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 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.     Yes þ

      Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)     Yes þ          No o

      Aggregate market value of the voting stock held by non-affiliates of the Registrant, calculated using the closing price on June 30, 2004: Common Stock, par value $0.01 per share, $2,777.9 million.

      Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 28, 2005: Common Stock, par value $0.01 per share, 65,327,329 shares outstanding, or 130,654,658 shares outstanding after giving retroactive effect to the registrant’s two-for-one stock split, effective March 30, 2005 for shareholders of record on March 16, 2005.

DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the Peabody Energy Corporation (the “Company”) Annual Report for the year ended December 31, 2004 are incorporated by reference into Part II hereof. Portions of the Company’s Proxy Statement to be filed with the SEC in connection with the Company’s Annual Meeting of Stockholders to be held on May 6, 2005 (the “Company’s 2005 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, such statements in 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 open 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 the documents incorporated by reference. We will not update these statements unless the securities laws require us to do so.

TABLE OF CONTENTS

PART I

Overview

      We are the largest private-sector coal company in the world. During the year ended December 31, 2004, we sold 227.2 million tons of coal. During this period, we sold coal to over 300 electricity generating and industrial plants in 16 countries. Our coal products fuel more than 10% of all U.S. electricity generation and 3% of worldwide electricity generation. At December 31, 2004, we had 9.3 billion tons of proven and probable coal reserves. The 9.3 billion tons of proven and probable coal reserves did not include approximately 300 million tons (based on Bureau of Land Management estimates) of Powder River Basin reserves we recently gained control of through a successful Federal Coal Lease bid.

      We own, through our subsidiaries, majority interests in 32 coal operations located throughout all major U.S. coal producing regions and in Australia. Additionally, we own interests in four mines through joint venture arrangements. We shipped 73% of our U.S. mining operations’ coal sales from the western United States during the year ended December 31, 2004 and the remaining 27% 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 37.0 million tons in fiscal year 1990 to 142.6 million tons during 2004, representing a compounded annual growth rate of 10%. 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 4 mines in Queensland, Australia, one of which was acquired in 2002, two were acquired during April 2004 and a fourth that was opened after the 2004 acquisition. Most of our Australian production is low-sulfur, metallurgical coal. We generated 79% of our production for the year ended December 31, 2004 from non-union mines.

      For the year ended December 31, 2004, 90% of our sales were to U.S. electricity generators, 7% were to customers outside the United States and 3% were to the U.S. industrial sector. Approximately 90% of our coal sales during the year ended December 31, 2004 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, 2004. The average volume weighted remaining term of our long-term contracts was approximately 3.4 years, with remaining terms ranging from one to 17 years. As of December 31, 2004, we had 5 to 10 million tons, 65 to 75 million tons and 130 to 140 million tons for 2005, 2006 and 2007, respectively, of expected production (including steam and metallurgical coal production) available for sale or repricing at market prices. We have an annual metallurgical coal production capacity of 12 to 14 million tons. Approximately 90% of our expected 2005 metallurgical coal production is priced, and our 2006 metallurgical production is mostly unpriced. The portion of 2006 that is priced primarily relates to tonnage committed at our Australian operations for delivery in the period from April 1, 2005 to March 31, 2006, the traditional contract year for many customers purchasing seaborne metallurgical coal. The metallurgical production we priced for 2005 and 2006 is priced, on average, at levels significantly above historical metallurgical coal prices.

      In addition to our mining operations, we market, broker and trade coal. Our total tons traded were 33.4 million for the year ended December 31, 2004. Our other energy related businesses 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 transportation services.

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 1990’s, 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 (ADR’s) 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.

      In January 2001, we sold our Peabody Resources Limited (in Australia) operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto Limited for $575 million (including debt assumed by the buyer).

      In April 2001, we changed our name to Peabody Energy Corporation (“Peabody”), reflecting our position as a premier energy supplier. In May 2001, after having reduced the debt incurred in the leveraged buyout by more than $1 billion, we completed an initial public offering of common stock, and the Company’s 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 three coal operations from RAG Coal International AG for a combined purchase price of $421 million, net of cash received in the transaction. The purchase included two mines in Queensland, Australia that produce a combined 7 to 8 million tons per year of metallurgical coal, and the Twentymile Mine in Colorado, which historically produced 7 to 8 million tons per year of low-sulfur, steam coal. In December 2004, we completed the purchase of a 25.5% equity interest in Carbones del Guasare, S.A. from RAG Coal International AG for a net purchase price of $32.5 million. Carbones del Guasare, a joint venture that also includes Anglo American plc and a Venezuelan governmental partner, operates the Paso Diablo surface mine in northwestern Venezuela, which produces approximately 7 million tons per year of coal for electricity generators and steel producers.

      From 1990 to 2004, Peabody redefined its business, as the company transformed itself into a more productive, low-cost, low-sulfur energy company, tripling its productivity and reducing costs 32% while improving safety performance 74%. In the 1990’s, we established our three core strategies: 1) managing safe, low-cost operations; 2) utilizing world-class sales and trading practices; and 3) creating value from our natural resource position.

Mining Operations

      The following provides a description of the operating characteristics of the principal mines and reserves of each of our business units and affiliates. The maps below show the mines we operated in 2004.

      Within the United States, we conduct operations in the Powder River Basin, Southwest, Colorado, Appalachia and Midwest regions. Internationally, we operate mines in Queensland, Australia and have a 25.5% interest in a mine in Venezuela. All of our operating segments are discussed in Note 26 to our consolidated financial statements.

      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 indicative of the subsidiary or subsidiaries which own the assets utilized in that mining operation.

Powder River Basin Operations

      We control approximately 3.1 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 Company and Caballo Coal Company, manage three low-sulfur, non-union surface mining complexes in Wyoming that sold 115.8 million tons of coal during the year ended December 31, 2004, or approximately 51% 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 Railway and the Union Pacific Railroad. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway.

      Our Wyoming Powder River Basin reserves are classified as surface mineable, subbituminous coal with seam thickness varying from 70 to 105 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 9,000 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 82.5 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu) during 2004. The North Antelope Rochelle facility is capable of loading its production in up to 2,000 railcars per day. 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.

      The Caballo Mine is located 20 miles south of Gillette, Wyoming. During 2004, it sold 26.5 million tons of compliance coal. Caballo is a truck-and-shovel operation with a coal handling system that includes two 12,000-ton silos and two 11,000-ton silos.

      The Rawhide Mine is located ten miles north of Gillette, Wyoming and uses truck-and-shovel mining methods. During 2004, it sold 6.9 million tons of compliance coal.

Southwest Operations

      We own and operate three mines in our Southwest operations — two in Arizona and one in New Mexico. The Arizona mines, which are managed by our Peabody Western Coal Company subsidiary, supply primarily bituminous compliance coal under long-term coal supply agreements to electricity generating stations in the region. 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 three mines sold 18.7 million tons of coal during 2004 and control 1.0 billion of proven and probable coal reserves.

