10-K 1 c75152e10vk.txt FORM 10-K -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER 1-16463 --------------------- PEABODY ENERGY CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 13-4004153 (State or other jurisdiction of incorporation or (I.R.S. Employer Identification No.) organization) 701 MARKET STREET, ST. LOUIS, MISSOURI 63101 (Address of principal executive offices) (Zip Code) (314) 342-3400 Registrant's telephone number, including area code SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- Common Stock, par value $0.01 per share New York Stock Exchange Preferred Share Purchase Rights New York Stock Exchange

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 [X] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act) Yes [X] No [ ] Aggregate market value of the voting stock held by non-affiliates of the Registrant, calculated using the closing price on June 28, 2002 of $28.30: Common Stock, par value $0.01 per share, $873.3 million. Number of shares outstanding of each of the Registrant's classes of Common Stock, as of March 1, 2003: Common Stock, par value $0.01 per share, 52,423,512 shares outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Peabody Energy Corporation (the "Company") Annual Report for the year ended December 31, 2002 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, 2003 (the "Company's 2003 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 Some of the information included in this report we have incorporated by reference contain 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. 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 they 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: - growth in coal and power markets; - coal's market share of electricity generation; - timing of reductions in customer coal inventories; - the pace and extent of the economic recovery and future economic conditions; - severity of weather; - railroad and other transportation performance and costs; - the ability to renew sales contracts upon expiration or renegotiation; - the ability to successfully implement operating strategies; - the effectiveness of our cost-cutting measures; - regulatory and court decisions; - future legislation; - changes in postretirement benefit and pension obligations; - credit, market and performance risk associated with our customers; - modification or termination of our long-term coal supply agreements; - reductions of purchases by major customers; - risks inherent to mining, including geologic conditions or unforeseen equipment problems; - terrorist attacks or threats affecting our or our customers' operations; - replacement of recoverable reserves; - implementation of new accounting standards; - inflationary trends, interest rates and access to capital markets and i - other factors, including those discussed in "Legal Proceedings," set forth in Item 3 of this report and the "Risks Related to Our Company" section of "Management's Discussion and Analysis of Financial Condition and Results of Operations," set forth in Item 7 of this report. When considering these forward-looking statements, you should keep in mind the cautionary statements in this report and the documents incorporated by reference. We will not update these statements unless the securities laws require us to do so. ii TABLE OF CONTENTS

PAGE ---- PART I. Item 1. Business.................................................... 2 Item 2. Properties.................................................. 21 Item 3. Legal Proceedings........................................... 26 Item 4. Submission of Matters to a Vote of Security Holders......... 31 Item 4A Executive Officers of the Company........................... 31 PART II. Item 5. Market For Registrant's Common Equity and Related Stockholder Matters......................................... 32 Item 6. Selected Financial Data..................................... 35 Item Management's Discussion and Analysis of Financial Condition 7..... and Results of Operations................................... 37 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................................................ 54 Item 8. Financial Statements and Supplementary Data................. 55 Item 9.. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.................................... 55 PART III. Item 10. Directors and Executive Officers of the Registrant.......... 56 Item 11. Executive Compensation...................................... 56 Item Security Ownership of Certain Beneficial Owners and 12.... Management and Related Stockholder Matters.................. 56 Item 13. Certain Relationships and Related Transactions.............. 56 Item 14. Controls and Procedures..................................... 56 PART IV. Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K......................................................... 56

