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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


Form 10-K

     
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the Fiscal Year Ended December 31, 2003
 
or
 
o
  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 organization)   (I.R.S. Employer Identification No.)
 
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
Preferred Share Purchase Rights
  New York Stock Exchange
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 þ          No o

      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     o

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

      Aggregate market value of the voting stock held by non-affiliates of the Registrant, calculated using the closing price on June 30, 2003 of $33.59: Common Stock, par value $0.01 per share, $1,244.1 million.

      Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 17, 2004: Common Stock, par value $0.01 per share, 54,905,060 shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the Peabody Energy Corporation (the “Company”) Annual Report for the year ended December 31, 2003 are incorporated by reference into Part II hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.




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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

      This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance. We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “will” or other similar words to identify forward-looking statements.

      Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements.

      Among the factors that could cause actual results to differ materially are:

  •  growth in coal and power markets;
 
  •  coal’s market share of electricity generation;
 
  •  the extent of the economic recovery and future economic conditions;
 
  •  milder than normal 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 reserves;
 
  •  implementation of new accounting standards;
 
  •  inflationary trends and interest rate changes;
 
  •  availability and costs of surety bonds and letters of credit;
 
  •  the effects of changes in currency exchange rates;
 
  •  the effects of interest rate changes on discounting future liabilities;
 
  •  the effects of acquisitions or divestitures;
 
  •  maintenance of satisfactory relations with our workforce;
 
  •  increased contribution requirements to multi-employer benefit funds; and

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  •  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.

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Page

 PART I.
   Business     2  
   Properties     21  
   Legal Proceedings     26  
   Submission of Matters to a Vote of Security Holders     31  
   Executive Officers of the Company     31  
 PART II.
   Market For Registrant’s Common Equity and Related Stockholder Matters     33  
   Selected Financial Data     34  
   Management’s Discussion and Analysis of Financial Condition and Results of Operations     37  
   Quantitative and Qualitative Disclosures About Market Risk     57  
   Financial Statements and Supplementary Data     59  
   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     59  
   Controls and Procedures     59  
 PART III.
   Directors and Executive Officers of the Registrant     59  
   Executive Compensation     62  
   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     71  
   Certain Relationships and Related Transactions     73  
   Principal Accounting Fees and Services     74  
 PART IV.
   Exhibits, Financial Statement Schedules, and Reports on Form 8-K     75  
 Form of Non-Qualified Stock Option Agreement
 Form of Amendment
 Form of Incentive
 Form of Non-Qualified Stock Option Agreement
 Form of Performance Unit Award Agreement
 Form of Non-Qualified Stock Option Agreement
 Form of Restricted Stock Agreement
 First Amendment
 Employment Agreement
 Indemnification Agreement
 List of Subsidiaries
 Consent
 Certification
 Certification
 Certification
 Certification

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Note:  The words “we,” “our,” or “the Company” 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, 2003, we sold 203.2 million tons of coal. During this period, we sold coal to nearly 270 electricity generating and industrial plants in 11 countries, and fueled the generation of approximately 9.8% of all electricity in the United States and nearly 2.5% of all electricity in the world. At December 31, 2003, we had 9.2 billion tons of proven and probable coal reserves.

      We own, through our subsidiaries, majority interests in 29 coal operations located throughout all major U.S. coal producing regions and in Australia, with 74% of our U.S. mining operations’ coal sales during the year ended December 31, 2003 shipped from the western United States and the remaining 26% 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 129.6 million tons during 2003, representing a compounded annual growth rate of 10%. In the west, we own and operate mines in Arizona, Colorado, New Mexico and Wyoming. In the east, we own and operate mines in Illinois, Indiana, Kentucky and West Virginia. In addition, we own one mine in Australia. We generated 80% of our production for the year ended December 31, 2003 from non-union mines.

      For the year ended December 31, 2003, 90% of our sales were to U.S. electricity generators, 6% were to customers outside the United States and 4% were to the U.S. industrial sector. Approximately 90% of our coal sales during the year ended December 31, 2003 were under long-term (one year or greater) contracts. Our sales backlog, including backlog subject to price reopener and/or extension provisions, was over one billion tons as of December 31, 2003. The average volume weighted remaining term of our long-term contracts is approximately 3.9 years, with remaining terms ranging from one to 18 years. As of December 31, 2003, we had approximately 14 million tons and 73 million tons of expected production unpriced for 2004 and 2005, respectively.

      In addition to our mining operations, we market, broker and trade coal. Our total tons traded were 40 million for the year ended December 31, 2003. Our other energy related businesses include the management of our vast coal reserve and real estate holdings, coalbed methane production, transportation services, and the development of mine-mouth 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 first listed on the Chicago Stock Exchange and, beginning in 1949, on the New York Stock Exchange.

      In 1955, Peabody Coal Company, primarily an underground mine operator, merged with Sinclair Coal Company, a major surface mining company. Peabody Coal Company was acquired by Kennecott Copper Company in 1968. The company was then sold to Peabody Holding Company in 1977, which was formed by a consortium of companies.

      During the 1980s, Peabody grew through expansion and acquisition, opening the North Antelope Mine in Wyoming’s coal-rich Powder River Basin in 1983 and the Rochelle Mine in 1985, and completing the acquisitions of the West Virginia coal properties of ARMCO Steel and Eastern Associated Coal Corp., which included seven operating mines and substantial low sulfur coal reserves in West Virginia.

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      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%. Peabody’s sales volume from the Powder River Basin increased from 31 million tons in 1993 to 106 million tons in 2003. In the 1990’s, we established three core strategies: 1) managing safe, low-cost operations; 2) applying world-class sales and trading skills; and 3) aggressively managing our vast resource position.

      In May 1998, Lehman Brothers Merchant Banking Partners II L.P. and affiliates (“Merchant Banking Fund”), an affiliate of Lehman Brothers Inc. (“Lehman Brothers”), purchased Peabody Holding Company and its affiliates, Peabody Resources Limited and Citizens Power LLC.

      In August 2000, Citizens Power, our subsidiary that marketed and traded electric power and energy-related commodity risk management products, was sold to Edison Mission Energy.

      In January 2001, we sold our Australian mining operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto Limited for $455 million.

      In April 2001, we changed our name to Peabody Energy Corporation (“Peabody”), reflecting our position as a premier energy supplier. In May 2001, we completed an initial public offering of common stock, and the Company’s shares began trading on the New York Stock Exchange under the ticker symbol “BTU,” the globally recognized symbol for energy.

      In June 2002, we acquired Beaver Dam Coal Company, a major holder of coal reserves in Western Kentucky. In August 2002, we acquired the Wilkie Creek Coal Mine in Queensland, Australia, marking a return to Australian mining operations. In September 2002, we purchased the remaining 25% interest in Arclar Company, LLC, which is 75% owned by our Black Beauty affiliate.

      In December 2002, we sold 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.

      In April 2003, Peabody acquired the remaining 18.3% interest in Black Beauty, Indiana’s largest coal producer, completing the final component of a series of step-acquisitions that began in 1994.

      On February 29, 2004, we signed two definitive agreements to purchase three coal operations from RAG Coal International AG. Closing on the transactions is expected within the next three months and requires no additional U.S. or Australian regulatory approvals. The combined purchase price is $441 million in cash, subject to certain price adjustments. The purchase includes two mines in Queensland, Australia that produce 7 to 8 million tons per year of metallurgical coal, and the Twentymile Mine in Colorado, which produces 7.5 million tons per year of low-sulfur steam coal. We continue with a memorandum of understanding with RAG Coal International AG for our purchase of a 25 percent interest in Carbones del Guasare, S.A., a joint venture that includes Anglo American plc and a Venezuelan governmental partner. Carbones del Guasare operates the Paso Diablo surface mine in northwestern Venezuela, which produces approximately 7 million tons per year of coal for electricity generators and steel producers.

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Mining Operations

      The following provides a description of the operating characteristics of the principal mines and reserves of each of our business units and affiliates in the United States. The map below shows the mines we operated in 2003.

(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 2.8 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 106.5 million tons of coal during the year ended December 31, 2003, or approximately 52% 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, operated the Big Sky Mine in Montana in the Northern Powder River Basin. This mine closed at the end of 2003, as discussed below.

 
North Antelope Rochelle Mine

      The North Antelope Rochelle Mine is located 65 miles south of Gillette, Wyoming. This mine is the largest in North America, selling 80.1 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu) during 2003. 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

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to 8,900 Btu per pound. The North Antelope Rochelle Mine produces the lowest sulfur coal in the United States, using two draglines along with six truck-and-shovel fleets.
 
Caballo Mine

      The Caballo Mine is located 20 miles south of Gillette, Wyoming. During 2003, it sold approximately 22.8 million tons of compliance coal. Caballo is a truck-and-shovel operation with a coal handling system that includes two 12,000-ton silos and two 11,000-ton silos.

 
Rawhide Mine

      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. The mine reopened in January 2002 as a result of improved demand for Powder River Basin coal. During 2003, it sold approximately 3.6 million tons of compliance coal.

 
Big Sky Mine

      The Big Sky Mine is located in the northern Powder River Basin near Colstrip, Montana and used dragline mining equipment. The mine sold 2.6 million tons of medium sulfur coal during 2003. The mine’s contract expired on December 31, 2003. This mine is near the exhaustion of its economically recoverable reserves, and because we have no current sales contract in place, we are in the process of closing the mine. Hourly workers at the Big Sky Mine are members of the United Mine Workers of America. The mine’s closure will not have a material adverse effect on our financial condition, results of operations or cash flows.

Southwest Operations

      We own and operate four mines in our Southwest operations — two in Arizona, one in Colorado and one in New Mexico. 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 20.5 million tons of coal during 2003.

 
Black Mesa Mine

      The Black Mesa Mine, which is located on the Navajo Nation and Hopi Tribe reservations in Arizona, uses two draglines and sold 4.5 million tons of coal during 2003. The Black Mesa Mine coal is crushed, mixed with water and then transported 273 miles through an underground pipeline owned by a third party. The coal is conveyed to the Mohave Generating Station near Laughlin, Nevada, which is operated and partially owned by Southern California Edison. The mine and pipeline were designed to deliver coal exclusively to the plant, which has no other source of coal. The Mohave Generating Station coal supply agreement extends until December 31, 2005. Further discussion of the issues surrounding the future of the Black Mesa Mine and Mohave Generating Station is provided in Item 3 (Legal Proceedings) of this report. Hourly workers at this mine are members of the United Mine Workers of America.

 
Kayenta Mine

      The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines in three mining areas. It sold approximately 7.6 million tons of coal during 2003. 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

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coal. The Navajo coal supply agreement extends until 2011. Hourly workers at this mine are members of the United Mine Workers of America.
 
Seneca Mine

      The Seneca Mine near Hayden, Colorado shipped 1.5 million tons of compliance coal during 2003, 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 7.0 million tons of medium sulfur coal during 2003. 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 five wholly owned business units and related facilities in West Virginia. Our subsidiary, Pine Ridge Coal Company, owns and manages the Big Mountain business unit, and our subsidiary, River’s Edge Mining, Inc. owns and manages our River’s Edge Mine. Eastern Associated Coal Corp. owns and manages the remaining wholly owned facilities. During 2003, these operations sold approximately 14.4 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 Kanawha Eagle Coal, LLC.

 
Big Mountain Business Unit

      The Big Mountain business unit is based near Prenter, West Virginia. This business unit’s primary mine is Big Mountain No. 16, and includes a small amount of contract mine production from coal reserves we control. During 2003, the Big Mountain business unit sold approximately 1.6 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 and then reopened it in February 2003.

 
Harris Business Unit

      The Harris business unit consists of the Harris No. 1 Mine near Bald Knob, West Virginia, which sold approximately 2.9 million tons of primarily metallurgical product during 2003. This mine uses both longwall and continuous mining equipment.

 
Rocklick Business Unit and Contract Mines

      The Rocklick preparation plant, located near Wharton, West Virginia, processes coal produced by the Harris No. 1 Mine and contract mining operations from coal reserves that we control. This preparation plant shipped approximately 1.8 million tons of steam and metallurgical coal sourced from the contract mines during 2003. 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 Business Unit

      The Wells business unit, in Boone County, West Virginia, sold approximately 3.9 million tons of metallurgical and steam coal during 2003. The unit consists of the Wells preparation plant, which

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processes purchased coal and production from our River’s Edge Mine and contract mines. The preparation plant is located near Wharton, West Virginia and the processed coal is loaded on the CSX railroad.
 
Federal No. 2 Mine

      The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining methods and shipped approximately 4.2 million tons of steam coal during 2003. Coal shipped from the Federal No. 2 Mine has a sulfur content only slightly above that of medium sulfur coal and has above average heating content. As a result, it is more marketable than some other medium sulfur coals. The CSX and Norfolk Southern railroads jointly serve the mine.

 
Kanawha Eagle Coal Joint Venture

      We have a 49% interest in Kanawha Eagle Coal, LLC, which owns and manages underground mining operations, a preparation plant and barge-and-rail loading facilities near Marmet, West Virginia. The mine is non-union and uses continuous mining equipment. It shipped 2.2 million tons during 2003.

Midwest Operations

      Our Midwest operations consist of five wholly-owned mines and Black Beauty Coal Company (“Black Beauty”). In 2003, these operations collectively sold 31.8 million tons of coal, more than any other midwestern coal producer. We ship coal from these mines primarily to electricity generators in the midwestern United States, and to industrial customers that generate their own power. We purchased a one-third interest in Black Beauty in 1994, increased our interest to 43.3% in 1998, 81.7% in 1999 and purchased the remaining minority interest in April 2003.

 
Highland Business Unit

      The Highland No. 9 Mine, which is owned and managed by our Highland Mining Company subsidiary, is located near Waverly, Kentucky, and produced 1.6 million tons during 2003. The Highland No. 9 Mine continues to ramp up its production levels and is expected to produce approximately four million tons annually when it reaches targeted capacity. Hourly workers at these operations are members of the United Mine Workers of America.

 
Midwest Business Unit

      The Midwest business unit, which is owned and managed by our Peabody Coal Company subsidiary near Graham, Kentucky, sold 0.6 million tons of coal during 2003. In 2003, the unit included the Gibraltar P&L surface mining operation, which used truck and shovel equipment. The Gibraltar P&L operation ceased production in the fourth quarter of 2003 as the mine reached the end of its economically recoverable reserves. Hourly workers at this operation are members of the United Mine Workers of America.

 
Patriot Coal Company

      Our subsidiary, Patriot Coal Company, owns and manages three mines. Patriot, a surface mine, and Freedom, an underground mine, are located in Henderson County, Kentucky. The Big Run underground mine is located in Ohio County, Kentucky. These mines sold 1.4 million tons, 1.6 million tons and 1.3 million tons, respectively, in 2003. 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. Patriot Coal Company operations utilize non-union labor.

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Black Beauty Coal Company

      Black Beauty Coal Company is the largest coal producer in the Illinois Basin, and currently manages seven mines in Indiana and three mines in Illinois. Black Beauty’s operations produced and sold 25.2 million tons of compliance, medium sulfur and high sulfur steam coal during 2003.

      Black Beauty’s principal Indiana mines include Air Quality No. 1, Farmersburg, Francisco and two mines near Somerville, Indiana. Air Quality No. 1 is an underground coal mine located near Monroe City, Indiana that shipped 1.9 million tons of compliance coal during 2003. Farmersburg is a surface mine situated in Vigo and Sullivan counties in Indiana that sold 4.2 million tons of medium sulfur coal during 2003. Francisco, a surface mine located in Gibson County, Indiana, sold 2.5 million tons during 2003, and the Somerville and Somerville Central surface mines, also located in Gibson County, shipped a total of 7.3 million tons in 2003. Two other surface mines located in Indiana, Viking and Miller Creek, collectively shipped 2.2 million tons during 2003.

      In east-central Illinois, Black Beauty manages the Riola Complex, an underground mining facility with two active portals. The Riola Complex sold 1.8 million tons during 2003. Black Beauty owns a 75% equity interest in Arclar Company, LLC (the remaining 25% is owned by another Peabody subsidiary) which operates the Cottage Grove surface mine and Willow Lake underground mining complex situated in Gallatin and Saline counties in southern Illinois. During 2003, these mines sold 2.5 million tons and 2.8 million tons, respectively, of coal that is 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. All other Black Beauty Coal Company operations utilize non-union labor.

      Black Beauty also owns a 75% interest in United Minerals Company, LLC. United Minerals currently acts as a contract miner for Black Beauty at the Somerville Mine and as contract operator for Black Beauty at the Evansville River Terminal.

 
Australian Mining Operations — Wilkie Creek Mine

      On August 22, 2002, we purchased the Wilkie Creek Coal Mine and coal reserves in Queensland, Australia. For the year ended December 31, 2003, the mine sold 1.3 million tons. Surrounding the mine are 147 million tons of proven and probable reserves.

Long-Term Coal Supply Agreements

      We currently have a sales backlog of approximately one billion tons of coal, including backlog subject to price reopener and/ or extension provisions, and our coal supply agreements have remaining terms ranging from one to 18 years and an average volume-weighted remaining term of approximately 3.9 years. For 2003, we sold 90% of our sales volume under long-term coal supply agreements. In 2003, we sold coal to nearly 270 electricity generating and industrial plants in 14 countries. Our primary customer base is in the United States. Three 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, 2003, we had approximately 14 million tons and 73 million tons of expected production available for sale or repricing at market prices for 2004 and 2005, 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.