      The Black Mesa Mine, which is located on the reservations of the Navajo Nation and Hopi Tribe in Arizona, uses two draglines and sold 4.7 million tons of coal during 2004. The Black Mesa Mine coal is crushed, mixed with water and then transported 273 miles through an underground pipeline owned by a third party. The coal is conveyed to the Mohave Generating Station near Laughlin, Nevada, which is operated and partially owned by Southern California Edison. The mine and pipeline were designed to deliver coal exclusively to the plant, which has no other source of coal. The Mohave Generating Station coal supply agreement extends until December 31, 2005. Further discussion of the issues surrounding the future of the Black Mesa Mine and Mohave Generating Station is provided in Item 3. Legal Proceedings of this report. Hourly workers at this mine are members of the United Mine Workers of America.

      The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines in three mining areas. It sold approximately 8.4 million tons of coal during 2004. 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.

      The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 5.6 million tons of medium sulfur coal during 2004. 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 Burlington Northern Santa Fe Railway.

Colorado Operations

      We control approximately 0.3 billion tons of coal reserves and currently have two mines operating in the Colorado Region. Our Twentymile underground mine is managed by our Twentymile Coal Company subsidiary and our Seneca surface mine is managed by our Seneca Coal Company subsidiary. During 2004, these operations sold approximately 7.6 million tons of compliance, low-sulfur, steam coal of above average heat content to customers throughout the United States.

      On April 15, 2004, we purchased the Twentymile Mine from RAG Coal International AG as discussed in Note 5 to our consolidated financial statements. The Twentymile Mine is located in Routt County, Colorado, and sold approximately 6.2 million tons of steam coal since the acquisition. This mine uses both longwall and continuous mining equipment and has perennially been one of the largest and most productive underground mines in the United States. The coal quality is high enough that only a small portion of the coal is washed, normally less than 15%. Approximately 95% all coal shipped is loaded on the Union Pacific railroad; the remainder is hauled by truck.

      The Seneca Mine near Hayden, Colorado shipped 1.5 million tons of compliance coal during 2004, operating with two draglines and a highwall miner in three separate mining areas. The mine’s coal is hauled by truck to the nearby Hayden Generating Station, operated by the Public Service of Colorado, under a coal supply agreement that extends until 2011. This mine is near the exhaustion of its economically recoverable reserves and upon closure (expected in late 2005) the Twentymile Mine is expected to supply the Hayden Generating Station. The mine’s closure is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. Hourly workers at Seneca are members of the United Mine Workers of America.

Appalachia Operations

      We manage five wholly-owned business units and related facilities in West Virginia and one in Western Kentucky. Our subsidiary, Pine Ridge Coal Company, manages the Big Mountain business unit, and our subsidiary, Rivers Edge Mining, Inc. manages our Rivers Edge Mine. Our Eastern Associated Coal Corp. subsidiary manages the remaining wholly-owned West Virginia facilities. In addition, Highland Mining manages the Highland Mine in Western Kentucky. During 2004, these operations sold approximately 19.2 million tons of compliance, medium-sulfur, high-sulfur steam and metallurgical coal to customers in the United States and abroad. Metallurgical coal accounted for 5.0 million tons of total sales for the year. All of the hourly workers at these subsidiaries are members of the United Mine Workers of America. In addition to our wholly-owned facilities, we own a 49% interest in Kanawha Eagle Mine, a joint venture which owns and manages underground mining operations. We control approximately 0.8 billion tons of proven and probable coal reserves in our Appalachia Operations.

      The Big Mountain business unit is based near Prenter, West Virginia. This business unit’s primary mine is Big Mountain No. 16, and includes a small amount of contract mine production from coal reserves we control. During 2004, the Big Mountain business unit sold approximately 1.9 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.

      The Harris business unit consists of the Harris No. 1 Mine near Bald Knob, West Virginia, which sold approximately 3.1 million tons of primarily metallurgical product during 2004. This mine uses both longwall and continuous mining equipment.

      The Rocklick preparation plant, located near Wharton, West Virginia, processes coal produced by the Harris No. 1 Mine and contract mining operations from coal reserves that we control. This preparation plant shipped approximately 2.0 million tons of steam and metallurgical coal sourced from the contract mines during 2004. 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.

      The Wells business unit, in Boone County, West Virginia, sold approximately 4.0 million tons of metallurgical and steam coal during 2004. The unit consists of the Wells preparation plant, which processes purchased coal and production from our River’s Edge Mine and contract mines. The preparation plant is located near Wharton, West Virginia and the processed coal is loaded on the CSX railroad.

      The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining methods and shipped approximately 4.8 million tons of steam coal during 2004. Coal shipped from the Federal No. 2 Mine has a sulfur content only slightly above that of medium sulfur coal and has above average heating content. As a result, it is more marketable than some other medium sulfur coals. The CSX and Norfolk Southern railroads jointly serve the mine.

      The Highland No. 9 Mine, which is managed by our Highland Mining Company subsidiary, is located near Waverly, Kentucky, and produced 3.3 million tons during 2004. Hourly workers at these operations are members of the United Mine Workers of America.

      We have a 49% interest in the Kanawha Eagle 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. They shipped 2.5 million tons during 2004.

Midwest Operations

      Our Midwest operations consist of 13 wholly-owned mines in the Illinois basin and are comprised of our Patriot Coal Company, Indian Hill Company and Black Beauty Coal Company subsidiaries. Our Midwest Operations control approximately 3.8 billion tons of proven and probable coal reserves. In 2004, these operations collectively sold 32.5 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 that generate their own power.

      Patriot Coal Company, owns and manages three mines. Patriot, a surface mine, and Freedom, an underground mine, are located in Henderson County, Kentucky. The Big Run underground mine is located in Ohio County, Kentucky. These mines sold 1.4 million tons, 1.5 million tons and 1.3 million tons, respectively, in 2004. The underground mines use continuous mining equipment and the surface mine uses truck and shovel equipment. Patriot Coal Company also manages a preparation plant and a dock. Patriot Coal Company operations utilize a non-union workforce.

      In late 2004, we purchased, through our wholly-owned subsidiary, Indian Hill Company, the remaining 55% interest of Dodge Hill Holding JV, LLC. Dodge Hill Holding manages Dodge Hill No. 1, an underground operation located in Union County, Kentucky which mined 1.2 million tons in 2004 utilizing non-union labor.

      Black Beauty Coal Company currently manages six mines in Indiana and three mines in Illinois. The Black Beauty mines produced and sold 27.1 million tons of compliance, medium sulfur and high sulfur steam coal during 2004.

      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 shipped 1.7 million tons of compliance coal during 2004. Farmersburg is a surface mine situated in Vigo and Sullivan counties in Indiana that sold 4.3 million tons of medium sulfur coal during 2004. The Francisco Mine, 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 2004. The Somerville mine complex, also located in Gibson County, shipped a total of 7.2 million tons of medium sulfur coal in 2004. Two other surface mines located in Indiana, Viking and Miller Creek, collectively shipped 2.3 million tons of medium sulfur coal during 2004.

      In east-central Illinois, Black Beauty’s Riola Complex is an underground mining facility with two active portals. The Riola Complex sold 2.3 million tons of medium sulfur coal during 2004. We operate the Cottage Grove surface mine and Willow Lake underground mining complex situated in Gallatin and Saline counties in southern Illinois. During 2004, these mines sold 2.7 million tons and 3.5 million tons, respectively, of medium sulfur coal that is primarily shipped by barge to downriver utility plants. Black Beauty provides a non-union contract workforce for the Arclar surface operation. The workforce at the Willow Lake underground mine is represented under a non-UMWA labor agreement that expires in late 2006. All other Black Beauty Coal Company operations utilize non-union labor.