1 Note: The words "we" or "our," as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries. PART I ITEM 1. BUSINESS OVERVIEW We are the largest private-sector coal company in the world. During the year ended December 31, 2002, we sold 197.9 million tons of coal. During this period, we sold coal to more than 280 electricity generating and industrial plants in 14 countries, and fueled the generation of more than 9% of all electricity in the United States and 2% of all electricity in the world. At December 31, 2002, we had 9.1 billion tons of proven and probable coal reserves. We own, through our subsidiaries, majority interests in 33 coal operations located throughout all major U.S. coal producing regions, with 73% of our U.S. mining operations' coal sales during the year ended December 31, 2002 shipped from the western United States 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 128.0 million tons during 2002, representing a compounded annual growth rate of 11%. In the west, we own and operate mines in Arizona, Colorado, Montana, New Mexico and Wyoming. In the east, we own and operate mines in Illinois, Indiana, Kentucky and West Virginia. We produced 78% of our sales volume for the year ended December 31, 2002 from non-union mines. For the year ended December 31, 2002, 94% of our sales were to U.S. electricity generators, 4% were to customers outside the United States and 2% were to the U.S. industrial sector. Approximately 97% of our coal sales during the year ended December 31, 2002 were under long-term contracts. Our sales backlog, including backlog subject to price reopener and/or extension provisions, approximated one billion tons as of December 31, 2002. The average volume weighted remaining term of our long-term contracts is approximately 4.4 years, with remaining terms ranging from one to 18 years. As of December 31, 2002, we had approximately eight million tons and 75 million tons of expected production unpriced for 2003 and 2004, respectively. We have the ability to increase production by four to five million tons each quarter by running our current operations at their full capacity. In addition to our mining operations, we market, broker and trade coal and emission allowances. Our total tons traded were 66.9 million for the year ended December 31, 2002. Our other energy related businesses include coalbed methane production, transportation services, third-party coal contract restructuring and the development of coal-fueled generating plants. HISTORY Peabody, Daniels and Co. was founded in 1883 as a retail coal supplier, entering the mining business in 1888 as Peabody & Co. Peabody's first coal mine was opened 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. In 1984, Peabody acquired the West Virginia coal properties of ARMCO Steel and in 1987 purchased Eastern Associated Coal Corp., which included seven operating mines and substantial low sulfur coal reserves in West Virginia. 2 In July 1990, Peabody Holding Company was acquired by Hanson PLC, a British-American industrial management company. From 1990 to 2002, Peabody's business was redefined, as the company transformed itself into a more productive, low-cost, low sulfur energy company, tripling its productivity and reducing costs 42% while improving safety performance 66%. In 1993, interests in three mines in New South Wales, Australia, were acquired from Costain Group in anticipation of the growing Pacific Rim market for coal. The properties included 100% ownership of the Ravensworth Mine, a 50% interest in the Narama Mine and a 28.75% interest in the Warkworth Mine, subsequently increased to 43.75%. We also subsequently developed a fourth mine, Bengalla, which began shipments in early 1999. Peabody's interest in the Bengalla joint venture was increased from 35% to 37% in 1998 and to 40% in 2000. In 1993, the company also acquired the Lee Ranch Mine in New Mexico. In 1994, Peabody purchased a one-third ownership in Black Beauty Coal Company, Indiana's largest coal producer. The Caballo and Rawhide mines in Wyoming's Powder River Basin also were purchased from Exxon Coal USA Inc. This acquisition, along with the expansion of the North Antelope and Rochelle mines, positioned Peabody as the leading producer in the Powder River Basin, the nation's largest and fastest growing coal region. Peabody's sales volume from the Powder River Basin increased from 31 million tons in 1993 to 105 million tons in 2002. In February 1997, Hanson spun off its energy-related businesses into The Energy Group PLC, which included Peabody Holding Company and Eastern Group, a United Kingdom electricity distribution and generating company. The Energy Group was a publicly traded company in the United Kingdom, and its American Depository Receipts (ADRs) were publicly traded on the New York Stock Exchange. In May 1997, The Energy Group, through Peabody, purchased Citizens Power LLC, a leading power marketer. Peabody increased its interest in Black Beauty to 43.3% in February 1998 and to 81.7% in January 1999. Black Beauty acquired Catlin Coal Company in 1999 and an additional 25% of Arclar Coal Company in 2000. In May 1998, Lehman Brothers Merchant Banking Partners II L.P., an affiliate of Lehman Brothers Inc., purchased Peabody Holding Company and its affiliates, Peabody Resources Limited and Citizens Power LLC. In August 1999, Peabody purchased a 55% interest in the Moura Mine in Queensland, Australia, which supplied a range of steam and metallurgical coals to Asia-Pacific customers and operated a coalbed methane extraction operation. In August 2000, Citizens Power, Peabody's subsidiary that marketed and traded electric power and energy-related commodity risk management products, was sold to Edison Mission Energy. In January 2001, Peabody sold its Australian mining operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto Limited for $455 million. In April 2001, Peabody changed its name to Peabody Energy Corporation ("Peabody"), reflecting its position as a premier energy supplier. In May 2001, Peabody 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 June 2002, Peabody acquired Beaver Dam Coal Company, a major holder of coal reserves in Western Kentucky. In August 2002, Peabody acquired the Wilkie Creek Coal Mine in Queensland, Australia, marking a return to Australian mining operations. In September 2002, Peabody purchased the remaining 25% interest in Arclar Company, LLC. Peabody's Black Beauty affiliate owns the remaining 75% interest of Arclar. In December 2002, Peabody contributed 120 million tons of coal reserves for $72.5 million in cash and a 15% interest in Penn Virginia Resource Partners, L.P. (NYSE: PVR), a publicly held master limited partnership. 3 MINING OPERATIONS The following provides a description of the operating characteristics of the principal mines and reserves of each of our operating units and affiliates in the United States. (US MAP) Within the United States, we conduct operations in the Powder River Basin, Southwest, Appalachia and Midwest regions. POWDER RIVER BASIN OPERATIONS We control approximately 2.9 billion tons of coal reserves in the Powder River Basin, the largest and fastest growing major U.S. coal-producing region. Our subsidiaries, Powder River Coal Company and Caballo Coal Company, own and manage three low sulfur, non-union surface mining complexes in Wyoming that sold approximately 104.8 million tons of coal during the year ended December 31, 2002, or approximately 53% 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 8,900 Btu per pound. Our subsidiary, Big Sky Coal Company, operates the Big Sky Mine in Montana in the Northern Powder River Basin. Coal is shipped from this mine to customers in the upper Midwest by the Burlington Northern Santa Fe Railway. NORTH ANTELOPE/ROCHELLE The North Antelope/Rochelle Mine is located 65 miles south of Gillette, Wyoming. This mine is the largest in the United States, selling 75.4 million tons during 2002. 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 4 States, using a dragline along with six truck-and-shovel fleets. We added a second dragline at this mine in 2002 to improve productivity. CABALLO The Caballo Mine is located 20 miles south of Gillette, Wyoming. During 2002, it sold approximately 26.0 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu). 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. RAWHIDE The Rawhide Mine is located ten miles north of Gillette, Wyoming and uses truck-and-shovel mining methods. Operations were suspended at the Rawhide mine in 1999, but the mine reopened in January 2002 as a result of improved demand for Powder River Basin coal. During 2002, it sold approximately 3.4 million tons of compliance coal. BIG SKY The Big Sky Mine is located in the northern Powder River Basin near Colstrip, Montana and uses dragline mining equipment. The mine sold 2.8 million tons of medium sulfur coal during 2002. Coal is shipped by rail to several major electricity generating customers in the upper midwestern United States. This mine is near the exhaustion of its economically recoverable reserves, and we may close it in the next several years, depending upon market and mining conditions. Hourly workers at the Big Sky Mine are members of the United Mine Workers of America. SOUTHWEST OPERATIONS We own and manage three mines in the western bituminous coal region -- two in Arizona and one in Colorado. The Colorado mine, which is owned and managed by Seneca Coal Company, and the Arizona mines, which are owned and managed by Peabody Western Coal Company, supply primarily 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 four mines sold 21.0 million tons of coal during 2002. BLACK MESA The Black Mesa Mine, which is located on the Navajo Nation and Hopi Tribe reservations in Arizona, uses two draglines and sold 4.6 million tons of coal during 2002. The Black Mesa Mine coal is crushed, mixed with water and then transported 273 miles through the underground Black Mesa Pipeline (which is owned by a third party) 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. Hourly workers at this mine are members of the United Mine Workers of America. KAYENTA The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines in three mining areas. It sold approximately 8.3 million tons of coal during 2002. The Kayenta Mine coal is crushed, then carried 17 miles by conveyor belt to storage silos where it is loaded on to 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. 5 SENECA The Seneca Mine near Hayden, Colorado shipped 1.8 million tons of compliance coal during 2002, operating with two draglines in two 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. Hourly workers at this mine are members of the United Mine Workers of America. LEE RANCH MINE The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 6.3 million tons of medium sulfur coal during 2002. Lee Ranch shipped the majority of its coal to two customers in Arizona and New Mexico under coal supply agreements extending until 2010 and 2014, respectively. Lee Ranch is a non-union surface mine that uses a combination of dragline and truck-and-shovel mining techniques. APPALACHIA OPERATIONS We own and manage six wholly owned operating units and related facilities in West Virginia. Our subsidiary, Pine Ridge Coal Company, owns and manages the Big Mountain Operating Unit, and our subsidiary, Eastern Associated Coal Corp., owns and manages the remaining wholly owned facilities. During 2002, these operations sold approximately 16.7 million tons of compliance, medium sulfur and high sulfur steam and metallurgical coal to customers in the United States and abroad. Hourly workers at these operations are members of the United Mine Workers of America. In addition to our wholly owned facilities, we own a 49% interest in another underground mine in West Virginia. BIG MOUNTAIN OPERATING UNIT The Big Mountain Operating Unit is based near Prenter, West Virginia. This operating unit's primary mine is Big Mountain No. 16, and includes a small amount of contract mine production from coal reserves we control. During 2002, the Big Mountain Operating Unit sold approximately 1.2 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. During the fourth quarter of 2002, we suspended operations of the unit in response to market conditions. The mine was reopened in February 2003. HARRIS OPERATING UNIT The Harris Operating Unit consists of the Harris No. 1 Mine near Bald Knob, West Virginia, which sold approximately 3.2 million tons of primarily metallurgical product during 2002. This mine uses both longwall and continuous mining equipment. ROCKLICK OPERATING UNIT AND CONTRACT MINES The Rocklick preparation plant, located near Wharton, West Virginia, processes coal produced by the Harris No.1 Mine, the Colony Bay Mine and contract mining operations from coal reserves that we control. This preparation plant shipped approximately 2.6 million tons of steam and metallurgical coal sourced from the contract mines during 2002. 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. WELLS OPERATING UNIT The Wells Operating Unit, in Boone County, West Virginia, sold approximately 3.9 million tons of metallurgical and steam coal during 2002. The unit consists of the River's Edge Mine, contract mine production and the Wells preparation plant, located near Wharton, West Virginia. Processed coal is loaded on the CSX railroad. The River's Edge mine replaced the Lightfoot No. 2 Mine, which depleted its economically recoverable reserves in the fourth quarter of 2002. 6 FEDERAL NO. 2 MINE The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining equipment and shipped approximately 5.0 million tons of steam coal during 2002. Coal shipped from the Federal No. 2 Mine has a sulfur content only slightly above that of medium sulfur coal and has an 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. COLONY BAY MINE The Colony Bay Mine is located in Boone County, West Virginia. The mine, which reopened in January 2002, utilized one spread of surface mining equipment and one highwall miner. Coal produced from the mine is transported to the Rocklick preparation plant prior to shipment to customers. The mine produced 0.8 million tons in 2002, but production was suspended during the fourth quarter of 2002 in response to market conditions. KANAWHA EAGLE COAL JOINT VENTURE We have a 49% interest in Kanawha Eagle Coal, LLC, which owns and manages an underground mine, preparation plant and barge-and-rail loading facilities near Marmet, West Virginia. The mine is non-union and uses continuous mining equipment. It shipped 1.5 million tons during 2002. MIDWEST OPERATIONS We operated seven wholly-owned mines in the midwestern United States during 2002, which collectively sold 7.3 million tons of coal. These operations include five underground and two surface mines, along with three preparation plants and three barge loading facilities, located in western Kentucky, southern Illinois and southwestern Indiana. We ship coal from these mines primarily to electricity generators in the midwestern United States, and to industrial customers that generate their own power. Our Camp and Midwest operating units are owned and managed by our Peabody Coal Company subsidiary. CAMP OPERATING UNIT The Camp Operating Unit, located near Morganfield, Kentucky, operated the Camp No. 11 Mine, an underground mine, and a large preparation plant and barge loading facility. The Camp No. 11 Mine sold 2.4 million tons of coal during 2002 before exhausting its economically recoverable reserves in December 2002. The Camp No. 11 Mine used both longwall and continuous mining equipment. We sold most of the Camp No. 11 production under contract to the Tennessee Valley Authority. This mine's production will be replaced with production from the Highland Operating Unit. Hourly workers at these operations were members of the United Mine Workers of America. HIGHLAND OPERATING UNIT The Highland Operating Unit, which is owned and managed by our Highland Mining Company subsidiary, is located near Waverly, Kentucky, and consists of two underground mines. The Highland No. 11 Mine produced 0.6 million tons from the No. 11 coal seam during 2002. The Highland No. 9 Mine is still in development and is expected to operate from the No. 9 coal seam beginning in the first quarter of 2003. Hourly workers at these operations are members of the United Mine Workers of America. MIDWEST OPERATING UNIT The Midwest Operating Unit near Graham, Kentucky sold 1.4 million tons of coal during 2002. In 2002, the unit included the Gibraltar surface mining operation, which uses truck-and-shovel equipment, and the Gibraltar Highwall Mine, which used continuous mining equipment. We sold coal from these mines under contract to the Tennessee Valley Authority. The Gibraltar Highwall Mine was closed in the 7 summer of 2002 as the mine reached the end of its economically recoverable reserves. Hourly workers at these operations are members of the United Mine Workers of America. PATRIOT COAL COMPANY Our subsidiary, Patriot Coal Company, owns and manages Patriot, a surface mine, and Freedom, an underground mine, in Henderson County, Kentucky, and sold approximately 2.6 million tons of coal during 2002. The Big Run underground mine in Ohio County, Kentucky began operations in the fourth quarter of 2002 and sold approximately 0.3 million tons. The underground mines use continuous mining equipment, and the surface mine uses truck-and-shovel equipment. Patriot Coal Company also operates a preparation plant and a dock. The Patriot Coal Company mines utilize non-union labor. In addition to the wholly-owned mines in our Midwest operating region, we have an 81.7% joint venture interest in Black Beauty, as discussed below. BLACK BEAUTY COAL COMPANY We own 81.7% of Black Beauty, the largest coal producer in the Illinois Basin, which currently manages eight active mines in Indiana and four active mines in Illinois. Together with its equity affiliates, Black Beauty's operations produced and sold 24.1 million tons of compliance, medium sulfur and high sulfur steam coal during 2002. We purchased a one-third interest in Black Beauty in 1994, and increased our interest to 43.3% in 1998 and 81.7% in 1999. Black Beauty Resources, Inc., owned by certain members of Black Beauty's management team, holds the remaining minority interest. Black Beauty's principal Indiana mines include Air Quality No. 1, Farmersburg, Francisco and three mines near Somerville, Indiana. Air Quality No. 1 is an underground coal mine located near Monroe City, Indiana that shipped 1.8 million tons of compliance coal during 2002. Farmersburg is a surface mine situated in Vigo and Sullivan counties in Indiana that sold 4.1 million tons of medium sulfur coal during 2002. Francisco, a surface mine located in Gibson county, Indiana, sold 2.4 million tons during 2002, and the three Somerville surface mines, also located in Gibson county, shipped a total of 7.0 million tons in fiscal year 2002. During 2002, Black Beauty began production at a new underground mining facility, the Vermilion Grove Mine, in east-central Illinois. Together with the existing Riola No. 1 Mine, these operations sold 1.8 millions tons during 2002. Black Beauty's remaining mines sold 2.7 million tons during 2002. All of Black Beauty Coal Company's wholly-owned operations utilize non-union labor. Black Beauty owns a 75% equity interest in Arclar Company, LLC, which operates the Cottage Grove surface mine and Willow Lake underground mining complex situated in Gallatin and Saline counties in southern Illinois. During 2002, these facilities sold 4.3 million tons of coal, primarily shipped by barge to downriver utility plants. Black Beauty provides a contract workforce for the Arclar surface operations; the workforce at the underground operations is represented under non-UMWA labor agreements. The Willow Lake Mine began operations during the first half of 2002. Willow Lake replaced Arclar's existing operations at Eagle Valley and Big Ridge. Once it reaches full capacity, Willow Lake is expected to produce about 3.5 million tons per year. In September 2002, Peabody purchased the 25% interest in Arclar Company, LLC not owned by Black Beauty for $14.9 million. Black Beauty also owns a 75% interest in United Minerals Company, LLC. United Minerals currently acts as a contract miner for Black Beauty at the Somerville North and Somerville South mines and as contract operator for Black Beauty at the Evansville River Terminal. We are considering the acquisition of the 18.3% minority interest of Black Beauty. In the event the acquisition is completed, we anticipate the continuing involvement of the current minority interest owners in the day-to-day management of the business. 8 AUSTRALIAN MINING OPERATIONS -- WILKIE CREEK MINE On August 22, 2002, we purchased the 1.4 million ton per year Wilkie Creek Coal Mine and coal reserves in Queensland, Australia. From the acquisition date to December 31, 2002, the mine sold 0.4 million tons. Evaluations are complete with respect to 147 million tons of proven and probable reserves acquired surrounding the Wilkie Creek Mine. We continue to evaluate other coal resources that were obtained in this acquisition to finalize the estimate of our total proven and probable reserves in Australia. PENN VIRGINIA RESOURCE PARTNERS, L.P. On December 19, 2002, we formed an alliance with Penn Virginia Resource Partners, L.P. (PVR) whereby we contributed 120 million tons of coal reserves in exchange for $72.5 million in cash and 2.76 million units, or 15%, of the publicly traded PVR master limited partnership. Our subsidiaries subsequently leased the coal and will pay royalties as the coal is mined. LONG-TERM COAL SUPPLY AGREEMENTS We currently have a sales backlog of approximately one billion tons of coal, and our coal supply agreements have remaining terms ranging from one to 18 years and an average volume-weighted remaining term of approximately 4.4 years. For 2002, we sold 97% of our sales volume under long-term coal supply agreements. In 2002, we sold coal to more than 280 electricity generating and industrial plants in 14 countries. Our primary customer base is in the United States. Two of our coal supply agreements are the subject of ongoing litigation and arbitration. 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, 2002, we had approximately eight million tons and 75 million tons of expected production unpriced for 2003 and 2004, respectively. 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 exposed 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 and force majeure, 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 language that allows for the recovery of costs impacted by the modifications or changes in the 9 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, subject to the payment of liquidated damages. 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 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 content (Btu), sulfur, ash, 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 U.S., approximately half of our customers require that the coal is sampled and weighed at the destination, whereas in the western U.S., 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 or at the discretion of the buyer. 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 as long as the replacement coal meets quality specifications and will be sold at the same delivered cost. SALES AND MARKETING Our sales, trading and marketing operations include Peabody COALSALES and Peabody COALTRADE. Through these entities, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and agent, trade coal and emission allowances, and provide transportation-related services. We also restructure coal supply agreements by acquiring rights to receive coal under a coal supply agreement, reselling that coal, and supplying coal from other sources. As of December 31, 2002, we had 60 employees in our sales, marketing, trading and transportation operations, including personnel dedicated to performing market research, contract administration and risk/credit management activities. TRANSPORTATION Coal consumed domestically is usually sold at the mine, and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port. The majority of our sales volume is shipped by rail, but a portion of our production is shipped by other modes of transportation. For example, coal from our Highland operating unit in Kentucky is shipped by barge to the Tennessee Valley Authority's Cumberland plant in Tennessee. Coal from our Black Mesa Mine in Arizona is transported by a 273-mile coal-water pipeline to the Mohave Generating Station in 10 southern Nevada. Coal from the Seneca Mine in Colorado is transported by truck to a nearby electricity generating plant. Other mines transport coal by rail and barge or by rail and lake carrier on the Great Lakes. 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 8,000 unit trains are loaded each year to accommodate the coal shipped by these mines. A unit train generally consists of 100 to 140 cars, each of which can hold 100 to 120 tons of coal. Our transportation department manages the loading of trains and barges. 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 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; however, we are not dependent on any one supplier for explosives. Further, purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop. TECHNICAL INNOVATION We place great emphasis on the application of technical innovation to improve new and existing equipment performance. This research and development effort is typically undertaken and funded by equipment manufacturers using our input and expertise. Our engineering, maintenance and purchasing personnel work together with manufacturers to design and produce equipment that we believe will add value to the business. We have worked with manufacturers to design larger trucks to haul overburden and coal at various mines throughout the company. In Wyoming, we were the first coal company to use the current, state-of-the-art 400-ton haul trucks. Additionally, we worked with manufacturers to develop higher horsepower, underground continuous mining machines and a continuous haulage machine, which mine the coal more effectively, at a lower cost per ton. We are a leader in retrofitting existing equipment to increase performance and extend the lives of assets. For example, a dragline from the Midwest was relocated to Wyoming and was upgraded with new motors and digital controllers to increase productivity. We also deploy extensive lubrication analysis technology, finite element analysis and remote monitoring to ensure full productive life of our equipment. As a result of these efforts, many of our mines have become among the most productive in the industry. We use sophisticated software to schedule and monitor trains, mine/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 advanced emissions reduction technology funded primarily through the U.S. Department of Energy and operated by an affiliate of Southern Company. COMPETITION The markets in which we sell our coal are highly competitive. According to the Energy Information Administration's "Annual Coal Report 2001," the top 10 coal producers in the United States produced 11 approximately 62% of total domestic coal in 2001. Our principal competitors are other large coal producers, including Arch Coal, Inc., Kennecott Energy Co., a subsidiary of Rio Tinto, RAG AG, CONSOL Energy Inc., Horizon Natural Resources, Inc. and Massey Energy Company, which collectively accounted for approximately 40% of total U.S. coal production in 2001. 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 industries in the United States, 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. POWER PLANT 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. Peabody is 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 over-comply with all current clean air standards using advanced emissions control technologies. In 2002, Peabody achieved a major milestone in the development of the 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky, when it received the final air quality permit from the Commonwealth of Kentucky. Certain environmental groups are challenging the air permit. In 2002, Peabody also signed a transmission agreement and received its water withdrawal permit for the 1,500 megawatt Prairie State Energy Campus in Washington County, Illinois. COALBED METHANE Our subsidiary, Peabody Natural Gas, LLC, produces coalbed methane from its operations located in the Southern Powder River Basin near our Caballo Mine. We purchased these coalbed methane assets in January 2001 for approximately $10 million. We will continue to evaluate further development of this business through acquisitions and development of our own reserves. CERTAIN LIABILITIES We have significant long-term liabilities for reclamation, 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. Reclamation. Reclamation liabilities primarily represent the future 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 reclamation costs and mine-closing liabilities totaled approximately $386.8 million as of December 31, 2002. Expense for the year ended December 31, 2002, the nine months ended December 31, 2001 and the fiscal year ended March 31, 2001 was $11.0 million, $9.6 million and $4.1 million, respectively. Our method for accounting for reclamation activities changed on January 1, 2003 as a result of the adoption of SFAS (Statement of Financial Accounting Standards) No. 143, "Accounting for Asset Retirement Obligations." The effects of the adoption of SFAS No. 143 are discussed in the "Accounting Pronouncements Not Yet Implemented" section of Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of this report. 12 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 $252.4 million as of December 31, 2002, $42.6 million of which was a current liability. Expense for the year ended December 31, 2002, the nine months ended December 31, 2001 and the fiscal year ended March 31, 2001 was $55.4 million, $36.6 million and $41.4 million, respectively. Pension-Related Provisions. Pension-related costs represent the actuarially-estimated cost of pension benefits. Annual 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 $127.6 million as of December 31, 2002, $7.4 million of which was a current liability. Expense for the year ended December 31, 2002, the nine months ended December 31, 2001 and the fiscal year ended March 31, 2001 was $4.8 million, $3.0 million and $0.3 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 the United Mine Workers of America Combined Fund created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of former employees who retired prior to 1976; 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. Our retiree health care liabilities totaled approximately $1,031.7 million as of December 31, 2002, $72.1 million of which was a current liability. Expense for the year ended December 31, 2002, the nine months ended December 31, 2001 and the fiscal year ended March 31, 2001 was $74.4 million, $49.8 million and $70.7 million, respectively. Obligations to the United Mine Workers of America Combined Fund totaled $67.3 million as of December 31, 2002, $17.5 million of which was a current liability. Expense for the year ended December 31, 2002 and the nine months ended December 31, 2001 was $16.7 million and $3.3 million, respectively. For the fiscal year ended March 31, 2001, income of $8.0 million was recorded, primarily due to the withdrawal by the Social Security Administration of certain beneficiaries previously assigned to us. The expense recorded during the year ended December 31, 2002 reflects the expected reassignment of these beneficiaries to us as a result of an adverse U.S. Supreme Court decision in January 2003. ELECTRICITY DEREGULATION Congress enacted the Energy Policy Act of 1992 to stimulate competition in electricity markets by giving wholesale suppliers access to the transmission lines of U.S. electricity generators. In April 1996, the Federal Energy Regulatory Commission issued the first of a series of orders establishing rules providing for open access to electricity transmission systems. The federal government is currently exploring a number of options concerning utility deregulation. Some individual states are also proceeding with their own deregulation initiatives. The pace of deregulation differs significantly from state to state. As of December 2002, 17 states and the District of Columbia had either enacted legislation leading to the deregulation of the electricity market or issued a regulatory order to implement retail access that would allow customers to choose their own supplier of generation. Five states have delayed restructuring and 27 are not actively pursuing deregulation. In California, where supply and demand imbalances created electricity supply shortages, the California Public Utilities Commission suspended deregulation. 13 A possible consequence of deregulation is downward pressure on fuel prices. However, because of coal's cost advantage and because some coal-fueled generating facilities are underutilized in the current regulated electricity market, we believe that additional coal demand would arise as electricity markets are deregulated if the most efficient coal-fueled power plants are operated at greater capacity. EMPLOYEES As of December 31, 2002, we and our subsidiaries had approximately 6,500 employees. As of December 31, 2002, the United Mine Workers of America represented approximately 31% of our employees, who produced 19% of our coal sales volume during the year ended December 31, 2002. An additional 4% of our employees are represented by labor unions other than the United Mine Workers of America. These employees produced 3% of our coal sales volume during the year ended December 31, 2002. Relations with organized labor are important to our success and we believe our relations with our employees are satisfactory. Hourly workers at our mines in Arizona, Colorado and Montana 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 also primarily represented by the United Mine Workers of America and is subject to the National Bituminous Coal Wage Agreement. The current five-year labor agreement was ratified in December 2001 and is effective from January 1, 2002 through December 31, 2006. REGULATORY MATTERS 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 upon us has been material. MINE SAFETY AND HEALTH 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 14 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 a superior safety and health regime is inherently tied to achieving our productivity and financial goals. 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. BLACK LUNG Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. 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 production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price. This tax is passed on to the purchaser under many of our coal supply agreements. In December 2000, the Department of Labor issued new amendments to the regulations implementing the federal black lung laws that, among other things, establish a presumption in favor of a claimant's treating physician and limit a coal operator's ability to introduce medical evidence regarding the claimant's medical condition. Industry reports anticipate that the number of claimants who are awarded benefits will increase, as will the amounts of those awards. The National Mining Association filed a lawsuit challenging these regulations, and the U.S. District Court of the District of Columbia upheld the regulations. The National Mining Association filed an appeal with the U.S. Court of Appeals for the District of Columbia, but the regulations were upheld, with some exceptions as to the retroactivity of the regulations. COAL INDUSTRY RETIREE HEALTH BENEFIT ACT OF 1992 The Coal Industry Retiree Health Benefit Act of 1992 ("Coal Act") provides for the funding of health benefits for certain 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. Companies that are liable under the Coal Act must pay premiums to these funds. Annual payments made by certain of our subsidiaries under the Coal Act totaled $11.1 million, $5.4 million and $4.2 million, respectively, during the year ended December 31, 2002, nine months ended December 31, 2001 and year ended March 31, 2001. In 1995, in a case filed by the National Coal Association on behalf of its members and others, 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 premium to all assigned operators. In 1996, the Combined Fund sued the Social Security Administration in the District of Columbia seeking a declaration that the Social Security Administration's original premium calculation was proper. Certain coal companies, but not our subsidiaries, intervened in the lawsuit. On February 25, 2000, the federal district court ruled in favor of the Combined Fund. In a decision dated December 16, 2002, the Court of Appeals for the District of Columbia Circuit affirmed in part and reversed in part the lower court's ruling and remanded the case for further proceedings. Among other things, the Court of Appeals directed the Commissioner of Social Security to void the agency's 1995 premium recalculation with respect to all assigned operators except those that had been parties to the 1995 Alabama litigation, including National Coal Association member companies. If the Combined Fund is able to obtain a court decision that would retroactively assess the higher premium rate to our subsidiaries, our 15 subsidiaries will be required to pay an additional premium to the Combined Fund of approximately $5.7 million. In that event, the prospective annual premium would also increase by approximately 10%. ENVIRONMENTAL LAWS We are subject to various federal, state and foreign environmental laws. Some of these laws, discussed below, place many requirements on our coal mining operations. Federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance. SURFACE MINING CONTROL AND RECLAMATION ACT 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 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 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 rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed prior to 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund. The fee, which partially expires on September 30, 2004, is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. After that date, a fee will be assessed each year to cover the expected health care benefit costs of the orphan beneficiaries. 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 16 (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 with the requirements of the Surface Mining Control and Reclamation Act and the state laws and regulations governing mine reclamation. On March 29, 2002, the U.S. District Court for the District of Columbia issued a ruling on SMCRA Section 522(e) banning underground coal mining under certain protected lands that were originally applicable only to surface coal mining operations. The U.S. Department of Interior filed an appeal. If the ruling is upheld, mining costs could increase and in some cases make portions of coal reserves infeasible to mine. CLEAN AIR ACT The Clean Air Act, the Clean Air Act Amendments and the corresponding state laws that regulate the emissions of materials into the air, affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-based electricity generating plants. 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. The extent of the potential direct impact of the new air quality standards on the coal industry will depend on the policies and control strategies associated with the state implementation process under the Clean Air Act, but could have a material adverse effect on our financial condition and results of operations. Title IV of the Clean Air Act Amendments 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. We cannot accurately predict the effect of these provisions of the Clean Air Act Amendments 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. The Clean Air Act Amendments also require electricity generators that currently are major sources of nitrogen oxides in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxides, which are precursors of ozone. In addition, the EPA promulgated the final rules that would require coal-burning power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions beginning in May 2004. Installation of additional control 17 measures required under the final rules will make it more costly to operate coal-based electricity generating plants. The Clean Air Act Amendments provisions for new source review require electricity generators to install the best available control technology if they make a major modification to a facility that results in an increase in its potential to emit regulated pollutants. From 1990 to 1999, the EPA interpreted the new source review criteria in a relatively consistent manner; however, the EPA changed their interpretation during 1999. The Justice Department, on behalf of the EPA, filed a number of lawsuits since November 1999, alleging that 10 electricity generators violated the new source review provisions of the Clean Air Act Amendments at power plants in the midwestern and southern United States. The EPA issued an administrative order alleging similar violations by the Tennessee Valley Authority, affecting seven plants and notices of violation for an additional eight plants owned by the affected electricity generators. Four electricity generators have announced settlements with the Justice Department requiring the installation of additional control equipment on selected generating units. 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, the fines and requirements to install additional control equipment could adversely affect the amount of coal they would burn if the plant operating costs were to increase to the point that the plants were operated less frequently. At the end of 2002, the EPA issued proposed new source review rules for sources that include electricity generators. These new rules define routine maintenance, repair and replacement. If these rules are finalized without material revisions, electricity generators should be better able to make needed repairs and improvements to their plants without the uncertainty of triggering cost-prohibitive environmental rules. The Clean Air Act Amendments set a national goal for the prevention of any future, and the remedying of any existing, impairment of visibility in 156 national parks and wildlife areas across the country. Under regulations issued by the EPA in 1999, states are required to set a goal of restoring natural visibility conditions in these Class I areas in their states by 2064 and to explain their reasons to the extent they determine that this goal cannot be met. The state plans may require the application of "Best Available Retrofit Technology" after 2010 on sources found to be contributing to visibility impairment of regional haze in these areas. The control technology requirements 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 dioxides and nitrogen oxides. The Clean Air Act Amendments require a study of electricity generating plant emissions of certain toxic substances, including mercury, and direct the EPA to regulate these substances, if warranted. In December 2000, the EPA decided that mercury air emissions from power plants should be regulated. The EPA will propose regulations by December 2003 and will issue final regulations by December 2004. It is possible that future regulatory activity may seek to reduce mercury emissions and these requirements, if adopted, could result in reduced use of coal if electricity generators switch to other sources of fuel. In addition, Vice President Cheney, as the head of the National Energy Policy Development Group, submitted to the President a National Energy Policy which recommended, among other things, that the President direct the EPA Administrator to work with Congress to propose legislation that would significantly reduce and cap emissions of sulfur dioxide, nitrogen oxide and mercury from electricity power generators. In February 2002, the President proposed to cut electricity power generator emissions by approximately 70% by 2018 using a cap and trade system similar to that now in effect for acid deposition control. The President's proposal has been translated into a legislative proposal. In addition, similar emission reduction proposals have been introduced in Congress, some of which propose to regulate the three pollutants and carbon dioxide, but 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 dioxides, nitrogen oxides, mercury and carbon dioxide. 18 In February 2003, seven states notified the EPA that they plan to sue the agency to force it to set new source performance standards for utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In January 2003, three of these states announced that they planned to seek a court order requiring the EPA to designate carbon dioxide as a criteria pollutant and to issue a new National Ambient Air Quality Standard for carbon dioxide. If these states file the lawsuits, are successful in obtaining a court order and the EPA agrees to set emission limitations for carbon dioxide and/or lower emission limitations for sulfur dioxide and particulate matter, it could adversely affect the amount of coal our customers would purchase from us. CLEAN WATER ACT The Clean Water Act of 1972 affects 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. On May 8, 2002, the U.S. District Court for the Southern District of West Virginia issued an injunction banning new Section 404 permits by the Huntington, West Virginia Office of the Army Corp of Engineers (COE). Section 404 permits are required for coal companies to place any material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. The COE filed for an appeal of the Court's order with the U.S. Court of Appeals for the Fourth Circuit. The COE Huntington office issues permits for portions of Ohio, Kentucky and West Virginia where Peabody mining operations are located. On January 29, 2003, the Fourth Circuit Court of Appeals vacated the District Court's injunction. 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." These regulations would prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality streams will be required to meet or exceed new "high quality" standards. The designation of high quality streams at our coal mines could require more costly water treatment and could aversely affect our coal production. RESOURCE CONSERVATION AND RECOVERY ACT The Resource Conservation and Recovery Act (RCRA), which was enacted in 1976, affects 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. 19 FEDERAL AND STATE SUPERFUND STATUTES Superfund and similar state laws affect coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. GLOBAL CLIMATE CHANGE The United States, Australia and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. 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, 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 Energy Information Administration's Emissions of Greenhouse Gases in the United States 2001, coal accounts for 32% 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 over the next 10 years which is approximately equivalent to the reduction that has occurred over each of the past two decades. PERMITTING Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with coal mining. These 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 revegetation. We must obtain permits from applicable state regulatory authorities before we begin to mine reserves. The 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 the Surface Mining Control and Reclamation Act, 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 Office of Surface Mining's Applicant Violator System. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review, technical review and public notice and comment period before it can be approved. Some Surface Mining Control and Reclamation Act mine permits can take over a year to prepare, depending on the size and complexity of the mine and often take six months to sometimes two years to 20 receive approval. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. 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 ensure that our operations are in full compliance with the requirements of the Surface Mining Control and Reclamation Act and the state laws and regulations governing mine reclamation. ADDITIONAL INFORMATION We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (SEC). You may access and read our SEC filings 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 700, St. Louis, Missouri 63101, attention: Investor Relations. ITEM 2. PROPERTIES COAL RESERVES We had an estimated 9.1 billion tons of proven and probable coal reserves as of December 31, 2002. An estimated 8.9 billion tons of our proven and probable coal reserves are in the United States, and 38% is compliance coal and 62% is non-compliance coal. We own approximately 46% of these reserves and lease property containing the remaining 54%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal. Below is a table summarizing the locations and reserves of our major operating regions.