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      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 provisions that allow for the recovery of costs impacted by the modifications or changes in the interpretation or application of any existing statute by local, state or federal government authorities. Some agreements provide that if the parties fail to agree on a price adjustment caused by cost increases due to changes in applicable laws and regulations, the purchaser may terminate the agreement, subject to the payment of liquidated damages.

      Price reopener provisions are present in many of our multi-year coal contracts. These provisions may allow either party to commence a renegotiation of the contract price at various intervals. In a limited number of agreements, if the parties do not agree on a new price, the purchaser or seller has an option to terminate the contract. Under some contracts, we have the right to match lower prices offered to our customers by other suppliers.

      Quality and volumes for the coal are stipulated in coal supply agreements, and in some limited instances buyers have the option to vary annual or monthly volumes if necessary. Variations to the quality and volumes of coal may lead to adjustments in the contract price. Most coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat 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 United States, approximately half of our customers require that the coal is sampled and weighed at the destination, whereas in the western United States, samples and weights are usually taken at the shipping source.

      Contract provisions in some cases set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions or serious transportation problems that affect the seller or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement 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.

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      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 the contracted 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, 2003, we had 65 employees in our sales, marketing, trading and transportation operations, including personnel dedicated to performing market research, contract administration and risk/credit management activities. These operations include seven employees at our COALTRADE Australia operation, which brokers coal in the Australia and Pacific Rim markets, and is based in Newcastle, Australia.

Transportation

      Coal consumed domestically is usually sold at the mine, and transportation costs are borne by the purchaser. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port.

      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 business 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 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 10,000 unit trains are loaded each year to accommodate the coal shipped by our 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. Although our current supply of explosives is concentrated with one supplier, alternative sources are available to us in the regions that we operate. Further, purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop.

Technical Innovation

      We continue to place great emphasis on the application of technical innovation to improve new and existing equipment performance. This research and development effort is typically undertaken and funded

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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. Currently, we are evaluating a new propulsion system fitted on a 240-ton haultruck. This system will allow the truck to run more efficiently and reduce maintenance cost compared to traditional systems. Additionally, we have recently installed a longwall system at our Federal No. 2 operation that is fitted with the state-of-the-art control technologies, and we have two state-of-the-art flexible coal train conveyor systems in operation at our Highland Mine.

      Condition-based maintenance is a growing activity within the company. Using these techniques allows us to maximize the life of major components while minimizing the risk of premature failures. Our lubrication volume is also decreased through sophisticated lubrication analysis. Lubrication is replaced on condition rather than time, reducing the volume consumed and insuring optimum equipment performance.

      We use sophisticated software to schedule and monitor trains, mine and pit blending, quality and customer shipments. The integrated software has been developed in-house and provides a competitive tool to differentiate our reliability and product consistency. We are the largest user of advanced coal quality analyzers among coal producers, according to the manufacturer of this sophisticated equipment. These analyzers allow continuous analysis of certain coal quality parameters, such as sulfur content. Their use helps ensure consistent product quality and helps customers meet stringent air emission requirements. We also support the Power Systems Development Facility, a highly efficient electricity generating plant using 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 National Mining Association’s “2002 Coal Producer Survey,” the top 10 coal companies in the United States produced approximately 69% of total domestic coal in 2002. Our principal competitors are other large coal producers, including Kennecott Energy & Coal Co., Arch Coal, Inc., RAG American Coal Holding, Inc., CONSOL Energy, Inc., A.T. Massey Coal Co., Inc., Vulcan Partners, L. P., and Horizon Natural Resources Inc, which collectively accounted for approximately 45% of total U.S. coal production in 2002.

      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.

Generation Development

      To best maximize our coal assets and land holdings for long-term growth, we are developing coal-fueled generating projects in areas of the country where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal.

      We are continuing to progress on the permitting processes, transmission access agreements and contractor-related activities for developing clean, low-cost mine-mouth generating plants using our surface lands and coal reserves. Because coal costs just a fraction of natural gas, mine-mouth generating plants can provide low-cost electricity to satisfy growing baseload generation demand. The plants will be designed to comply with all current clean air standards using advanced emissions control technologies.

      In 2003, we achieved a major milestone in the development of the 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky, when we received a conditional Certificate to Construct from the Commonwealth of Kentucky. We and the Commonwealth of Kentucky are defending the air

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permit granted in 2002 to Thoroughbred Energy Campus, as certain environmental groups are challenging the air permit.

      In 2003, we signed an agreement providing a backup water supply for the proposed 1,500 megawatt Prairie State Energy Campus in Washington County, Illinois. We also issued Request For Proposals (RFPs) for the Engineering, Procurement and Construction (EPC) of the Prairie State Energy Campus. The responses are due in March of 2004. In February 2004, we received a draft air permit from the State of Illinois for the Prairie State Energy Campus. During 2003, we entered negotiations with several potential partners and customers for both projects.

      The plants are expected to be operational following a four-year construction phase, which would begin when the company has completed all necessary permitting, selected partners and sold the majority of the output of the plant.

Resource Development

      Our subsidiary, Peabody Natural Gas, LLC, produces coalbed methane from its operations in the Southern Powder River Basin near the Caballo Mine and North Antelope Rochelle Mine. At December 31, 2003, we operated 58 producing wells which generate approximately 3.6 million cubic feet per day. We are also evaluating the coalbed methane resources in several deep coal seams on more than 27,000 acres in the Western Powder River Basin near Buffalo Wyoming. We purchased these coalbed methane assets in January 2001 for approximately $10 million. In Southern Illinois, Peabody Natural Gas is continuing a five-well coalbed methane pilot program at its Broughton project. More than 10,000 net coal acres and coalbed methane leases covering property adjacent to and near the Broughton project were recently purchased and will be added to the project. A coalbed methane testing program is also being conducted in Western Kentucky. We will continue to evaluate further development of this business through acquisitions and development of our own property.

      As part of our ongoing reclamation and management of our lands, we engage in land development opportunities from time to time. In December 2003, we entered into an agreement with a major real estate developer to explore the development of a 2,300-acre tract in Southern Illinois as a recreational/ residential community.

Certain Liabilities

      We have significant long-term liabilities for reclamation (also called asset retirement obligations), work-related injuries and illnesses, pensions and retiree health care. In addition, labor contracts with the United Mine Workers of America and voluntary arrangements with non-union employees include long-term benefits, notably health care coverage for retired and future retirees and their dependents. The majority of our existing liabilities relate to our past operations, which had more mines and employees than we currently have.

      Asset Retirement Obligations. Asset Retirement Obligations primarily represent the 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 asset retirement obligations totaled approximately $384.0 million as of December 31, 2002. Expense for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001 was $31.2 million, $11.0 million and $9.6 million, respectively. Our method for accounting for reclamation activities changed on January 1, 2003 as a result of the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” The effect of the adoption of SFAS No. 143 is discussed in Note 7 to our consolidated financial statements.

      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 $253.6 million as of

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December 31, 2003, $43.6 million of which was a current liability. Expense for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001 was $50.6 million, $55.4 million and $36.6 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 $130.9 million as of December 31, 2003, $14.1 million of which was a current liability. Expense for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001 was $20.7 million, $4.8 million and $3.0 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 $1,034.3 million as of December 31, 2003, $72.5 million of which was a current liability. Expense for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001 was $83.6 million, $74.4 million and $49.8 million, respectively. Obligations to the United Mine Workers of America Combined Fund totaled $51.5 million as of December 31, 2003, $6.7 million of which was a current liability. Expense for the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001 was $1.2 million, $16.7 million and $3.3 million, respectively. The expense recorded during the year ended December 31, 2002 reflects the reassignment of certain beneficiaries to us as a result of an adverse U.S. Supreme Court decision in January 2003. Those beneficiaries had been deemed improperly assigned to us in a prior U.S. Circuit Court decision.

Employees

      As of December 31, 2003, we and our subsidiaries had approximately 6,900 employees. As of December 31, 2003, approximately 65% of our employees were non-union and they generated 80% of our 2003 coal production. The United Mine Workers of America represented approximately 30% of our employees, who generated 18% of our production during the year ended December 31, 2003. An additional 5% of our employees are represented by labor unions other than the United Mine Workers of America. These employees generated 2% of our production during the year ended December 31, 2003. 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

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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 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.

      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.

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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 $20.6 million $11.1 million and $4.9 million, respectively, during the years ended December 31, 2003 and 2002 and the nine months ended December 31, 2001.

      In 1995, in a case filed by the National Coal Association on behalf of its members, a federal district court in Alabama ordered the Commissioner of Social Security to recalculate the per-beneficiary premium, which the Combined Fund charges assigned operators. The Commissioner applied the recalculated, lower premium to all assigned operators including our subsidiaries. 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. On February 25, 2000, the Washington, D.C. federal district court ruled that the original, higher per beneficiary premium was proper and that decision was upheld on appeal. 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. The members of the association including our subsidiaries and the Combined Fund filed lawsuits in Alabama and Washington, D.C., respectively, seeking a determination regarding the Commissioner’s 2003 premium recalculation. The members’ lawsuit was transferred to federal court in Maryland and the Combined Fund’s lawsuit has also been transferred to the same court.

      Our subsidiaries have been billed a retroactive assessment in the amount of $7.4 million for periods prior to October 1, 2003 as well as a current fund year increase of $0.7 million as a result of the Social Security Administration’s premium recalculation. These amounts are being paid in twelve monthly installments as required by the Combined Fund Trustees, but are being paid under protest. If the Combined Fund is able to obtain a court decision that would confirm the applicability of the higher premium rate to our subsidiaries, our subsidiaries will not be able to seek a refund of the premiums paid under protest. In that event, the prospective annual premium would also increase by approximately 12%.

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

 
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.

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      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 the right to comment on and otherwise engage in the permitting process, including through intervention in the courts.

      Before a SMCRA permit is issued, a mine operator must submit a bond or 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 expires on September 30, 2004, is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. It is expected the fee will be renewed, although its purpose and the amount per ton are still to be determined as part of the United States government’s budget process.

      SMCRA stipulates compliance with many other major environmental programs. These programs include the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (“RCRA”); Comprehensive Environmental Response, Compensation, and Liability Acts (“CERCLA”) superfund and employee right-to-know provisions. Besides OSM, other Federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The U.S. Environmental Protection Agency (“EPA”) is the lead agency for States or Tribes with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers (“COE”) regulates activities affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms (“ATF”) regulates the use of explosive blasting.

      We do not believe there are any substantial matters that pose a risk to maintaining our existing mining permits or hinder our ability to acquire future mining permits. It is our policy to comply with the requirements of the Surface Mining Control and Reclamation Act and the state and tribal laws and regulations governing mine reclamation.

      On October 23, 2003, several citizens groups sued the COE in the U. S. District Court for the Southern District of West Virginia seeking to invalidate a “nationwide” permit utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs seek to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators, but not the Company’s subsidiaries, from additional use of the existing nationwide permit approvals until they obtain more detailed “individual” permits. If the plaintiffs are successful, there may be some disruptions in our existing operations and delays in obtaining new COE permits.

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     Clean Air Act

      The Clean Air Act 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 oxide, mercury and other compounds emitted by coal-based electricity generating plants.

      Title IV of the Clean Air Act places limits on sulfur dioxide emissions from electric power generation plants. The limits set baseline emission standards for these facilities. Reductions in emissions occurred in Phase I in 1995 and in Phase II in 2000 and apply to all coal-based power plants. The affected electricity generators have been able to meet these requirements by, among other ways, switching to lower sulfur fuels, installing pollution control devices, such as flue gas desulfurization systems, which are known as “scrubbers,” reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Emission sources receive these sulfur dioxide emission allowances, which can be traded or sold to allow other units to emit higher levels of sulfur dioxide. Title IV also required that certain categories of coal-based electric generating stations install certain types of nitrogen oxide controls. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. At this time, we believe that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur coals, as additional coal-based electricity generating plants have complied with the restrictions of Title IV.

      In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for very fine particulate matter and ozone. As a result, some states will be required to change their existing implementation plans to attain and maintain compliance with the new air quality standards. Our mining operations and electricity generating customers are likely to be directly affected when the revisions to the air quality standards are implemented by the states. State and federal regulations relating to implementation of the new air quality standards may restrict our ability to develop new mines or could require us to modify our existing operations.

      In December 2003, EPA proposed the Interstate Air Quality Rule, which is designed to help bring the eastern half of the United States into compliance with the National Ambient Air Quality Standards for fine particulates and ozone. The proposed rule would require further reduction of sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 28 states. The proposed rules would reduce sulfur dioxide and nitrogen oxide emissions by approximately 70% from current levels by 2015. The extent of the potential direct impact on the coal industry will depend on the policies and control strategies associated with the state implementation process under the Interstate Air Quality Rule and other aspects of the Clean Air Act. These actions could have a material adverse effect on our financial condition and results of operations.

      The Clean Air Act also requires electricity generators that currently are major sources of nitrogen oxide in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxide, which is a precursor of ozone. In addition, the EPA promulgated the final “NOx SIP Call” rules that would require coal-fueled power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions. These regulations become fully effective for these states in May 2004. Portions of two additional states will complete their NOX SIPs in 2005 as the final installment of the requirement. Installation of additional control measures required under the final rules will make it more costly to operate coal-based electricity generating plants.

      The Justice Department, on behalf of the EPA, has filed a number of lawsuits since November 1999, alleging that 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

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additional control equipment on selected generating units, and at least one generator has received a favorable court decision. If the remaining electricity generators are found to be in violation, they could be subject to civil penalties and be required to install the required control equipment or cease operations. Our customers are among the named electricity generators and if found not to be in compliance, our customers could be required to install additional control equipment at the affected plants or they could decide to close some or all of those plants. If our customers decide to install additional pollution control equipment at the affected plants, we have the ability to supply coal from various regions to meet any new coal requirements.

      In October 2003, EPA promulgated new regulations clarifying the types of plant modifications that electric generators could make without triggering best available control technology requirements. These regulations could affect the pending new source review cases and whether additional cases are brought. Various parties filed an appeal of these regulations in the United States Court of Appeals for the D.C. Circuit. The Court recently issued a stay of these regulations pending a decision on the merits.

      The Clean Air Act set a national goal for the prevention of any future, and the remedying of any existing, impairment of visibility in 156 national parks and wilderness areas across the country. Under regulations issued by the EPA in 1999, states are required to consider setting a goal of restoring natural visibility conditions in Class I areas in their states by 2064 and to explain their reasons to the extent they determine not to adopt this goal. The state plans must require the application of “Best Available Retrofit Technology” (“BART”) after 2010 on certain electric generating stations found to be causing or contributing to regional haze that causes visibility impairment in these areas. The extent and nature of these BART requirements have been the subject of litigation, with EPA expected to issue new regulations in the Spring of 2004. Nine western states have been given the option by EPA of regulating visibility-impairing emissions through a regional rather than a source-by-source approach. These 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 dioxide and nitrogen oxide.

      EPA recently issued proposed regulations setting forth two alternative approaches for regulating mercury emissions from electric generating stations. Under one approach, mercury emissions would be reduced by about 30 percent by 2007 from current emission rates. Under the other approach, mercury emissions would be reduced in two stages in 2010 and 2018, with an emissions reduction of 70 percent by the latter year. Implementation of either of these or similar proposals could cause our customers to switch to other fuels to the extent it would be economically preferable for them to do so, and could impact the completion or success of our generation development projects.

      Legislation supported by the Administration has been introduced in Congress that would reduce emissions of sulfur dioxide, nitrogen oxide and mercury in phases, with reductions of 70 percent by 2018. Other similar emission reduction proposals have been introduced in Congress, some of which propose to also regulate carbon dioxide. No such legislation has passed either house of the Congress. If this type of legislation were enacted into law, it could impact the amount of coal supplied to those electricity generating customers if they decide to switch to other sources of fuel whose use would result in lower emission of sulfur dioxide, nitrogen oxide, mercury and carbon dioxide.

      A small number of states have either proposed or adopted legislation or regulations limiting emissions of sulfur dioxide, nitrogen oxide and mercury from electric generating stations. A smaller number of states have also proposed to limit emissions of carbon dioxide from electric generating stations. Limitations imposed by states on emissions of any of these four substances from electric generating stations could result in fuel switching by the generators they determined it to be economically preferable to do so.

     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

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Elimination System (“NPDES”). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water.

      Section 404 under the Clean Water Act requires mining companies to obtain permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. Our current mining operations are not impacted by the Section 404 regulations.

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

      States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality/ exceptional use.” These regulations would prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality/ exceptional use streams will be required to meet or exceed new high quality/ exceptional use standards. The designation of high quality streams at our coal mines could require more costly water treatment and could aversely affect our coal production.

      On October 23, 2003, several citizens groups sued the COE in the U. S. District Court for the Southern District of West Virginia seeking to invalidate a “nationwide” permit utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs seek to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional filling under existing nationwide permit approvals until they obtain more detailed “individual” permits. If the plaintiffs are successful, there may be some disruptions in existing operations and delays in obtaining new COE permits. If the plaintiffs are successful, we believe our existing operations will not be impacted. However, new mines may experience additional permit requirements and potential delays in permit approvals.