      Black Beauty also owns a 75% interest in United Minerals Company, LLC (“United Minerals”). United Minerals, which utilizes non-union labor, currently acts as a contract miner for Black Beauty at part of the Somerville Mine Complex and as contract operator for Black Beauty at the Evansville River Terminal.

Australian Mining Operations

      We manage four mines in Queensland, Australia through our wholly-owned subsidiary, Peabody Pacific Pty Limited. In addition to our Wilkie Creek Mine acquired in August 2002, we purchased two coal mines, Burton and North Goonyella, on April 15, 2004 and recently opened our Eaglefield Mine, which is a surface operation adjacent to, and fulfilling contract tonnages in conjunction with, the North Goonyella underground mine. During 2004, these operations sold 6.1 million tons of coal, 4.4 millions tons

of which were metallurgical coal. Coal from these mines is shipped via rail from the mine to the loading point at Dalrymple Bay, where the coal is loaded onto ocean-going vessels. All 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 0.2 billion tons of proven and probable reserves.

      Our Wilkie Creek Coal Mine is a surface, truck-and-shovel operation. For the year ended December 31, 2004, the mine’s contract workforce produced 1.3 million tons of steam coal, which was sold to the Asia export market.

      Burton is a surface mine using the truck-and-shovel mining technique. From the date of acquisition in 2004, the Burton Mine sold 3.1 million tons of metallurgical coal. We own 95% of the Burton operation and the remaining five percent interest is owned by the contract miner operating on reserves that we control.

      The North Goonyella Mine is a longwall underground operation. From the date of acquisition in 2004, the North Goonyella Mine sold 1.7 million tons of coal.

      Our recently opened Eaglefield Mine 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.

Venezuelan Mining Operations

      In December 2004, we acquired 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 7 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.

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 17 years and an average volume-weighted remaining term of approximately 3.4 years. For 2004, we sold approximately 90% of our sales volume under long-term coal supply agreements. In 2004, we sold coal to over 300 electricity generating and industrial plants in 16 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. Two of our largest coal supply agreements are the subject of ongoing litigation and arbitration, as discussed at 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 supply contracts when we can do so at prices we believe are favorable. As of December 31, 2004, we had 5 to 10 million tons, 65 to 75 million tons and 130 to 140 million tons for 2005, 2006 and 2007, respectively, of expected production (including steam and metallurgical coal production) available for sale or repricing at market prices. We have an

annual metallurgical coal production capacity of 12 to 14 million tons. Approximately 90% of our expected 2005 metallurgical coal production is priced, and our 2006 metallurgical production is mostly unpriced. The portion of 2006 that is priced primarily relates to tonnage committed at our Australian operations for delivery in the period from April 1, 2005 to March 31, 2006, the traditional contract year for many customers purchasing seaborne metallurgical coal. The metallurgical production we priced for 2005 and 2006 is priced, on average, at levels significantly above historical metallurgical coal prices.

      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, including unexpected downturns in market prices.

      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 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 of 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, the purchaser 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, 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.

Sales and Marketing

      Our sales, trading, brokerage and marketing operations include COALSALES, LLC; COALSALES II, LLC (formerly Peabody COALSALES Company); COALTRADE, LLC (formerly Peabody COALTRADE, Inc.) and COALTRADE International, LLC. Through our sales, trading, brokerage and marketing, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and agent, trade coal and emission allowances, and provide transportation-related services. As of December 31, 2004, we had 74 employees in our sales, trading, brokerage, marketing and transportation operations, including personnel dedicated to performing market research, contract administration and risk/credit management activities. These operations also include seven employees at our COALTRADE Australia operation, which brokers coal in the Australia and Pacific Rim markets, and is based in Newcastle, Australia.

Transportation

      Coal consumed domestically is usually 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 and ocean-going vessels. Our transportation department manages the loading of trains and barges.

      Coal from our Black Mesa Mine in Arizona is transported by a 273-mile coal-water pipeline to the Mohave Generating Station in southern Nevada. Coal from the Seneca Mine in Colorado is transported by truck to the nearby Hayden Plant. All coal from our southern Powder River Basin mines in Wyoming is shipped by rail, and two competing railroads, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad, serve our North Antelope Rochelle and Caballo mines. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway. 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 enjoy 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 products and lubricants. We have many long, established relationships with our key suppliers, and 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 has been some consolidation. Recent 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, alternative sources are available to us in the regions where we operate. Further, purchases of certain

underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop. In the past year, 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 by up to several months, although no material impact is currently expected to our financial condition, results of operations or cash flows.

Technical Innovation

      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.

      A major effort has been under way to improve the performance of our draglines which move a third of the billion tons of overburden handled annually. 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 new digital drive design has been tested on an overburden shovel in the Powder River Basin with excellent results and will be installed on our other shovels. Blasting performance has improved through the use of new products including digital detonation, air decking, blast-hole sleeving and new blasting agents. Filtered used lubrication oils are also utilized in our blasting products.

      We plan to install a longwall system at our Twentymile Mine with state-of-the-art controls and software to enable increased mine output beginning in 2006. In addition, the North Goonyella Mine in Australia has purchased upgraded longwall components to widen the longwall face and improve operating performance. We have two state-of-the-art flexible coal train conveyor systems in operation at our Highland Mine that continuously transport coal from the continuous miner to the conveyor belt system. Upgrades at four preparation plants are scheduled in 2005 which will improve coal recovery and output.

      World-class maintenance standards based on condition-based maintenance practices are being implemented at all operations. Using these techniques allows us to increase equipment utilization and reduce capital through 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. We are upgrading our computerized maintenance management system to support our maintenance practices. Also, a remote data acquisition system is being installed to more efficiently dispatch mobile equipment and monitor equipment performance on a real-time basis.

      Our mines use sophisticated software to schedule and monitor trains, mine and pit blending, quality and customer shipments. The integrated software has been developed in-house and provides a competitive tool to differentiate our reliability and product consistency. We are the largest user of advanced coal quality analyzers among coal producers, according to the manufacturer of this sophisticated 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 also support the Power Systems Development Facility, a highly efficient electricity generating plant using coal gasification generation technology, funded primarily through the U.S. Department of Energy and operated by an affiliate of Southern Company. Peabody is a member of the multi-company alliance working with the Department of Energy on FutureGen, a long-term project to develop near-zero emission power generation technology that will produce both power and hydrogen from coal and will capture and sequester carbon dioxide.

Competition

      The markets in which we sell our coal are highly competitive. According to the National Mining Association’s “2003 Coal Producer Survey,” the top 10 coal companies in the United States produced approximately 69% of total domestic coal in 2003. Our principal U.S. competitors are other large coal producers, including Kennecott Energy Company, Arch Coal, Inc., Foundation Coal, CONSOL Energy Inc. and Massey Energy Company, which collectively accounted for approximately 41% of total U.S. coal production in 2003. 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 best maximize our coal assets and land holdings for long-term growth, we are developing coal-fueled generating projects in areas of the country where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal.

      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 described below are expected to be operational following a four-year construction phase, which is conditioned upon the company completing all necessary permitting, selection of partners, securing financing and selling the majority of the output of the plant. These plants will not be operational until at least 2010.