PROVEN AND PROBABLE RESERVES AS OF DECEMBER 31, 2002(1) ---------------------- OWNED LEASED TOTAL OPERATING REGIONS LOCATIONS TONS TONS TONS ----------------- --------- ----- ------ ----- (TONS IN MILLIONS) Powder River Basin.................. Wyoming and Montana 190 2,732 2,922 Southwest........................... Arizona, Colorado and New Mexico 603 641 1,244 Appalachia.......................... West Virginia 210 480 690 Midwest............................. Illinois, Indiana and Kentucky 3,131 946 4,077 Australia........................... Queensland -- 147 147 ----- ----- ----- Total Proven and Probable Coal Reserves..................... 4,134 4,946 9,080 ===== ===== =====

--------------- (1) Reserves have been adjusted to take into account estimated losses involved in producing a saleable product. Proven and probable coal reserves are classified as follows: Proven Reserves -- Reserve estimates in this category have the highest degree of geologic assurance. Proven coal lies within one-quarter mile of a valid point of measurement or point of 21 observation (such as exploratory drill holes or previously mined areas) supporting such measurements. The sites for thickness measurement are so closely spaced, and the geologic character is so well defined, that the average thickness, area extent, size, shape and depth of coalbeds are well established. Probable Reserves -- Reserve estimates in this category have a moderate degree of geologic assurance. There are no sample and measurement sites in areas of indicated coal. However, a single measurement can be used to classify coal lying beyond measured as probable. Probable coal lies more than one-quarter mile, but less than three quarters of a mile from a point of thickness measurement. Further exploration is necessary to place probable coal into the proven category. In areas where geologic conditions indicate potential inconsistencies related to coal reserves, we perform additional drilling to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes that are spaced closer together than those distances cited above. We prepare our reserve estimates based on geological data assembled and analyzed by our staff, which includes various geologists and engineers. 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. We maintain 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, through a computerized land management system that we developed. Our reserve estimates are predicated on information obtained from our extensive drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole system 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 drill hole data 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. In addition, 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 March 2001, 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 9.5 billion tons of proven and probable reserves as of April 1, 2000. After adjusting for acquisitions and production through December 31, 2002, proven and probable reserves totaled 9.1 billion tons (see charts on page 24-25 of this report). 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, 2002, we leased or had applied to lease 23,384 acres of federal land in Colorado, 11,252 acres in Montana and 34,766 acres in Wyoming, for a total of 69,402 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. 22 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 9.1 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our reserve base 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. 23 The following chart provides a summary, by mining complex, of production for the year ended December 31, 2002, nine months ended December 31, 2001, and fiscal year ended March 31, 2001, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities. PRODUCTION AND ASSIGNED RESERVES(1) (TONS IN MILLIONS)

PRODUCTION SULFUR CONTENT(2) --------------------------------------- --------------------------------- 9 MONTHS YEAR <1.2 LBS. >1.2 TO 2.5 LBS. YEAR ENDED ENDED ENDED SULFUR DIOXIDE SULFUR DIOXIDE DECEMBER 31, DECEMBER 31, MARCH 31, TYPE OF PER MILLION PER MILLION MINING COMPLEX 2002 2001 2001 COAL BTU BTU -------------- ------------ ------------ --------- ---------- -------------- ---------------- Northern Appalachia: Federal No. 2............. 5.0 3.6 4.7 Steam -- -- ----- ----- ----- ------- ----- Northern Appalachia....... 5.0 3.6 4.7 -- -- Southern Appalachia: Big Mountain/White's Branch.................. 1.0 1.6 2.0 Steam 4.1 8.4 Harris #1................. 3.2 2.7 3.9 Steam/Met... 0.8 10.4 Rocklick.................. 3.5 2.5 3.2 Steam/Met... 25.2 8.1 Wells..................... 2.4 1.2 1.6 Steam/Met... 22.3 13.1 ----- ----- ----- ------- ----- Southern Appalachia....... 10.1 7.9 10.7 52.4 40.0 Midwest: Camps/Highland............ 3.0 2.4 5.4 Steam -- -- Midwest Operating Unit.... 1.7 1.3 1.2 Steam -- -- Patriot................... 2.6 1.8 2.0 Steam -- -- Black Beauty Air Quality No. 1....... 1.9 1.4 1.7 Steam 51.6 -- Riola No. 1............. 1.0 0.8 1.0 Steam -- -- Vermilion Grove......... 0.9 -- -- Steam -- -- Miller Creek/Sugar Ridge................. 0.6 0.8 0.1 Steam -- 1.7 Francisco............... 2.4 2.0 2.2 Steam -- -- Eel..................... 0.2 -- -- Steam -- -- Columbia................ 0.4 0.5 0.8 Steam -- -- Discovery............... 0.8 0.8 0.3 Steam -- -- Farmersburg............. 4.1 2.9 4.1 Steam -- 18.7 Birdwell................ -- -- 0.9 Steam -- -- Somerville Central...... 3.1 2.4 2.0 Steam -- -- Somerville North/West... 3.1 2.3 2.8 Steam -- -- Viking/Corning.......... 1.3 1.1 1.0 Steam -- 1.8 Arclar.................. 4.9 4.1 5.0 Steam -- -- West Fork............... -- -- 0.2 Steam -- -- Deanefield.............. -- 0.1 0.8 Steam -- -- ----- ----- ----- ------- ----- Midwest................... 32.0 24.7 31.5 51.6 22.2 Powder River Basin: Big Sky................... 2.8 2.0 1.7 Steam -- 13.7 North Antelope/Rochelle... 74.8 56.3 72.3 Steam 1,280.1 -- Caballo................... 26.0 20.7 25.6 Steam 775.1 31.6 Rawhide................... 3.5 -- -- Steam 376.8 108.7 ----- ----- ----- ------- ----- Powder River Basin........ 107.1 79.0 99.6 2,432.0 154.0 Southwest Black Mesa................ 4.7 3.4 4.9 Steam 72.6 11.2 Kayenta................... 8.4 6.2 8.5 Steam 226.4 81.9 Lee Ranch................. 6.4 4.7 5.2 Steam -- 156.0 Seneca.................... 1.8 1.3 1.5 Steam 11.7 0.1 ----- ----- ----- ------- ----- Southwest................. 21.3 15.6 20.1 310.7 249.2 Australia Wilkie Creek.............. 0.4 -- -- Steam 25.0 -- ----- ----- ----- ------- ----- Total...................... 175.9 130.9 166.6 2,871.7 465.4 ===== ===== ===== ======= =====

SULFUR CONTENT(2) AS OF DECEMBER 31, 2002 ---------------- ----------------------------------------------------- >2.5 LBS. AS ASSIGNED SULFUR DIOXIDE RECEIVED PROVEN AND PER MILLION BTU PER PROBABLE MINING COMPLEX BTU POUND(3) RESERVES OWNED LEASED SURFACE UNDERGROUND -------------- -------------- --------- ---------- ----- ------- ------- ------------ Northern Appalachia: Federal No. 2............. 39.0 13,334 39.0 0.3 38.7 -- 39.0 ----- ------- ----- ------- ------- ----- Northern Appalachia....... 39.0 39.0 0.3 38.7 -- 39.0 Southern Appalachia: Big Mountain/White's Branch.................. -- 12,541 12.5 -- 12.5 -- 12.5 Harris #1................. -- 13,474 11.2 -- 11.2 -- 11.2 Rocklick.................. -- 13,014 33.3 -- 33.3 23.3 10.0 Wells..................... -- 13,579 35.4 -- 35.4 -- 35.4 ----- ------- ----- ------- ------- ----- Southern Appalachia....... -- 92.4 -- 92.4 23.3 69.1 Midwest: Camps/Highland............ 226.6 11,078 226.6 41.1 185.5 -- 226.6 Midwest Operating Unit.... 15.9 10,886 15.9 15.0 0.9 3.0 12.9 Patriot................... 51.1 10,919 51.1 -- 51.1 4.9 46.2 Black Beauty Air Quality No. 1....... -- 11,043 51.6 0.4 51.2 -- 51.6 Riola No. 1............. 10.7 10,654 10.7 -- 10.7 -- 10.7 Vermilion Grove......... 23.7 10,647 23.7 -- 23.7 -- 23.7 Miller Creek/Sugar Ridge................. -- 11,549 1.7 0.3 1.4 1.7 -- Francisco............... 12.6 11,276 12.6 3.4 9.2 12.6 -- Eel..................... -- N/A -- -- -- -- -- Columbia................ -- N/A -- -- -- -- -- Discovery............... 0.2 10,556 0.2 -- 0.2 0.2 -- Farmersburg............. 4.2 10,867 22.9 16.3 6.6 22.9 -- Birdwell................ -- N/A -- -- -- -- -- Somerville Central...... 13.3 11,176 13.3 9.2 4.1 13.3 -- Somerville North/West... 10.9 11,237 10.9 8.5 2.4 10.9 -- Viking/Corning.......... 11.2 11,479 13.0 -- 13.0 13.0 -- Arclar.................. 53.7 12,210 53.7 47.3 6.4 3.7 50.0 West Fork............... -- N/A -- -- -- -- -- Deanefield.............. -- N/A -- -- -- -- -- ----- ------- ----- ------- ------- ----- Midwest................... 434.1 507.9 141.5 366.4 86.2 421.7 Powder River Basin: Big Sky................... 1.6 8,769 15.3 -- 15.3 15.3 -- North Antelope/Rochelle... -- 8,751 1,280.1 -- 1,280.1 1,280.1 -- Caballo................... 0.7 8,689 807.4 -- 807.4 807.4 -- Rawhide................... 9.3 8,505 494.8 -- 494.8 494.8 -- ----- ------- ----- ------- ------- ----- Powder River Basin........ 11.6 2,597.6 -- 2,597.6 2,597.6 -- Southwest Black Mesa................ -- 10,782 83.8 -- 83.8 83.8 -- Kayenta................... 3.4 10,949 311.7 -- 311.7 311.7 -- Lee Ranch................. 22.5 9,837 178.5 91.6 86.9 178.5 -- Seneca.................... 0.6 10,409 12.4 0.5 11.9 12.4 -- ----- ------- ----- ------- ------- ----- Southwest................. 26.5 586.4 92.1 494.3 586.4 -- Australia Wilkie Creek.............. -- 11,480 25.0 -- 25.0 25.0 -- ----- ------- ----- ------- ------- ----- Total...................... 511.2 3,848.3 233.9 3,614.4 3,318.5 529.8 ===== ======= ===== ======= ======= =====

24 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. ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES(1) AS OF DECEMBER 31, 2002 (TONS IN MILLIONS)

SULFUR CONTENT(2) -------------- <1.2 LBS. TOTAL TONS PROVEN AND SULFUR DIOXIDE --------------------- PROBABLE TYPE OF PER MILLION LOCATION ASSIGNED UNASSIGNED RESERVES PROVEN PROBABLE COAL BTU -------- -------- ---------- ---------- ------- -------- ---------- -------------- Northern Appalachia: Ohio....................... -- 39.7 39.7 27.5 12.2 Steam -- West Virginia.............. 39.0 219.2 258.2 96.1 162.1 Steam -- ------- ------- ------- ------- ------- ------- Northern Appalachia........ 39.0 258.9 297.9 123.6 174.3 -- Southern Appalachia: West Virginia.............. 92.4 299.3 391.7 267.3 124.4 Steam/Met.. 217.0 ------- ------- ------- ------- ------- ------- Southern Appalachia........ 92.4 299.3 391.7 267.3 124.4 217.0 Midwest: Illinois................... -- 2,260.4 2,260.4 1,046.1 1,214.3 Steam 4.9 Indiana.................... -- 323.9 323.9 207.5 116.4 Steam 0.1 Kentucky................... 293.6 802.2 1,095.8 648.9 446.9 Steam 0.2 Black Beauty Coal Company (Illinois, Indiana, Kentucky)................ 214.3 170.5 384.8 352.1 32.7 Steam 56.1 Missouri................... -- 11.8 11.8 10.7 1.1 Steam -- ------- ------- ------- ------- ------- ------- Midwest.................... 507.9 3,568.8 4,076.7 2,265.3 1,811.4 61.3 Powder River Basin: Montana.................... 15.3 301.3 316.6 288.4 28.2 Steam 42.1 Wyoming.................... 2,582.3 23.5 2,605.8 2,498.3 107.5 Steam 2,432.1 ------- ------- ------- ------- ------- ------- Powder River Basin......... 2,597.6 324.8 2,922.4 2,786.7 135.7 2,474.2 Southwest: Arizona.................... 395.5 -- 395.5 395.5 -- Steam 299.1 Colorado................... 12.4 152.7 165.1 134.7 30.4 Steam 62.8 New Mexico................. 178.5 501.4 679.9 318.1 361.8 Steam 233.3 Utah....................... -- 3.6 3.6 -- 3.6 Steam 3.6 ------- ------- ------- ------- ------- ------- Southwest.................. 586.4 657.7 1,244.1 848.3 395.8 598.8 Australia Queensland................. 25.0 122.0 147.0 133.0 14.0 Steam 147.0 ------- ------- ------- ------- ------- ------- Total Proven and Probable... 3,848.3 5,231.5 9,079.8 6,424.2 2,655.6 3,498.3 ======= ======= ======= ======= ======= =======

SULFUR CONTENT(2) --------------------------------- >1.2 TO 2.5 LBS. >2.5 LBS. AS SULFUR DIOXIDE SULFUR DIOXIDE RECEIVED RESERVE CONTROL MINING METHOD PER MILLION PER MILLION BTU PER ----------------- --------------------- LOCATION BTU BTU POUND(3) OWNED LEASED SURFACE UNDERGROUND -------- ---------------- -------------- -------- ------- ------- ------- ----------- Northern Appalachia: Ohio....................... -- 39.7 11,250 30.4 9.3 -- 39.7 West Virginia.............. 116.6 141.6 12,717 164.1 94.1 -- 258.2 ------- ------- ------- ------- ------- ------- Northern Appalachia........ 116.6 181.3 194.5 103.4 -- 297.9 Southern Appalachia: West Virginia.............. 142.6 32.1 13,197 15.6 376.1 47.6 344.1 ------- ------- ------- ------- ------- ------- Southern Appalachia........ 142.6 32.1 15.6 376.1 47.6 344.1 Midwest: Illinois................... 65.8 2,189.7 10,290 2,158.8 101.6 61.9 2,198.5 Indiana.................... 2.9 320.9 10,509 271.9 52.0 92.2 231.7 Kentucky................... 0.3 1,095.3 10,904 528.6 567.2 142.2 953.6 Black Beauty Coal Company (Illinois, Indiana, Kentucky)................ 3.5 325.2 11,355 170.8 214.0 106.3 278.5 Missouri................... -- 11.8 10,036 1.1 10.7 11.8 -- ------- ------- ------- ------- ------- ------- Midwest.................... 72.5 3,942.9 3,131.2 945.5 414.4 3,662.3 Powder River Basin: Montana.................... 127.9 146.6 8,594 189.2 127.4 316.6 -- Wyoming.................... 140.3 33.4 8,685 1.0 2,604.8 2,605.8 -- ------- ------- ------- ------- ------- ------- Powder River Basin......... 268.2 180.0 190.2 2,732.2 2,922.4 -- Southwest: Arizona.................... 93.0 3.4 10,914 -- 395.5 395.5 -- Colorado................... 101.7 0.6 10,787 6.8 158.3 13.0 152.1 New Mexico................. 424.1 22.5 8,422 593.0 86.9 662.7 17.2 Utah....................... -- -- 10,444 3.6 -- -- 3.6 ------- ------- ------- ------- ------- ------- Southwest.................. 618.8 26.5 603.4 640.7 1,071.2 172.9 Australia Queensland................. -- -- 11,180 -- 147.0 147.0 -- ------- ------- ------- ------- ------- ------- Total Proven and Probable... 1,218.7 4,362.8 4,134.9 4,944.9 4,602.6 4,477.2 ======= ======= ======= ======= ======= =======

25 --------------- (1) Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2002. Unassigned reserves represent coal at suspended locations and coal that has not been committed, and that would require new mine development, mining equipment or plant facilities before operations could begin on the property. (2) Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal. (3) As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The following table reflects the average moisture content used in the determination of as-received Btu by region:

Northern Appalachia......................................... 6.0% Southern Appalachia......................................... 7.0% Midwest: Illinois.................................................. 14.0% Indiana................................................... 15.0% Kentucky.................................................. 12.5% Black Beauty Coal Company................................. 14.5% Missouri/Oklahoma......................................... 12.0% Powder River Basin: Montana................................................... 26.5% Wyoming................................................... 27.5% Southwest: Arizona................................................... 13.0% Colorado.................................................. 14.0% New Mexico................................................ 15.5% Utah...................................................... 15.5%