 
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.

 
CERCLA (Superfund)

      The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” — commonly known as Superfund) affects 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

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damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault.

      Under EPA’s Toxic Release Inventory process, companies are required to report annually listed toxic materials that exceed defined quantities.

 
Global Climate Change

      The United States, Australia and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which addresses emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place, 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 2002, coal accounts for 30% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. In March 2001, President Bush reiterated his opposition to the Kyoto Protocol and further stated that he did not believe that the government should impose mandatory carbon dioxide emission reductions on power plants. In February 2002, President Bush announced a new approach to climate change, confirming the Administration’s opposition to the Kyoto Protocol and proposing voluntary actions to reduce the greenhouse gas intensity of the United States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The President’s climate change initiative calls for a reduction in greenhouse gas intensity of 18% over the next 10 years which is approximately equivalent to the reduction that has occurred over each of the past two decades. Ratification and implementation of the Kyoto Protocol by the United States or other actions to limit carbon dioxide emissions could result in fuel switching by electric generators.

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 900, St. Louis, Missouri 63101, attention: Investor Relations.

Item 2.     Properties.

Coal Reserves

      We had an estimated 9.2 billion tons of proven and probable coal reserves as of December 31, 2003. An estimated 9.0 billion tons of our proven and probable coal reserves are in the United States, and 36% is compliance coal and 64% is non-compliance coal. We own approximately 45% of these reserves and lease property containing the remaining 55%. 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.

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      Below is a table summarizing the locations and reserves of our major operating regions.

                                   
Proven and Probable
Reserves as of
December 31, 2003(1)

Owned Leased Total
Operating Regions Locations Tons Tons Tons





(Tons in millions)
Powder River Basin
    Wyoming and Montana       190       2,623       2,813  
Southwest
    Arizona, Colorado and New Mexico       670       601       1,271  
Appalachia
    West Virginia       195       426       621  
Midwest
    Illinois, Indiana and Kentucky       3,082       1,237       4,319  
Australia
    Queensland             146       146  
             
     
     
 
 
Total Proven and Probable Coal Reserves
            4,137       5,033       9,170  
             
     
     
 


(1)  Reserves have been adjusted to take into account estimated losses involved in producing a saleable product.

      Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:

        Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
 
        Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measure) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.
 
        Our estimates of proven and probable coal reserves are established within these guidelines. Proven reserves require the coal to lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas. Estimates of probable reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties have a much higher degree of reliability because we generally have points of observation as close as 330 feet.

      Our reserve estimates are prepared by our staff of geologists, whose experience ranges from 10 to 30 years. We also have a chief geologist of reserve reporting whose primary responsibility is to track changes in reserve estimates, supervise the Company’s other geologists and coordinate periodic third party reviews of our reserve estimates by qualified mining consultants.

      Our reserve estimates are predicated on information obtained from our ongoing drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal are determined. The density of the drill pattern determines whether the reserves will be classified as proven or probable. The reserve estimates are then input into our computerized land management system, which overlays the geological data with data on ownership or control of the mineral

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and surface interests to determine the extent of our reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserve and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.

      Our estimate of the economic recoverability of our reserves is based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to existing market prices for the quality of coal expected to be mined and taking into consideration typical contractual sales agreements for the region and product. Where possible, we also review production by competitors in similar mining areas. Only reserves expected to be mined economically and with an acceptable profit margin are included in our reserve estimates. Finally, our reserve estimates include reductions for recoverability factors to estimate a saleable product.

      We periodically engage independent mining and geological consultants to review estimates of our coal reserves. The most recent of these reviews, which was completed in April 2003, included a review of the procedures used by us to prepare our internal estimates, verification of the accuracy of selected property reserve estimates and retabulation of reserve groups according to standard classifications of reliability. This study confirmed that we controlled approximately 9.1 billion tons of proven and probable reserves as of December 31, 2002. After adjusting for acquisitions, divestitures, production and estimate refinements (through additional drilling and exploration) through December 31, 2003, proven and probable reserves totaled 9.2 billion tons.

      With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10 percent of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification. On a regional basis, the expected degree of variance from reserve estimate to tons produced is lower in the Powder River Basin, Southwest, and Illinois Basin due to the continuity of the coal seams as confirmed by the mining history. Appalachia, however, has a higher degree of risk due to the mountainous nature of the topography. Our recovered reserves in Appalachia are less predictable and may vary by an additional one to two percent above the threshold discussed above.

      We have numerous federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2003, 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.

      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

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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 9.2 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our significant reserve holdings is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.

      Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.

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      The following chart provides a summary, by mining complex, of production for the years ended December 31, 2003 and 2002 and the nine months ended December 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 <1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. As
Year Ended Year Ended Ended Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Received
Mining Dec. 31, Dec. 31, Dec. 31, Type of per Million per Million per Million Btu per
Complex 2003 2002 2001 Coal Btu Btu Btu pound(3)









Northern Appalachia:
                                                               
 
Federal No. 2
    4.2       5.0       3.6       Steam                   32       13,300  
     
     
     
             
     
     
         
 
Northern Appalachia
    4.2       5.0       3.6                           32          
Southern Appalachia:
                                                               
 
Big Mountain/ White’s Branch
    1.5       1.0       1.6       Steam       5       8             12,600  
 
Harris #1
    3.0       3.2       2.7       Steam/Met.       1       8             13,500  
 
Rocklick
    1.8       3.5       2.5       Steam/Met.       23       15             13,000  
 
Wells
    2.4       2.3       1.2       Steam/Met.       21       12             13,600  
     
     
     
             
     
     
         
 
Southern Appalachia
    8.7       10.0       8.0               50       43                
Midwest:
                                                               
 
Camps/ Highland
    1.8       3.0       2.4       Steam                   115       11,000  
 
Midwest Operating Unit
    0.6       1.4       1.3       Steam                   9       11,100  
 
Patriot
    4.2       2.7       1.8       Steam                   51       10,900  
 
Black Beauty
                                                               
   
Air Quality No. 1
    1.9       1.8       1.4       Steam       42                   11,000  
   
Riola No. 1/ Vermilion Grove
    1.8       1.9       0.8       Steam                   33       10,700  
   
Miller Creek
    0.8       0.8       0.8       Steam             1             11,600  
   
Francisco.
    2.5       2.4       2.0       Steam                   9       11,100  
   
Farmersburg
    4.3       4.1       2.9       Steam             16       3       10,900  
   
Somerville Central
    3.3       3.1       2.4       Steam                   12       11,200  
   
Somerville
    4.0       3.9       3.1       Steam                   22       11,200  
   
Viking
    1.4       1.3       1.1       Steam             2       11       11,500  
   
Cottage Grove
    2.5       2.0       1.1       Steam                   6       12,200  
   
Willow Lake
    2.9       2.4       3.0       Steam                   49       12,100  
   
Columbia
          0.4       0.5       Steam                         N/A  
   
Deanefield
                0.1       Steam                         N/A  
     
     
     
             
     
     
         
 
Midwest
    32.0       31.2       24.7               42       19       320          
Powder River Basin:
                                                               
 
Big Sky
    2.6       2.8       2.0       Steam             11       1       8,800  
 
North Antelope/ Rochelle
    80.1       74.8       56.3       Steam       1,202                   8,800  
 
Caballo
    22.7       26.0       20.7       Steam       752       32             8,700  
 
Rawhide
    3.6       3.5             Steam       373       108       9       8,500  
     
     
     
             
     
     
         
 
Powder River Basin
    109.0       107.1       79.0               2,327       151       10          
Southwest
                                                               
 
Black Mesa
    4.4       4.6       3.4       Steam       69       11             10,800  
 
Kayenta
    7.8       8.2       6.2       Steam       220       82       3       10,900  
 
Lee Ranch
    6.9       6.4       4.7       Steam             150       21       9,800  
 
Seneca
    1.4       1.8       1.3       Steam       10             1       10,400  
     
     
     
             
     
     
         
 
Southwest
    20.5       21.0       15.6               299       243       25          
Australia
                                                               
 
Wilkie Creek
    1.3       0.4             Steam       24                   11,500  
     
     
     
             
     
     
         
Total
    175.7       174.7       130.9               2,742       456       387          
     
     
     
             
     
     
         

[Additional columns below]

[Continued from above table, first column(s) repeated]

                                             
As of December 31, 2003

Assigned
Proven and
Mining Probable
Complex Reserves Owned Leased Surface Underground






Northern Appalachia:
                                       
 
Federal No. 2
    32       2       30             32  
     
     
     
     
     
 
 
Northern Appalachia
    32       2       30             32  
Southern Appalachia:
                                       
 
Big Mountain/ White’s Branch
    13             13             13  
 
Harris #1
    9             9             9  
 
Rocklick
    38             38       22       16  
 
Wells
    33             33             33  
     
     
     
     
     
 
 
Southern Appalachia
    93             93       22       71  
Midwest:
                                       
 
Camps/ Highland
    115       39       76             115  
 
Midwest Operating Unit
    9       9                   9  
 
Patriot
    51             51       4       47  
 
Black Beauty
                                       
   
Air Quality No. 1
    42             42             42  
   
Riola No. 1/ Vermilion Grove
    33             33             33  
   
Miller Creek
    1             1       1        
   
Francisco.
    9       2       7       9        
   
Farmersburg
    19       14       5       19        
   
Somerville Central
    12       8       4       12        
   
Somerville
    22       15       7       22        
   
Viking
    13             13       13        
   
Cottage Grove
    6       3       3       6        
   
Willow Lake
    49       42       7             49  
   
Columbia
                             
   
Deanefield
                             
     
     
     
     
     
 
 
Midwest
    381       132       249       86       295  
Powder River Basin:
                                       
 
Big Sky
    12             12       12        
 
North Antelope/ Rochelle
    1,202             1,202       1,202        
 
Caballo
    784             784       784        
 
Rawhide
    490             490       490        
     
     
     
     
     
 
 
Powder River Basin
    2,488             2,488       2,488        
Southwest
                                       
 
Black Mesa
    80             80       80        
 
Kayenta
    305             305       305        
 
Lee Ranch
    171       90       81       171        
 
Seneca
    11             11       11        
     
     
     
     
     
 
 
Southwest
    567       90       477       567        
Australia
                                       
 
Wilkie Creek
    24             24       24        
     
     
     
     
     
 
Total
    3,585       224       3,361       3,187       398  
     
     
     
     
     
 

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     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, 2003
(Tons in millions)
                                                   
Total Tons Proven and

Probable Type of
Location Assigned Unassigned Reserves Proven Probable Coal







Northern Appalachia:
                                               
 
Ohio
          40       40       28       12       Steam  
 
West Virginia
    32       219       251       93       158       Steam  
     
     
     
     
     
         
 
Northern Appalachia
    32       259       291       121       170          
Southern Appalachia:
                                               
 
West Virginia
    93       237       330       232       98       Steam/Met.  
     
     
     
     
     
         
 
Southern Appalachia
    93       237       330       232       98          
Midwest:
                                               
 
Illinois
    49       2,574       2,623       1,172       1,451       Steam  
 
Indiana
          278       278       169       109       Steam  
 
Kentucky
    175       921       1,096       642       454       Steam  
 
Black Beauty Coal Company (Illinois, Indiana, Kentucky)
    157       153       310       256       54       Steam  
 
Missouri
          12       12       11       1       Steam  
     
     
     
     
     
         
 
Midwest
    381       3,938       4,319       2,250       2,069          
Powder River Basin:
                                               
 
Montana
    12       301       313       285       28       Steam  
 
Wyoming
    2,476       24       2,500       2,392       108       Steam  
     
     
     
     
     
         
 
Powder River Basin
    2,488       325       2,813       2,677       136          
Southwest:
                                               
 
Arizona
    384             384       384             Steam  
 
Colorado
    11       153       164       134       30       Steam  
 
New Mexico
    172       547       719       453       266       Steam  
 
Utah
          4       4             4       Steam  
     
     
     
     
     
         
 
Southwest
    567       704       1,271       971       300          
Australia
                                               
 
Queensland
    24       122       146       132       14       Steam  
     
     
     
     
     
         
Total Proven and Probable
    3,585       5,585       9,170       6,383       2,787          
     
     
     
     
     
         

[Additional columns below]

[Continued from above table, first column(s) repeated]

                                                                   
Sulfur Content(2)

<1.2 lbs. >1.2 to 2.5 lbs. >2.5 lbs. As
Sulfur Dioxide Sulfur Dioxide Sulfur Dioxide Received Reserve Control Mining Method
per Million per Million per Million Btu per

Location Btu Btu Btu pound(3) Owned Leased Surface Underground









Northern Appalachia:
                                                               
 
Ohio
                40       11,300       30       10             40  
 
West Virginia
          117       134       12,700       165       86             251  
     
     
     
             
     
     
     
 
 
Northern Appalachia
          117       174               195       96             291  
Southern Appalachia:
                                                               
 
West Virginia
    178       111       41       13,200             330       35       295  
     
     
     
             
     
     
     
 
 
Southern Appalachia
    178       111       41                     330       35       295  
Midwest:
                                                               
 
Illinois
    5       65       2,553       10,300       2,226       397       62       2,561  
 
Indiana
          3       275       10,400       228       50       91       187  
 
Kentucky
                1,096       10,900       527       569       140       956  
 
Black Beauty Coal Company (Illinois, Indiana, Kentucky)
    43       19       248       11,100       100       210       89       221  
 
Missouri
                12       10,000       1       11       12        
     
     
     
             
     
     
     
 
 
Midwest
    48       87       4,184               3,082       1,237       394       3,925  
Powder River Basin:
                                                               
 
Montana
    42       125       146       8,600       189       124       313        
 
Wyoming
    2,327       140       33       8,700       1       2,499       2,500        
     
     
     
             
     
     
     
 
 
Powder River Basin
    2,369       265       179               190       2,623       2,813        
Southwest:
                                                               
 
Arizona
    288       93       3       10,900             384       384        
 
Colorado
    62       102             10,800       40       124       12       152  
 
New Mexico
    238       384       97       8,700       626       93       702       17  
 
Utah
    4                   10,400       4                   4  
     
     
     
             
     
     
     
 
 
Southwest
    592       579       100               670       601       1,098       173  
Australia
                                                               
 
Queensland
    146                   11,200             146       146        
     
     
     
             
     
     
     
 
Total Proven and Probable
    3,333       1,159       4,678               4,137       5,033       4,486       4,684  
     
     
     
             
     
     
     
 

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(1)  Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2003. 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 9.2 billion tons of proven and probable coal reserves. Our Resource Development group constantly reviews these reserves for opportunities to generate revenues through the sale of non-strategic coal reserves and surface land. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties, coalbed methane production and farm income from surface land under third party contracts.

 
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, results of operations or cash flows. We discuss our significant legal proceedings below.

Navajo Nation

      On June 18, 1999, the Navajo Nation served the Company’s 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

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alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act, or RICO, violations and fraud and tortious interference with contractual relationships. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. Plaintiff also alleges that defendants interfered with the fiduciary relationship between the United States and the Navajo Nation. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases for the Kayenta and Black Mesa mines have terminated due to Peabody Western’s breach of these leases and a reformation of the two coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted seven claims including fraud and is seeking various remedies including unspecified actual damages, punitive damages and reformation of its coal lease.

      On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States. The Court rejected the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments and was liable for money damages. On May 2, 2003, the Company’s subsidiaries filed a renewed motion to dismiss the Navajo Nation’s lawsuit against them based on the Supreme Court’s decision. While discovery is ongoing, a trial date has not been set.

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

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

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

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

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

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

      Peabody Western has a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. 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. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to recovery of future capital expenditures for new pollution abatement equipment for the station. Alternatively, Southern California Edison has asked for authorization to spend money for the shutdown of the Mohave plant. In a July 2003 filing with the California Public Utilities Commission, the

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operator affirmed that the Mohave plant is not forecast to return to service as a coal-fired resource until mid-2009 at the earliest. The Company is 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 on December 31, 2005. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 4.5 million tons of coal in 2003. If the Company is unable to renew the coal supply agreement with the Mohave Generating Station, our results of operations and cash flows could be somewhat reduced after 2005.

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 breached its 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, declaratory judgment, and damages for breach of contract and damages for tortious interference committed by AEP Energy Services and American Electric Power Service Corporation. The trial is set for April 2004.

      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.

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.

Citizens Power

      In connection with the August 2000 sale of the Company’s former subsidiary, Citizens Power LLC (Citizens Power), the Company has indemnified the buyer, Edison Mission Energy, from certain losses

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resulting from specified power contracts and guarantees. Other than those discussed below, there are no known issues with any of the specified power contracts and guarantees.

      During the period that Citizens Power was owned by the Company, Citizens Power guaranteed the obligations of two affiliates to make payments to third parties for power delivered under fixed-priced power sales agreements with terms that extend through 2008. Edison Mission Energy has stated and the Company believes there will be sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. To our knowledge, the power purchasers have made timely payments to the Citizens Power affiliates and Edison Mission Energy has not made a claim against the Company under the indemnity.