      Our Prairie State Energy Campus is a planned 1,500-megawatt coal-fueled electricity generation project located in Washington County, Illinois. Prairie State would be fueled by 6 million tons of coal each year produced from an adjacent underground mine. During August of 2004, Prairie State signed a letter of intent with Fluor Daniel Illinois, Inc. for engineering, design and construction of Prairie State’s power-related facilities. In January 2005, Prairie State achieved a major milestone when the State of Illinois issued the final air permit for the electric generating station and adjoining coal mine. 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, Kentucky Municipal Power Agency, Wolverine Power Cooperative, Northern Illinois Municipal Power Agency, Indiana Municipal Power Agency and the Missouri Joint Municipal Electric Utility Commission. In February 2005, certain parties filed an appeal with the Environmental Appeals Board in Washington, D.C. challenging the air permit issued by the Illinois Environmental Protection Agency. The appeal must be resolved before construction of the project can begin.

      In 2003, we achieved a major milestone in the development of the 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky, when we received a conditional Certificate to Construct

from the Commonwealth of Kentucky. We and the Commonwealth of Kentucky are defending the air permit granted in 2002 to Thoroughbred Energy Campus, as certain environmental groups are challenging the air permit. Hearings and final briefings were completed before year end and we now await the findings of the Administrative Law Judge.

      In October 2004, our Mustang Energy Project was awarded a $19.7 million Clean Coal Power Initiative grant from the Department of Energy to demonstrate technology to achieve ultra-low emissions at the proposed 300 megawatt generating station near Grants, New Mexico. The project is in the early stages of obtaining all necessary permits. If successfully completed, the Mustang Energy project would be located near our Lee Ranch Coal Company operations using lands and coal reserves controlled by us. The plant would be fueled by about 1 million tons of coal each year. The plant is expected to use proprietary technology to remove 99.5% of sulfur dioxide, 98% of nitrogen oxide and 90% of mercury from the plant’s emissions. By-products from the scrubbing process would be used to create high value, granular fertilizer.

Coalbed Methane

      We continue to evaluate the potential of the coalbed methane business and will make acquisitions, develop our properties, enter into partnerships with other companies or make property sales as appropriate. Our subsidiary, Peabody Natural Gas, LLC, produces coalbed methane from its operations in the Southern Powder River Basin near the Caballo Mine and North Antelope Rochelle Mine. At December 31, 2004, we operated 60 coalbed methane wells with net production of approximately 2.4 million cubic feet per day. We are also evaluating the coalbed methane resources in several deep coal seams on more than 27,000 acres in the Western Powder River Basin near Buffalo, Wyoming. We purchased these coalbed methane assets in January 2001 and are engaged in an ongoing drilling and testing program to continue to evaluate the property. In Southern Illinois, Peabody Natural Gas is continuing a five-well coalbed methane pilot program at its Broughton project. More than 15,000 net coal acres and coalbed methane leases covering property near the Broughton project were purchased in December 2003 and have been added to the project. In June 2004, we purchased operating rights and a 50% working interest in a five-well coalbed methane pilot program on over 9,400 acres in Gallatin County, Illinois. The test program is being conducted with AFS Development Company, LLC, an affiliate of Ameren Corporation. A coalbed methane testing program is also being conducted in Western Kentucky.

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 United Mine Workers of America and voluntary arrangements with non-union employees include long-term benefits, notably health care coverage for retired and future retirees and their dependents. The majority of our existing liabilities relate to our past operations, which had more mines and employees than we currently have.

      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. Our asset retirement obligations totaled approximately $396.0 million as of December 31, 2004. Expense for the years ended December 31, 2004, 2003 and 2002 was $42.4 million, $31.2 million and $11.0 million, respectively. Our method for accounting for reclamation activities changed on January 1, 2003 as a result of the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” The effect of the adoption of SFAS No. 143 is discussed in Note 6 to our consolidated financial statements. Total asset retirement obligations as of December 31, 2004 of $396.0 million consisted of $303.7 million related to locations with active mining operations and $92.3 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 former employees who filed claims after June 1973. These liabilities totaled approximately $268.9 million as of December 31, 2004, $41.4 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $59.2 million, $50.6 million and $55.4 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 Employee Retirement Income Security Act minimum funding standards and an agreement with the Pension Benefit Guaranty Corporation. Pension-related liabilities totaled approximately $95.8 million as of December 31, 2004, $5.8 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $28.5 million, $20.7 million and $4.8 million, respectively.

      Retiree Health Care. Consistent with SFAS No. 106, 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.

      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 our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of out of business 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 also created by the same federal law in 1992 provides benefits to qualifying retired former employees of 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, 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, however our liability is limited to our contractual commitment of $0.50 per hour worked.

      Our retiree health care liabilities totaled approximately $1,020.8 million as of December 31, 2004, $81.3 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $58.4 million, $83.6 million and $74.4 million, respectively. Obligations to the United Mine Workers of America Combined Fund totaled $39.8 million as of December 31, 2004, $6.4 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $4.9 million, $1.2 million and $16.7 million, respectively. The expense recorded during the year ended December 31, 2002 reflects the reassignment of certain beneficiaries to us as a result of an adverse U.S. Supreme Court decision in January 2003. Those beneficiaries had been deemed improperly assigned to us in a prior U.S. Circuit Court decision. The 1992 Fund and the 1993 Fund are expensed as payments are made and no liability was recorded other than amounts due and unpaid. Expense related to these funds was $4.4 million, $5.3 million and $4.1 million for the years ended December 31, 2004, 2003 and 2002 respectively.

Employees

      As of December 31, 2004, we and our subsidiaries had approximately 7,900 employees. As of December 31, 2004, approximately 60% of our hourly employees were non-union and they generated 79%

of our 2004 coal production. Relations with our employees and, where applicable, organized labor are important to our success.

      Approximately 63% of our U.S. miners are non-union and are employed in the states of Wyoming, Colorado, Indiana, New Mexico, Illinois and Kentucky. The United Mine Workers of America represented approximately 30% of our hourly employees, who generated 16% of our domestic production during the year ended December 31, 2004. An additional 6% of our hourly employees are represented by labor unions other than the United Mine Workers of America. These employees generated 2% of our production during the year ended December 31, 2004. Hourly workers at our mines in Arizona and one of our mines in Colorado are represented by the United Mine Workers of America under the Western Surface Agreement, which was ratified in 2000 and is effective through September 1, 2005. Our union labor east of the Mississippi River is primarily represented by the United Mine Workers of America and the majority of union mines are subject to the National Bituminous Coal Wage Agreement. The current five-year labor agreement was ratified in December 2001 and is effective through December 31, 2006.

      The Australian coal mining industry is highly unionized and the majority of workers employed at our Australian Mining Operations are members of trade unions. These employees are represented by three unions: the Construction Forestry Mining and Energy Union (“CFMEU”), which represents the production employees, and two unions that represent the other staff. Our Australian employees are approximately 4% of our entire workforce and generated 3% of our total production in the year ended December 31, 2004. The miners at Wilkie Creek operate under a labor agreement that expires in June 2006. The miners at Burton operate under a labor agreement that is currently under negotiation. The miners at North Goonyella operate under a labor agreement which expires in March 2008. The miners at Eaglefield operate under a labor agreement that expires in May 2007.