RESOURCE DEVELOPMENT We hold approximately 9.1 billion tons of proven and probable coal reserves. Our Resource Development group constantly reviews this reserve base 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 leased to third parties and farm income from surface land under third party contracts. ITEM 3. LEGAL PROCEEDINGS From time to time, we are involved in legal proceedings arising in the ordinary course of business. We believe we have recorded adequate 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 or results of operations. 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. Other defendants in the litigation are one customer, one current employee and one former employee. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act, or RICO, 26 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 February 21, 2002, our subsidiaries commenced a lawsuit against the Navajo Nation in the U.S. District Court for the District of Arizona seeking enforcement of an arbitration award or, alternatively, to compel arbitration pursuant to the April 1, 1998 Arbitration Agreement with the Navajo Nation. On January 14, 2003, the Arizona District Court dismissed the lawsuit. Our subsidiaries have filed an appeal of this decision with the Ninth Circuit Court of Appeals. On February 22, 2002, our subsidiaries filed in the U.S. District Court for the District of Columbia a motion for leave to file an amended answer and conditional counterclaim. The counterclaim is conditional because our subsidiaries contend that the lease provisions the Navajo Nation seeks to invalidate have previously been upheld in an arbitration proceeding and are not subject to further litigation. On March 4, 2002, our subsidiaries filed in the U.S. District Court for the District of Columbia a motion to transfer that case to Arizona or, alternatively, to stay the District of Columbia litigation. The District of Columbia District Court denied our motion for a stay and we appealed that ruling to the District of Columbia Court of Appeals. Oral argument on our appeal is scheduled for April 14, 2003. 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 U.S. breached its trust responsibilities to the Tribe in approving the coal lease amendments and was liable for money damages. 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 or results of operations. SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT -- PRICE REVIEW In May 1997, Salt River Project Agricultural Improvement and Power District, or Salt River, acting for all owners of the Navajo Generating Station, exercised their contractual option to review certain cumulative cost changes during a five-year period from 1992 to 1996. Peabody Western sells approximately 7 to 8 million tons of coal per year to the owners of the Navajo Generation Station under a long-term contract. In July 1999, Salt River notified Peabody Western that it believed the owners were entitled to a price decrease of $1.92 per ton as a result of the review. Salt River also claimed entitlement to a retroactive price adjustment to January 1997 and that an overbilling of $50.5 million had occurred during the same five-year period. In October 1999, Peabody Western notified Salt River that it believed it was entitled to a $2.00 per ton price increase as a result of the review. The parties were unable to settle the dispute and Peabody Western filed a demand for arbitration in September 2000. The arbitration hearing was held in April 2002. On July 20, 2002, Peabody Western received a favorable decision from the arbitrators. The decision increased the price of coal by approximately $0.50 per ton from 1997 through 2001 and thereafter. As a result of the decision, we received pre-tax earnings of approximately $22 million during the quarter ended September 30, 2002. The exact impact of the ruling on the pricing of coal sales from January 1, 2002 forward will not be determined until Salt River completes a review of the cumulative cost changes under the contract for the years 1997 through 2001. 27 SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT -- MINE CLOSING AND RETIREE HEALTH CARE Salt River 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 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 or results of operations. SOUTHERN CALIFORNIA EDISON COMPANY In response to a demand for arbitration by one of our subsidiaries, Peabody Western, Southern California Edison and the other owners of the Mohave Generating Station filed a lawsuit on June 20, 1996 in the Superior Court of Maricopa County, Arizona. The lawsuit sought a declaratory judgment that mine decommissioning costs and retiree health care costs are not recoverable by Peabody Western under the terms of a coal supply agreement dated May 26, 1976. Peabody Western filed a motion to compel arbitration that was granted by the trial court. Southern California Edison appealed this order to the Arizona Court of Appeals, which denied its appeal. Southern California Edison then appealed the order to the Arizona Supreme Court, which remanded the case to the Arizona Court of Appeals and ordered the appellate court to determine whether the trial court was correct in determining that Peabody Western's claims are arbitrable. The Arizona Court of Appeals ruled that neither mine decommissioning costs nor retiree health care costs are to be arbitrated and that both issues should be resolved in litigation. The matter has been remanded to the Superior Court of Maricopa County, Arizona. Peabody Western answered the complaint and asserted counterclaims. The court then permitted Southern California Edison to amend its complaint to add a claim of overcharges of at least $19.2 million by Peabody Western. By order filed July 2, 2001, the court granted Peabody Western's motion for summary judgment on liability with respect to retiree healthcare costs. Southern California Edison filed a motion for reconsideration, which was denied by the court on October 16, 2001. Peabody Western filed a supplemental motion for summary judgment on liability with respect to mine decommissioning costs that was denied by the trial court on February 6, 2002. Peabody Western reached a mediated settlement with the owners of the Mohave Generating Station, which resulted in the recognition of $15.1 million in pre-tax earnings during the quarter ended September 30, 2002. The settlement provides for customer reimbursement of mine decommissioning and certain other post-mining expenditures. The reimbursement commenced in January 2003 and continues on a monthly basis through December 2005. All of the owners except one exercised their option to prepay these reimbursements in 2002. 28 CALIFORNIA PUBLIC UTILITIES COMMISSION PROCEEDINGS REGARDING THE FUTURE OF THE MOHAVE GENERATING STATION We have a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline to the Mohave plant. Also, Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utility Commission proceeding related to recovery of future capital expenditures for new pollution abatement equipment for the station. As a result of these issues, the owners of the Mohave Generating Station have announced that they expect to idle the plant for at least 12 to 18 months beginning in 2006. We are in active discussions to resolve the complex issues 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 beginning on December 31, 2005. The Mohave plant is the sole customer of our Black Mesa Mine, which sold 4.6 million tons of coal in 2002. SOCIAL SECURITY ADMINISTRATION In 1999, Eastern Associated Coal Corp. and Peabody Coal Company filed a lawsuit in the U.S. District Court for the Western District of Kentucky against the Social Security Administration asserting that the Social Security Administration, under the Coal Act, had improperly assigned certain beneficiaries to us. Subsequently, Peabody Coal and Eastern Associated moved for summary judgment on this claim. Summary judgment was granted and in 2000, the Social Security Administration filed an appeal of the district court's decision with the U.S. Court of Appeals for the Sixth Circuit. On June 21, 2001, the Sixth Circuit Court denied the Social Security Administration's appeal. The U.S. Supreme Court granted the federal government's petition for certiorari and on January 15, 2003 the Court ruled against our subsidiaries and overturned the Sixth Circuit's decision. As a result of the ruling, we recorded an after-tax charge of approximately $10 million in 2002 and our subsidiaries will be responsible for the health care premiums of the previously assigned defined group of approximately 300 beneficiaries. INDIANA MICHIGAN POWER COMPANY On September 27, 2001, our subsidiaries, Caballo Coal Company and Peabody COALSALES Company, filed suit in the U.S. District Court for the Eastern District of Missouri against Indiana Michigan Power Company, AEP Energy Services, Inc. and American Electric Power Service Corporation. Our subsidiaries contend that Indiana Michigan Power and American Electric Power Service Corporation breached their obligations under a coal supply agreement dated January 17, 1974. The agreement provides for a price renegotiation every five years. Our subsidiaries called for a price renegotiation in 2001, effective for coal delivered during 2002 through 2006. Our subsidiaries assert that Indiana Michigan Power and American Electric Power Service Corporation did not negotiate in good faith in that they did not submit a competitive offer to supply coal, as required under the contract, when they did not accept the offer submitted by our subsidiaries. Our subsidiaries are seeking specific performance of the agreement, injunctive relief, declaratory judgment, and damages for breach of contract and damages for tortious interference committed by AEP Energy Services. In January 2002, the court denied our motion for a preliminary injunction and the court's decision on the preliminary injunction was upheld on appeal. The case is now in the discovery phase. We are no longer shipping any coal to Indiana Michigan Power under this contract. Indiana Michigan Power contends that the contract terminated on December 31, 2001, which ended its obligation to purchase 3.5 million tons of coal annually. 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 that the only potential adverse impact on us, if Indiana Michigan Power is ultimately successful, will be our inability to ship further coal to the utility under the contract. 29 WEST VIRGINIA FLOODING LITIGATION Three of our subsidiaries have been named in four 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. As a result of this ruling, the cases have been transferred to the Circuit Court of Raleigh County in West Virginia to be handled by a panel consisting of three circuit court judges. They 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 or results of operations. ENVIRONMENTAL Federal and State Superfund Statutes. 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. Our subsidiary, Gold Fields Mining Corporation ("Gold Fields"), its predecessors and its former parent company are or may become parties to environmental proceedings that have commenced or may commence in the United States in relation to certain sites previously owned or operated by those entities or companies associated with them. We have agreed to indemnify Gold Fields' former parent company for any environmental claims resulting from any activities, operations or conditions that occurred prior to the sale of Gold Fields to us. Gold Fields and other potentially responsible parties are currently involved in environmental investigation, litigation or remediation at 11 sites. These 11 sites were formerly owned or operated by Gold Fields or Gold Fields' predecessors, associated companies and its former parent company. The Environmental Protection Agency has placed two of these sites on the National Priorities List, promulgated pursuant to Superfund, and one of the sites is on a similar state priority list. There are a number of additional sites in the United States that were previously owned or operated by such companies that could give rise to environmental proceedings in which Gold Fields could incur liabilities. Where the sites were identified, independent environmental consultants were employed in 1997 in order to assess the estimated total amount of the liability per site and the proportion of those liabilities that Gold Fields is likely to bear. The available information on which to base this review was very limited since all of the sites except for two sites (on which no remediation is currently taking place) are no longer owned by Gold Fields. Independent environmental consultants conducted another assessment in 2002. We have accrued liabilities of $42.1 million as of December 31, 2002 for the environmental liabilities described above relating to Gold Fields that are included as part of "other noncurrent liabilities" in our consolidated balance sheet. Significant uncertainty exists as to whether these 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. We believe that the remaining amount of the provision is adequate to cover these environmental liabilities. 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. 30 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. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted to a vote of security holders during the quarter ended December 31, 2002. ITEM 4A. EXECUTIVE OFFICERS OF THE COMPANY Set forth below are the names, ages as of February 28, 2003 and current positions of our executive officers. Executive officers are appointed by, and hold office at, the discretion of the Company's Board of Directors.

NAME AGE POSITION ---- --- -------- Irl F. Engelhardt..................... 56 Chairman, Chief Executive Officer and Director Richard M. Whiting.................... 48 Executive Vice President -- Sales, Marketing and Trading Roger B. Walcott, Jr.................. 46 Executive Vice President -- Corporate Development Richard A. Navarre.................... 42 Executive Vice President and Chief Financial Officer Fredrick D. Palmer.................... 58 Executive Vice President -- Legal and External Affairs and Secretary Sharon D. Fiehler..................... 46 Executive Vice President -- Human Resources and Administration Jeffery L. Klinger.................... 55 Vice President -- Legal Services and Assistant Secretary

Irl F. Engelhardt has been a director of the Company since 1998. He is Chairman and Chief Executive Officer of the Company, a position he has held since 1998. He served as Chief Executive Officer of a predecessor of the Company from 1990 to 1998. He also served as Chairman of a predecessor of the Company from 1993 to 1998 and as President from 1990 to 1995. Since joining a predecessor of the Company 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 and Co-Chairman of the National Mining Association's Sustainable Development and Health Care Reforms Committees. He has previously served as Chairman of the National Mining Association, the Coal Industry Advisory Board of the International Energy Agency, the Center for Energy and Economic Development, and the Co-Chairman of the Coal Utilization Research Council. He is also a director of U.S. Bank, N.A. Richard M. Whiting became Executive Vice President -- Sales, Marketing and Trading in October 2002. Previously, Mr. Whiting served as President and Chief Operating Officer of the Company and President of Peabody COALSALES Company. He joined a predecessor of the Company in 1976 and has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Mr. Whiting is 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 Chairman of the Bituminous Coal Operators' Association, Chairman of the National Mining Association's Safety and Health Committee and is a member of the Visiting Committee of West Virginia University College of Engineering and Mineral Resources. 31 Roger B. Walcott, Jr. became Executive Vice President -- Corporate Development of our company in February 2001. Prior to that, he was Executive Vice President of our company since 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 A. Navarre became Executive Vice President and Chief Financial Officer of our company in February 2001. Prior to that, he was Vice President -- Chief Financial Officer of our company 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 company in 1993 as Director of Financial Planning. Prior to joining us, Mr. Navarre was a senior manager with KPMG Peat Marwick. Mr. Navarre serves on the Board of Advisors to the College of Business for Southern Illinois University -- Carbondale. He is a member of Financial Executives International and the NYMEX Coal Advisory Council. Fredrick D. Palmer became Executive Vice President -- Legal and External Affairs of our company in February 2001. He is responsible for our legal and governmental affairs. Prior to joining Peabody, 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. Sharon D. Fiehler has been Executive Vice President of Human Resources and Administration of our company 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. Prior to joining Peabody, Ms. Fiehler, who earned degrees in social work and psychology and an MBA, was a personnel representative for Ford Motor Company. Ms. Fiehler is the chair of the Benefits Committee of the Bituminous Coal Operators' Association and is a member of the National Mining Association's Human Resource Committee. Jeffery L. Klinger was named Vice President -- Legal Services of our company in May 1998. Prior to that, he had been our Vice President, Secretary and Chief Legal Officer since October 1990. 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 ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS In May 2001, we completed an initial public offering of our common stock and sold 17.25 million shares to the public at an offering price of $28 per share. Our net proceeds from the offering totaled $449.8 million. Our common stock is listed on the New York Stock Exchange, under the symbol "BTU." 32 The table below sets forth the range of quarterly high and low sales prices for our common stock on the New York Stock Exchange during the calendar quarters indicated.

HIGH LOW ------ ------ 2002 First Quarter............................................... $30.03 $23.24 Second Quarter.............................................. 30.75 26.16 Third Quarter............................................... 28.26 17.50 Fourth Quarter.............................................. 29.27 22.60 2001 Second Quarter (from May 22, 2001).......................... $38.05 $26.00 Third Quarter............................................... 32.00 22.20 Fourth Quarter.............................................. 31.90 23.35

As of February 28, 2003, our authorized capital stock consisted of (1) 150.0 million shares of common stock, par value $0.01 per share, of which 52.4 million shares of common stock are issued and outstanding, (2) 10.0 million shares of preferred stock, par value $.01 per share, of which no shares are issued and outstanding and (3) 40.0 million shares of series common stock, par value $.01 per share, of which no shares are issued and outstanding. As of February 26, 2003, there were approximately 124 holders of record of our common stock. On April 5, 2002, certain of our shareholders, including our largest shareholder, Lehman Brothers Merchant Banking Partners II L.P. and affiliates (collectively "Lehman Brothers"), sold 9,000,000 shares of common stock in a secondary offering. The selling shareholders received all net proceeds. We did not sell any shares through the offering. The underwriters of the secondary offering were granted the right to purchase up to an additional 1,100,000 shares of common stock to cover over-allotments. The underwriters exercised the over-allotment option, and on May 8, 2002, purchased an additional 148,000 shares. Lehman Brothers sold, in the aggregate, 8,155,000 shares in the offering, and their beneficial ownership of our outstanding common stock declined from 57% to 41% immediately following the offering. On July 23, 2002, our Board of Directors adopted a preferred share purchase rights plan (the "Rights Plan"). In connection with the Rights Plan, the Board of Directors declared a dividend of one preferred share purchase right (a "Right") for each outstanding share of our common stock, par value $0.01 per share. The Rights dividend was payable on August 12, 2002 to the stockholders of record on that date. The description and terms of the Rights are set forth in an Agreement, dated as of July 24, 2002, between us and EquiServe Trust Company, N.A., as Rights Agent. The Rights have certain anti-takeover effects. The Rights will cause substantial dilution to a person or group that attempts to acquire us on terms not approved by our Board of Directors, except pursuant to any offer conditioned on a substantial number of Rights being acquired. The Rights should not interfere with any merger or other business combination approved by the Board of Directors since we may redeem the Rights at a redemption price of $0.001 per Right prior to the time that a person or group has acquired beneficial ownership of 15% or more of our common stock. In addition, the Board of Directors is authorized to reduce the 15% threshold to not less than 10%. DIVIDEND POLICY We paid quarterly dividends totaling $0.40 per share during the year ended December 31, 2002 and $0.20 per share during the nine months ended December 31, 2001. 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. Our Senior Credit Facility, as amended, allows us to pay annual dividends of up to the greater of $25.0 million or 10% of consolidated EBITDA as defined in the facility. 33 The indentures governing our Senior Notes and Senior Subordinated Notes permit us to pay annual dividends of up to the greater of 6% ($27.0 million) of the net proceeds from our initial public offering, or additional amounts based on, among other things, the sum of 50% of cumulative defined net income (since July 1, 1998) and 100% of the proceeds of our initial public offering. However, our Board of Directors will determine the actual amount of any dividends. RECENT SALES OF UNREGISTERED SECURITIES We sold shares of and issued options for common stock and preferred stock in the amounts, at the times, and for the aggregate amounts of consideration listed below without registration under the Securities Act of 1933. Exemption from registration under the Securities Act for each of the following sales is claimed under Section 4(2) of the Securities Act because each of the transactions was by the issuer and did not involve a public offering: On January 1, 2000, we issued 6,300 shares of common stock to two executives of our Citizens Power subsidiary in consideration for their services. Additionally, we issued 320,461 options to purchase common stock at an exercise price of $14.29 per share to our executives and to other employees. On July 1, 2000, we issued 42,087 shares of common stock to three executives in consideration for their services.(1) Additionally, we issued 398,929 options to purchase common stock at an exercise price of $14.29 per share to our executives and other employees. On October 1, 2000, we issued 49,350 shares of common stock at an exercise price of $14.29 per share to our executives. On December 29, 2000, we issued 83,255 shares of common stock to nine executives in consideration for their services. On January 1, 2001, we issued 945,263 options to purchase common stock at an exercise price of $14.29 per share to executives and to other employees in consideration for their services. On February 1, 2001, we issued 205,304 shares of common stock for an aggregate consideration of $1,096,912 to 20 of our executives in consideration for their services. On February 12, 2001, we issued 63,000 options to purchase common stock at an exercise price of $14.29 per share to one of our executives in consideration for his services. On April 9, 2001, we issued 11,466 shares of common stock for an aggregate consideration of $61,261 to one of our executives in consideration for his services. From May 22, 2001 through December 31, 2001, we issued 67,066 shares of common stock as a result of the exercise of options. During 2002, we issued 291,203 shares of common stock as a result of the exercise of options. All of these options were exercised at a price of $14.29 per share. --------------- (1) These shares had been acquired by us from terminated employees. 34 EQUITY COMPENSATION PLAN INFORMATION As required by Item 201(d) of Regulation S-K, the table below provides information regarding our equity compensation plans as of December 31, 2002:

(a) NUMBER OF SECURITIES -------------------- REMAINING AVAILABLE NUMBER OF FOR FUTURE ISSUANCE SECURITIES TO BE WEIGHTED-AVERAGE UNDER EQUITY ISSUED UPON EXERCISE EXERCISE PRICE OF COMPENSATION PLANS OF OUTSTANDING OUTSTANDING (EXCLUDING SECURITIES PLAN OPTIONS, WARRANTS OPTIONS, WARRANTS REFLECTED IN COLUMN CATEGORY AND RIGHTS AND RIGHTS (a)) -------- -------------------- -------------------- ----------------------- Equity compensation plans approved by security holders... 5,773,829 $17.02 2,437,205 Equity compensation plans not approved by security holders............ -- -- -- --------- ------ --------- Total........... 5,773,829 $17.02 2,437,205 ========= ====== =========

ITEM 6. SELECTED FINANCIAL DATA The following table presents selected financial and other data about us and our predecessor. We purchased our operating subsidiaries on May 19, 1998, and prior to that date we had no substantial operations. The period ended March 31, 1999 is thus a full fiscal year, but includes results of operations only from May 20, 1998. For periods prior to May 19, 1998, the results of operations are for the operating subsidiaries acquired, which we refer to as our "predecessor company" and which we include for comparative purposes. In early 1999, we increased our equity interest in Black Beauty Coal Company ("Black Beauty") from 43.3% to 81.7%. Our results of operations include the consolidated results of Black Beauty, effective January 1, 1999. Prior to that date, we accounted for our investment in Black Beauty under the equity method, under which we reflected our share of Black Beauty's results of operations as a component of "Other revenues" in the consolidated statements of operations, and our interest in Black Beauty's net assets within "Investments and other assets" in the consolidated balance sheets. 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, and recorded an estimated loss on the sale of $78.3 million, net of income taxes. We have adjusted our results of operations to reflect the classification of Citizens Power as a discontinued operation for all periods presented. 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. 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. We have derived the selected historical financial data for our predecessor for the period from April 1, 1998 to May 19, 1998 and as of May 19, 1998, and the selected historical financial data for our company for the period from May 20, 1998 to March 31, 1999 and as of March 31, 1999, the years ended and as of March 31, 2000 and 2001, the nine months ended and as of December 31, 2001 and the year ended and as of December 31, 2002 from our predecessor company's and our audited financial statements. You should read the following table in conjunction with the financial statements, the related notes to those financial 35 statements, and "Management's Discussion and Analysis of Financial Condition and Results of Operations."