      In 1997, a Citizens Power subsidiary, now called Edison Mission Marketing & Trading (“EMMT”), entered into a power purchase agreement to sell power in connection with a restructured power supply agreement that runs through 2016. In 1999, the Citizens Power subsidiary entered into a power purchase agreement with NRG Power Marketing Inc. (NRG Power Marketing) for the same term, and NRG Power Marketing’s performance was guaranteed by NRG Energy, its parent. NRG Power Marketing subsequently filed a Chapter 11 bankruptcy petition and on August 6, 2003, NRG Power Marketing obtained bankruptcy court approval to reject the power purchase agreement. EMMT has reached an agreement with NRG Power Marketing to settle the claims filed in the bankruptcy court for the benefit of the members of CL Power Sales Eight LLC (“CL8”). The NRG Power Marketing power sales contract is one of the contracts covered by the indemnity provision, but the Company indemnity does not apply to losses caused by the negligent act or omission of EMMT, Edison Mission Energy or its affiliates. The Company authorized EMMT to purchase power through March 31, 2004 to cap the exposure of the power supply during that time while a restructuring of the CL8 power sale contract was underway and related regulatory approvals were sought. The Company does not believe its exposure under the authorized power purchase agreement is material. NRG Power Marketing is no longer delivering power to EMMT and the power is being supplied by EMMT as discussed above. The Company may be responsible for the incremental costs incurred by EMMT related to the authorized power purchases; however, the Company has reserved its rights against EMMT and Edison Mission Energy. To complicate the issues, CL8 is in discussions with its noteholders as the project is in default of its note agreement as a result of the bankruptcy of an unaffiliated guarantor of EMMT, TXU Europe Limited. The noteholders, members of CL8 and EMMT are in discussions to restructure the project’s power supply arrangements.

      Due to the length, legal complexity and specific requirements of the contracts covered by the indemnity, the impact of the power purchase transactions, the uncertainty surrounding the project default, and the prospects for restructuring described above, the Company cannot reasonably estimate its exposure under the indemnity beyond March 31, 2004.

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.

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

      The Company’s policy is to accrue environmental cleanup-related costs of a noncapital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of

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environmental exposures requires an assessment of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. For certain sites, the Company also assesses the financial capability of other potentially responsible parties and, where allegations are based on tentative findings, the reasonableness of the Company’s apportionment. The Company has not anticipated any recoveries from insurance carriers or other potentially responsible third parties in the estimation of liabilities recorded on its consolidated balance sheets. The undiscounted liabilities for environmental cleanup-related costs recorded as part of “Other noncurrent liabilities” were $38.9 million and $42.1 million at December 31, 2003 and December 31, 2002, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than this provision.

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

Oklahoma Lead Litigation

      Gold Fields was named in June 2003 as a defendant, along with five other companies, in a class action lawsuit filed in the U.S. District Court for the Northern District of Oklahoma. The plaintiffs have asserted nuisance and trespass claims predicated on allegations of intentional lead exposure by the defendants, including Gold Fields, and are seeking compensatory damages for diminution of property value, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950’s. The plaintiff classes include all persons who have resided or owned property in the towns of Cardin and Picher within a specified time period. Gold Fields has agreed to indemnify one of the other defendants, which is a former subsidiary of Gold Fields. Gold Fields is also a defendant, along with other companies, in 17 individual lawsuits arising out of the same lead mill operations involved in the class action. Plaintiffs in these actions are seeking compensatory and punitive damages for alleged personal injuries from lead exposure. Seven of those lawsuits, including the four previously set for trial, have been settled. In December 2003, the Quapaw Indian tribe and certain Quapaw owners of interests in land filed a class action lawsuit against Gold Fields and five other companies in U.S. District Court for the Northern District of Oklahoma. The plaintiffs are seeking compensatory and punitive damages based on public and private nuisance, trespass, unjust enrichment, strict liability and deceit claims. Gold Fields has denied liability to the plaintiffs, has filed counterclaims against the plaintiffs seeking indemnification and contribution and has filed a third-party complaint against the United States, owners of interests in chat and real property in the Picher area. The Quapaw tribe also filed a notice of intent to sue Gold Fields and the other mining companies under CERCLA regarding alleged damages to natural resources held in trust by the Tribe and RCRA for an alleged abatement of an imminent and substantial endangerment to health and the environment. In February 2004, the town of Quapaw filed a class action lawsuit against Gold Fields and other mining companies asserting claims similar to those asserted by the towns of Picher and Cardin.

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

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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, 2003.

 
Item 4A. Executive Officers of the Company

      Set forth below are the names, ages as of February 1, 2004 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
    57     Chairman, Chief Executive Officer and Director
Gregory H. Boyce
    49     President and Chief Operating Officer
Sharon D. Fiehler
    47     Executive Vice President — Human Resources and Administration
Richard A. Navarre
    43     Executive Vice President and Chief Financial Officer
Fredrick D. Palmer
    59     Executive Vice President — Legal and External Affairs and Secretary
Roger B. Walcott, Jr.
    47     Executive Vice President — Corporate Development
Richard M. Whiting
    49     Executive Vice President — Sales, Marketing and Trading
Jeffery L. Klinger
    56     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 Chairman of the Center for Energy and Economic Development, 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, and the Coal Utilization Research Council. He also serves on the advisory board of U.S. Bank, N.A. (St. Louis).

      Gregory H. Boyce became President and Chief Operating Officer of the Company in October 2003. Mr. Boyce had served as Chief Executive Officer — Energy of Rio Tinto PLC from 2000 to 2003. His prior positions include President and Chief Executive Officer of Kennecott Energy Company from 1994 to 1999 and President of Kennecott Minerals Company from 1993 to 1994. He has extensive engineering and operating experience with Kennecott and also served as Executive Assistant to the Vice Chairman of Standard Oil from 1983 to 1984. Mr. Boyce is a member of the Coal Industry Advisory Board of the International Energy Agency. He is a past board member of the Center for Energy and Economic Development, the National Mining Association, Western Regional Council, National Coal Council, Mountain States Employers Council and Wyoming Business Council.

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      Sharon D. Fiehler has been Executive Vice President of Human Resources and Administration of the 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. Ms. Fiehler, holds degrees in social work and psychology and an MBA, and prior to joining Peabody was a personnel representative for Ford Motor Company. Ms. Fiehler is the chair of the Benefits Committee of the Bituminous Coal Operators’ Association, on the Executive Committee and Board of Directors of Junior Achievement of St. Louis and is a member of the National Mining Association’s Human Resource Committee.

      Richard A. Navarre became Executive Vice President and Chief Financial Officer of the Company in February 2001. Prior to that, he was Vice President and Chief Financial Officer of the 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 predecessor company in 1993 as Director of Financial Planning. Prior to joining us, Mr. Navarre was a senior manager with KPMG Peat Marwick. Mr. Navarre is Chairman of the Bituminous Coal Operators’ Association. He serves on the Board of Advisors to the College of Business for Southern Illinois University at Carbondale. He is a member of Financial Executives International and the NYMEX Coal Advisory Council.

      Fredrick D. Palmer became Executive Vice President — Legal and External Affairs of the 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.

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

      Richard M. Whiting became 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 the former Chairman of the National Mining Association’s Safety and Health Committee, the former Chairman of the Bituminous Coal Operators’ Association, a past board member of the National Coal Council and is a member of the Visiting Committee of West Virginia University College of Engineering and Mineral Resources.

      Jeffery L. Klinger was named Vice President — Legal Services of the Company in May 1998. Previously, he was 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.

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PART II

Item 5.     Market for Registrant’s Common Equity and Related Stockholder Matters.

      Our common stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 10, 2004, there were approximately 114 holders of record of our common stock.

      The table below sets forth the range of quarterly high and low sales prices for our common stock on the New York Stock Exchange during the calendar quarters indicated.

                   
High Low


2003
               
 
First Quarter
  $ 29.60     $ 24.52  
 
Second Quarter
    35.11       26.72  
 
Third Quarter
    33.64       28.61  
 
Fourth Quarter
    43.00       31.35  
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  

Dividend Policy

      We paid quarterly dividends totaling $0.45 per share during the year ended December 31, 2003 and $0.40 per share during the year ended December 31, 2002. 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. Limitations on our ability to pay dividends imposed by our debt instruments are discussed in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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:

      During 2003, we issued 19,578 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.

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Equity Compensation Plan Information

      As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2003:

                           
(a) Number of Securities

Remaining Available
Number of Securities for Future Issuance
to be Issued Weighted-Average Under Equity
upon Exercise of Exercise Price of Compensation Plans
Outstanding Options, Outstanding Options, (Excluding Securities
Plan Category Warrants and Rights Warrants and Rights Reflected in Column (a))




Equity compensation plans approved by security holders
    4,386,843     $ 20.88       1,068,670  
Equity compensation plans not approved by security holders
                 
     
     
     
 
 
Total
    4,386,843     $ 20.88       1,068,670  
     
     
     
 

Item 6.     Selected Financial Data.

      The following table presents selected financial and other data about us for the most recent five fiscal periods. The following table and the discussion of our results of operations in 2003 and 2002 in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” includes references to, and analysis of, our “Adjusted EBITDA” results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

      Results of operations for the year ended December 31, 2003 include early debt extinguishment costs of $53.5 million pursuant to our debt refinancing in the first half of 2003. Prior to the adoption of Statement of Financial Accounting Standards No. 145 on January 1, 2003, all costs related to early debt extinguishment were classified as extraordinary items. In addition, results included expense relating to the cumulative effect of accounting changes, net of income taxes, of $10.1 million. This amount represents the aggregate amount of the recognition of accounting changes pursuant to the adoption of SFAS No. 143, the change in method of amortization of actuarial gains and losses related to net periodic postretirement benefit costs and the effect of the rescission of EITF No. 98-10. These accounting changes are further discussed in Note 7 to our financial statements.

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

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

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

      As a result of the adoption of SFAS No. 145 on January 1, 2003, costs related to early debt extinguishment that were previously reported (net of tax) as extraordinary items in the nine months ended December 31, 2001 and the year ended March 31, 2001 were reclassified as a component of income (loss) from continuing operations.

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      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.

      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 a 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.

      We have derived the selected historical financial data for the years ended and as of December 31, 2003 and 2002, the nine months ended and as of December 31, 2001, and for the years ended and as of March 31, 2001 and 2000 from our audited financial statements. You should read the following table in conjunction with the financial statements, the related notes to those financial statements, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

      The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, the “Risks Relating To Our

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Company” section of Item 7 of this report includes a discussion of risk factors that could impact our future results of operations.
                                             
Nine Months
Year Ended Year Ended Ended Year Ended Year Ended
December 31, December 31, December 31, March 31, March 31,
2003 2002 2001 2001 2000





(Dollars in thousands, except share and per share data)
Results of Operations Data
                                       
Revenues
                                       
 
Sales
  $ 2,729,323     $ 2,630,371     $ 1,869,321     $ 2,534,964     $ 2,610,991  
 
Other revenues
    100,157       86,727       68,619       93,164       99,509  
     
     
     
     
     
 
   
Total revenues
    2,829,480       2,717,098       1,937,940       2,628,128       2,710,500  
Costs and expenses
                                       
 
Operating costs and expenses
    2,335,800       2,225,344       1,588,596       2,123,526       2,178,664  
 
Depreciation, depletion and amortization
    234,336       232,413       174,587       240,968       249,782  
 
Asset retirement obligation expense
    31,156                          
 
Selling and administrative expenses
    108,525       101,416       73,553       99,267       95,256  
 
Gain on sale of Australian operations
                      (171,735 )      
 
Net gain on property and equipment disposals
    (25,123 )     (15,763 )     (14,327 )     (5,737 )     (6,439 )
     
     
     
     
     
 
Operating profit
    144,786       173,688       115,531       341,839       193,237  
 
Interest expense
    98,540       102,458       88,686       197,686       205,056  
 
Early debt extinguishment costs
    53,513             38,628       11,025        
 
Interest income
    (4,086 )     (7,574 )     (2,155 )     (8,741 )     (4,421 )
     
     
     
     
     
 
Income (loss) before income taxes and minority interests
    (3,181 )     78,804       (9,628 )     141,869       (7,398 )
 
Income tax provision (benefit)
    (47,708 )     (40,007 )     (7,193 )     40,210       (141,522 )
 
Minority interests
    3,035       13,292       7,248       7,524       15,554  
     
     
     
     
     
 
Income (loss) from continuing operations
    41,492       105,519       (9,683 )     94,135       118,570  
 
Income (loss) from discontinued operations
                      12,925       (90,360 )
     
     
     
     
     
 
Income (loss) before accounting changes
    41,492       105,519       (9,683 )     107,060       28,210  
 
Cumulative effect of accounting changes
    (10,144 )                        
     
     
     
     
     
 
Net income (loss)
  $ 31,348     $ 105,519     $ (9,683 )   $ 107,060     $ 28,210  
     
     
     
     
     
 
Basic earnings (loss) per share from continuing operations
  $ 0.78     $ 2.02     $ (0.20 )                
Diluted earnings (loss) per share from continuing operations
  $ 0.76     $ 1.96     $ (0.20 )                
Basic and diluted earnings per Class A/B share from continuing operations
                          $ 2.73     $ 3.43  
Weighted average shares used in calculating basic earnings (loss) per share
    53,409,521       52,165,735       48,746,444       27,524,626       27,586,370  
Weighted average shares used in calculating diluted earnings (loss) per share
    54,835,628       53,821,760       48,746,444       27,524,626       27,586,370  
Dividends declared per share
  $ 0.45     $ 0.40     $ 0.20              
Other Data
                                       
Tons sold (in millions)
    203.2       197.9       146.5       192.4       190.3  
Net cash provided by (used in):
                                       
 
Operating activities
  $ 188,861     $ 234,804     $ 99,492     $ 111,980     $ 162,911  
 
Investing activities
    (192,280 )     (144,078 )     (172,989 )     388,462       (185,384 )
 
Financing activities
    48,598       (58,398 )     49,396       (503,337 )     (105,181 )
Adjusted EBITDA(1)
    410,278       406,101       290,118       582,807       443,019  
Depreciation, depletion and amortization
    234,336       232,413       174,587       240,968       249,782  
Capital expenditures
    156,443       208,562       194,246       151,358       178,754  
Balance Sheet Data (at period end)
                                       
 
Total assets
  $ 5,280,265     $ 5,125,949     $ 5,150,902     $ 5,209,487     $ 5,826,849  
 
Total debt
    1,196,539       1,029,211       1,031,067       1,405,621       2,076,166  
 
Total stockholders’ equity
    1,132,057       1,081,138       1,035,472       631,238       508,426  


(1)  Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation

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expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

      Adjusted EBITDA is calculated as follows (unaudited):

                                         
Nine Months
Year Ended Year Ended Ended Year Ended Year Ended
December 31, December 31, December 31, March 31, March 31,
2003 2002 2001 2001 2000





Income (loss) from continuing operations
  $ 41,492     $ 105,519     $ (9,683 )   $ 94,135     $ 118,570  
Income tax provision (benefit)
    (47,708 )     (40,007 )     (7,193 )     40,210       (141,522 )
Depreciation, depletion and amortization
    234,336       232,413       174,587       240,968       249,782  
Asset retirement obligation expense
    31,156                          
Interest expense
    98,540       102,458       88,686       197,686       205,056  
Early debt extinguishment costs
    53,513             38,628       11,025        
Interest income
    (4,086 )     (7,574 )     (2,155 )     (8,741 )     (4,421 )
Minority interests
    3,035       13,292       7,248       7,524       15,554  
     
     
     
     
     
 
Adjusted EBITDA
  $ 410,278     $ 406,101     $ 290,118     $ 582,807     $ 443,019  
     
     
     
     
     
 

Item 7.     Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Overview

      We are the largest private sector coal company in the world, with majority interests in 29 active coal operations located throughout all major U.S. coal producing regions and in Australia. In 2003, we sold 203.2 million tons of coal that accounted for an estimated 18% of all U.S. coal sales, and were more than 70% greater than the sales of our closest competitor. The Energy Information Administration estimates that 1.1 billion tons of coal were consumed in the United States in 2003 and expects domestic consumption of coal by electricity generators to grow at a rate of 1.8% per year through 2025. Coal-fueled generation is used in most cases to meet baseload requirements, and coal use generally grows at the pace of electricity growth. In 2003, coal’s share of electricity generation was approximately 52%, which was more than all other fuels combined.

      Our primary customers are U.S. utilities, which accounted for 90% of our sales in 2003. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2003, 90% of our sales were under long-term contracts. As of December 31, 2003, we had entered into commitments to sell 183 million tons, or approximately 96% of our expected 2004 production. As discussed more fully in “Risks Relating to Our Company”, our results of operations in the near term can be negatively impacted by poor weather conditions and unforeseen geologic conditions or equipment problems at mining locations, and by the availability of transportation for coal shipments (particularly in the western United States). On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine or increase the cost of mining coal. In the past, we have achieved production levels that are relatively consistent with our projections. We conduct business through three principal operating segments: Western U.S. Mining, Eastern U.S. Mining and Trading and Brokerage. The principal business of the Eastern U.S. Mining and Western U.S. Mining segments is the mining, preparation and sale of steam coal, sold primarily to electric utilities. The Eastern U.S. Mining operations also mine metallurgical

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coal, sold to steel and coke producers. Eastern U.S. Mining operations are characterized by predominantly underground extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances). Conversely, Western U.S. Mining operations are characterized by predominantly surface extraction processes, lower sulfur content and Btu of coal, and higher customer transportation costs (due to longer shipping distances). Geologically, Eastern operations mine bituminous and Western operations mine primarily subbituminous coal deposits. Our Eastern U.S. Mining operations consist of our Appalachia and Midwest operations, and our Western U.S. Mining operations consist of our Powder River Basin and Southwest operations, which are each described in Item 1 of this report. The Trading and Brokerage segment’s principal business is the marketing, brokerage and trading of coal.