      The Australian Federal Government, as part of micro-economic reform, has long had a Workplace Relations Strategy that seeks structural reform to encourage an enterprise focus and to facilitate enterprise agreements. Further industrial reform is likely from July 1, 2005 when the Federal Government has control of both Houses of Parliament.

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 may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment. These requirements could prove costly and time-consuming and could delay commencing or continuing exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, our activities may be more closely regulated. Such legislation and regulations, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.

      We 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.

      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.

      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. While regulation has a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation.

      Our goal is to achieve excellent safety and health performance. We measure our success 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 establishing 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.

      In the U.S., 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 secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits by the federal government. 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 United Mine Workers of America 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 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 $19.3 million, $20.6 million and $11.1 million, respectively, during the years ended December 31, 2004, 2003 and 2002.

      In 1995, in a case filed by the National Coal Association on behalf of its members, a federal district court in Alabama ordered the Commissioner of Social Security to recalculate the per-beneficiary premium which the Combined Fund charges assigned operators. The Commissioner applied the recalculated, lower premium to all assigned operators, including our subsidiaries. As a result of separate litigation brought by the Combined Fund, a Washington, D.C. federal district court ruled on February 25, 2000 that the original, higher per beneficiary premium was proper and that decision was upheld on appeal. The Commissioner of Social Security issued a higher premium recalculation in 2003 to our subsidiaries and other coal companies. Other coal companies and our subsidiaries filed a lawsuit seeking a determination that the Commissioner’s 2003 premium recalculation was improper or not applicable to them and that lawsuit has been transferred to federal court in Maryland.

      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 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. If the Combined Fund is able to obtain a court decision that would confirm the applicability of the higher premium rate to our subsidiaries, our subsidiaries will not be able to seek a refund of the premiums paid under protest. In that event, the prospective annual premium would also increase by approximately 12%.

      Additionally, the Trustees assessed our subsidiaries a $1.1 million contribution for the period October 1, 2003 through September 30, 2004 related to an estimated shortfall in the amount necessary to fund the required unassigned orphaned beneficiary premium. This amount was also paid in twelve monthly installments as required by the Combined Fund Trustees, but was paid under protest.

      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 U.S., 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 review 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 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, which expired on September 30, 2004 and was subsequently extended to June 30, 2005, is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. It is expected the fee will be renewed, although its purpose and the amount per ton are still to be determined as part of the United States government’s budget process.

      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”); Comprehensive Environmental Response, Compensation, and Liability Acts (“CERCLA”) superfund and employee right-to-know provisions. 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 (“COE”) 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, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen 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. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. At this time, we believe that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur coals, as additional coal-based electricity generating plants have complied with the restrictions of Title IV.

      In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for very fine particulate matter 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, EPA proposed the Clean Air Interstate Rule, 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. The rules will reduce sulfur dioxide and nitrogen oxide emissions by approximately 70% from current levels by 2015.

      The Clean Air Act also requires electricity generators that currently are major sources of nitrogen oxide in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxide, which is a precursor of ozone. In addition, the EPA promulgated the final “NOx SIP Call” rules that would require coal-fueled power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions. These regulations became fully effective for these states in May 2004. Portions of two additional states will complete their NOX SIPs in 2005 as the final installment of the requirement. Installation of additional control measures required under the final rules will 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. Our customers are among the named electricity generators 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 October 2003, EPA promulgated new regulations clarifying the types of plant modifications that electric generators could make without triggering best available control technology requirements. These regulations could affect the pending new source review cases and whether additional cases are brought. Various parties filed an appeal of these regulations in the United States Court of Appeals for the D.C. Circuit. The Court issued a stay of these regulations pending a decision on the merits.

      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 are 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, with EPA expected to issue new regulations in the Spring of 2005. Five western states have elected an option offered by EPA of regulating visibility-impairing emissions through a regional rather than a source-by-source approach. However, this option is currently the subject of litigation, with a court decision expected over the next several months. EPA’s regional haze regulations, once finalized, 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.

      EPA recently issued proposed regulations setting forth two alternative approaches for regulating mercury emissions from electric generating stations. Under one approach, mercury emissions would be reduced by about 30 percent by 2007 from current emission rates. Under the other approach, mercury emissions would be reduced in two stages in 2010 and 2018, with an emissions reduction of 70 percent by the latter year. Implementation of either of these or similar proposals 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.

      Legislation supported by the Administration has been introduced in Congress that would reduce emissions of sulfur dioxide, nitrogen oxide and mercury in phases, with reductions of 70 percent by 2018.

Other similar emission reduction proposals have been introduced in Congress, some of which propose to also regulate carbon dioxide. No such legislation has passed either house of the Congress. If this type of legislation were enacted into law, it could impact the amount of coal supplied to those 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. 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 Clean Water Act of 1972 affects U.S. coal mining operations by establishing in-stream water quality standards 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.

      Section 404 under the Clean Water Act requires mining companies to obtain permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.

      On October 23, 2003, several citizens groups sued the COE in the U.S. District Court for the Southern District of West Virginia seeking to invalidate a “nationwide” permit utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs seek to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional filling under existing nationwide permit approvals until they obtain more detailed “individual” permits. On July 8, 2004, the U.S. District Court ruled in favor of the citizens groups. The court found the COE’s procedure in authorizing projects under the nationwide permit process was in violation of the Clean Water Act. The court enjoined the COE from using nationwide permits in the Southern District of West Virginia. The District Court’s decision has been appealed to the Fourth Circuit Court of Appeals. We believe our existing operations will not be significantly impacted. However, permits for new mines and permit revisions for existing mines may experience additional permit requirements and potential delays in permit approvals.

      Total Maximum Daily Load (“TMDL”) regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL effluent standards for these stream segments. The adoption of new TMDL effluent limitations for our coal mines could require more costly water treatment and could adversely affect our coal production.

      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 prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality/exceptional use streams will be required to meet or exceed new high quality/exceptional use standards. The designation of high quality streams at our coal mines could require more costly water treatment and could aversely affect our coal production.

      The Resource Conservation and Recovery Act (“RCRA”), which was enacted in 1976, affects U.S. coal mining operations by establishing requirements for the treatment, storage and disposal of hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

      Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill. The agency also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators.

      The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” — commonly known as Superfund) 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 listed toxic materials that exceed defined quantities. We report chemicals used in water treatment and ash received for disposal from power generation customers.

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 and 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 rehabilitation.

      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.

      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 an approval to be 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 itself (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 filled. 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 in respect of the compensation of injured workers; similar schemes are in effect throughout Australia which are 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

      The United States, Australia and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which addresses emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place in the U.S., these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. 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. In March 2001, President Bush reiterated his opposition to the Kyoto Protocol and further stated that he did not believe that the government should impose mandatory carbon dioxide emission reductions on power plants. In February 2002, President Bush announced a new approach to climate change, confirming the Administration’s opposition to the Kyoto Protocol and proposing voluntary actions to reduce the greenhouse gas intensity of the United States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The President’s climate change initiative calls for a reduction in greenhouse gas intensity of 18% over the next 10 years which is approximately equivalent to the reduction that has occurred over each of the past two decades. Ratification and

implementation of the Kyoto Protocol 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.