NINE MONTHS YEAR ENDED ENDED YEAR ENDED YEAR ENDED DECEMBER 31, DECEMBER 31, MARCH 31, MARCH 31, 2002(1) 2001 2001(2) 2000(3) ------------ ------------ ----------- ----------- (DOLLARS IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA) RESULTS OF OPERATIONS DATA Revenues Sales....................... $ 2,630,371 $ 1,869,321 $2,534,964 $2,610,991 Other revenues.............. 86,727 68,619 93,164 99,509 ----------- ----------- ----------- ----------- Total revenues............ 2,717,098 1,937,940 2,628,128 2,710,500 Costs and expenses Operating costs and expenses.................. 2,225,344 1,588,596 2,123,526 2,178,664 Depreciation, depletion and amortization.............. 232,413 174,587 240,968 249,782 Selling and administrative expenses.................. 101,416 73,553 99,267 95,256 Gain on sale of Australian operations................ -- -- (171,735) -- Net gain on property and equipment disposals....... (15,763) (14,327) (5,737) (6,439) ----------- ----------- ----------- ----------- Operating profit............. 173,688 115,531 341,839 193,237 Interest expense............ 102,458 88,686 197,686 205,056 Interest income............. (7,574) (2,155) (8,741) (4,421) ----------- ----------- ----------- ----------- Income (loss) before income taxes and minority interests................... 78,804 29,000 152,894 (7,398) Income tax provision (benefit)................. (40,007) 2,465 42,690 (141,522) Minority interests.......... 13,292 7,248 7,524 15,554 ----------- ----------- ----------- ----------- Income (loss) from continuing operations.................. 105,519 19,287 102,680 118,570 Income (loss) from discontinued operations... -- -- 12,925 (90,360) ----------- ----------- ----------- ----------- Income before extraordinary item........................ 105,519 19,287 115,605 28,210 Extraordinary loss from early extinguishment of debt...................... -- (28,970) (8,545) -- ----------- ----------- ----------- ----------- Net income (loss)............ $ 105,519 $ (9,683) $ 107,060 $ 28,210 =========== =========== =========== =========== Basic earnings per share from continuing operations....... $ 2.02 $ 0.40 Diluted earnings per share from continuing operations.................. $ 1.96 $ 0.38 Basic and diluted earnings (loss) per Class A/B share from continuing operations.................. $ 2.97 $ 3.43 Weighted average shares used in calculating basic earnings (loss) per share... 52,165,735 48,746,444 27,524,626 27,586,370 Weighted average shares used in calculating diluted earnings (loss) per share... 53,821,760 50,524,978 27,524,626 27,586,370 Dividends declared per share....................... $ 0.40 $ 0.20 -- -- OTHER DATA Tons sold (in millions)...... 197.9 146.5 192.4 190.3 Adjusted EBITDA(5)........... $ 406,101 $ 290,118 $ 582,807 $ 443,019 Net cash provided by (used in): Operating activities........ 231,204 114,492 151,980 262,911 Investing activities........ (144,078) (172,989) 388,462 (185,384) Financing activities........ (54,798) 34,396 (543,337) (205,181) Depreciation, depletion and amortization................ 232,413 174,587 240,968 249,782 Capital expenditures......... 208,562 194,246 151,358 178,754 BALANCE SHEET DATA (AT PERIOD END) Total assets................ $ 5,140,177 $ 5,150,902 $5,209,487 $5,826,849 Total debt.................. 1,029,211 1,031,067 1,405,621 2,076,166 Total stockholders' equity/ invested capital.......... 1,081,138 1,035,472 631,238 508,426

PREDECESSOR COMPANY ---------------- PERIOD FROM PERIOD FROM TOTAL FISCAL MAY 20, 1998 TO APRIL 1, 1998 TO 1999(4) MARCH 31, 1999 MAY 19, 1998 ------------ --------------- ---------------- (DOLLARS IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA) RESULTS OF OPERATIONS DATA Revenues Sales....................... $ 2,249,887 $ 1,970,957 $ 278,930 Other revenues.............. 97,603 85,875 11,728 ----------- ----------- ---------- Total revenues............ 2,347,490 2,056,832 290,658 Costs and expenses Operating costs and expenses.................. 1,887,846 1,643,718 244,128 Depreciation, depletion and amortization.............. 204,698 179,182 25,516 Selling and administrative expenses.................. 88,905 76,888 12,017 Gain on sale of Australian operations................ -- -- -- Net gain on property and equipment disposals....... (328) -- (328) ----------- ----------- ---------- Operating profit............. 166,369 157,044 9,325 Interest expense............ 180,327 176,105 4,222 Interest income............. (20,194) (18,527) (1,667) ----------- ----------- ---------- Income (loss) before income taxes and minority interests................... 6,236 (534) 6,770 Income tax provision (benefit)................. 7,542 3,012 4,530 Minority interests.......... 1,887 1,887 -- ----------- ----------- ---------- Income (loss) from continuing operations.................. (3,193) (5,433) 2,240 Income (loss) from discontinued operations... 4,678 6,442 (1,764) ----------- ----------- ---------- Income before extraordinary item........................ 1,485 1,009 476 Extraordinary loss from early extinguishment of debt...................... -- -- -- ----------- ----------- ---------- Net income (loss)............ $ 1,485 $ 1,009 $ 476 =========== =========== ========== Basic earnings per share from continuing operations....... Diluted earnings per share from continuing operations.................. Basic and diluted earnings (loss) per Class A/B share from continuing operations.................. $ (0.16) Weighted average shares used in calculating basic earnings (loss) per share... 26,823,383 Weighted average shares used in calculating diluted earnings (loss) per share... 26,823,383 Dividends declared per share....................... -- OTHER DATA Tons sold (in millions)...... 176.0 154.3 21.7 Adjusted EBITDA(5)........... $ 371,067 $ 336,226 $ 34,841 Net cash provided by (used in): Operating activities........ 253,865 282,022 (28,157) Investing activities........ (2,270,886) (2,249,336) (21,550) Financing activities........ 2,184,818 2,161,281 23,537 Depreciation, depletion and amortization................ 204,698 179,182 25,516 Capital expenditures......... 195,394 174,520 20,874 BALANCE SHEET DATA (AT PERIOD END) Total assets................ $ 7,023,931 $ 7,023,931 $6,406,587 Total debt.................. 2,542,379 2,542,379 633,562 Total stockholders' equity/ invested capital.......... 495,230 495,230 1,497,374

--------------- (1) Results of operations for the year ended December 31, 2002 included an income tax benefit of $40.0 million. This benefit results primarily from significant tax benefits realized as a result of utilizing net operating loss carryforwards to offset taxable gains recognized in connection with the Penn 36 Virginia and landfill sale transactions (discussed in Item 7 of this report). Utilization of the loss carryforwards required the reduction of a previously recorded valuation allowance that had reduced the book value of the loss carryforwards. In 2002, due to a change in accounting principle discussed in Note 1 to our consolidated financial statements, we began recording revenues related to all coal trading activities on a net basis in "Other revenues," and all prior period amounts were reclassified. Had our physically settled trading transactions been recorded on a gross basis, total revenues and operating costs would have been $161.9 million, $88.8 million and $41.6 million higher for the year ended December 31, 2002, the nine months ended December 31, 2001 and the year ended March 31, 2001, respectively. (2) 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. (3) Results of operations for the year ended March 31, 2000 included a $144.0 million income tax benefit associated with an increase in the tax basis of a subsidiary's assets due to a change in federal income tax regulations. (4) For comparative purposes, we derived the "Total Fiscal 1999" column by adding the period from May 20, 1998 to March 31, 1999 with our predecessor company results for the period from April 1, 1998 to May 19, 1998. The effects of purchase accounting have not been reflected in the results of our predecessor company. (5) Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, minority interests and depreciation, depletion and amortization. Adjusted EBITDA is not a substitute for operating income, net income and cash flow from operating activities as determined in accordance with generally accepted accounting principles as a measure of profitability or liquidity. Adjusted EBITDA is presented as additional information because management 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. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FISCAL YEAR CHANGE 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. FACTORS AFFECTING COMPARABILITY SALE OF PEABODY RESOURCES LIMITED OPERATIONS In December 2000, we signed a share purchase agreement for the sale of the stock in two U.K. holding companies which, in turn, owned our Peabody Resources Limited subsidiaries in Australia, to a subsidiary of Rio Tinto Limited. These operations consisted of interests in six coal mines, as well as a mining services operation in Brisbane, Australia. The sale price was $455.0 million in cash, plus the assumption of all liabilities. The sale closed on January 29, 2001. DISCONTINUED OPERATIONS In August 2000, we sold Citizens Power, our subsidiary that marketed and traded electric power and energy-related commodity risk management products, to Edison Mission Energy. We classified Citizens Power as a discontinued operation as of March 31, 2000, and recorded an estimated loss on the sale of $78.3 million, net of income taxes. 37 CRITICAL ACCOUNTING POLICIES Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. EMPLOYEE-RELATED LIABILITIES Our subsidiaries have significant long-term liabilities for postretirement benefit costs, workers' compensation obligations and defined benefit pension plans. Detailed information related to these liabilities is included in the notes to our consolidated financial statements. Liabilities for postretirement benefit costs and workers' compensation obligations are not funded. Our pension obligations are funded in accordance with the provisions of federal law. Each of these liabilities are actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injuries and illnesses obligations. In addition, we make assumptions related to future compensation increases and rates of return on plan assets in the estimates of pension obligations. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. Expense for the year ended December 31, 2002 for these liabilities totaled $134.6 million, while payments were $143.9 million. RECLAMATION Our subsidiaries have significant long-term liabilities relating to mine reclamation and end of mine closure costs. Liabilities are recorded for the estimated costs to reclaim land as the acreage is disturbed during the ongoing surface mining process. The estimated costs to reclaim support acreage and perform other functions at both surface and underground mines are recorded ratably over the lives of the mines. Reclamation liabilities are not funded. The liability is determined on a by-mine basis and we use various assumptions, including estimates of disturbed acreage as determined from engineering data and the costs to reclaim the disturbed acreage. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Expense related to reclamation liabilities for the year ended December 31, 2002 was $11.0 million, and payments totaled $21.4 million. Our method for accounting for reclamation activities changed on January 1, 2003 as a result of the adoption of SFAS No. 143, "Accounting for Asset Retirement Obligations." The estimated effect of the adoption of SFAS No. 143 is discussed in the "Accounting Pronouncements Not Yet Implemented" section of Item 7 of this report, below. 38 TRADING ACTIVITIES We engage in the buying and selling of coal and emission allowances in over-the-counter markets. During 2002, accounting requirements related to our trading activities changed due to the rescission of Emerging Issues Task Force (EITF) Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." Contracts we entered into after October 25, 2002 were only accounted for on a fair value basis if they met the SFAS No. 133 definition of a derivative. This accounting change is discussed in Note 1 to our consolidated financial statements. To establish fair values for our trading contracts, we use bid/ask price quotations obtained from multiple, independent third party brokers to value coal and emission allowance positions. Prices from these sources are then averaged to obtain trading position values. We would experience difficulty in valuing our market positions if the number of third party brokers should decrease or market liquidity is reduced. Eighty-nine percent of the contracts in our trading portfolio as of December 31, 2002 were valued utilizing prices from over-the-counter market sources. The remaining 11% of our contracts were valued based on over-the-counter market source prices adjusted for differences in coal quality and content, as well as contract duration. As of December 31, 2002, the timing of trading portfolio contract expirations is as follows:

PERCENTAGE OF YEAR OF EXPIRATION PORTFOLIO ------------------ ------------- 2003........................................................ 48% 2004........................................................ 43% 2005........................................................ 8% 2006........................................................ 1% --- 100% ===

YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR ENDED DECEMBER 31, 2001 (NOT PRESENTED HEREIN) Sales. Sales for the year ended December 31, 2002 increased $115.8 million, or 4.6%, to $2,630.4 million. U.S. sales increased $121.9 million, a 4.9% increase from the prior year. Pricing increases in all regions drove the sales increase. Our average sales price was 5.6% higher than the prior year. The average price increase was impacted by higher priced contracts signed in 2001 and a $27.7 million increase in sales related to a favorable arbitration ruling that resulted in a retroactive price increase on our Navajo station coal supply agreement. This ruling is discussed in detail in Note 24 to our consolidated financial statements. The pricing increase was partially mitigated by sales mix, as higher priced tons in the Appalachia and Midwest regions represented a lower percentage of overall sales in the current year compared to the prior year. U.S. mining and broker operations' sales volume for the year ended December 31, 2002 was 183.5 million tons, which was 2.2 million tons below the prior year. We had lower sales volume at our Appalachia and Midwest operations, driven by soft market demand as a result of mild weather early in the year, a slower U.S. economy and more aggressive management of coal stockpile levels by customers. Volume decreases at our eastern operations more than offset a 1.4 million ton increase in sales volume at our western operations. Powder River Basin sales increased $130.3 million, due to improved pricing and slightly higher volume in the current year, driven by continued strong customer demand. Sales in the Southwest region were $33.9 million higher than the prior year, primarily due to the effect of the arbitration ruling previously discussed, combined with slightly higher pricing and volume. Appalachia region sales increased $7.7 million, as higher pricing offset lower volume from softer demand, which resulted in suspension of the Big Mountain Mine twice during the year and the Colony Bay Mine during the fourth quarter. Midwest region sales decreased $31.0 million, as higher prices were more than offset by lower volume due to 39 geologic problems at the Camp No. 11 Mine and delays in the startup of two new mines in the region, combined with softer coal demand in the current year. Finally, sales from coal brokerage activities decreased $20.3 million due to a change in sales mix and slightly lower volume. Sales from our Australian mining operations decreased $6.1 million compared to the prior year. The current year includes $9.9 million of sales related to the Wilkie Creek mining operations purchased in 2002, while the prior year included $16.0 million of sales from our Peabody Resources Limited operations that were sold in January 2001. Other Revenues. Other revenues for the year ended December 31, 2002 decreased $7.9 million from the prior year, to $86.7 million. The current year included a $15.1 million gain from a mediated settlement related to the Mohave generating station coal supply agreement. This settlement is discussed in detail in Note 24 to our consolidated financial statements. Revenues from trading operations increased $9.0 million, primarily due to $10.0 million related to a forward sale that will settle during 2003 and 2004. These improvements were offset by significantly lower coal royalty revenues. Other revenues in the prior year included higher coal royalties of $12.0 million, primarily due to two non-refundable advance royalties, $9.9 million related to the monetization of coal brokerage agreements that had increased in value due to favorable market conditions and $4.5 million of mining services revenues from our Peabody Resources Limited operations. Selling and Administrative Expenses. Selling and administrative expenses of $101.4 million for the year ended December 31, 2002 were $4.5 million lower than the prior year, due to the reduction of corporate expenses in response to difficult market conditions in the current year, combined with stock compensation charges recorded in the prior year related in part to our initial public offering. Gain on Sale of Peabody Resources Limited Operations. On January 29, 2001, we sold our Peabody Resources Limited operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto Limited. The selling price was $455.0 million, plus the assumption of all liabilities. We recorded a pretax gain of $171.7 million on the sale ($124.2 million after taxes). Net Gain on Property and Equipment Disposals. Net gain on property and equipment disposals of $15.8 million was $0.8 million higher than the prior year. The current year included a $10.1 million gain related to the sale of a landfill site that we developed and permitted using idle assets to serve Los Angeles County. The prior year included a $6.4 million gain on the sale of certain idle coal reserves and other reserve and equipment sales. Operating Profit. Excluding the effect of the $171.7 million gain on sale of our Peabody Resources Limited operations, operating profit increased $21.1 million, or 13.8%, to $173.7 million. Operating profit from U.S. operations increased $22.6 million, or 15.3%, to $170.9 million for the year ended December 31, 2002. The increase at the U.S. operations was driven by higher operating profit of $75.8 million from U.S. mining operations (excluding operating costs related to post-mining activities and net gains on property disposals) as a result of higher overall pricing due to contracts signed in 2001, combined with the effects of the Navajo station arbitration ruling and Mohave station mediated settlement, which increased operating profit by $37.1 million. In the west, the Powder River Basin region's operating profit increased $31.5 million as improved prices and higher volume overcame higher royalty and tax expenses associated with improved prices, higher repair and maintenance costs and higher fixed costs associated with running mines at lower than anticipated capacity in the current year. The Southwest region's operating profit increased $21.6 million as the $37.1 million increase related to the Navajo arbitration ruling and Mohave mediated settlement was partially offset by higher truck, dragline and shovel maintenance and repairs expense. In addition, two outages of the Southwest region's coal transportation pipeline contributed to higher costs in the current year. In the east, both regions' profits were negatively impacted by running mines at lower than anticipated capacity in the current year and charges in the fourth quarter related to the suspension of two mines in Appalachia due to lower than anticipated demand and the early closure of the Camp No. 11 Mine in the 40 Midwest due to geologic difficulties. Despite these issues, operating profit in the Midwest region increased $12.1 million compared to the prior year, as lower overall sales levels in the region and geologic difficulties at the Camp No. 11 mine were more than offset by improved pricing and lower fuel and maintenance and repair costs at Black Beauty. The Appalachia region's operating profit increased $10.6 million due to strong sales price improvement, which overcame higher per ton mining costs due to lower than planned production volume, the mine suspensions previously mentioned and production difficulties at the Harris Mine's longwall. Operating profit from trading and brokerage operations increased $7.3 million over the prior year, primarily due to the $10.0 million transaction discussed above in "Other Revenues." Our trading volume increased to 66.9 million tons in 2002 from 53.7 million tons traded in the prior year. Operating costs related to post-mining activities were $36.2 million higher in the year ended December 31, 2002, primarily due to $14.1 million of higher excise tax refunds in the prior year and a $17.2 million charge in the current year related to an adverse U.S. Supreme Court decision which assigned us responsibility for the health care premiums of certain beneficiaries previously withdrawn by the Social Security Administration as a result of a prior U.S. Circuit Court of Appeals decision. The remainder of the year-over-year increase related primarily to higher retiree healthcare costs. U.S. operations' operating profit was also affected by lower coal royalty income of $12.8 million and lower results from other commercial activities of $7.3 million. The current year also included $2.8 million from our Wilkie Creek operations in Australia, while the prior year included operating profit of $4.3 million from Peabody Resources Limited operations prior to their sale in January 2001. Interest Expense. Interest expense for 2002 was $102.5 million, a decrease of $30.5 million, or 22.9%, from the prior year. The decrease in borrowing cost was due to the significant long-term debt repayments made during 2001, and lower short-term interest rates in the current year. Utilizing proceeds from the sale of our Peabody Resources Limited operations in January 2001 and our initial public offering in May 2001, we reduced long-term debt by approximately $0.8 billion during 2001. As of December 31, 2002, our debt totaled approximately $1.0 billion. Interest Income. Interest income increased $3.7 million, to $7.6 million, for 2002. The current year included $4.6 million in interest income received related to excise tax refunds, while the prior year included interest earned on cash received from the sale of our Peabody Resources Limited operations in January 2001. Income Taxes. For 2002, we had an income tax benefit of $40.0 million on income before income taxes and minority interests of $78.8 million, compared to income tax expense of $41.5 million on income before income taxes and minority interests of $195.3 million in the prior year. Overall, our effective tax rate is sensitive to the benefit of the percentage depletion tax deduction relative to our annual profitability, as well as our ability to utilize our existing net operating loss carryforwards of over $500 million available for federal income tax purposes. In the prior year, the provision was affected by the sale of our Peabody Resources Limited operations. In 2002, our tax provision reflected significant tax benefits realized as a result of utilizing net operating loss carryforwards to offset taxable gains recognized in connection with the Penn Virginia (discussed in Item 2 of this report) and landfill sale transactions. Utilization of these net operating loss carryforwards allowed for the reduction of a previously recorded valuation allowance that had reduced the carrying value of our net operating loss carryforward tax benefits. Gain from Disposal of Discontinued Operations. During the year ended December 31, 2001, we reduced our loss on the sale of Citizens Power by $1.2 million. Extraordinary Loss from Early Extinguishment of Debt. During the year ended December 31, 2001, we repaid debt using proceeds from the sale of our Australian operations and our initial public offering. We recorded an extraordinary loss of $37.5 million, net of income taxes, which represented the excess of 41 cash paid over the carrying value of the debt retired and the write-off of debt issuance costs associated with the debt retired. NINE MONTHS ENDED DECEMBER 31, 2001 COMPARED TO NINE MONTHS ENDED DECEMBER 31, 2000 (NOT PRESENTED HEREIN) Sales. Sales for the nine months ended December 31, 2001 for the U.S. operations (represents all of our operations, except for Australian operations sold in January 2001) increased $153.8 million, to $1,869.3 million, a 9.0% increase from the prior year nine-month period. Improved sales volume in all mining operating regions and price improvements in all regions except the Midwest, where pricing remained level with the prior year nine-month period, led the increase. Sales volume for the U.S. operations was 146.5 million tons for the nine months ended December 31, 2001, compared to 133.7 million tons for the prior year nine-month period, an increase of 9.6%. Higher sales volume at our Powder River Basin, Southwest and Midwest operations led the increase, as our previous capital investments in these regions allowed us to meet increased customer demand. Overall U.S. operations' average sales price was 2.8% higher than the prior year nine-month period due to improved prices in the Appalachia and Powder River Basin markets that were driven by strong customer demand in those regions. The average pricing increase was slightly mitigated by sales mix, as the Appalachia and Midwest regions' higher priced tons represented a lower percentage of overall sales in the nine months ended December 31, 2001 compared to the prior year nine-month period. Total sales for the nine months ended December 31, 2001 decreased $20.4 million, or 1.1%, from the prior nine-month period, as the prior period included $174.2 million in sales from our Peabody Resources Limited operations, from sales volume of 9.8 million tons. Powder River Basin sales increased $58.8 million, due to improved pricing and volume from strong customer demand. Sales in the Midwest region increased $35.0 million, led by improved operational performance and higher sales volume at our Black Beauty operations. This improvement was partially offset by lower production at the Camps operating unit related to equipment problems in the nine months ended December 31, 2001, combined with the closure of the Camp No. 1 Mine in October 2000. Appalachian sales increased $33.0 million, as a result of improved demand-driven pricing. Sales in the Southwest region increased $28.1 million, as we expanded production at the Lee Ranch Mine to meet new sales commitments, and had higher demand at both of our Arizona mines. Other Revenues. Other revenues for the nine months ended December 31, 2001 for U.S. operations increased $45.2 million over the prior year nine-month period. The increase was primarily driven by higher revenues from trading and brokerage operations, and $9.9 million in proceeds from the profitable monetization of coal brokerage agreements with Enron. In addition, coal royalty income increased $10.9 million, primarily due to two non-refundable advance coal royalties received during the nine months ended December 31, 2001. Other revenues from Peabody Resources Limited operations included in the prior nine-month period were $43.8 million. Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense at U.S. operations increased $17.7 million in the nine months ended December 31, 2001, as compared with the prior year nine-month period. Higher production volume, combined with $3.6 million of additional depletion associated with the new coal royalty agreements discussed above, and $2.0 million of depletion associated with coalbed methane operations acquired early in 2001 led to the increase. Total depreciation, depletion and amortization expense of $174.6 million decreased $5.6 million, as the nine months ended December 31, 2000 included $23.3 million of expense from Australian operations. Selling and Administrative Expenses. Selling and administrative expenses of $73.6 million in the nine months ended December 31, 2001 increased $6.6 million compared to the nine months ended December 31, 2000. Selling and administrative expenses associated with increased volume, power plant development projects, higher insurance costs, and additional costs associated with being a public company drove the increase. 42 Net Gain on Property and Equipment Disposals. Net gain on property and equipment disposals increased $9.3 million, mainly due to gains on the sale of certain idle coal reserves in the nine months ended December 31, 2001. Operating Profit. Operating profit from U.S. operations increased $31.5 million, or 37.6%, for the nine months ended December 31, 2001. Overall operating profit decreased $17.5 million, or 13.2%, compared to the prior year nine-month period, which included $49.0 million of operating profit from Australian operations. Operating profit from U.S. mining operations increased $17.0 million for the nine months ended December 31, 2001, driven primarily by increased sales prices, especially in Appalachia and the Powder River Basin. The profit increase was achieved despite increased royalty and tax expense, increased energy- related mining costs, and higher maintenance, repair, and overtime costs. Royalty and tax expense, driven by higher sales prices, increased $20.5 million. Energy-related mining costs, particularly explosives costs, increased $17.4 million. Finally, maintenance and repair costs and overtime costs increased in most regions due to extended periods of producing at peak levels. In the west, the Powder River Basin region's operating profit increased $14.0 million, as higher volume and improved prices overcame higher explosives, fuel and repair and maintenance costs. In the Southwest region, operating profit was flat as higher sales volume was offset by higher explosives and power costs. In the east, the Appalachia region's operating profit increased $12.7 million due to strong sales prices, which overcame higher maintenance and repairs and labor costs driven by certain production difficulties and severe flooding in the current nine-month period. Operating profit in the Midwest region declined $9.3 million, as higher sales volume and improved productivity at our Black Beauty operations were more than offset by higher fuel and explosives costs at Black Beauty and production and equipment problems at the Camps operating unit in the nine months ended December 31, 2001. Operating costs related to post-mining activities were $9.8 million higher in the nine months ended December 31, 2001, primarily due to a $10.0 million reduction of our UMWA Combined Fund liability related to the withdrawal of certain beneficiaries by the Social Security Administration in the prior year nine-month period. In the nine months ended December 31, 2001, savings from prescription drug costs as a result of the implementation of a mail order drug program were offset by an $8.0 million reduction in the prior year nine-month period of our liability for environmental cleanup-related costs. Operating profit from trading and brokerage operations increased $16.4 million, as increased market volatility, liquidity and improved sourcing flexibility provided product and price arbitrage opportunities. The increase was achieved despite a $6.6 million charge related to the Enron bankruptcy in the nine months ended December 31, 2001. Operating profit also improved due to higher gains on the sale of coal reserves and increased coal royalties, discussed above. Increased selling and administrative costs decreased operating profit by $6.6 million. Interest Expense. Interest expense for the nine months ended December 31, 2001 was $88.7 million, a $64.8 million decrease, or 42.2%, from the prior year nine-month period. The decrease was due to the significant long-term debt repayments made since December 31, 2000. Utilizing proceeds from the sale of our Australian operations, combined with proceeds from our initial public offering in May 2001, we reduced long-term debt by $835 million from December 31, 2000 to December 31, 2001. We also benefited from a decrease in our average borrowing rate on our variable rate debt in the nine months ended December 31, 2001. Additionally, we entered into fixed to floating rate interest rate swaps with notional amounts totaling $150.0 million in October 2001, and realized interest savings of $0.6 million. Interest Income. Interest income decreased $4.8 million, to $2.2 million, for the nine months ended December 31, 2001. The decrease was mainly due to $3.6 million of interest income included in the prior 43 year nine-month period associated with excise tax refunds for the period from January 1, 1994 to March 31, 1998. Income Taxes. For the nine months ended December 31, 2001, income tax expense was $2.5 million on income before income taxes and minority interests of $29.0 million, compared to income tax expense of $3.7 million on a loss before income taxes and minority interests of $13.4 million in the prior year nine- month period. Excluding the effect of Australian operating results included in the prior year nine-month period, there was an income tax benefit of $13.8 million on a loss before income taxes and minority interests of $57.4 million. Overall, our effective tax rate is sensitive to the benefit of the percentage depletion tax deduction relative to our annual profitability, as well as our ability to utilize our existing net operating loss carryforwards. Income taxes for the nine months ended December 31, 2001 reflected a reduction in our effective income tax rate from 25.0% to 8.5%, primarily resulting from the impact of the allowance for percentage depletion for tax purposes in relation to pre-tax income from continuing operations. Gain from Disposal of Discontinued Operations. During the nine months ended December 31, 2000, we reduced our estimated loss on the sale of Citizens Power by $11.8 million, net of income taxes. The reduction reflected a decrease in the estimated operating losses of Citizens Power during the disposal period due to higher income from electricity trading activities driven by increased volatility and prices for electricity in the western U.S. power markets ($8.8 million) and higher estimated proceeds from the monetization of power contracts as part of the wind-down of Citizens Power's operations ($3.0 million). Citizens Power was classified as a discontinued operation effective March 31, 2000, and the sale was completed during the fiscal year ended March 31, 2001. Extraordinary Loss from Early Extinguishment of Debt. During the nine months ended December 31, 2001, we recorded an extraordinary loss of $29.0 million, net of income taxes, which represented the excess of cash paid over the carrying value of the debt retired and the write-off of debt issuance costs associated with the debt retired. LIQUIDITY AND CAPITAL RESOURCES Cash provided by operating activities was $231.2 million for the year ended December 31, 2002, an increase of $58.7 million, or 34% from the year ended December 31, 2001. Income before taxes and minority interests (excluding the gain on sale of Peabody Resources Limited operations included in the prior year) was $55.2 million higher than the prior year. Working capital cash usages were $22.8 million higher in 2002, while reclamation, workers' compensation and retiree healthcare spending was $26.5 million lower in 2002. Net cash used in investing activities was $144.1 million for 2002, compared to cash provided by investing activities of $247.2 million in the prior year. The prior year included $455.0 million of proceeds from the sale of our Peabody Resources Limited operations, and $16.9 million of proceeds related to the sale of Citizens Power. Capital expenditures decreased $27.7 million, to $208.6 million, in 2002. These capital expenditures were primarily for the replacement of mining equipment, the expansion of capacity at certain mines and projects to improve the efficiency of mining operations. Proceeds from property and equipment disposals increased $110.7 million to $125.4 million; proceeds in the current year included $72.5 million received related to our contribution of reserves to Penn Virginia and $27.7 million related to the landfill sale. Finally, 2002 included higher acquisition expenditures of $38.1 million. The 2002 acquisitions are discussed in detail in the notes to our consolidated financial statements. Net cash used by financing activities was $54.8 million for 2002, compared with cash used in financing activities of $414.1 million in the prior year. The prior year included $449.8 million of net proceeds from our initial public offering. Net debt repayments were $842.9 million higher in 2001, principally as a result of the usage of proceeds received from the sale of our Peabody Resources Limited operations and our initial public offering to repay debt. We also received a $19.9 million dividend in 2001 44 from our Peabody Resources Limited operations. In addition, we increased dividends paid to our shareholders by $10.5 million in 2002. The following table reflects our total indebtedness as of December 31, 2002 (in thousands):

9.625% Senior Subordinated Notes ("Senior Subordinated Notes") due 2008.......................................... $ 391,490 8.875% Senior Notes ("Senior Notes") due 2008............... 316,498 5.0% Subordinated Note...................................... 85,055 Senior unsecured notes under various agreements............. 58,214 Unsecured revolving credit agreement of Black Beauty........ 116,584 Other....................................................... 61,370 ---------- Total debt........................................ $1,029,211 ==========

As of December 31, 2002, our revolving credit and letter of credit borrowing facilities included the $480.0 million Revolving Credit Facility under our Senior Credit Facility and Black Beauty's $140.0 million revolving credit facility. The Revolving Credit Facility has a borrowing sub-limit of $350.0 million and a letter of credit sub-limit of $330.0 million. Together, these facilities total $620.0 million, and had a total of $316.6 million available for borrowing as of December 31, 2002. Revolving loans under our Revolving Credit Facility bear interest based on the Base Rate (as defined in the Senior Credit Facility), or LIBOR (as defined in the Senior Credit Facility) at our option. The applicable rate was 2.9% at December 31, 2002. Black Beauty has a $140.0 million revolving credit facility that matures on April 17, 2004. Black Beauty may elect one or a combination of interest rates based on LIBOR or the corporate base rate plus a margin, which fluctuates based on specified leverage ratios. The effective annual interest rate was 3.0% as of December 31, 2002. The revolving credit facility contains customary restrictive covenants including limitations on additional debt, investments and dividends. As of December 31, 2002, we had borrowings of $116.6 million outstanding under the Black Beauty revolving credit facility and no borrowings outstanding under our Revolving Credit Facility. The following is a summary of commercial commitments available to us under our Revolving Credit Facility and Black Beauty's revolving credit facility as of December 31, 2002 (in thousands):

EXPIRATION PER YEAR --------------------------------------------------------------- TOTAL AMOUNTS WITHIN COMMITTED 1 YEAR 2-3 YEARS 4-5 YEARS OVER 5 YEARS ------------- -------- --------- --------- ------------ Lines of credit............. $490,000 -- $490,000 -- -- Standby letters of credit... 330,000 -- 330,000 -- --

As of December 31, 2002, we have issued letters of credit totaling $186.8 million under our Revolving Credit Facility, leaving $143.2 million of letter of credit capacity available under the Revolving Credit Facility. We are considering the acquisition of the 18.3% minority interest of Black Beauty. Should we complete this acquisition, we anticipate funding it from our available borrowing capacity. The indentures governing our Senior Notes and Senior Subordinated Notes permit us and our Restricted Subsidiaries (as defined in the indentures) to incur additional indebtedness, including secured indebtedness, subject to certain limitations. In addition, the indentures limit our and our Restricted Subsidiaries' ability to: lease, convey or otherwise dispose of all or substantially all of our assets; issue specified types of capital stock; enter into guarantees of indebtedness; incur liens; merge or consolidate with any other person or enter into transactions with affiliates; and repurchase junior securities or make specified types of investments. The indentures permit us to pay annual dividends of up to the greater of 6% ($27.0 million) of the net proceeds from our initial public offering, or additional amounts based on, among other things, the sum of 50% of cumulative defined net income (since July 1, 1998) and 100% of the 45 proceeds of our initial public offering. We expressly reserve the right, at our sole discretion, from time to time, to purchase any notes, in the open market or through privately negotiated transactions. On February 27, 2003, we commenced a tender offer to purchase for cash any and all of our outstanding Senior Notes and Senior Subordinated Notes. The tender offer or any redemption of notes on May 15, 2003 will be conditioned upon obtaining sufficient proceeds from the refinancing initiatives announced in February 2003. These initiatives include a new $600 million revolving credit facility and a new $600 million bank term loan, and issuance of other senior debt in the amount of $500 million. We intend to use a portion of the net proceeds from these financings to fund the purchase of the senior notes and the senior subordinated notes in connection with the tender offer. We intend to call for redemption on May 15, 2003, in accordance with the applicable indenture, all notes that remain outstanding after the tender offer, at the redemption price of 104.438% of the principal amount with respect to the Senior Notes and at the redemption price of 104.813% of the principal amount with respect to the Senior Subordinated Notes, plus interest accrued and unpaid up to but not including, the redemption date. We have designated interest rate swaps with notional amounts totaling $150.0 million as a fair value hedge of our Senior Notes. Under the swaps, we pay a floating rate based upon the six-month LIBOR rate for a period of seven years ending May 15, 2008. The applicable rate was 5.41% as of December 31, 2002. We realized interest savings of $4.2 million related to the swaps during 2002. During the year, Fitch Ratings, Inc. affirmed its investment-grade BBB rating on the corporate senior unsecured notes and unsecured bank revolver of Black Beauty. On October 2, 2002, Moody's assigned us an SGL-1 liquidity rating. Under Moody's rating system, SGL-1 means "very good" liquidity. Moody's SGL ratings, an assessment of liquidity, are used to supplement the current Moody's credit ratings for companies rated from "Ba1" to "C." In January 2003, Standard & Poor's announced that it assigned its BB+ rating to our Senior Credit Facility. The agency also affirmed its BB corporate credit rating and its stable outlook. CONTRACTUAL OBLIGATIONS The following is a summary of our significant contractual obligations as of December 31, 2002 (in thousands):

PAYMENTS DUE BY YEAR ------------------------------------------- WITHIN AFTER 1 YEAR 2-3 YEARS 4-5 YEARS 5 YEARS -------- --------- --------- -------- Long-term debt............................. $ 47,515 $196,502 $ 70,563 $714,631 Capital lease obligations.................. 3,879 976 372 16 Operating leases........................... 100,526 165,158 100,863 87,505 Unconditional purchase obligations......... 56,825 -- -- -- Coal reserve obligations................... 24,676 51,696 48,617 66,027 -------- -------- -------- -------- Total contractual cash obligations.... $233,421 $414,332 $220,415 $868,179 ======== ======== ======== ========

Additionally, we have long-term liabilities relating to retiree health care (postretirement benefits and multi-employer benefit plans), work-related injuries and illnesses, defined benefit pension plans and mine reclamation and end of mine closure costs. The following is the estimated spending related to these items as of December 31, 2002 (in thousands):

ESTIMATED EXPENDITURES ---------------------- Within 1 Year............................................... $201,200 2-3 Years................................................... 378,300 4-5 Years................................................... 410,000