      In addition to our mining operations, which comprised 86% of revenues in 2003, we also generate revenues from brokering and trading coal (12% of revenues), and by aggressively managing our vast natural resource position by selling non-core land holdings and mineral interests to generate additional cash flows ($37.5 million in 2003). 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. These projects involve mine-mouth generating plants using our surface lands and coal reserves. Two projects are currently being evaluated — a 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky and a 1,500 megawatt Prairie State Energy Campus in Washington County, Illinois. The plants are expected to be operational following a four-year construction phase, which would begin when the company has completed necessary permitting, selected partners and sold the majority of the output of the plant.

Results of Operations

 
Adjusted EBITDA

      The discussion of our results of operations in 2003 and 2002 below includes references to, and analysis of our “Adjusted EBITDA” results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under generally accepted accounting principles, in Note 28 to our consolidated financial statements.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

 
Summary

      In 2003, our revenues rose to $2.83 billion, a 4.1% increase over the prior year, led by industry-record sales volume of 203.2 million tons. Our sales volume in the second-half of 2003 was 8.6% stronger than the first half as generators completed upgrades to emission control equipment and increased coal consumption to meet growing industrial demand.

      Our Adjusted EBITDA totaled $410.3 million for the full year, compared with $406.1 million in the prior year. The improvement was due to higher U.S. Mining results (excluding $37.1 million in contract settlements from 2002 results), Trading and Brokerage results, and net gains on property disposals, partially offset by higher retiree healthcare and pension costs and selling and administrative expenses.

      Net income in 2003 totaled $31.3 million, or $0.57 per share, compared with $105.5 million, or $1.96 per share in 2002. The decrease in net income was due to higher asset retirement obligation costs resulting from the adoption of SFAS No. 143, combined with $53.5 million in early debt extinguishment charges and a $10.1 million charge for the cumulative effect of accounting changes, both recorded in the first half of 2003.

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Revenues
                                   
Year Ended Year Ended Increase (Decrease)
December 31, December 31,
2003 2002 $ %




(dollars in thousands)
Sales
  $ 2,729,323     $ 2,630,371     $ 98,952       3.8%  
Other revenues
    100,157       86,727       13,430       15.5%  
     
     
     
         
 
Total revenues
  $ 2,829,480     $ 2,717,098     $ 112,382       4.1%  
     
     
     
         

      Overall, our revenues increased 4.1% over the prior year. Sales increased 3.8% due to a 5.2% sales volume improvement in 2003. Volume from our brokerage operations increased substantially in 2003 due to improved domestic and export demand, and the inclusion of a full year of sales from the Australian mining operations acquired in August 2002 also contributed to the volume increase. In the west, revenues were essentially flat compared with the prior year, as record volumes due to strong second-half demand in the Powder River Basin were offset by lower volumes in the Southwest as a result of customer outages due to major power plant repairs in the first half of the year. In the east, revenues declined 5.0% as slightly higher volumes in the Midwest to meet higher demand were more than offset by lower production in Appalachia due to poor weather in both the first and second quarters, and lower production at the Harris Mine and certain contract mines due to equipment and geologic difficulties. Midwest production overcame ramp-up issues at the new Highland Mine and the Vermilion Grove portal of the Riola Mine, which have not yet reached full production capacity. Overall, our average sales price decreased 1.4%, due to $27.7 million in sales recorded in 2002 as a result of a favorable arbitration ruling that resulted in a retroactive price adjustment to our Navajo station coal supply agreement, combined with a change in sales mix, as higher priced tons in the Appalachia and Midwest regions represented a lower percentage of our overall sales in 2003. On a regional basis, excluding the effect of the arbitration ruling in the prior year, in 2003 we realized comparable pricing in Appalachia, and improved pricing in the Southwest and Powder River Basin. Midwest prices decreased slightly from 2002 levels.

      Other revenues increased $13.4 million from the prior year, due to $6.6 million in higher mark-to-market revenues from trading operations, combined with $8.3 million of higher earnings from equity investments in 2003.

 
Adjusted EBITDA

      Our Adjusted EBITDA totaled $410.3 million for the full year, compared with $406.1 million in the prior year, broken down as follows.

                                   
Year Ended Year Ended Increase (Decrease)
December 31, December 31,
2003 2002 $ %




(dollars in thousands)
Western U.S. Mining
  $ 357,021     $ 355,955     $ 1,066       0.3%  
Eastern U.S. Mining
    199,114       220,340       (21,226 )     -9.6%  
Trading and Brokerage
    45,828       36,984       8,844       23.9%  
Australian Mining
    2,225       3,007       (782 )     -26.0%  
Corporate and Other
    (193,910 )     (210,185 )     16,275       -7.7%  
     
     
     
         
 
Total Adjusted EBITDA
  $ 410,278     $ 406,101     $ 4,177       1.0%  
     
     
     
         

      Adjusted EBITDA from our Western U.S. Mining operations increased $1.1 million in 2003. Excluding $37.1 million from 2002 results related to a favorable arbitration ruling and a mediated settlement, Western U.S. Mining Adjusted EBITDA improved $38.2 million, and our margin per ton improved $0.28, or 11%. The improvement was driven by our Powder River Basin operations, which realized improved pricing and record volume from strong demand for its products, combined with lower maintenance and repair costs, that overcame higher fuel and explosives costs. Adjusted EBITDA from our

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Eastern operations decreased $21.2 million (margin per ton decreased $0.27, or 6%) as a result of a $30.3 million decrease in contribution from our Appalachia operations, primarily due to lower production and higher costs at the Harris Mine, as a result of geologic difficulties, and equipment-related operating difficulties at certain contract mines in 2003. This decrease was partially offset by a $9.1 million improvement in our Midwest operations’ results. The Midwest operations benefited from higher overall volume and improved pricing at our Black Beauty operations, which overcame higher fuel and explosives costs at our Black Beauty operations and ramp-up issues at the new Highland Mine and the Vermilion Grove portal of the Riola Mine, which have not reached full production capacity.

      Adjusted EBITDA from Trading and Brokerage operations increased $8.8 million over the prior year, primarily due to higher profit from improved brokerage volume and the impact of adopting EITF Issue 02-3 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” Trading and Brokerage results in 2003 included $6.8 million in unrealized profit related to a contract restructuring wherein the new contract’s terms and conditions required it to be classified as a derivative (and therefore marked to market). The unrealized profit related to this contract will be converted to cash by the end of 2005. An additional $5.3 million of unrealized profit related to three other contract modifications, and the unrealized profit related to these contracts will be converted to cash by the end of 2004.

      Corporate and Other Adjusted EBITDA results include selling and administrative expenses, net gains on property disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development and resource management. In 2003, these result were impacted by:

  •  higher net gains on property disposals of $9.4 million;
 
  •  a $7.6 million gain in 2003 on the sale of 1.15 million units of Penn Virginia Resource Partners LP (“Penn Virginia”);
 
  •  higher selling and administrative expenses of $7.1 million associated with salaried pensions, incentive compensation, litigation, additional healthcare cost controls and Sarbanes-Oxley compliance; and
 
  •  lower costs ($7.3 million) associated with past mining obligations, as the prior year included a $17.2 million charge 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, while the current year included higher retiree healthcare costs of $8.9 million.
 
Income (Loss) Before Income Taxes And Minority Interests
                                 
Year Ended Year Ended Increase (Decrease)
December 31, December 31,
2003 2002 $ %




(dollars in thousands)
Adjusted EBITDA
  $ 410,278     $ 406,101     $ 4,177       1.0 %
Depreciation, depletion and amortization
    234,336       232,413       1,923       0.8 %
Asset retirement obligation expense
    31,156             31,156        
Early debt extinguishment costs
    53,513             53,513        
Interest expense
    98,540       102,458       (3,918 )     -3.8 %
Interest income
    (4,086 )     (7,574 )     3,488       -46.1 %
     
     
                 
Income (loss) before income taxes and minority interests
  $ (3,181 )   $ 78,804     $ (81,985 )     -104.0 %
     
     
                 

      Income (loss) before income taxes and minority interests decreased $82.0 million from 2002, due to early debt extinguishment costs of $53.5 million incurred in 2003 pursuant to our refinancing (see Note 15

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to our consolidated financial statements) and asset retirement obligation expense of $31.2 million recognized in 2003 in accordance with SFAS No. 143. Expense in 2002 related to reclamation activities was $11.0 million and was included in “operating costs and expenses” in the statement of operations. The adoption of SFAS No. 143 is discussed in Note 7 to our consolidated financial statements. Interest expense in 2003 decreased $3.9 million, due to $8.9 million in savings realized from our 2003 refinancing, partially offset by $5.0 million higher costs related to surety bonds and letters of credit used to secure our obligations for reclamation, workers’ compensation and lease commitments. Prior year interest income included $4.6 million in interest income received related to excise tax refunds.
 
Net Income
                                   
Year Ended Year Ended Increase (Decrease)
December 31, December 31,
2003 2002 $ %




(dollars in thousands)
Income (loss) before income taxes and minority interests
  $ (3,181 )   $ 78,804     $ (81,985 )     -104.0 %
 
Income tax benefit
    (47,708 )     (40,007 )     7,701       -19.2 %
 
Minority interests
    3,035       13,292       (10,257 )     -77.2 %
     
     
                 
Income before accounting changes
    41,492       105,519       (64,027 )     -60.7 %
 
Cumulative effect of accounting changes
    (10,144 )           (10,144 )      
     
     
                 
Net income
  $ 31,348     $ 105,519     $ (74,171 )     -70.3 %
     
     
                 

      Net income decreased $74.2 million from 2002 due to the decrease in income (loss) before income taxes and minority interests discussed above, combined with:

  •  a higher tax benefit of $7.7 million in 2003. The tax benefit recorded in 2003 differs from the tax expense in 2002 primarily as a result of the magnitude of the percentage depletion deduction (which is a permanent difference) relative to pre-tax income, and a $10.0 million adjustment to our tax reserves;
 
  •  lower minority interests expense in 2003 due to the purchase of the remaining 25% of Arclar Coal Company in September 2002 and the acquisition in April 2003 of the remaining 18.3% of Black Beauty Coal Company; and
 
  •  a charge in 2003 relating to the cumulative effect of accounting changes, net of income taxes, of $10.1 million. This amount represents the aggregate amount of the recognition of accounting changes pursuant to the adoption of SFAS No. 143, the change in method of amortization of actuarial gains and losses related to net periodic postretirement benefit costs and the effect of the rescission of EITF No. 98-10, as discussed in Note 7 to the consolidated financial statements.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001 (Not Presented Herein)

 
Summary

      In 2002, our revenues rose to $2.72 billion, a 4.1% increase from 2001, due primarily to higher pricing from contracts signed in 2001. Our Adjusted EBITDA totaled $406.1 million in 2002, compared with $559.7 million in 2001, which included a $171.7 million gain on the sale of our Peabody Resources Limited operations in Australia. Excluding the gain on sale of the Peabody Resources Limited operations, Adjusted EBITDA increased $18.1 million, or 4.7%. The improvement was due to higher U.S. Mining and Trading and Brokerage results partially offset by higher costs related past mining obligations and lower coal royalties.

      Income before taxes and minority interests decreased $66.8 million in 2002, due primarily to the $171.7 million gain on the sale of our Peabody Resources Limited operations in 2001, partially offset by $49.7 million in early debt extinguishment charges in 2001, lower interest expense in 2002 of $30.5 million

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and higher Adjusted EBITDA in 2002 of $18.1 million (excluding the gain on sale of the Peabody Resources Limited operations).
 
Revenues
                                     
(Unaudited)
Year Ended Year Ended Increase (Decrease)
December 31, December 31,
2002 2001 $ %




(dollars in thousands)
Revenues
                               
 
Sales
  $ 2,630,371     $ 2,514,591     $ 115,780       4.6 %
 
Other revenues
    86,727       94,592       (7,865 )     -8.3 %
     
     
     
         
   
Total revenues
  $ 2,717,098     $ 2,609,183     $ 107,915       4.1 %
     
     
     
         

      Overall, our revenues increased 4.1% in 2002 from 2001. 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. The pricing increase was partially mitigated by sales mix, as higher priced tons in our Eastern U.S. Mining operations 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 Eastern U.S. Mining 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.

      In the west, our 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. In the east, Appalachia region sales increased $7.7 million, as higher pricing offset lower volume from softer demand, which resulted in the 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 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.

      Other revenues decreased $7.9 million from 2001, to $86.7 million. Revenues in 2002 included a $15.1 million gain from a mediated settlement related to the Mohave generating station coal supply agreement, offset by significantly lower coal royalty revenues, as 2001 included higher coal royalties of $12.0 million, primarily due to two non-refundable advance royalties, and $9.9 million of revenue in 2001 related to the monetization of coal brokerage agreements that had increased in value due to favorable market conditions.

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Adjusted EBITDA
                                   
(Unaudited)
Year Ended Year Ended Increase (Decrease)
December 31, December 31,
2002 2001 $ %




(dollars in thousands)
Western U.S. Mining
  $ 355,955     $ 298,609     $ 57,346       19.2 %
Eastern U.S. Mining
    220,340       198,116       22,224       11.2 %
Trading and Brokerage
    36,984       31,645       5,339       16.9 %
Australian Mining
    3,007       6,393       (3,386 )     -53.0 %
Gain on sale of Peabody Resources Ltd.
          171,735       (171,735 )     -100.0 %
Corporate and Other
    (210,185 )     (146,749 )     (63,436 )     43.2 %
     
     
     
         
 
Total Adjusted EBITDA
  $ 406,101     $ 559,749     $ (153,648 )     -27.4 %
     
     
     
         

      Excluding the effect of the $171.7 million gain on sale of our Peabody Resources Limited operations, Adjusted EBITDA increased $18.1 million in 2002, or 4.7%, to $406.1 million. Both the Western U.S. Mining and Eastern U.S. Mining segments’ EBITDA increased as a result of higher overall pricing due to contracts signed in 2001. Western U.S. Mining results include the effects of the Navajo station arbitration ruling and Mohave station mediated settlement, which increased Adjusted EBITDA by $37.1 million.

      In the west, the Powder River Basin region’s Adjusted EBITDA increased $35.1 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 2002. The Southwest region’s Adjusted EBITDA increased $22.2 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 Midwest due to geologic difficulties. Despite these issues, Adjusted EBITDA in the Midwest region increased $14.8 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 Adjusted EBITDA increased $7.4 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.

      Adjusted EBITDA from trading and brokerage operations increased $5.3 million over the prior year, primarily due to $10.0 million in profit related to a forward sale that settles during 2003 and 2004.

      Corporate and Other Adjusted EBITDA results include selling and administrative expenses, net gains on property disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development and resource management. In 2002, these result were impacted by:

  •  higher costs related to post-mining activities of $36.2 million, 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.

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  •  lower coal royalty income of $12.8 million and lower results from other commercial activities of $7.3 million.
 
Income (Loss) Before Income Taxes And Minority Interests
                                 
(Unaudited)
Year Ended Year Ended Increase (Decrease)
December 31, December 31,
2002 2001 $ %




(dollars in thousands)
Adjusted EBITDA
  $ 406,101     $ 559,749     $ (153,648 )     -27.4 %
Depreciation, depletion and amortization
    232,413       235,421       (3,008 )     -1.3 %
Early debt extinguishment costs
          49,653       (49,653 )     -100.0 %
Interest expense
    102,458       132,928       (30,470 )     -22.9 %
Interest income
    (7,574 )     (3,905 )     (3,669 )     94.0 %
     
     
                 
Income before income taxes and minority interests
  $ 78,804     $ 145,652     $ (66,848 )     -45.9 %
     
     
                 

      Income before taxes and minority interests decreased $66.8 million in 2002, due primarily to the $171.7 million gain on the sale of our Peabody Resources Limited operations in 2001, partially offset by $49.7 million in early debt extinguishment charges in 2001, lower interest expense in 2002 of $30.5 million and higher Adjusted EBITDA in 2002 of $18.1 million (excluding the gain on sale of the Peabody Resources Limited operations). The $30.5 million decrease in interest expense was due to significant long-term debt repayments made during 2001, and lower short-term interest rates in 2002. 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.

 
Net Income
                                   
(Unaudited)
Year Ended Year Ended Increase (Decrease)
December 31, December 31,
2002 2001 $ %




(dollars in thousands)
Income before income taxes and minority interests
  $ 78,804     $ 145,652     $ (66,848 )     -45.9 %
 
Income tax provision (benefit)
    (40,007 )     29,331       69,338       236.4 %
 
Minority interests
    13,292       10,131       3,161       31.2 %
     
     
                 
Income from continuing operations
    105,519       106,190       (671 )     -0.6 %
 
Income from discontinued operations
          1,165       (1,165 )     -100.0 %
     
     
                 
Net income
  $ 105,519     $ 107,355     $ (1,836 )     -1.7 %
     
     
                 

      Net income decreased $1.8 million from 2001 due to the decrease in income before income taxes and minority interests discussed above, combined with a $69.3 million increase in income tax benefits. 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 $29.3 million on income before income taxes and minority interests of $145.7 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. In 2001, 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 coal reserves and landfill sale transactions. Utilization of 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.