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 without 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 450 Fifth Street, N.W., 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, at no cost, 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.

Coal Reserves

      We had an estimated 9.3 billion tons of proven and probable coal reserves as of December 31, 2004. An estimated 9.1 billion tons of our proven and probable coal reserves are in the United States and 0.2 billion tons are in Australia. Forty-one percent of our reserves, or 3.8 billion tons, are compliance coal and 59% are non-compliance coal. We own approximately 43% of these reserves and lease property containing the remaining 57%. 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 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 reserve 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 and with an acceptable profit margin 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 reviews, which was completed in April 2003, 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 study confirmed that we controlled approximately 9.1 billion tons of proven and probable reserves as of December 31, 2002. After adjusting for acquisitions, divestitures, production and estimate refinements (through additional drilling and exploration) through December 31, 2004, proven and probable reserves totaled 9.3 billion tons.

      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. 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 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, 2004, we leased 11,922 acres of federal land in Colorado, 11,254 acres in Montana and 36,964 acres in Wyoming, for a total of 60,140 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 9.3 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, 2004 and 2003 and 2002, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities. The chart below breaks down our assigned proven and probable reserves into the mining complexes located in a particular geographic region, and does not indicate the legal entity that owns or controls the reserves.

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, the predominant type of coal mined in the applicable location, our property interest in the reserves and other characteristics of the facilities. The chart below breaks down our proven and probable reserves into geographic regions, and does not indicate the legal entity that owns or controls the reserves.

ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES

As of December 31, 2004

(Tons in millions)

Resource Development

      We hold approximately 9.3 billion tons of proven and probable coal reserves and interest in approximately 400,000 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.

      From time to time, we are involved in legal proceedings arising in the ordinary course of business. We believe we have recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on our financial condition, results of operations or cash flows. We discuss our significant legal proceedings below.

Navajo Nation

      On June 18, 1999, the Navajo Nation served our subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company (“Peabody Western”), with a complaint that had been filed in the U.S. District Court for the District of Columbia. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act, or RICO, violations and fraud and tortious interference with contractual relationships. The complaint alleges that the defendants

jointly participated in unlawful activity to obtain favorable coal lease amendments. Plaintiff also alleges that defendants interfered with the fiduciary relationship between the United States and the Navajo Nation. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases for the Kayenta and Black Mesa mines have terminated due to Peabody Western’s breach of these leases and a reformation of the two coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted seven claims including fraud and is seeking various remedies including unspecified actual damages, punitive damages and reformation of its coal lease.

      On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States. The Court rejected the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments and was liable for money damages.

      On February 9, 2005, the U.S. District Court for the District of Columbia granted a consent motion to stay the litigation until further order of the Court. Peabody Western, the Navajo Nation, the Hopi Tribe and the customers purchasing coal from the Black Mesa and Kayenta mines are in mediation with respect to this litigation and other business issues.

      While the outcome of litigation is subject to uncertainties, based on our preliminary evaluation of the issues and their potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

Salt River Project Agricultural Improvement and Power District — Mine Closing and Retiree Health Care

      Salt River Project and the other owners of the Navajo Generating Station filed a lawsuit on September 27, 1996 in the Superior Court of Maricopa County in Arizona seeking a declaratory judgment that certain costs relating to final reclamation, environmental monitoring work and mine decommissioning and costs primarily relating to retiree health care benefits are not recoverable by our subsidiary, Peabody Western Coal Company, under the terms of a coal supply agreement dated February 18, 1977. The contract expires in 2011.

      Peabody Western filed a motion to compel arbitration of these claims, which was granted in part by the trial court. Specifically, the trial court ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. This ruling was subsequently upheld on appeal. As a result, Peabody Western, Salt River Project and the other owners of the Navajo Generating Station will arbitrate the mine decommissioning costs issue and will litigate the retiree health care costs issue.

      While the outcome of litigation and arbitration is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, and based on outcomes in similar proceedings, we believe that the matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

Navajo and Mohave Generating Stations — Legal Fees and Costs

      In 2003, Peabody Western Coal Company invoked arbitration and commenced two lawsuits in the Superior Court of Maricopa County, Arizona with respect to the failure of the owners of the Navajo and Mohave Generating Stations to pay for certain of Peabody Western’s legal fees and costs under two coal supply agreements. Peabody Western seeks reimbursement under the agreements for its legal fees and costs in the Navajo Nation litigation referenced above and related litigation. As of December 31, 2004, Peabody Western has billed the owners of the Navajo and Mohave Generating Station $18.1 million in fees and costs which remain unpaid.

California Public Utilities Commission Proceedings Regarding the Future of the Mohave Generating Station

      Peabody Western has a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to the operation of the Mohave plant beyond 2005 or a temporary or permanent shutdown of the plant. In filings with the California Public Utilities Commission, the operator affirmed that the Mohave plant was not forecast to return to service as a coal-fueled resource until mid-2009 at the earliest if the plant is shutdown at December 31, 2005. On December 2, 2004, the California Public Utilities Commission issued an opinion authorizing Southern California Edison to make necessary expenditures at the Mohave plant to preserve the “Mohave-open” option while Southern California Edison continues to seek resolution of the water and coal issues. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline from Peabody Western’s Black Mesa Mine to the Mohave plant. As a part of the alternate dispute resolution referenced in the Navajo Nation litigation, Peabody Western has been participating in mediation with the owners of the Mohave Generating Station and the Navajo Generating Station, and the two tribes to resolve the complex issues surrounding the groundwater dispute and other disputes involving the two generating stations. Resolution of these issues is critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. If these issues are not resolved in a timely manner, the operation of the Mohave plant will cease or be suspended on December 31, 2005. Absent a satisfactory alternate dispute resolution, it is unlikely that the coal supply agreement for the Mohave plant will be renewed in time to avoid a shutdown of the mine in 2006. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 4.7 million tons in 2004. In 2004, the mine generated $25.2 million of Adjusted EBITDA, which represents 4.5% of our Adjusted EBITDA total of $559.2 million (reconciled to its most comparable GAAP measure in Note 26 to the financial statements).

West Virginia Flooding Litigation

      Three of our subsidiaries have been named in five separate complaints filed in Boone, Kanawha and Wyoming Counties, West Virginia. These cases collectively include 622 plaintiffs who are seeking damages for property damage and personal injuries arising out of flooding that occurred in southern West Virginia in July of 2001. The plaintiffs have sued coal, timber, railroad and land companies under the theory that mining, construction of haul roads and removal of timber caused natural surface waters to be diverted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that these four cases, along with over 10 additional flood damage cases not involving our subsidiaries, be handled pursuant to the Court’s Mass Litigation rules. All discovery has been stayed. On December 9, 2004, the West Virginia Supreme Court answered questions that were certified to it by the Mass Litigation Panel. The Panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts.

      While the outcome of litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

Citizens Power

      In connection with the August 2000 sale of our former subsidiary, Citizens Power LLC (“Citizens Power”), we have indemnified the buyer, Edison Mission Energy, from certain losses resulting from specified power contracts and guarantees. Other than those discussed below, there are no known issues with any of the specified power contracts and guarantees.