We had $56.8 million of committed capital expenditures at December 31, 2002. Total capital expenditures for 2003 are expected to range from $175 million to $200 million, and have been and will be 46 primarily used to develop existing reserves, replace or add equipment, acquire additional low sulfur or other strategic coal reserves and fund cost reduction initiatives. We anticipate funding these capital expenditures through operating cash flow. In addition, cash requirements to fund employee related and reclamation liabilities included above are expected to be funded from operating cash flow, along with obligations related to long-term debt, capital and operating leases and coal reserves. We believe the risk of generating lower than anticipated operating cash flow in 2003 is reduced by our high level of sales commitments (95% of 2003 planned production) and recent efforts to improve our operating cost structure. OFF-BALANCE SHEET ARRANGEMENTS In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds and our $140.0 million accounts receivable securitization. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements. We use surety bonds to secure our reclamation, workers' compensation, postretirement benefits and coal lease obligations. As of December 31, 2002, we had outstanding surety bonds with third parties for post-mining reclamation totaling $622.6 million. We had an additional $164.4 million of surety bonds in place for workers' compensation and retiree healthcare obligations and $69.0 million of surety bonds securing coal leases. Recently, surety bond costs have increased, while the market terms of surety bonds have generally become less favorable to us. To the extent that surety bonds become unavailable, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral. We have guaranteed $14.9 million of debt of an affiliate in which we have a 49% equity investment, as described in Note 22 to our consolidated financial statements. We maintain letters of credit totaling $223.8 million to secure lease, workers' compensation, postretirement benefits, and other obligations, as discussed in Notes 11, 15, 17 and 22, respectively, to our consolidated financial statements. Our remaining guarantees and indemnifications are discussed in Note 22 to our consolidated financial statements. In March 2000, we established an accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been contributed to the Seller are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit ("Conduit"). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We used proceeds from the sale of our accounts receivable to repay long-term debt, effectively reducing our overall borrowing costs. The funding cost of the securitization program was $3.3 million for the year ended December 31, 2002. The securitization program is currently scheduled to expire in 2007. Under the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," the securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from our consolidated balance sheet. The amount of undivided interests in accounts receivable sold to the Conduit were $136.4 million as of December 31, 2002. A detailed description of our $140.0 million accounts receivable securitization is included in Note 5 to our consolidated financial statements. ACCOUNTING PRONOUNCEMENTS NOT YET IMPLEMENTED In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This Statement is effective for fiscal years beginning after June 15, 2002 (effective January 1, 2003 for Peabody), and primarily changes the manner in which we recognize expense for final reclamation of acreage disturbed during the mining process. Based on recent industry implementation guidance, we anticipate recording a cumulative gain of approximately $10 million to $15 million, net of income taxes, upon adoption of SFAS No. 143. Beginning 47 with 2003, we expect depreciation and accretion expense of approximately $10 million to $15 million in addition to the $11.0 million of expense recorded for final reclamation for the year ended December 31, 2002. Future changes to implementation guidance, if any, could result in changes to these anticipated impacts. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections," which is effective January 1, 2003 for Peabody. As a result of SFAS No. 145, gains or losses on debt extinguishment previously reported as extraordinary items will be presented as a component of results from continuing operations unless the extinguishment meets the criteria for classification as an extraordinary item in Accounting Principles Board Opinion No. 30. On February 27, 2003, we commenced a tender offer to purchase for cash any and all of our outstanding Senior Notes and Senior Subordinated Notes. The tender offer or any redemption of notes on May 15, 2003 will be conditioned upon obtaining sufficient proceeds from the refinancing initiatives announced in February 2003. These initiatives include a new $600 million revolving credit facility and a new $600 million bank term loan, and issuance of other senior debt in the amount of $500 million. Any charges incurred pursuant to the extinguishment of our existing debt as a result of the refinancing will impact our results from continuing operations. On October 25, 2002, the EITF rescinded EITF Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The effects of the rescission on the Company's accounting for coal and emission allowance trading activities are discussed in Note 1 to our consolidated financial statements. As a result of the rescission, energy trading contracts we entered into after October 25, 2002 are evaluated under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The effect of the rescission on non-derivative energy trading contracts entered into prior to October 25, 2002 will be recorded as a cumulative effect of a change in accounting principle in the first quarter of 2003. We anticipate we will record a cumulative effect loss of $15 to $20 million, net of income taxes, to reverse the net unrealized gains on non-derivative energy trading contracts recorded prior to December 31, 2002. These non-derivative energy trading contracts will settle in 2003 and 2004. In November 2002, the FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others" (FIN 45). The disclosure requirements of FIN 45 are effective for our 2002 consolidated financial statements. For applicable guarantees issued after January 1, 2003, FIN 45 requires that a guarantor recognize a liability for the fair value of the obligation undertaken in issuing the guarantee. We do not believe that the accounting requirements of FIN 45 will have a material effect on our financial condition or results of operations. In January 2003, FASB issued Interpretation No. 46, "Consolidation of Variable Interest Entities" (FIN 46), which requires the consolidation of variable interest entities, as defined. FIN 46 is applicable to financial statements to be issued after 2002; however, disclosures are required currently if any variable interest entities are expected to be consolidated. We do not believe that any entities will be consolidated as a result of FIN 46. RISKS RELATING TO OUR COMPANY IF A SUBSTANTIAL PORTION OF OUR LONG-TERM COAL SUPPLY AGREEMENTS TERMINATE, OUR REVENUES AND OPERATING PROFITS COULD SUFFER IF WE WERE UNABLE TO FIND ALTERNATE BUYERS WILLING TO PURCHASE OUR COAL ON COMPARABLE TERMS TO THOSE IN OUR CONTRACTS. A substantial portion of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. For the year ended December 31, 2002, 97% of our sales volume was sold under long-term coal supply agreements. At December 31, 2002, our coal supply agreements had remaining terms ranging from one to 18 years and an average volume-weighted remaining term of approximately 4.4 years. 48 Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We may adjust these contract prices based on inflation and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. We sometimes experience a reduction in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements permit the customer to terminate the contract if transportation costs, which our customers typically bear, increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits. The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Some of our coal supply agreements are for prices above current market prices. Although market prices for coal increased in most regions in 2001, market prices for coal decreased in most regions in 2002. As a result, we cannot predict the future strength of the coal market and cannot assure you that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, two of our coal supply agreements are the subject of ongoing litigation and arbitration, as discussed in Item 3 of this report. THE LOSS OF, OR SIGNIFICANT REDUCTION IN, PURCHASES BY OUR LARGEST CUSTOMERS COULD ADVERSELY AFFECT OUR REVENUES. For the year ended December 31, 2002, we derived 28% of our total coal revenues from sales to our five largest customers. At December 31, 2002, we had 31 coal supply agreements with these customers that expire at various times from 2003 to 2015. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and those customers may not continue to purchase coal from us under long-term coal supply agreements. If a number of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially. In addition, we sold 4.6 million tons of coal to the Mohave Generating Station in 2002. We have a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of coal by pipeline to the Mohave Generating Station. Also, Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utility Commission proceeding related to recovery of future capital expenditures for new pollution abatement equipment for the station. As a result of these issues, the owners of the Mohave Generating Station have announced that they expect to idle the plant for at least 12 to 18 months beginning in 2006. We are in active discussions to resolve the complex issues 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 Generating Station will be resolved. The Mohave Generating Station is the sole customer of our Black Mesa Mine, which produces and sells 4.5 to 49 5 million tons of coal per year. If we are unable to renew the coal supply agreement with the Mohave Generating Station, our financial condition and results of operations could be adversely affected after 2005. OUR FINANCIAL PERFORMANCE COULD BE ADVERSELY AFFECTED BY OUR SUBSTANTIAL DEBT. Our financial performance could be affected by our substantial indebtedness. As of December 31, 2002, we had total indebtedness of $1,029.2 million. We currently have total borrowing capacity under our and Black Beauty's revolving credit facilities of $490.0 million. We may also incur additional indebtedness in the future. Our ability to pay principal and interest on our debt depends upon the operating performance of our subsidiaries, which will be affected by, among other things, prevailing economic conditions in the markets they serve, some of which are beyond our control. Our business may not generate sufficient cash flow from operations and future borrowings may not be available under our revolving credit facilities or otherwise in an amount sufficient to enable us to service our indebtedness or to fund our other liquidity needs. The degree to which we are leveraged could have important consequences, including, but not limited to: (1) making it more difficult for us to pay dividends and satisfy our debt obligations; (2) increasing our vulnerability to general adverse economic and industry conditions; (3) requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal of, and interest on, our indebtedness, thereby reducing the availability of the cash flow to fund working capital, capital expenditures, research and development or other general corporate uses; (4) limiting our ability to obtain additional financing to fund future working capital, capital expenditures, research and development or other general corporate requirements; (5) limiting our flexibility in planning for, or reacting to, changes in our business; and (6) placing us at a competitive disadvantage compared to less leveraged competitors. In addition, our indebtedness subjects us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us. Furthermore, substantially all of our assets, except for the assets of Black Beauty Coal Company and its affiliates, secure our indebtedness under our senior credit facility. IF TRANSPORTATION FOR OUR COAL BECOMES UNAVAILABLE OR UNECONOMIC FOR OUR CUSTOMERS, OUR ABILITY TO SELL COAL COULD SUFFER. Transportation costs represent a significant portion of the total cost of coal, and as a result, the cost of transportation is a critical factor in a customer's purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make some of our operations less competitive than other sources of coal. Certain coal supply agreements permit the customer to terminate the contract if the cost of transportation increases by an amount ranging from 10% to 20% in any given 12-month period. Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to deliver coal to markets. While U.S. coal customers typically arrange and pay for transportation of coal from the mine to the point of use, disruption of these transportation services because of weather-related problems, strikes, lock-outs or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations. For example, the high volume of coal shipped from all Southern Powder River Basin mines could create temporary congestion on the rail systems servicing that region. RISKS INHERENT TO MINING COULD INCREASE THE COST OF OPERATING OUR BUSINESS. Our mining operations are subject to conditions beyond our control that can delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include weather and natural disasters, unexpected maintenance problems, key equipment failures, variations in coal seam thickness, variations in the amount of rock and soil overlying the coal deposit, variations in rock and other natural materials and variations in geologic conditions. 50 THE GOVERNMENT EXTENSIVELY REGULATES OUR MINING OPERATIONS, WHICH IMPOSES SIGNIFICANT COSTS ON US, AND FUTURE REGULATIONS COULD INCREASE THOSE COSTS OR LIMIT OUR ABILITY TO PRODUCE COAL. Federal, state and local authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers' ability to use coal. New legislation or administrative regulations (or judicial interpretations of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser's plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations. In addition, the United States and over 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. 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 U.S. greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely impact the price of and demand for coal. According to the Energy Information Administration's Emissions of Greenhouse Gases in the United States 2001, coal accounts for 32% 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 sources of fuel with lower carbon dioxide emissions. Further developments in connection with regulations or other limits on carbon dioxide emissions could have a material adverse effect on our financial condition or results of operations. OUR EXPENDITURES FOR POSTRETIREMENT BENEFIT AND PENSION OBLIGATIONS COULD BE MATERIALLY HIGHER THAN WE HAVE PREDICTED IF OUR UNDERLYING ASSUMPTIONS PROVE TO BE INCORRECT. We provide postretirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation under Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," which we estimate had a present value of $1,031.7 million as of December 31, 2002, $72.1 million of which was a current liability. We have estimated these unfunded obligations based on assumptions described in the notes to our consolidated financial statements. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher. Moreover, regulatory changes could increase our obligations to provide these or additional benefits. We are party to an agreement with the Pension Benefit Guaranty Corporation, or the PBGC, and TXU Europe Limited, an affiliate of our former parent corporation, under which we are required to make specified contributions to two of our defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If we or the PBGC give notice of an intent to terminate one or more of the 51 covered pension plans in which liabilities are not fully funded, or if we fail to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guaranty in place from TXU Europe Limited in favor of the PBGC before it draws on our letter of credit. On November 19, 2002 TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the United States). As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guaranty. In addition, certain of our subsidiaries participate in two multi-employer pension funds and have an obligation to contribute to a multi-employer defined contribution benefit fund. Contributions to these funds could increase as a result of future collective bargaining with the United Mine Workers of America, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute, lower than expected returns on pension fund assets, higher medical and drug costs or other funding deficiencies. Certain of our subsidiaries are statutorily obligated to contribute to the 1992 Fund under the Coal Act. Contributions to this fund could increase as a result of a shrinking contribution base and increasing beneficiaries due to the insolvency of other coal companies who currently contribute, higher medical and drug costs or other funding deficiencies. OUR FUTURE SUCCESS DEPENDS UPON OUR ABILITY TO CONTINUE ACQUIRING AND DEVELOPING COAL RESERVES THAT ARE ECONOMICALLY RECOVERABLE. Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserve base through acquisitions of government and other leases and producing properties and continuing to use our existing properties. The federal government also leases natural gas and coalbed methane reserves in the west, including in the Powder River Basin. Some of these natural gas and coalbed methane reserves are located on, or adjacent to, some of our Powder River Basin reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees' rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2002, we leased or had applied to lease a total of 69,402 acres from the federal government. The limit could restrict our ability to lease additional federal lands. Our planned development and exploration projects and acquisition activities may not result in significant additional reserves and we may not have continuing success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because title to most of our leased properties and mineral rights are not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we must receive various governmental permits. We cannot predict whether we will continue to receive the permits necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties or obtain mining contracts for properties containing additional reserves or maintain our leasehold interest in properties on which mining operations are not commenced during the term of the lease. From time to time, we have experienced litigation with lessors of our coal properties and with royalty holders. IF THE COAL INDUSTRY EXPERIENCES OVERCAPACITY IN THE FUTURE, OUR PROFITABILITY COULD BE IMPAIRED. During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in added production capacity throughout the industry, all of which led to increased competition and lower coal 52 prices. Similarly, an increase in future coal prices could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices in the future. OUR FINANCIAL CONDITION COULD BE NEGATIVELY AFFECTED IF WE FAIL TO MAINTAIN SATISFACTORY LABOR RELATIONS. As of December 31, 2002, the United Mine Workers of America represented approximately 31% of our employees, who produced 19% of our coal sales volume during 2002. An additional 4% of our employees are represented by labor unions other than the United Mine Workers of America. These employees produced 3% of our coal sales volume during 2002. Because of the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our non-unionized competitors may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. The ten-month United Mine Workers of America strike in 1993 had a material adverse effect on us. Two of our subsidiaries, Peabody Coal Company and Eastern Associated Coal Corp., operate under a union contract that is in effect through December 31, 2006. Peabody Western Coal Company operates under a union contract that is in effect through September 1, 2005. OUR OPERATIONS COULD BE ADVERSELY AFFECTED IF WE FAIL TO MAINTAIN REQUIRED SURETY BONDS. Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers' compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. As of December 31, 2002, we had outstanding surety bonds with third parties for post-mining reclamation totaling $622.6 million. Furthermore, we had an additional $164.4 million of surety bonds in place for workers' compensation and retiree healthcare obligations and $69.0 million of surety bonds securing coal leases. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us to secure new surety bonds or renew bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material adverse effect on us. That failure could result from a variety of factors including the following: - lack of availability, higher expense or unfavorable market terms of new surety bonds; - restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures or senior credit facility; and - the exercise by third-party surety bond issuers of their right to refuse to renew the surety. LEHMAN BROTHERS MERCHANT BANKING HAS SIGNIFICANT INFLUENCE ON ALL STOCKHOLDER VOTES AND MAY HAVE CONFLICTS OF INTEREST WITH OTHER STOCKHOLDERS IN THE FUTURE. At December 31, 2002, Lehman Brothers Merchant Banking and its affiliates beneficially owned approximately 41% of our common stock. As a result, Lehman Brothers Merchant Banking will effectively continue to be able to influence the election of our directors and determine our corporate and management policies and actions, including potential mergers or acquisitions, asset sales and other significant corporate transactions. The interests of Lehman Brothers Merchant Banking may not coincide with the interests of other holders of our common stock. We have retained affiliates of Lehman Brothers Merchant Banking to perform advisory and financing services for us in the past, and may continue to do so in the future. OUR ABILITY TO OPERATE OUR COMPANY EFFECTIVELY COULD BE IMPAIRED IF WE LOSE KEY PERSONNEL. We manage our business with a number of key personnel, in particular the executive officers discussed previously in Part I, Item 4A of this report. The loss of a number of key personnel could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success 53 will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot assure you that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. We do not have "key person" life insurance to cover our executive officers. Failure to retain or attract key personnel could have a material adverse effect on us. TERRORIST ATTACKS AND THREATS, ESCALATION OF MILITARY ACTIVITY IN RESPONSE TO SUCH ATTACKS OR ACTS OF WAR MAY NEGATIVELY AFFECT OUR BUSINESS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS. Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers, may materially adversely affect our operations. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations. OUR ABILITY TO COLLECT PAYMENTS FROM OUR CUSTOMERS COULD BE IMPAIRED IF THEIR CREDITWORTHINESS DETERIORATES. Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties. These new power plant owners may have credit ratings that are below investment grade. In addition, the creditworthiness of certain of our customers and trading counterparties has deteriorated due to lower than anticipated demand for energy and lower volume and volatility in the traded energy markets in 2002. If deterioration of the creditworthiness of other electric power generator customers or trading counterparties continues, our $140.0 million accounts receivable securitization program and our business could be adversely affected. OUR CERTIFICATE OF INCORPORATION AND BY-LAWS INCLUDE PROVISIONS THAT MAY DISCOURAGE A TAKEOVER ATTEMPT. Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. For example, a change of control of our company may be delayed or deterred as a result of the stockholders' rights plan adopted by our board of directors. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK TRADING ACTIVITIES TRADING ACTIVITIES We market and trade coal and emission allowances. These activities give rise to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits 54 prescribed by management. For example, we have policies in place that limit the amount of total exposure we may assume at any point in time. We account for coal and emission allowance trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, futures, options and swaps, at market value in our consolidated financial statements. Our policy for accounting for coal and emission allowance trading activities is described in Note 1 to our consolidated financial statements. We perform a value at risk analysis on our trading portfolio, which includes over-the-counter and brokerage trading of coal and emission allowances. The use of value at risk allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. Our value at risk model is based on the industry standard risk-metrics variance/co-variance approach. This captures our exposure related to both option and forward positions. Our value at risk model assumes a 15-day holding period and a 95% one-tailed confidence interval. The use of value at risk allows management to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. Due to the subjectivity in the choice of the liquidation period, reliance on historical data to calibrate the models and the inherent limitations in the value at risk methodology, including the use of delta/gamma adjustments related to options, we perform regular stress, back testing and scenario analysis to estimate the impacts of market changes on the value of the portfolio. The results of these analyses are used to supplement the value at risk methodology and identify additional market-related risks. During the year ended December 31, 2002, the low, high, and average values at risk for our coal trading portfolio were $0.3 million, $3.9 million, and $1.7 million, respectively. Our emission allowance value at risk during the year ended December 31, 2002 never exceeded $0.2 million. Forty-eight percent of the value of our trading portfolio is scheduled to be realized by the end of 2003, and 91% of the value of our trading portfolio is scheduled to be realized by the end of 2004. We also monitor other types of risk associated with our coal and emission allowance trading activities, including credit, market liquidity and counterparty nonperformance. NON-TRADING ACTIVITIES We manage our commodity price risk for non-trading purposes through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 97% of our sales volume under long-term coal supply agreements during 2002. We have sales commitments for 95% of our 2003 production. Some of the products used in our mining activities, such as diesel fuel, are subject to price volatility. We, through our suppliers, utilize forward contracts to manage the exposure related to this volatility. We have exposure to changes in interest rates due to our existing level of indebtedness. As of December 31, 2002, after taking into consideration the effects of interest rate swaps, we had $721.5 million of fixed-rate borrowings and $307.7 million of variable-rate borrowings outstanding. A one percent increase in interest rates would result in an annualized increase to interest expense of $3.1 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a $34.4 million decrease in the fair value of these borrowings. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA See Part IV, Item 15 of this report for the information required by this Item. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 55 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by Item 401 of Regulation S-K is included under the caption "Election of Directors" in the Company's 2003 Proxy Statement and in Part I, Item 4A of this report under the caption "Executive Officers of the Company." Such information is incorporated herein by reference. The information required by Item 405 of Regulation S-K is included under the caption "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's 2003 Proxy Statement and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION The information required by Item 402 of Regulation S-K is included under the caption "Executive Compensation" in the Company's 2003 Proxy Statement and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required by Item 403 of Regulation S-K is included under the caption "Ownership of Company Securities" in the Company's 2003 Proxy Statement and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by Item 404 of Regulation S-K is included under the caption "Related Party Transactions" in the Company's 2003 Proxy Statement and is incorporated herein by reference. ITEM 14. CONTROLS AND PROCEDURES The Chief Executive Officer and Executive Vice President and Chief Financial Officer have evaluated our disclosure controls and procedures within 90 days of the filing of this report and have concluded that there are no significant deficiencies or material weaknesses. There have been no significant changes in our internal controls or in other factors subsequent to the date of our most recent evaluation that could significantly affect these controls. There have been no significant changes in the Corporation's internal controls or in other factors that could significantly affect internal controls subsequent to December 31, 2002. PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Financial Statements (1) The following consolidated financial statements of Peabody Energy Corporation included in the Company's December 31, 2002 Annual Report to Stockholders are incorporated by reference: Report of Independent Auditors Consolidated Statements of Operations -- Year Ended December 31, 2002, Nine Months Ended December 31, 2001 and the Year Ended March 31, 2001 Consolidated Balance Sheets -- December 31, 2002 and December 31, 2001 Consolidated Statements of Changes in Stockholders' Equity -- Year Ended December 31, 2002, Nine Months Ended December 31, 2001 and the Year Ended March 31, 2001 Consolidated Statements of Cash Flows -- Year Ended December 31, 2002, Nine Months Ended December 31, 2001 and the Year Ended March 31, 2001 Notes to Consolidated Financial Statements 56 (2) Financial Statement Schedule The following financial statement schedule of Peabody Energy Corporation is included in Item 15, along with the report of independent auditors thereon, at the pages indicated:

PAGE ---- Report of Independent Auditors on Financial Statement Schedule.................................................. F-1 Valuation and Qualifying Accounts........................... F-2

All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted. (3) Exhibits See Exhibit Index hereto. (b) Reports on Form 8-K On October 17, 2002, we filed a Form 8-K under Item 5, Other Events and Regulation FD Disclosure, concerning Adjusted EBITDA and earnings per share for the quarter ended September 30, 2002 and revised guidance on Adjusted EBITDA and earnings per share for the year ended December 31, 2002. On December 23, 2002, we filed a Form 8-K under Item 5, Other Events and Regulation FD Disclosure, concerning our exchange of coal reserves for $72.5 million in cash and 2.76 million units of Penn Virginia Resource Partners, L.P., a publicly-held master limited partnership. On January 17, 2003, we filed a Form 8-K under Item 5, Other Events and Regulation FD Disclosure, announcing two events, an adverse U.S. Supreme Court ruling and the recognition of certain income tax benefits, that impacted our earnings in the fourth quarter of 2002. On January 31, 2003, we filed a Form 8-K under Item 9, Regulation FD Disclosure, concerning our calendar year and fourth quarter 2002 earnings, and our 2003 forecast. On February 27, 2003, we filed a Form 8-K under Item 5, Other Events and Regulation FD Disclosure, announcing that we had commenced a tender offer to purchase for cash any and all of our outstanding 8 7/8% Senior Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008. 57 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PEABODY ENERGY CORPORATION /s/ IRL F. ENGELHARDT -------------------------------------- Irl F. Engelhardt Chairman and Chief Executive Officer Date: March 7, 2003 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.

SIGNATURE TITLE DATE --------- ----- ---- /s/ IRL F. ENGELHARDT Chairman, Chief Executive Officer March 7, 2003 ------------------------------------------------ and Director (principal executive Irl F. Engelhardt officer) /s/ RICHARD A. NAVARRE Executive Vice President and Chief March 7, 2003 ------------------------------------------------ Financial Officer (principal Richard A. Navarre financial and accounting officer) /s/ HENRY E. LENTZ Vice President, Assistant March 7, 2003 ------------------------------------------------ Secretary and Director Henry E. Lentz /s/ BERNARD J. DUROC-DANNER Director March 7, 2003 ------------------------------------------------ Bernard J. Duroc-Danner /s/ ROGER H. GOODSPEED Director March 7, 2003 ------------------------------------------------ Roger H. Goodspeed /s/ WILLIAM E. JAMES Director March 7, 2003 ------------------------------------------------ William E. James /s/ ROBERT B. KARN III Director March 7, 2003 ------------------------------------------------ Robert B. Karn III /s/ WILLIAM C. RUSNACK Director March 7, 2003 ------------------------------------------------ William C. Rusnack /s/ JAMES R. SCHLESINGER Director March 7, 2003 ------------------------------------------------ James R. Schlesinger /s/ BLANCHE M. TOUHILL Director March 7, 2003 ------------------------------------------------ Blanche M. Touhill /s/ SANDRA VAN TREASE Director March 7, 2003 ------------------------------------------------ Sandra Van Trease /s/ ALAN H. WASHKOWITZ Director March 7, 2003 ------------------------------------------------ Alan H. Washkowitz

58 CERTIFICATION I, Irl F. Engelhardt, certify that: 1. I have reviewed this annual report on Form 10-K of Peabody Energy Corporation ("the registrant"); 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and (c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. IRL F. ENGELHARDT -------------------------------------- Irl F. Engelhardt, Chief Executive Officer Date: March 7, 2003 59 CERTIFICATION I, Richard A. Navarre, certify that: 1. I have reviewed this annual report on Form 10-K of Peabody Energy Corporation ("the registrant"); 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have: (a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; (b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and (c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions): (a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and (b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. RICHARD A. NAVARRE -------------------------------------- Richard A. Navarre Executive Vice President and Chief Financial Officer Date: March 7, 2003 60 REPORT OF INDEPENDENT AUDITORS Board of Directors Peabody Energy Corporation We have audited the consolidated financial statements of Peabody Energy Corporation (the Company) as of December 31, 2002 and 2001, and for the year ended December 31, 2002, the nine months ended December 31, 2001 and the year ended March 31, 2001, and have issued our report thereon dated January 18, 2003. Our audits also included the financial statement schedule listed in Item 15(a). This schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. ERNST & YOUNG LLP St. Louis, Missouri January 18, 2003 F-1 PEABODY ENERGY CORPORATION SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS

BALANCE AT CHARGED TO BALANCE BEGINNING COSTS AND AT END DESCRIPTION OF PERIOD EXPENSES DEDUCTIONS(1) OTHER OF PERIOD ----------- ---------- ---------- ------------- ------ --------- YEAR ENDED DECEMBER 31, 2002 Reserves deducted from asset accounts: Land and coal interests............ $12,836 $ 780 $ -- $ (31) $13,585 Reserve for materials and supplies......................... 9,893 -- (847) 19 9,065 Allowance for doubtful accounts.... 1,496 (165) -- -- 1,331 NINE MONTHS ENDED DECEMBER 31, 2001 Reserves deducted from asset accounts: Land and coal interests............ $13,184 $(275) $ -- $ (73) $12,836 Reserve for materials and supplies......................... 11,562 -- (1,689) 20 9,893 Allowance for doubtful accounts.... 1,213 283 -- -- 1,496 YEAR ENDED MARCH 31, 2001 Reserves deducted from asset accounts: Land and coal interests............ $13,199 $ 605 $ -- $ (620)(2) $13,184 Reserve for materials and supplies......................... 12,400 -- (2,672) 1,834(2) 11,562 Allowance for doubtful accounts.... 1,233 -- (20) -- 1,213

--------------- (1) Reserves utilized, unless otherwise indicated. (2) Balances transferred from other accounts. F-2 EXHIBIT INDEX The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.

EXHIBIT NUMBER DESCRIPTION ------- ----------- 3.1 Third Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant's Form S-1 Registration Statement No. 333-55412). 3.2 Amended and restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.2 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, filed on November 14, 2002). 3.3 Certificate of Designations of Series A Junior Participating Preferred Stock of the Company, filed with the Secretary of State of the State of Delaware on July 24, 2002 (Incorporated herein by reference to Exhibit 3.1 to the Company's Registration Statement on Form 8-A, filed on July 24, 2002.). 4.1 Senior Note Indenture dated as of May 18, 1998 between the Registrant and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.1 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.2 Senior Subordinated Note Indenture dated as of May 18, 1998 between the Registrant and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.2 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.3 First Supplemental Senior Note Indenture dated as of May 19, 1998 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.3 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.4 First Supplemental Senior Subordinated Note Indenture dated as of May 19, 1998 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.4 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.5 Notation of Senior Subsidiary Guarantee dated as of May 19, 1998 among the Senior Note Guarantors (as defined in the Senior Note Indenture) (Incorporated by reference to Exhibit 4.5 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.6 Notation of Subordinated Subsidiary Guarantee dated as of May 19, 1998 among the Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) (Incorporated by reference to Exhibit 4.6 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.7 Senior Note Registration Rights Agreement dated as of May 18, 1998 between the Registrant and Lehman Brothers Inc. (Incorporated by reference to Exhibit 4.7 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.8 Senior Subordinated Note Registration Rights Agreement dated as of May 18, 1998 between the Registrant and Lehman Brothers Inc. (Incorporated by reference to Exhibit 4.8 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.9 Second Supplemental Senior Note Indenture dated as of December 31, 1998 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.9 of the Registrant's Form 10-Q for the quarter ended December 31, 1999). 4.10 Second Supplemental Senior Subordinated Note Indenture dated as of December 31, 1998 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.10 of the Registrant's Form 10-Q for the quarter ended December 31, 1999).

EXHIBIT NUMBER DESCRIPTION ------- ----------- 4.11 Third Supplemental Senior Note Indenture dated as of June 30, 1999 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.11 of the Registrant's Form 10-Q for the quarter ended December 31, 1999). 4.12 Third Supplemental Senior Subordinated Note Indenture dated as of June 30, 1999 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.12 of the Registrant's Form 10-Q for the quarter ended December 31, 1999). 4.13 Specimen of stock certificate representing the Registrant's common stock, $.01 par value. (Incorporated by reference to Exhibit 4.13 of the Registrant's Form S-1 Registration Statement No. 333-55412). 4.14 Stockholders' Agreement dated as of May 19, 1998 among the Registrant, Lehman Brothers Merchant Banking Partners II L.P., Lehman Brothers Offshore Investment Partners II L.P., LB I Group Inc., Lehman Brothers Capital Partners III, L.P., Lehman Brothers Capital Partners IV, L.P., Lehman Brothers MBG Partners 1998 (A) L.P. and certain members of the Registrant's management (Incorporated by reference to Exhibit 4.14 of the Registrant's Form S-1 Registration Statement No. 333-55412). 4.15 Stockholders' Agreement dated as of July 23, 1998 among the Registrant, Lehman Brothers Merchant Banking Partners II L.P., Lehman Brothers Offshore Investment Partners II L.P., LB I Group Inc., Lehman Brothers Capital Partners III, L.P., Lehman Brothers Capital Partners IV, L.P., Lehman Brothers MBG Partners 1998 (A) L.P., Co-Investment Partners, L.P., The Mutual Life Insurance Company of New York and Finlayson Investments Pte Ltd. (Incorporated by reference to Exhibit 4.15 of the Registrant's Form S-1 Registration Statement No. 333-55412). 4.16 Registration Rights Agreement, dated as of December 2001, among the Registrant, Lehman Brothers Merchant Banking Partners II L.P., Lehman Brothers Offshore Investment Partners II L.P., LB I Group, Inc., Lehman Brothers Capital Partners III L.P., Lehman Brothers Capital Partners IV L.P., Lehman Brothers MBG Partners (A) L.P., Lehman Brothers MBG Partners (B) L.P. and Lehman MBG Partners (C) L.P. (Incorporated by reference to Exhibit 4.16 to the Registrant's Annual Report on Form 10-K for the nine months ended December 31, 2002, filed on March 12, 2002). 4.17 Form of Fourth Supplemental Senior Note Indenture dated as of February 16, 2000 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.17 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, filed on May 13, 2002). 4.18 Form of Fourth Supplemental Senior Subordinated Note Indenture dated as of February 16, 2000 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.18 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, filed on May 13, 2002). 4.19 Fifth Supplemental Senior Note Indenture dated as of March 27, 2000 among the Registrant, each Senior Note Guarantor (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.19 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, filed on May 13, 2002). 4.20 Fifth Supplemental Senior Subordinated Note Indenture dated as of March 27, 2000 among the Registrant, each Senior Subordinated Note Guarantor (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.20 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, filed on May 13, 2002).

EXHIBIT NUMBER DESCRIPTION ------- ----------- 4.21 Form of Sixth Supplemental Senior Note Indenture dated as of February 11, 2002 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.21 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, filed on May 13, 2002). 4.22 Form of Sixth Supplemental Senior Subordinated Note Indenture dated as of February 11, 2002 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.22 to the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, filed on May 13, 2002). 4.23 Rights Agreement, dated as of July 24, 2002, between the Company and EquiServe Trust Company, N.A., as Rights Agent (which includes the form of Certificate of Designations of Series A Junior Preferred Stock of the Company as Exhibit A, the form of Right Certificate as Exhibit B and the Summary of Rights to Purchase Preferred Shares as Exhibit C) (Incorporated herein by reference to Exhibit 4.1 to the Company's Registration Statement on Form 8-A, filed on July 24, 2002). 4.24 Seventh Supplemental Senior Note Indenture dated as of August 14, 2002 among the Registrant, each Senior Note Guarantor (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.24 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, filed on November 14, 2002). 4.25 Seventh Supplemental Senior Subordinated Note Indenture dated as of August 14, 2002 among the Registrant, each Senior Subordinated Note Guarantor (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.25 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, filed on November 14, 2002). 10.1 Amended and Restated Credit Agreement dated as of June 9, 1998 among the Registrant, as Borrower, Lehman Brothers Inc., as Arranger, Lehman Commercial Paper Inc., as Syndication Agent, Documentation Agent, and Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.2 Guarantee and Collateral Agreement dated as of May 14, 1997 made by the Guarantors, in favor of Lehman Commercial Paper, Inc., as Administrative Agent for the banks and other financial institutions (Incorporated by reference to Exhibit 10.2 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.3 Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.4 Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.5 Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.6 Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.7 Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.8 Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.9 Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (Incorporated by reference to Exhibit 10.9 of the Registrant's Form 10-Q for the second quarter ended September 30, 1998).

EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.10* 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.10 of the Registrant's Form 10-Q for the third quarter ended December 1998). 10.11* Employment Agreement between Irl F. Engelhardt and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.11 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.12* Employment Agreement between Richard M. Whiting and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.12 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.13* Employment Agreement between Richard A. Navarre and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.13 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.14* Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.14 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.15* Employment Agreement between Paul H. Vining and the Registrant dated July 1, 2000 (Incorporated by reference to Exhibit 10.19 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.16 Amendment No. 1 to Credit Agreement dated as of April 30, 2001 among the Registrant, as Borrower, Lehman Brothers Inc., as Arranger, Lehman Commercial Paper Inc., as Syndication Agent, Bank of America National Trust & Savings Association and The Fuji Bank, Limited, as Documentation Agents, Bank One, NA, as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.20 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.17* First Amendment to the Employment Agreement between Irl F. Engelhardt and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.21 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.18* First Amendment to the Employment Agreement between Richard M. Whiting and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.22 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.19* First Amendment to the Employment Agreement between Richard A. Navarre and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.23 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.20* First Amendment to the Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.24 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.21* First Amendment to the Employment Agreement between Paul H. Vining and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.25 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.22* Form of First Amendment to Stockholders' Agreement dated as of May 19, 1998 (Incorporated by reference to Exhibit 10.26 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.23* Form of Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.27 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.24* Form of 2001 Employee Stock Purchase Plan (Incorporated by reference to Exhibit 10.28 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.25* Form of Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.29 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.26* Form of Amendment to the Non-Qualified Stock Option Agreement (Incorporated by reference to Exhibit 10.30 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.27* Peabody Energy Corporation Deferred Compensation Plan (Incorporated by reference to Exhibit 10.30 of the Registrant's Form 10-Q for the quarter ended September 30, 2001).

EXHIBIT NUMBER DESCRIPTION ------- ----------- 10.28 Receivables Purchase Agreement as of February 20, 2002, by and among Seller, the Registrant, Market Street Funding Corporation, and PNC Bank, National Association, as Administrator (Incorporated by reference to Exhibit 10.28 of the Registrant's Form 10-K for the nine months ended December 31, 2001, filed on March 12, 2002). 10.29 Settlement Agreement and Mutual Release as of October 1, 2002, by and among Peabody Western Coal Company and Southern California Edison, Salt River Project Agricultural Improvement and Power District, Los Angeles Department of Water and Power and Nevada Power Company (Incorporated by reference to Exhibit 10.29 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, filed on November 14, 2002). 10.30 Purchase And Sale Agreement by and among Peabody Energy Corporation, Eastern Associated Coal Corp., Peabody Natural Resources Company, and Penn Virginia Resource Partners, L.P. dated December 19, 2002 (Incorporated by reference to Exhibit 10.30 to the Registrant's Form 8-K, filed on December 23, 2002). 10.31*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Irl F. Engelhardt. 10.32*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Bernard J. Duroc-Danner. 10.33*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Roger H. Goodspeed. 10.34*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and William E. James. 10.35*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Henry E. Lentz. 10.36*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and William C. Rusnack. 10.37*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Dr. James R. Schlesinger. 10.38*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Dr. Blanche M. Touhill. 10.39*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Alan H. Washkowitz. 10.40*+ Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Richard A. Navarre. 10.41*+ Indemnification Agreement, dated as of January 16, 2003, by and between Registrant and Robert B. Karn III. 10.42*+ Indemnification Agreement, dated as of January 16, 2003, by and between Registrant and Sandra A. Van Trease. 13+ Portions of the Company's Annual Report to Stockholders for the year ended December 31, 2002. 21+ List of Subsidiaries. 23+ Consent of Ernst & Young LLP, Independent Auditors. 99.1+ Certification of Principal Executive Officer Pursuant to 18 U.S.C. 1350 (Section 906 of the Sarbanes-Oxley Act of 2002) 99.2+ Certification of Principal Financial Officer Pursuant to 18 U.S.C. 1350 (Section 906 of the Sarbanes-Oxley Act of 2002).

--------------- * These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(c) of this report. + Filed herewith.