UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission File Number 1-16463

Peabody Energy Corporation

(Exact name of registrant as specified in its charter)

(314) 342-3400

Registrant’s telephone number, including area code

Securities Registered Pursuant to Section 12(b) of the Act:

Securities Registered Pursuant to Section 12(g) of the Act:

None

      Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act     Yes 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.

DOCUMENTS INCORPORATED BY REFERENCE

      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:

      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.

TABLE OF CONTENTS

PART I

Overview

      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.

History

      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.

Mining Operations

      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.

      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.

      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.

      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.

      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”).

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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 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, 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, 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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

Resource Management

      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.

Sales and Marketing

      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.

Transportation

      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.

Suppliers

      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.

Technical Innovation

      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).

Competition

      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.

      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.

      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.

      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.

Employees

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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 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 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.

      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.

      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.

Global Climate Change

      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.

Additional Information

      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.

Item 1A.     Risk Factors.

      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.

      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.

      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.

      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.

      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.

      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.

      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 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.

      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 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:

      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.

      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.

      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:

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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.

      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 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.

      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 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.

      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.

      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.

      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.

      None.

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.

      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:

      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⁾

(Tons in millions)

     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

(Tons in millions)