      During the period that Citizens Power was owned by us, Citizens Power guaranteed the obligations of two affiliates to make payments to third parties for power delivered under fixed-priced power sales

agreements with terms that extend through 2008. Edison Mission Energy has stated and we believe there will be sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. To our knowledge, the power purchasers have made timely payments to the Citizens Power affiliates and Edison Mission Energy has not made a claim against us under the indemnity.

Environmental

      Superfund and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under that legislation and many state Superfund statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault.

      Environmental claims have been asserted against a subsidiary of ours, Gold Fields Mining Corporation (“Gold Fields”), at 22 sites in the United States and remediation has been completed or substantially completed at four of those sites. Gold Fields is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, a predecessor owner of ours. In the February 1997 spin-off of its energy businesses, Hanson PLC combined Gold Fields with the Company. These sites are related to activities of Gold Fields or its former subsidiaries. Some of these claims are based on the Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, and on similar state statutes.

      Our policy is to accrue environmental cleanup-related costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures requires an assessment of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. For certain sites, we also assess the financial capability of other potentially responsible parties and, where allegations are based on tentative findings, the reasonableness of our apportionment. We have not anticipated any recoveries from insurance carriers or other potentially responsible third parties in the estimation of liabilities recorded on its consolidated balance sheets. Undiscounted liabilities for environmental cleanup-related costs included in other non-current liabilities totaled $40.5 million as of December 31, 2004 and $38.9 million at December 31, 2003, $15.1 million and $6.9 million of which was a current liability, respectively. These amounts represent those costs that we believe are probable and reasonably estimable. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than this provision.

      Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of Superfund and similar legislation, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed by the statute. Thus, coal mines currently or previously owned or operated by us, and sites to which we have sent waste materials, may be subject to liability under Superfund and similar state laws.

Oklahoma Lead Litigation

      Gold Fields was named in June 2003 as a defendant, along with five other companies, in a class action lawsuit filed in the U.S. District Court for the Northern District of Oklahoma. The plaintiffs have asserted nuisance and trespass claims predicated on allegations of intentional lead exposure by the defendants, including Gold Fields, and are seeking compensatory damages for diminution of property value, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950’s. The plaintiff classes include all persons who have resided or owned property in the towns of Cardin and Picher within a specified time period. Gold Fields has agreed to indemnify one of the other defendants, which is a former subsidiary of Gold Fields. Gold Fields is also a defendant, along with other companies, in five individual lawsuits arising out of the same lead mill operations involved in the class

action. Plaintiffs in these actions are seeking compensatory and punitive damages for alleged personal injuries from lead exposure. In December 2003, the Quapaw Indian tribe and certain Quapaw owners of interests in land filed a class action lawsuit against Gold Fields and five other companies in U.S. District Court for the Northern District of Oklahoma. The plaintiffs are seeking compensatory and punitive damages based on public and private nuisance, trespass, unjust enrichment, CERCLA RCRA, strict liability and deceit claims. Gold Fields has denied liability to the plaintiffs, has filed counterclaims against the plaintiffs seeking indemnification and contribution and has filed a third-party complaint against the United States, owners of interests in chat and real property in the Picher area. The Quapaw tribe also filed a notice of intent to sue Gold Fields and the other mining companies under CERCLA regarding alleged damages to natural resources held in trust by the Tribe and RCRA for an alleged abatement of an imminent and substantial endangerment to health and the environment.

      In February 2004, the town of Quapaw filed a class action lawsuit against Gold Fields and other mining companies asserting claims similar to those asserted by the towns of Picher and Cardin as well as natural resource damage claims. In July 2004, two lawsuits were filed, one in the U.S. District Court for the Northern District of Oklahoma and one in Ottawa County, Oklahoma (subsequently removed to the U.S. District Court for the Northern District of Oklahoma), against Gold Fields and three other companies in which 48 individuals are seeking compensatory and punitive damages and injunctive relief from alleged personal injuries resulting from lead exposure. The allegations relate to the same two lead mills located near Picher, Oklahoma. The trials for a few of the individual plaintiffs have been set for November 2005.

      While the outcome of litigation is subject to uncertainties, based on our preliminary evaluation of the issues and their potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

      No matters were submitted to a vote of security holders during the quarter ended December 31, 2004.

Executive Officers of the Company

      Set forth below are the names, ages as of March 1, 2005 and current positions of our executive officers. Executive officers are appointed by, and hold office at, the discretion of our Board of Directors.

      Irl F. Engelhardt has been a director of ours since 1998. He is our Chairman and Chief Executive Officer, a position he has held since 1998. He served as Chief Executive Officer of a predecessor of ours from 1990 to 1998. He also served as Chairman of a predecessor of ours from 1993 to 1998 and as President from 1990 to 1995. Since joining our predecessor in 1979, he has held various officer level positions in the executive, sales, business development and administrative areas, including serving as Chairman of Peabody Resources Ltd. (Australia) and Chairman of Citizens Power LLC. Mr. Engelhardt

also served as Co-Chief Executive Officer and executive director of The Energy Group from February 1997 to May 1998, Chairman of Cornerstone Construction & Materials, Inc. from September 1994 to May 1995 and Chairman of Suburban Propane Company from May 1995 to February 1996. He also served as a director and Group Vice President of Hanson Industries from 1995 to 1996. Mr. Engelhardt is Co-Chairman of the Coal-Based Generation Stakeholders Group. He has previously served as Chairman of the National Mining Association, the Coal Industry Advisory Board of the International Energy Agency, and the Coal Utilization Research Council. He also serves on the Board of Directors of The Federal Reserve Bank of St. Louis. It was announced on March 1, 2005 that Mr. Engelhardt will continue his duties as Chairman and Chief Executive Officer for the duration of 2005 and will remain employed as Chairman of the Board as of January 1, 2006.

      Gregory H. Boyce was elected by our Board of Directors to the position of President and Chief Executive Officer, effective January 1, 2006. Mr. Boyce also was elected to the Board of Directors of the Company, and named Chairman of the Executive Committee of the Board, effective March 1, 2005. He continues to serve as our President and Chief Operating Officer, a position he has held since October 2003. Mr. Boyce had served as Chief Executive Officer — Energy of Rio Tinto PLC from 2000 to 2003. His prior positions include President and Chief Executive Officer of Kennecott Energy Company from 1994 to 1999 and President of Kennecott Minerals Company from 1993 to 1994. He has extensive engineering and operating experience with Kennecott and also served as Executive Assistant to the Vice Chairman of Standard Oil from 1983 to 1984. Mr. Boyce is a member of the Coal Industry Advisory Board of the International Energy Agency. He is a past board member of the Center for Energy and Economic Development, the National Mining Association, Western Regional Council, National Coal Council, Mountain States Employers Council and Wyoming Business Council. He also serves on the board of directors of the St. Louis Regional Chamber and Growth Association.

      Sharon D. Fiehler has been our Executive Vice President of Human Resources and Administration since April 2002, with executive responsibility for information services, employee development, benefits, compensation, employee relations and affirmative action programs. She joined Peabody in 1981 as Manager — Salary Administration and has held a series of employee relations, compensation and salaried benefits positions. Ms. Fiehler, holds degrees in social work and psychology and an MBA, and prior to joining Peabody was a personnel representative for Ford Motor Company. Ms. Fiehler is the chair of the Benefits Committee of the Bituminous Coal Operators’ Association, on the Executive Committee and Board of Directors of Junior Achievement of St. Louis and is a member of the National Mining Association’s Human Resource Committee.

