item 9A. Controls and Procedures.
  As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective in timely alerting them to material information relating to our company and its consolidated subsidiaries required to be included in our periodic SEC filings.
  There were no changes in our internal control over financial reporting identified during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
  Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
  Because of inherent limitations, any system of internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
  Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control — Integrated Framework. Based on this assessment,
  management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2006.
  Management’s assessment of internal control over financial reporting excludes the operations of Excel Coal Limited acquired during 2006, as allowed by SEC guidance related to internal controls of recently acquired entities. These operations constituted $2.34 billion and $1.58 billion of total and net assets, respectively; and $105.1 million and $8.4 million of revenues and operating profits, respectively; and such amounts are included in our consolidated financial statements as of and for the year ended December 31, 2006. Management did not assess the effectiveness of internal control over financial reporting at these operations because we continue to integrate these operations into our control environment, thus making it impractical to complete an assessment by December 31, 2006.
  Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited this assessment of our internal control over financial reporting, as stated in their attestation report included herein.
  /s/ GREGORY H. BOYCE /s/ RICHARD A. NAVARRE
  Gregory H. Boyce Richard A. Navarre
  President and Chief Executive Officer Chief Financial Officer and
  of Corporate Development
  The Board of Directors and Stockholders
  We have audited management’s assessment, included in the accompanying Management’s Report on Internal Controls, that Peabody Energy Corporation maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Peabody Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
  We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
  A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
  Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
  As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls over Excel Coal Limited acquired in 2006, which is included in the December 31, 2006, consolidated financial statements of Peabody Energy Corporation and constituted $2.34 billion and $1.58 billion of total and net assets, respectively, as of December 31, 2006, and $105.1 million and $8.4 million of revenues and operating profits, respectively, for the year then ended. Our audit of internal control over financial reporting of Peabody Energy Corporation also did not include an evaluation of the internal control over financial reporting of Excel Coal Limited.
  In our opinion, management’s assessment that Peabody Energy Corporation maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Peabody Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.
  We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Peabody Energy Corporation as of
  December 31, 2006 and 2005, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006, and our report dated February 20, 2007, expressed an unqualified opinion thereon.
  Item 9B. Other Information.
  Item 10. Directors, Executive Officers and Corporate Governance.
  The information required by Item 401 of Regulation S-K is included under the caption “Election of Directors” in our 2007 Proxy Statement and in Part I of this report under the caption Executive Officers of the Company. The information required by Item 405, 406 and 407(c)(3), (d)(4) and (d)(5) of Regulation S-K is included under the captions “Ownership of Company Securities — Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance Matters” and “Information Regarding Board of Directors and Committees” in our 2007 Proxy Statement. Such information is incorporated herein by reference.
  Item 11. Executive Compensation.
  The information required by Items 402 and 407 (e)(4) and (e)(5) of Regulation S-K is included under the captions “Executive Compensation,” “Compensation Committee Interlocks and Insider Participation” and “Report of the Compensation Committee” in our 2007 Proxy Statement and is incorporated herein by reference.
  Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
  The information required by Item 403 of Regulation S-K is included under the caption “Ownership of Company Securities” in our 2007 Proxy Statement and is incorporated herein by reference.
  As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2006:
  Number of Securities
  (a) Remaining Available for
  Number of Securities Future Issuance Under
  to be Issued upon Weighted-Average Equity Compensation
  Exercise of Exercise Price of Plans (Excluding
  Outstanding Options, Outstanding Options, Securities Reflected in
  Plan Category Warrants and Rights Warrants and Rights Column (a))
  Equity compensation plans approved by security holders
  9,320,718 $ 8.16 14,967,519
  Equity compensation plans not approved by security holders
  Item 13. Certain Relationships and Related Transactions, and Director Independence.
  The information required by Items 404 and 407(a) of Regulation S-K is included under the captions “Certain Transactions and Relationships” and “Information Regarding Board of Directors and Committees” in our 2007 Proxy Statement and is incorporated herein by reference.
  Item 14. Principal Accounting Fees and Services.