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Outlook

      Our outlook for the coal markets is positive for 2004, as indicated by strong domestic and international pricing, especially in late 2003 and early 2004. Strong demand for coal-based electricity generation is being driven by a strengthening economy, low customer stockpiles, production difficulties of some producers, capacity constraints of nuclear generation and high prices of natural gas and oil. The high price of the primary competing fuel, natural gas, is leading to coal generating plants operating at increasing levels. We are targeting 2004 production of 190 to 195 million tons, and total sales volume of 210 million to 220 million tons. As of December 31, 2003 we have committed 183 million tons and priced 181 million tons of 2004 production.

      Increased demand for our products contributes to an improved cost structure as we are able to more fully utilize our installed production capacity. We continue to aggressively manage our cost structure and have programs in place to limit, to the extent possible, the impact of rising costs on our operating margins. We are experiencing increases in operating costs related to higher fuel and explosives costs driven by higher energy prices, higher steel costs, healthcare costs and other costs. In addition, historically low interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. We may also encounter poor geologic conditions or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on these and other costs exceeds our ability to realize sales increases, our operating margins would be negatively impacted.

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. Expense for the year ended December 31, 2003 for these liabilities totaled $156.1 million, while payments were $146.7 million.

      Each of these liabilities are actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items.

      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. Our most significant employee liability is postretirement health care, and assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for health care plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.

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      Health care cost trend rate (dollars in thousands):

                 
One Percentage- One Percentage-
Point Increase Point Decrease


Effect on total service and interest cost components(1)
  $ 10,014     $ (8,389 )
Effect on total postretirement benefit obligation(1)
  $ 111,745     $ (94,218 )

      Discount rate (dollars in thousands):

                 
One Half One Half
Percentage-Point Percentage-Point
Increase Decrease


Effect on total service and interest cost components(1)
  $ 790     $ (956 )
Effect on total postretirement benefit obligation(1)
  $ (51,971 )   $ 57,180  


(1)  In addition to the effect on total service and interest cost components of expense, changes in trend and discount rates would also increase or decrease the actuarial gain or loss amortization expense component. The gain or loss amortization would approximate the increase or decrease in the obligation divided by 8.43 years at December 31, 2003.
 
Asset Retirement Obligations

      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 asset retirement obligation is determined on a by-mine basis and we use various assumptions, including estimates of disturbed acreage as determined from engineering data and the timing of and 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. Asset retirement obligation expense for the year ended December 31, 2003 was $31.2 million, and payments totaled $38.1 million.

 
Trading Activities

      We engage in the buying and selling of coal in over-the-counter markets. Our coal trading contracts are accounted for on a fair value basis under SFAS No. 133.

      To establish fair values for our trading contracts, we use bid/ask price quotations obtained from multiple, independent third party brokers to value coal and emission allowance positions. Prices from these sources are then averaged to obtain trading position values. We could experience difficulty in valuing our market positions if the number of third party brokers should decrease or market liquidity is reduced.

      Ninety-nine percent of the contracts in our trading portfolio as of December 31, 2003 were valued utilizing prices from over-the-counter market sources, adjusted for coal quality, and one percent of our contracts were valued based on similar market transactions.

      As of December 31, 2003, the timing of trading portfolio contract expirations is as follows:

         
Percentage of
Year of Expiration Portfolio


2004
    93 %
2005
    7 %
     
 
      100 %
     
 

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Income Taxes

      We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes,” which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in the evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made.

Liquidity and Capital Resources

      Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities and sales of non-core assets. Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs and costs related to past mining obligations. Our ability to pay dividends, service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. We typically fund all of our capital expenditure requirements with cash generated from operations, and, particularly in 2003, have had few borrowings outstanding under our revolving line of credit. This provides us with available excess borrowing capacity ($363.4 million as of December 31, 2003) to use to fund strategic acquisitions or meet other financing needs.

      Cash provided by operating activities was $188.9 million in 2003, a decrease of $45.9 million from 2002. The decrease is primarily due to lower income from continuing operations in the current year, combined with a higher portion of 2003 income generated by activities whose related cash flows are classified as cash flows from investing activities. In addition, the prior year period’s cash flows include $26.8 million of excise tax refunds and $33.9 million received related to the arbitration ruling and mediation settlement previously mentioned.

      Net cash used in investing activities was $192.3 million in 2003, $48.2 million lower than 2002. Capital expenditures decreased $52.1 million, to $156.4 million, in 2003. The decrease was driven by the deferral of some 2003 capital spending to 2004, combined with higher expenditures for reserve acquisitions in 2002. Major capital expenditures incurred in 2003 related to the startup of the Highland Mine and the installation of new longwall equipment and development of a new reserve area at our 5 million ton per year Federal Mine. Other 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. Acquisition expenditures increased $45.4 million in the current year, due to the $90.0 million acquisition of the remaining 18.3% of Black Beauty Coal Company in 2003. The prior year included $45.5 million of expenditures related to the acquisitions of Beaver Dam Coal Company, the remaining 25% interest in Arclar Coal Company and our Australian Mining operations. In addition, 2003 included $32.1 million in proceeds from the sale of 1.15 million units of Penn Virginia, while 2002 included $72.5 million from the sale of reserves to Penn Virginia. Finally, the current year includes $15.4 million lower proceeds from property and equipment disposals.

      Net cash provided by financing activities was $48.6 million in 2003, a $107.0 million increase from 2002. The current year included proceeds from long-term debt of $1.1 billion from the refinancing transactions. A detailed discussion of the sources and uses of proceeds from the refinancing transactions is included in Note 15 to the consolidated financial statements. The refinancing proceeds were used, among other things, to repay line of credit borrowings of $121.6 million, long-term debt of $831.0 million and to pay $23.7 million in debt issuance costs in connection with the new debt issued. The current year includes other debt repayments of $37.4 million, while 2002 includes net repayments of $31.3 million. Financing cash flows in 2003 and 2002 reflect dividends paid of $24.1 million and $20.9 million, respectively. Finally,

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2003 included lower proceeds from securitized interests in accounts receivable of $42.8 million and higher proceeds from the exercise of stock options of $28.7 million.

      The Company filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission on October 22, 2003. Once the registration statement is effective, the Company may offer and sell from time to time unsecured debt securities consisting of notes, debentures, and other debt securities; common stock; preferred stock; warrants; and/or units totaling a maximum of $1.25 billion. Related proceeds would be used for general corporate purposes including repayment of other debt, capital expenditures, possible acquisitions and any other purposes that may be stated in any prospectus supplement.

      As of December 31, 2003 and 2002, our total indebtedness consisted of the following (dollars in thousands):

                 
December 31, 2003 December 31, 2002


Term Loan under Senior Secured Credit Facility
  $ 446,625     $  
6.875% Senior Notes due 2013
    650,000        
Fair value of interest rate swaps — 6.875% Senior Notes
    4,239        
9.625% Senior Subordinated Notes redeemed in 2003
          391,490  
8.875% Senior Notes redeemed in 2003
          316,498  
5.0% Subordinated Note
    79,412       85,055  
Senior unsecured notes under various agreements
          58,214  
Unsecured revolving credit agreement
          116,584  
Other
    16,263       61,370  
     
     
 
    $ 1,196,539     $ 1,029,211  
     
     
 

      During 2003, we completed a comprehensive debt refinancing to lower our borrowing costs, expand our borrowing capacity, extend our debt maturities and simplify our capital structure. The new debt instruments are discussed in detail in Note 15 to our consolidated financial statements. Our Senior Secured Credit Facility and 6.875% Senior Notes have been rated Ba1 and BB-, respectively, by Moody’s Investors Service, BB+ and BB- by Standard & Poor’s and BB+ and BB by Fitch. Recently, Moody’s reaffirmed our SGL-1 liquidity rating. Under Moody’s rating system, SGL-1 means “very good” liquidity. Moody’s SGL ratings are used to supplement their credit ratings for companies rated from “Ba1” to “C.”

      These security ratings reflect the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from each rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

      We were in compliance with all of the covenants of the Senior Secured Credit Facility and 6.875% Senior Notes as of December 31, 2003.

      In July 2003, our board of directors approved a 25% increase in the regular quarterly dividend on common stock, to $0.125 per share.

      In May 2003, we entered into and designated four interest rate swaps with notional amounts totaling $100.0 million as a fair value hedge of our 6.875% Senior Notes. Under the swaps, the Company pays a floating rate that resets each March 15 and September 15, based upon the six-month LIBOR rate, for a period of ten years ending March 15, 2013 and receives a fixed rate of 6.875%. The average applicable floating rate of the four swaps was 4.25% as of December 31, 2003. At current LIBOR levels, we would realize annualized savings of approximately $2.6 million over the term of the swaps.

      In September 2003, the Company entered into two $400.0 million interest rate swaps. One $400.0 million notional amount floating-to-fixed interest rate swap, expiring March 15, 2010, was

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designated as a hedge of changes in expected cash flows on the term loan under Senior Secured Credit Facility. Under this swap, the Company pays a fixed rate of 6.764% and receives a floating rate of LIBOR plus 2.5% (3.67% at December 31, 2003) that resets quarterly based upon the three-month LIBOR rate. Another $400.0 million notional amount fixed-to-floating interest rate swap, expiring March 15, 2013, was designated as a hedge of the changes in the fair value of the 6.875% Senior Notes due 2013. Under this swap, the Company pays a floating rate of LIBOR plus 1.97% (3.14% at December 31, 2003) that resets quarterly based upon the three-month LIBOR rate and receives a fixed rate of 6.875%. The effect of the swaps was to lower the Company’s overall borrowing costs on $400.0 million of debt principal by 0.64% as of December 31, 2003, which will result in annualized interest savings of $2.6 million over the term of the fixed-to-floating swap.

      The following is a summary of commercial commitments available to us as of December 31, 2003 (in thousands):

                                         
Expiration Per Year

Total Amounts Within
Committed 1 Year 2-3 Years 4-5 Years Over 5 Years





Lines of credit and/or standby letters of credit
  $ 600,000                 $ 600,000        

      As of December 31, 2003, there were no outstanding borrowings under our $600.0 million Revolving Credit Facility. We had letters of credit outstanding under the facility of $236.6 million, leaving $363.4 million available for borrowing.

Contractual Obligations

      The following is a summary of our significant contractual obligations as of December 31, 2003 (in thousands):

                                   
Payments Due by Year

Within After
1 Year 2-3 Years 4-5 Years 5 Years




Long-term debt (principal and interest)
  $ 83,983     $ 154,868     $ 173,178     $ 1,262,371  
Capital lease obligations
    1,474       1,529       353        
Operating leases
    90,833       147,160       85,013       56,782  
Capital purchase obligations(1)
    39,566                    
Coal reserve lease obligations
    25,362       53,279       44,187       52,672  
     
     
     
     
 
 
Total contractual cash obligations
  $ 241,218     $ 356,836     $ 302,731     $ 1,371,825  
     
     
     
     
 


(1)  We have purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which are not recognized as a liability until the purchased items are received) under these purchase agreements, combined with any other open purchase orders, are not material.

      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, 2003 (in thousands):

         
Estimated Expenditures

Within 1 year
  $ 185,300  
2-3 years
    414,700  
4-5 years
    394,500  

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      We had $39.6 million of committed capital expenditures at December 31, 2003. Total capital expenditures for 2004 are expected to range from $220 million to $240 million, and have been and will be 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 2004 is reduced by our high level of sales commitments (96% of 2004 planned production) and ongoing 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 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, 2003, we had outstanding surety bonds with third parties for post-mining reclamation totaling $499.6 million. We had an additional $178.9 million of surety bonds in place for workers’ compensation and retiree healthcare obligations and $66.0 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 $7.6 million of debt of an affiliate in which we have a 49% equity investment, and $4.0 million of debt of an affiliate in which we have 45% investment, as described in Note 24 to our consolidated financial statements. We maintain letters of credit totaling $239.1 million to secure lease, workers’ compensation, postretirement benefits, and other obligations. Our remaining guarantees and indemnifications are discussed in Note 24 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 $2.3 million for the year ended December 31, 2003. 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 $90.0 million as of December 31, 2003. A detailed description of our $140.0 million accounts receivable securitization is included in Note 5 to our consolidated financial statements.

Mining Industry Accounting Issues — Emerging Issues Task Force

      Historical practice in extractive industries has been to classify leased coal interests and advance royalties as tangible assets, which is consistent with the classification of owned coal due to the similar rights of the leaseholder. SFAS No. 141, “Business Combinations,” provides mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of SFAS No. 141 (and SFAS No. 142, “Goodwill and Other Intangible Assets”) in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the Emerging Issues Task Force (the “EITF”) has established a Mining Industry Working Group that is currently addressing this issue. The classification

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of our leased coal interests and advance royalties in our consolidated balance sheet may be revised depending upon the conclusions reached by the Mining Industry Working Group and the EITF.

Other

      On February 29, 2004, we signed two definitive agreements to purchase three coal operations from RAG Coal International AG. Closing on the transactions is expected within the next three months and requires no additional U.S. or Australian regulatory approvals. The combined purchase price is $441 million in cash, subject to certain price adjustments. The purchase includes two mines in Queensland, Australia that produce 7 to 8 million tons per year of metallurgical coal, and the Twentymile Mine in Colorado, which produces 7.5 million tons per year of low-sulfur steam coal. We continue with a memorandum of understanding with RAG Coal International AG for our purchase of a 25 percent interest in Carbones del Guasare, S.A., a joint venture that includes Anglo American plc and a Venezuelan governmental partner. Carbones del Guasare operates the Paso Diablo surface mine in northwestern Venezuela, which produces approximately 7 million tons per year of coal for electricity generators and steel producers.

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 is 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, 2003, 90% of our sales volume was sold under long-term coal supply agreements. At December 31, 2003, our coal supply agreements had remaining terms ranging from one to 18 years and an average volume-weighted remaining term of approximately 3.9 years.

      Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We may adjust these contract prices based on inflation or deflation and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. We sometimes experience a reduction in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements permit the customer to terminate the contract if transportation costs, which our customers typically bear, increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.

      The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. 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. In 2003, pricing improved for eastern coal regions and moved slightly higher for western coal regions. As a result, we cannot predict the future

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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.
 
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.

      For the year ended December 31, 2003, we derived 26% of our total coal revenues from sales to our five largest customers. At December 31, 2003, we had 28 coal supply agreements with these customers that expire at various times from 2004 to 2012. 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.

      Peabody Western has 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. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to recovery of future capital expenditures for new pollution abatement equipment for the station. Alternatively, Southern California Edison has asked for authorization to spend money for the shutdown of the Mohave plant. In a July 2003 filing with the California Public Utilities Commission, the operator affirmed that the Mohave plant is not forecast to return to service as a coal-fired resource until mid-2009 at the earliest. The Company is 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 on December 31, 2005. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 4.5 million tons of coal in 2003. If the Company is unable to renew the coal supply agreement with the Mohave Generating Station, our results of operations and cash flows could be somewhat reduced 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, 2003, our total indebtedness was approximately $1,196.5 million, and we had $363.4 million of available borrowing capacity under our revolving credit facility. We may also incur additional indebtedness in the future.

      The degree to which we are leveraged could have important consequences, including, but not limited to:

  •  making it more difficult for us to pay interest and satisfy our debt obligations;
 
  •  increasing our vulnerability to general adverse economic and industry conditions;
 
  •  requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal of, and interest on, our indebtedness, thereby reducing the availability of the cash flow to fund working capital, capital expenditures or other general corporate uses;
 
  •  limiting our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements;
 
  •  limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; and

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  •  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 secure our indebtedness under our credit facility.

      If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness, including the notes. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. The new credit facility and the indenture governing the notes restrict our ability to sell assets and use the proceeds from the sales. We may not be able to consummate those sales or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

 
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 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.

 
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. The possibility exists that new legislation and/or regulations and orders may be

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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 2002, coal accounts for 30% 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 $1,034.3 million as of December 31, 2003, $72.5 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 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 to these funds, lower than expected returns on pension fund assets, higher medical and drug costs or other

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funding deficiencies. Certain of our subsidiaries are statutorily obligated to contribute to the 1992 Fund under the Coal Industry Retiree Health Benefit Act of 1992.
 
Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable.

      Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties. The federal government also leases natural gas and coalbed methane reserves in the west, including in the Powder River Basin. Some of these natural gas and coalbed methane reserves are located on, or adjacent to, some of our Powder River Basin reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2003, 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 mine development projects and acquisition activities may not result in significant additional reserves and we may not have continuing success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because title to most of our leased properties and mineral rights are not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we must receive various governmental permits. We cannot predict whether we will continue to receive the permits necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties 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 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, 2003, the United Mine Workers of America represented approximately 30% of our employees, who generated 18% of our production during 2003. An additional 5% of our employees are represented by labor unions other than the United Mine Workers of America. These employees generated 2% of our production during 2003. 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 10-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

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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, 2003, we had outstanding surety bonds with third parties for post-mining reclamation totaling $499.6 million. We had an additional $178.9 million of surety bonds in place for workers’ compensation and retiree healthcare obligations and $66.0 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 indenture or new credit facility; and
 
  •  the exercise by third-party surety bond issuers of their right to refuse to renew the surety.