      Richard A. Navarre became our Executive Vice President and Chief Financial Officer in February 2001. Prior to that, he was our Vice President and Chief Financial Officer since October 1999. He was President of Peabody COALSALES Company from January 1998 to October 1999 and previously served as President of Peabody Energy Solutions, Inc. Prior to his roles in sales and marketing, he was Vice President of Finance and served as Vice President and Controller. He joined our predecessor company in 1993 as Director of Financial and Strategic Planning. Prior to joining us, Mr. Navarre was a senior manager with KPMG Peat Marwick. Mr. Navarre is Chairman of the Bituminous Coal Operators’ Association. He serves on the Board of Advisors to the College of Business for Southern Illinois University at Carbondale. He is a member of Financial Executives International and the NYMEX Coal Advisory Council.

      Fredrick D. Palmer became our Senior Vice President — Government Relations in February 2005. He is responsible for our governmental affairs. Prior to that he was our Executive Vice President — Legal and External Affairs since February 2001. Prior to joining Peabody in 2001, he served for 15 years as chief executive officer and five years as general counsel of Western Fuels Association, Inc. For a short period in 2001, he also was of counsel in the Washington, D.C. office of Shook Hardy & Bacon, a Kansas City-based law firm. He received a BA and a JD from the University of Arizona.

      Roger B. Walcott, Jr. became our Executive Vice President — Corporate Development in February 2001. Prior to that, he was Executive Vice President since joining us in June 1998. From 1987 to 1998, he was a Senior Vice President and a director with The Boston Consulting Group where he served a variety of clients in strategy and operational assignments. He joined Boston Consulting Group in 1981, and was Chairman of The Boston Consulting Group’s Human Resource Capabilities Committee. Mr. Walcott holds an MBA with high distinction from the Harvard Business School.

      Richard M. Whiting became our Executive Vice President — Sales, Marketing and Trading in October 2002. Previously, Mr. Whiting served as our President and Chief Operating Officer and President of Peabody COALSALES Company. He joined a our predecessor in 1976 and has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Mr. Whiting is currently a member of the Board of Directors of Penn Virginia Resource GP, LLC, the general partner of Penn Virginia Resource Partners, L.P. He is the former Chairman of the National Mining Association’s Safety and Health Committee, the former Chairman of the Bituminous Coal Operators’ Association, a past board member of the National Coal Council and is a member of the Visiting Committee of West Virginia University College of Engineering and Mineral Resources.

      Jeffery L. Klinger was named our Vice President — General Counsel and Secretary in February 2005. Previously, he was our Vice President — Legal Services since May 1998. He was Vice President, Secretary and Chief Legal Officer from October 1990 to May 1998. He served from 1986 to October 1990 as Eastern Regional Counsel for Peabody Holding Company, from 1982 to 1986 as Director of Legal and Public Affairs, Eastern Division of Peabody Coal Company and from 1978 to 1982 as Director of Legal and Public Affairs, Indiana Division of Peabody Coal Company. He is a past President of the Indiana Coal Council and is currently a trustee of the Energy and Mineral Law Foundation and a past Treasurer and member of its Executive Committee. Mr. Klinger is also a member of the National Mining Association’s Legal Affairs Committee.

PART II

      Our common stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 28, 2005, there were approximately 307 holders of record of our common stock.

      The table below sets forth the range of quarterly high and low sales prices for our common stock (after giving retroactive effect to a two-for-one stock split effective March 30, 2005) on the New York Stock Exchange during the calendar quarters indicated.

Dividend Policy

      After giving retroactive effect to a two-for-one stock split effective March 30, 2005, the quarterly dividend rate for Common Stock was increased by the Board of Directors to $0.075 per share effective November 3, 2004. We paid quarterly dividends totaling $0.26 per share during the year ended December 31, 2004 and $0.23 per share during the year ended December 31, 2003. On January 25, 2005, a dividend of $0.075 per share was declared on Common Stock, payable on March 1, 2005 to stockholders of record on February 8, 2005. The declaration and payment of dividends and the amount of dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt instruments and other factors deemed relevant by our Board of Directors; however, we presently expect that dividends will continue to be paid. Limitations on our ability to pay dividends imposed by our debt instruments are discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Stock Split

      On March 2, 2005, we announced that our Board of Directors had authorized a two-for-one stock split on all shares of our common stock. Shareholders of record at the close of business on March 16, 2005 will be entitled to a dividend of one share of stock for every share held. The additional shares will be distributed on March 30, 2005, and the stock will begin trading ex-split on March 31, 2005. All share and per share amounts in this Annual Report on Form 10-K reflect the two-for-one stock split.

      The following table presents selected financial and other data about us for the most recent five fiscal periods. The following table and the discussion of our results of operations in 2004 and 2003 in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, includes references to, and analysis of, our Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

      Beginning with the year ended December 31, 2004, our equity in earnings of affiliates and all gains on asset disposals were classified separately as a component of operating income. Prior periods have been restated to conform with current presentation.

      On April 15 2004, we acquired three coal operations from RAG Coal International AG. Our results of operations for the year ended December 31, 2004 include the results of operations of the two mines in Queensland, Australia and the results of operations of the Twentymile Mine in Colorado from the April 15, 2004 purchase date. The acquisition was accounted for as a purchase.

      Results of operations for the year ended December 31, 2003 include early debt extinguishment costs of $53.5 million pursuant to our debt refinancing in the first half of 2003. In addition, results included expense relating to the cumulative effect of accounting changes, net of income taxes, of $10.1 million. This amount represents the aggregate amount of the recognition of accounting changes pursuant to the adoption of SFAS No. 143, the change in method of amortization of actuarial gains and losses related to net periodic postretirement benefit costs and the effect of the rescission of EITF No. 98-10. These accounting changes are further discussed in Note 6 to our financial statements.

      In July 2001, we changed our fiscal year end from March 31 to December 31. The change was first effective with respect to the nine months ended December 31, 2001.

      On May 22, 2001, concurrent with our initial public offering, we converted our Class A common stock and Class B common stock into a single class of common stock, all on a one-for-one basis.

      Results of operations for the year ended March 31, 2001 included a $171.7 million pretax gain on the sale of our Peabody Resources Limited operations in Australia. Capital expenditures of $151.4 million for this period do not include Peabody Resources Limited capital expenditures.

      In anticipation of the sale of Citizens Power, which occurred in August 2000, we classified Citizens Power as a discontinued operation as of March 31, 2000. Results in 2004 include a $2.8 million loss, net of taxes, from discontinued operations related to the settlement of a Citizens Power indemnification claim. Citizens Power is presented as a discontinued operation for all periods presented.

      We have derived the selected historical financial data for the years ended and as of December 31, 2004, 2003 and 2002, the nine months ended and as of December 31, 2001, and for the year ended and as of March 31, 2001 from our audited financial statements. All share and per share amounts included in the following consolidated financial data have been retroactively adjusted to reflect a two-for-one stock split, effective March 30, 2005. You should read the following table in conjunction with the financial statements, the related notes to those financial statements, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

      The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, the “Risks Relating To Our Company” section of Item 7 of this report includes a discussion of risk factors that could impact our future results of operations.