  The information required by Item 9(e) of Schedule 14A is included under the caption “Appointment of Independent Registered Public Accounting Firm and Fees” in our 2007 Proxy Statement and is incorporated herein by reference.
  Item 15. Exhibits and Financial Statement Schedules.
  (a) Documents Filed as Part of the Report
  (1) Financial Statements.
  The following consolidated financial statements of Peabody Energy Corporation are included herein on the pages indicated:
  Consolidated Statements of Operations — Years Ended December 31, 2006, 2005 and 2004
  Consolidated Balance Sheets — December 31, 2006 and December 31, 2005
  Consolidated Statements of Cash Flows — Years Ended December 31, 2006, 2005 and 2004
  Consolidated Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2006, 2005 and 2004
  (2) Financial Statement Schedule.
  The following financial statement schedule of Peabody Energy Corporation and the report thereon of the independent registered public accounting firm are at the pages indicated:
  Report of Independent Registered Public Accounting Firm on Financial Statement Schedule
  Valuation and Qualifying Accounts
  All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.
  (3) Exhibits.
  See Exhibit Index hereto.
  Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
  /s/ GREGORY H. BOYCE
  Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.
  Gregory H. Boyce President, Chief Executive Officer and Director (principal executive officer) February 28, 2007
  /s/ RICHARD A. NAVARRE
  Richard A. Navarre Chief Financial Officer and Executive Vice President of Corporate Development (principal financial and accounting officer) February 28, 2007
  /s/ IRL F. ENGELHARDT
  Irl F. Engelhardt Chairman February 28, 2007
  /s/ B.R. BROWN
  B.R. Brown Director February 28, 2007
  /s/ WILLIAM A. COLEY
  William A. Coley Director February 28, 2007
  /s/ HENRY GIVENS, JR., PhD
  Henry Givens, Jr., PhD Director February 28, 2007
  /s/ WILLIAM E. JAMES
  William E. James Director February 28, 2007
  /s/ ROBERT B. KARN III
  Robert B. Karn III Director February 28, 2007
  /s/ HENRY E. LENTZ
  Henry E. Lentz Director February 28, 2007
  /s/ WILLIAM C. RUSNACK
  William C. Rusnack Director February 28, 2007
  /s/ JAMES R. SCHLESINGER, PhD
  James R. Schlesinger, PhD Director February 28, 2007
  /s/ BLANCHE M. TOUHILL, PhD
  Blanche M. Touhill, PhD Director February 28, 2007
  /s/ JOHN F. TURNER
  John F. Turner Director February 28, 2007
  /s/ SANDRA VAN TREASE
  Sandra Van Trease Director February 28, 2007
  /s/ ALAN H. WASHKOWITZ
  Alan H. Washkowitz Director February 28, 2007
  We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation as of December 31, 2006 and 2005, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
  In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Peabody Energy Corporation at December 31, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.
  As discussed in Note 1 to the consolidated financial statements, on January 1, 2006, the Company changed its method of accounting for stripping costs and share-based payments, and on December 31, 2006, the Company changed its method of accounting for defined pension benefit and other postretirement plans.
  We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 20, 2007, expressed an unqualified opinion thereon.
  $ 5,144,925 $ 4,545,323 $ 3,545,027
  5,256,315 4,644,453 3,631,582
  Net gain on disposal or exchange of assets
  (132,162 ) (101,487 ) (23,829 )
  Income from equity affiliates
  (23,852 ) (30,096 ) (12,399 )
  143,450 102,939 96,793
  1,396 — 1,751
  (12,726 ) (10,641 ) (4,917 )
  Income From Continuing Operations Before Income Taxes and Minority Interests
  (81,515 ) 960 (26,437 )
  Loss from discontinued operations, net of income tax benefit of $1,893
  — — (2,839 )
  $ 600,697 $ 422,653 $ 175,387
  — — (0.01 )
  Weighted Average Shares Outstanding — Basic
  Weighted Average Shares Outstanding — Diluted
  See accompanying notes to consolidated financial statements
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