      In addition, if we were required, as a result of the EITF’s mining accounting issues project discussed above, to reclassify our leased coal interests as an intangible asset, our ability to maintain or secure surety bonds could be negatively impacted.

 
Lehman Brothers Merchant Banking Partners II L.P. and affiliates could have influence on all stockholder votes.

      At December 31, 2003, the Merchant Banking Fund beneficially owned approximately 19% of our common stock, and has two representatives on our Board of Directors. As a result, the Merchant Banking Fund may be able to influence the election of our directors and our corporate and management policies and actions, including potential mergers or acquisitions, asset sales and other significant corporate transactions. We have retained affiliates of Lehman Brothers to perform advisory and financing services for us in the past, and may continue to do so in the future, provided that the Audit Committee approves in advance all services provided by Lehman Brothers.

 
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, the loss of a number of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot assure you that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. We do not have “key person” life insurance to cover our executive officers. Failure to retain or attract key personnel could have a material adverse effect on us.

 
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

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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

      We engage in over-the-counter and brokerage trading of coal. 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 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 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 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. 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.

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      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, 2003, the low, high, and average values at risk for our coal trading portfolio were $0.4 million, $2.0 million, and $1.0 million, respectively. Ninety-three percent of the value of our trading portfolio is scheduled to be realized by the end of 2004, and the remainder of the value of our trading portfolio is scheduled to be realized by the end of 2005.

      We also monitor other types of risk associated with our coal trading activities, including credit, market liquidity and counterparty nonperformance.

Credit Risk

      Our concentration of credit risk is substantially with energy producers and marketers and electric utilities. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor the credit extended. In the event that we engage in a transaction with a counterparty that does not meet our credit standards, we will protect our position by requiring the counterparty to provide appropriate credit enhancement. When appropriate, we have taken steps to reduce our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk, as determined by our credit management function, of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to fund the payment for coal under existing coal supply agreements. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties. Counterparty risk with respect to interest rate swap and foreign currency forwards and options transactions is not considered to be significant based upon the creditworthiness of the participating financial institutions.

Foreign Currency Risk

      We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures and certain firm purchase commitments denominated in Australian dollars. No derivatives utilized for currency hedging purposes have expiration dates beyond 2004. As of December 31, 2003, we had in place: forward contracts designated as cash flows hedges with notional amounts outstanding totaling $33.0 million; option contracts designated as cash flow hedges with notional amounts outstanding totaling $9.7 million; and forward contracts designated as fair value hedges with notional amounts outstanding totaling $6.1 million. The accounting for these derivatives is discussed in Note 3 to our consolidated financial statements.

Interest Rate Risk

      We have exposure to changes in interest rates due to our existing level of indebtedness. We manage our interest rate risk utilizing interest rate swaps, which are discussed in detail in Note 15 to our consolidated financial statements. As of December 31, 2003, after taking into consideration the effects of interest rate swaps, we had $644.9 million of fixed-rate borrowings and $551.6 million of variable-rate borrowings outstanding. A one percent increase in interest rates would result in an annualized increase to interest expense of $5.5 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase would result in a $50.8 million decrease in the fair value of these borrowings.

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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 90% of our sales volume under long-term coal supply agreements during 2003. We have sales commitments for 96% of our 2004 production.

      Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to price volatility. We, through our suppliers, utilize forward contracts to manage the exposure related to this volatility.

Item 8.     Financial Statements and Supplementary Data.

      See Part IV, Item 15 of this report for information required by this Item, which is incorporated by reference from our December 31, 2003 Annual Report to Stockholders.

 
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

      None.

 
Item 9A. Controls and Procedures.

      The Chief Executive Officer and Executive Vice President and Chief Financial Officer have evaluated our disclosure controls and procedures as of December 31, 2003 and have concluded that the disclosure controls and procedures were effective. Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that information required under the securities laws in the reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the rules of the Securities and Exchange Commission.

      Additionally, during the most recent fiscal quarter, there have been no changes to our internal control over financial reporting that could materially affect, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III

 
Item 10. Directors and Executive Officers of the Registrant.

      The information required by Item 401 of Regulation S-K related our Executive Officers is included in Part I, Item 4A of this report under the caption “Executive Officers of the Company.” The information required by Item 401 of Regulation S-K related our Board of Directors is included below.

Peabody Energy Board of Directors

Class III Directors — Terms Expiring in 2004

      Irl F. Engelhardt, age 57, 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 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 Chairman of the Center for Energy and Economic Development, Co-Chairman of

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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, and the Coal Utilization Research Council. He also serves on the advisory board of U.S. Bank, N.A. (St. Louis).

      William C. Rusnack, age 59, has been a director of the Company since January 2002. Mr. Rusnack is Former President and Chief Executive Officer of Premcor Inc., one of the largest independent oil refiners in the United States. He served as President, Chief Executive Officer and Director of Premcor from 1998 to February 2002. Prior to joining Premcor, Mr. Rusnack was President of ARCO Products Company, the refining and marketing division of Atlantic Richfield Company. During a 31-year career at ARCO, he was also President of ARCO Transportation Company and Vice President of Corporate Planning. He is also a director of Sempra Energy and Flowserve Corporation.

      Alan H. Washkowitz, age 63, has been a director of the Company since 1998. He is also a Managing Director of Lehman Brothers Inc., an investment banking firm, and head of the firm’s Merchant Banking Group, responsible for oversight of Lehman Brothers Merchant Banking Partners II L.P. Mr. Washkowitz joined Kuhn Loeb & Co. in 1968 and became a general partner of Lehman Brothers in 1978 when it acquired Kuhn Loeb & Co. Prior to joining the Merchant Banking Group, he headed Lehman Brothers’ Financial Restructuring Group. He is also a director of CP Kelco Inc., L-3 Communications Corporation and K&F Industries, Inc.

Class I Directors — Terms Expiring in 2005

      B. R. Brown, age 71, has been a director of the Company since December 2003. Mr. Brown is the retired Chairman, President and Chief Executive Officer of CONSOL Energy, Inc., a domestic coal and gas producer and energy services provider. He served as Chairman, President and Chief Executive Officer of CONSOL and predecessor companies from 1977 to 1999. He also served as a Senior Vice President of E. I. Du Pont De Nemours & Co., CONSOL’s controlling shareholder, from 1982 to 1992. Before joining CONSOL, Mr. Brown was a Senior Vice President at Conoco. From 1990 to 1995, he also was President and Chief Executive Officer of Remington Arms Co., Inc. Mr. Brown has previously served as Director and Chairman of the Bituminous Coal Operators Association Negotiating Committee, Chairman of the National Mining Association, and Chairman of the Coal Industry Advisory Board of the International Energy Agency. He also was a member of the reorganized Board of Directors of AEI Resources Holding Inc. from May 2002 until February 2003. He is currently a director of Delta Trust & Bank and Remington Arms Co., Inc.

      James R. Schlesinger, PhD., age 75, has been a director of the Company since 2001. He is Chairman of the Board of Trustees of MITRE Corporation, a not-for-profit corporation that provides systems engineering, research and development and information technology support to the government, a position he has held since 1985. Dr. Schlesinger also serves as Senior Advisor and Consultant to Lehman Brothers, a role he has held since 1980, and as Counselor to the Center for Strategic and International Studies. Dr. Schlesinger served as U.S. Secretary of Energy from 1977 to 1979. He also held senior executive positions for three U.S. Presidents, serving as Chairman of the U.S. Atomic Energy Commission from 1971 to 1973, Director of the Central Intelligence Agency in 1973 and Secretary of Defense from 1973 to 1975. Other past positions include Assistant Director of the Office of Management and Budget, Director of Strategic Studies at the Rand Corporation, Associate Professor of Economics at the University of Virginia and consultant to the Federal Reserve Board of Governors. Dr. Schlesinger is also a director of BNFL, Inc., KFx Inc. and Sandia Corporation.

      Sandra Van Trease, age 43, has been a director of the Company since January 2003. Ms. Van Trease is President and Chief Executive Officer of UNICARE, an operating affiliate of WellPoint Health Networks Inc., one of the nation’s largest publicly traded managed care companies. She has held that position since 2002, when her prior employer, RightCHOICE Managed Care, Inc., was acquired by WellPoint. Ms. Van Trease served as President, Chief Financial Officer and Chief Operating Officer of

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RightCHOICE from 2000 to 2002, and as Executive Vice President, Chief Financial Officer and Chief Operating Officer from 1997 to 2000. Prior to joining RightCHOICE in 1994, she was a Senior Audit Manager with Price Waterhouse LLP. She is a Certified Public Accountant and Certified Management Accountant. Ms. Van Trease also serves on the advisory board of U.S. Bank, N.A. (St. Louis).

Class II Directors — Terms Expiring in 2006

      William E. James, age 58, has been a director of the Company since 2001. Since July 2000, Mr. James has been Founding Partner of RockPort Capital Partners LLC, a venture fund specializing in energy and environmental technology and advanced materials. He is also Chairman of RockPort Group, a holding company engaged in international oil trading, banking and communications. Prior to joining RockPort, Mr. James co-founded and served as Chairman and Chief Executive Officer of Citizens Power LLC, a leading power marketer. He also co-founded the non-profit Citizens Energy Corporation and served as the Chairman and Chief Executive Officer of Citizens Corporation, its for-profit subsidiary, from 1987 to 1996. Mr. James periodically provides consulting services to Lehman Brothers, on matters unrelated to the Company. He also serves on the Boards of The United Bank for Africa and The Pan African Health Foundation.

      Robert B. Karn III, age 62, has been a director of the Company since January 2003. Mr. Karn is a financial consultant and former managing partner in financial and economic consulting with Arthur Andersen LLP in St. Louis. Before retiring from Arthur Andersen in 1998, Mr. Karn served in a variety of accounting, audit and financial roles over a 33-year career, including Managing Partner in charge of the global coal mining practice from 1981 through 1998. He is a Certified Public Accountant and has served as a Panel Arbitrator with the American Arbitration Association. Mr. Karn is also a director of Natural Resource Partners, a coal-oriented master limited partnership that is listed on the New York Stock Exchange.

      Henry E. Lentz, age 59, has been a director of the Company since 1998. Mr. Lentz is an Advisory Director of Lehman Brothers. He joined Lehman Brothers in 1971 and became a Managing Director in 1976. He left the firm in 1988 to become Vice Chairman of Wasserstein Perella Group, Inc., an investment banking firm. In 1993, he returned to Lehman Brothers as a Managing Director and served as head of the firm’s worldwide energy practice. In 1996, he joined Lehman Brothers’ Merchant Banking Group as a Principal and in January 2003 became a consultant to the Merchant Banking Group. He assumed his current role with Lehman Brothers effective January 2004. Mr. Lentz is also a director of Rowan Companies, Inc., CARBO Ceramics, Inc. and Antero Resources, Inc.

      Blanche M. Touhill, PhD, age 72, has been a director of the Company since 2001. Dr. Touhill is Chancellor Emeritus and Professor Emeritus at the University of Missouri — St. Louis. She previously served as Chancellor and Professor of History and Education at the University of Missouri — St. Louis from 1991 through 2002. Prior to her appointment as Chancellor, Dr. Touhill held the positions of Vice Chancellor for Academic Affairs and Interim Chancellor at the University of Missouri — St. Louis. Dr. Touhill also has served on the Boards of Directors of Trans World Airlines and Delta Dental. She holds bachelor’s and doctoral degrees in history and a master’s degree in geography from St. Louis University.

Section 16(a) Beneficial Ownership Reporting Compliance

      The Company’s executive officers and directors and persons beneficially holding more than ten percent of the Company’s Common Stock are required under the Securities Exchange Act of 1934 to file reports of ownership and changes in ownership of Company Common Stock with the Securities and Exchange Commission and the New York Stock Exchange. The Company files these reports of ownership and changes in ownership on behalf of its executive officers and directors. During the fiscal year ended December 31, 2003, the Company inadvertently made one late filing on behalf of each of the following officers when reporting their annual stock option grants in January 2003: Ian Craig, Irl Engelhardt, Sharon Fiehler, Jeffery Klinger, Richard Navarre, Jiri Nemec, Fredrick Palmer, Richard Whiting, Roger Walcott

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and John Wasik. To the best of the Company’s knowledge, based solely on its review of the copies of such reports furnished to the Company during the fiscal year ending December 31, 2003, and written representations from certain reporting persons that no additional reports were required, all other required reports were timely filed.

Corporate Governance and Code of Ethics

      The Board of Directors has a separately designated standing Audit Committee as required by the Securities Exchange Act of 1934 and New York Stock Exchange rules. The members of the Audit Committee are William C. Rusnack (Chairman), Robert B. Karn III and Sandra Van Trease. The Board of Directors has affirmatively determined that, in its judgment, each member of the Audit Committee meets all applicable independence standards established by the New York Stock Exchange. The Board of Directors also has determined that each of Messrs. Rusnack and Karn and Ms. Van Trease is an “audit committee financial expert” under rules and regulations adopted by the SEC.

      The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s Chief Executive Officer, Chief Financial Officer, Controller and other Company personnel. The Company also has adopted Corporate Governance Guidelines and charters for each of its standing Board of Directors Committees. Copies of the Code of Business Conduct and Ethics, Corporate Governance Guidelines and Committee charters are available on the Company’s website at peabodyenergy.com in the “Investor Relations” section under the heading “Corporate Governance.”

 
Item 11. Executive Compensation.

      The following table summarizes the annual and long-term compensation paid to the Chief Executive Officer and the four other most highly compensated executive officers of the Company for their service to the Company during the periods indicated.

Summary Compensation Table

                                                         
Annual Compensation Long-Term Compensation


Restricted Securities
Fiscal Stock Underlying LTIP All Other
Period Salary Bonus Awards Options Payments Compensation
Name and Principal Position Ended(1) ($) ($)(2) (#) (#)(3) ($)(4) ($)(5)








Irl F. Engelhardt
    12/31/03       875,000       1,500,000             41,110       594,484       94,693  
Chairman, Chief Executive
    12/31/02       739,583       280,000             40,488             69,673  
Officer and Director
    12/31/01       543,750       1,270,895             38,839             63,227  
      3/31/01       700,000       1,050,000             64,019             56,434  
Richard M. Whiting
    12/31/03       462,200       410,136             15,074       232,331       48,467  
Executive Vice President —
    12/31/02       432,500       70,400             15,823             39,389  
Sales, Marketing and Trading
    12/31/01       318,750       412,590             15,179             35,628  
      3/31/01       400,000       600,000             22,696             31,630  
Richard A. Navarre
    12/31/03       432,438       420,000             14,560       164,004       44,000  
Executive Vice President and
    12/31/02       323,542       119,000             11,169             28,737  
Chief Financial Officer
    12/31/01       225,000       451,520             10,714             23,720  
      3/31/01       250,000       406,250             55,084             19,615  
Roger B. Walcott, Jr.
    12/31/03       421,225       374,000             14,217       218,672       43,040  
Executive Vice President —
    12/31/02       407,500       80,000             14,892             37,094  
Corporate Development
    12/31/01       300,000       490,720             14,286             32,465  
      3/31/01       350,000       525,000             22,696             27,530  
Fredrick D. Palmer(6)
    12/31/03       364,500       320,000             12,333       191,321       28,383  
Executive Vice President —
    12/31/02       355,000       57,600             13,031             24,074  
Legal and External Affairs
    12/31/01       262,500       343,980             12,500             18,731  
      3/31/01       49,135       43,225             63,000             1,879  


(1)  Due to a change in the Company’s fiscal year-end, amounts shown for the period ended December 31, 2001 relate to the nine-month fiscal period ended December 31, 2001.

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(2)  Amounts for the nine months ended December 31, 2001 include special bonuses paid with respect to the Company’s initial public offering and prorated annual incentive bonuses paid for the nine-month period.
 
(3)  Represents number of shares of Common Stock underlying options.
 
(4)  Long-term performance awards earned in fiscal year 2003 were based on achievement of performance objectives for the period May 22, 2001 to December 31, 2003.
 
(5)  Includes annual matching contributions and performance contributions to qualified and non-qualified savings and investment plans on behalf of the named executives in the following amounts: Mr. Engelhardt, $90,500; Mr. Whiting, $47,732; Mr. Navarre, $43,541; Mr. Walcott, $42,372; and Mr. Palmer, $26,760. All remaining amounts are for group term life insurance.
 
(6)  Mr. Palmer was employed by the Company effective February 12, 2001.

      The following table sets forth information concerning the grant of stock options to each of the Company’s executive officers listed on the Summary Compensation Table above during the fiscal year ended December 31, 2003. The exercise price for all options granted is equal to the fair market value of the Company’s Common Stock on the date of grant.

Option Grants in Last Fiscal Year

                                                 
Individual Grants Potential Realizable

Value at Assumed
Percent of Annual Rates of Stock
Number of Options Price Appreciation for
Securities Granted to Option Term
Underlying Employees Exercise or
Options in Fiscal Base Price Expiration 5%(2) 10%(2)
Name Granted (#)(1) Year ($/Share) Date ($) ($)







Irl F. Engelhardt
    41,110       4.3 %     29.19       1/02/13       754,674       1,912,492  
Richard M. Whiting
    15,074       1.6 %     29.19       1/02/13       276,720       701,263  
Richard A. Navarre
    14,560       1.5 %     29.19       1/02/13       267,284       677,351  
Roger B. Walcott, Jr.
    14,217       1.5 %     29.19       1/02/13       260,988       661,394  
Fredrick D. Palmer
    12,333       1.3 %     29.19       1/02/13       226,402       573,748  


(1)  Other material terms of these options are described under the caption “Stock Options” in the Report of the Compensation Committee below.
 
(2)  The dollar amounts under these columns are the result of calculations at the 5% and 10% rates set by the SEC, and therefore are not intended to forecast possible future appreciation, if any, of the Company’s Common Stock price. The dollar amounts reflect an assumed annualized growth rate, as indicated, in the market value of the Company’s Common Stock from the date of grant to the end of the option term.

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      The following table sets forth information concerning the exercise of stock options by the executive officers listed on the Summary Compensation Table above, and the number and value of securities underlying unexercised options held by such executive officers as of December 31, 2003.

Aggregated Option Exercises in Last Fiscal Year

and Fiscal Year-End Option Values(1)
                                                 
Number of Securities
Underlying Unexercised Value of Unexercised
Options at In-The-Money Options at
Shares Fiscal Year-End Fiscal Year-End
Acquired on Value

Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
Name (#) ($) (#) (#) ($) ($)







Irl F. Engelhardt
    85,000       1,559,158       406,637       392,616       10,625,349       9,636,213  
Richard M. Whiting
    110,000       2,055,412       71,047       139,484       1,743,071       3,398,088  
Richard A. Navarre
    140,000       2,671,348       17,719       122,670       341,126       3,004,113  
Roger B. Walcott, Jr.
    150,000       2,759,990       30,141       137,709       633,495       3,374,066  
Fredrick D. Palmer
    34,000       615,589       20,677       46,187       398,114       916,361  


(1)  Values are calculated based on the closing price of Peabody Energy Corporation Common Stock on December 31, 2003 (i.e., $41.71 per share) less the applicable exercise price.

      The following table sets forth information concerning the grant of performance units to each of the Company’s executive officers listed on the Summary Compensation Table above during the fiscal year ended December 31, 2003. The performance period with respect to such awards is January 2, 2003 through December 31, 2005.

Long-Term Incentive Plans —

Awards in Last Fiscal Year
                 
Number of Shares, Performance or
Units or Other Period
Other Rights Until Maturation
Name (#)(1) or Payout



Irl F. Engelhardt
    43,828       1/2/03 – 12/31/05  
Richard M. Whiting
    8,035       1/2/03 – 12/31/05  
Richard A. Navarre
    7,761       1/2/03 – 12/31/05  
Roger B. Walcott, Jr.
    7,579       1/2/03 – 12/31/05  
Fredrick D. Palmer
    6,574       1/2/03 – 12/31/05  


(1)  The material terms of these performance units are described under the caption “Performance Units” in the Report of the Compensation Committee below.

Pension Benefits

      The Company’s Salaried Employees Retirement Plan, or pension plan, is a “defined benefit” plan. The pension plan provides a monthly annuity to salaried employees when they retire. A salaried employee must have at least five years of service to be vested in the pension plan. A full benefit is available to a retiree at age 62. A retiree can begin receiving a benefit as early as age 55; however, a 4% reduction factor applies for each year a retiree receives a benefit prior to age 62.

      An individual’s retirement benefit under the pension plan is equal to the sum of (1) 1.112% of the highest average monthly earnings over 60 consecutive months up to the “covered compensation limit” multiplied by the employee’s years of service, not to exceed 35 years, and (2) 1.5% of the average monthly earnings over 60 consecutive months over the “covered compensation limit” multiplied by the employee’s years of service, not to exceed 35 years.

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      The Company announced in February 1999 that the pension plan would be phased out beginning January 1, 2001. Certain transition benefits were introduced based on the age and service of the employee at December 31, 2000: (1) employees age 50 or older will continue to accrue service at 100%; (2) employees between the ages of 45 and 49 or under age 45 with 20 years or more of service will accrue service at the rate of 50% for each year of service worked after December 31, 2000; and (3) employees under age 45 with less than 20 years of service will have their pension benefits frozen. In all cases, final average earnings for retirement purposes will be capped at December 31, 2000 levels.

      The estimated annual pension benefits payable upon retirement at age 62, the normal retirement age, for the Chief Executive Officer and the other eligible named executive officers are as follows:

         
Irl F. Engelhardt
  $ 490,008  
Richard M. Whiting
    264,786  
Richard A. Navarre
    37,993  
Roger B. Walcott, Jr.
    24,663  
Fredrick D. Palmer
     

      The Company has one supplemental defined benefit retirement plan that provides retirement benefits to executives whose pay exceeds legislative limits for qualified defined benefit plans.

Employment Agreements

      The Company has entered into employment agreements with each of the named executive officers and with certain other key executives. The Chief Executive Officer’s and the Chief Operating Officer’s employment agreements provide for three-year terms that extend day-to-day so that there are at all times remaining terms of three years. Following a termination without cause or resignation for good reason, the Chief Executive Officer and the Chief Operating Officer are each entitled to a payment in substantially equal installments equal to three years’ base salary and three times the higher of (1) the target annual bonus for the year of termination or (2) the average of the actual annual bonuses paid in the three prior years. The Chief Executive Officer and Chief Operating Officer are each also entitled to a one-time prorated bonus for the year of termination (based on the Company’s actual performance multiplied by a fraction, the numerator of which is the number of business days the Executive was employed during the year of termination, and the denominator of which is the total number of business days during that year), payable when bonuses, if any, are paid to other executives. The Chief Executive Officer and Chief Operating Officer will also receive qualified and nonqualified retirement, life insurance, medical and other benefits for three years. In addition to the aforementioned, following a termination without cause or resignation for good reason (as defined in the employment agreement), the Chief Operating Officer will be paid a lump sum of $800,000 if the termination occurs on or after age 52. If the Chief Operating Officer terminates for any reason on or after age 55 or dies or becomes disabled, the lump sum of $800,000 will also be paid. The Chief Operating Officer, upon termination without cause, resignation for good reason, death, disability, or termination for any reason after the earlier of (1) reaching age 55 or (2) five years after being named the Chief Executive Officer (if applicable) is entitled to deferred compensation payable in cash in one of the following amounts: if termination occurs (a) prior to age 55, the greater of (i) the cash equivalent of the fair market value of 20,000 shares of Company common stock on October 1, 2003 plus interest or (ii) an amount equal to the fair market value of 20,000 shares on the date of termination; (b) on or after age 55 but prior to age 62, the greater of (i) the amount referenced in (a) on date of termination, (ii) $1.6 million reduced by .333% for each month that termination occurs before reaching age 62, or (iii) the fair market value of 20,000 shares on the date of termination; (c) on or after age 62, the greater of the amount referenced in (b) on date of termination or $1.6 million. If the Chief Operating Officer terminates for any other reason and it is prior to the earlier of (1) reaching age 55 or (2) five years after being named the Chief Executive Officer (if applicable), the deferred compensation amount is forfeited.

      Other executives’ employment agreements have either one-year or two-year terms which extend day-to-day so that there is at all times a remaining term of one or two years, respectively. The other key

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executives are entitled to the following benefits, payable in equal installments over one or two years: (1) one or two times base salary and (2) one or two times the higher of (A) the target annual bonus or (B) the average of the actual annual bonuses paid in the three prior years. In addition, the other executives are entitled to (1) a one-time prorated bonus for the year of termination (based on the Company’s actual performance multiplied by a fraction, the numerator of which is the number of business days the executive officer was employed during the year of termination, and the denominator of which is the total number of business days during that year), payable when bonuses, if any, are paid to the Company’s other executives, and (2) qualified and nonqualified pension, life insurance, medical and other benefits for the one or two-year period, as applicable, following termination.

      Under all executives’ employment agreements, the Company is not obligated to provide any benefits under tax qualified plans that are not permitted by the terms of each plan or by applicable law or that could jeopardize the plan’s tax status. Continuing benefit coverage will terminate to the extent an executive is offered or obtains comparable coverage from any other employer. The employment agreements provide for confidentiality during and following employment, and include a noncompetition and nonsolicitation agreement that is effective during and for one year following employment. If an executive breaches any of his or her confidentiality, noncompetition or nonsolicitation agreements, the executive will forfeit any unpaid amounts or benefits. To the extent that excise taxes are incurred by an executive as a result of “excess parachute payments,” as defined by IRS regulations, the Company will pay additional amounts up to $13 million, in the aggregate, so that executives would be in the same financial position as if the excise taxes were not incurred.

      In 2003, to ensure continued succession planning of key executives, the Company entered into retention agreements with both the Chief Financial Officer and the Executive Vice President — Sales, Marketing and Trading. If the Chief Financial Officer remains employed by the Company through August 28, 2005 and meets applicable performance goals as determined by the Chief Executive Officer, a bonus equal to one time his then base salary will be paid. Following a termination without cause or resignation for good reason, the Chief Financial Officer is entitled to the full retention bonus as of the date of such termination. If employment is terminated as a result of death or Disability (as defined in the Employment Agreement), prior to August 29, 2005, the Chief Financial Officer (or beneficiary) will be entitled to receive a prorated payment (equal to the retention bonus multiplied by a fraction, the numerator, which is the number of full calendar months that will have elapsed during the period beginning August 29, 2003 and ending on the date of termination of employment, and the denominator, which is 24). If employment ends for any reason other than for the above-mentioned reasons prior to August 29, 2005, or if the Chief Financial Officer fails to meet the established performance goals during the retention period, the retention bonus will be forfeited.

      If the Executive Vice President-Sales, Marketing and Trading remains employed by the Company through August 31, 2005 and meets applicable performance goals, as determined by the Chief Executive Officer, he will receive a retention bonus equal to the lesser of (A) the current annual base salary plus the higher of the actual incentive earned in the 2003 or 2004 fiscal years or (B) $1.2 million less certain offsets attributable to pay increases received during the retention period. If employment with the Company is terminated before September 1, 2005, either by the Executive for Good Reason or by the Company without Cause, the Executive will be entitled to receive the retention bonus as of the date of such termination; provided that such retention bonus will be equal to $1,200,000 less certain offsets attributable to pay increases received during the retention period. If employment is terminated before September 1, 2005, as a result of death or Disability (as defined in the Employment Agreement), the Executive (or beneficiary) will be entitled to receive, as of the date of such termination, a prorated payment, as calculated under termination for Good Reason (as described above), (multiplied by a fraction the numerator of which is the number of calendar days that will have elapsed during the period beginning September 1, 2003, and ending on the date of termination, and the denominator of which is 731). If employment ends for any reason other than for the above-mentioned reasons prior to September 1, 2005, or if the Executive fails to meet the established performance goals during the retention period, the retention bonus will be forfeited.

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Report of the Compensation Committee

      The Compensation Committee is comprised entirely of independent directors and has the responsibility for reviewing and approving changes to the Company’s executive compensation policies and programs. The Compensation Committee also approves all compensation payments to the Chief Executive Officer and the other named executive officers, including annual and long-term incentive awards. In addition, the Compensation Committee approves Company-wide salary increase budgets and overall compensation and benefit plans, administers the Company’s annual and long-term incentive plans and periodically assesses the Company’s director compensation program.

 
Compensation Philosophy

      The fundamental objective of the Company’s executive compensation program is to attract, retain and motivate key executives to enhance long-term profitability and stockholder value.

      The Company’s compensation program is based on the following policies and objectives:

  •  Programs will have a clear link to stockholder value.
 
  •  Programs will be designed to support achievement of the Company’s business objectives.
 
  •  Total compensation opportunities will be established at levels which are competitive with marketplace practices and other pertinent criteria, taking into account such factors as executive performance, level of experience and retention value.
 
  •  Variable incentive pay will constitute a significant portion of each executive’s compensation.
 
  •  Incentive pay will be designed to:

  •  Reflect company-wide, business unit and individual performance, based on each individual’s position and level; and
 
  •  Incorporate “absolute” (internal) and “relative” (external) performance measures.

  •  Programs will be communicated so that participants understand how their decisions affect business results and their compensation.

      With these policies and objectives in mind, the Compensation Committee has designed a pay structure for the named executive officers that incorporates three key components: base salary, annual incentive compensation, and long-term incentive compensation consisting of stock options and performance units.

 
Compensation Program Competitiveness Study

      The Compensation Committee commissioned an in-depth compensation analysis conducted by an independent third party in June 2003 to determine whether the Company’s executive compensation programs were consistent with those of other publicly held companies of similar size and in a similar industry. The results of this study confirmed that the Company’s executive compensation programs are consistent with those of other publicly held companies of similar size and in a similar industry, including, but not limited to, those companies that comprise the “Custom Composite Index” component of the “Stock Performance Graph” included in the Company’s 2004 Proxy Statement. The Compensation Committee will continue to periodically review the Company’s executive compensation programs to ensure that such programs remain competitive and continue to meet their objectives.

 
Annual Base Salary

      Based upon the above-referenced study, the Compensation Committee reviewed the base salaries of the Company’s executive officers to ensure competitiveness in the marketplace. The Compensation Committee will continue to review the base salaries of the named executive officers to ensure salaries

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continue to reflect marketplace practices and take into account performance, experience and retention value.
 
Annual Incentive Plan

      The Company’s annual incentive compensation plan provides opportunities for key executives to earn annual cash incentive payments tied to the successful achievement of pre-established objectives.

      All annual incentive plan participants are assigned threshold, target and maximum incentive percentages. If performance does not meet the threshold level, no incentive is earned. At threshold levels, the incentive that can be earned generally equals 50% of the target incentive. The target incentive represents the level of compensation that is considered to be required to stay competitive with the desired pay position in the market. Target incentive payments generally are received for achieving budgeted financial goals and meeting personal performance goals. Maximum incentive payments generally are received when financial goals and performance goals are significantly exceeded. A participant’s annual incentive opportunity is based upon his or her level of participation in the incentive plan. The incentive opportunity increases based upon an executive’s potential to affect operations or profitability.

      Awards for corporate employees, including the Chief Executive Officer, are based on achievement of corporate and individual performance goals. Awards to operating employees are based on achievement of a combination of corporate, business unit and individual performance goals. Achievement of corporate performance is determined by comparing the Company’s actual performance against objective goals, and achievement of personal goals is determined by evaluating a combination of both objective and subjective performance measures. All goals are established by the Compensation Committee at the beginning of each calendar year. In 2003, the performance measures for the named executive officers included Adjusted EBITDA, return on invested capital (ROIC) and individual performance.

      All award payments to the named executive officers are subject to the review and approval of the Compensation Committee. In addition, the Chief Executive Officer’s award payment is subject to the review and approval of the independent members of the Board of Directors.

 
2003 Incentive Payments

      For the fiscal year ended December 31, 2003, the Company awarded annual incentive payments to the Chief Executive Officer and the other four named executive officers, as reflected in the bonus column of the Summary Compensation Table. Other eligible executives were paid under the same annual incentive plan. Annual incentive payouts for 2003 were based on the Company’s achievement of goals for Adjusted EBITDA, ROIC and individual performance. The cash awards are intended to link executive performance, annual performance measures and long-term stockholder value.

 
Long-Term Incentives

      The Compensation Committee has determined that a long-term incentive opportunity will be made available to each of the Company’s named executive officers through annual awards of stock options and performance units. The targeted value of these awards generally is split equally between stock options and performance units and ranges from 100% to 225% of base salary for each of the named executive officers. The Compensation Committee intends that these long-term incentive opportunities be competitive and based on actual Company performance.

 
Stock Options

  The Company’s stock option program is a long-term plan designed to create a direct link between executive compensation and increased stockholder value. The targeted value of annual option awards to the named executive officers ranges from 50% to 112.5% of base salary as described above, but awards can deviate from these guidelines at the discretion of the Compensation Committee. The

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  Company uses a Black-Scholes valuation model to establish the value of its stock option grants. The grants are currently made in the form of nonqualified stock options.
 
  All stock options are granted at an exercise price equal to the closing price of the Company’s Common Stock on the date of grant. Stock options generally vest in one-third increments over a period of three years; however, options will immediately vest upon a change of control of the Company or upon an employee’s death, disability or a recapitalization event. Options expire ten years from the date of grant.
 
Performance Units

  Certain key executives are eligible to receive long-term incentive awards in the form of performance units. The targeted value of performance unit awards to the named executive officers ranges from 50% to 112.5% of base salary as described above, but awards can deviate from these guidelines at the discretion of the Compensation Committee. Performance units awarded in 2003 will be payable in cash, if earned. For units awarded in 2003, the value of the performance units is tied to the relative performance of the Company’s Common Stock. The percentage of the performance units earned is based on the Company’s total stockholder return (TSR) over a period beginning January 2, 2003 and ending December 31, 2005 relative to both an industry comparator group (the Industry Peer Group) and the S&P Industrial Index. TSR measures cumulative stock price appreciation plus dividends. The Industry Peer Group generally is perceived to be subject to similar market conditions and investor reactions as the Company. For this reason, the Industry Peer Group is weighted at 75% while the S&P Industrial Index is weighted at 25%.
 
  Performance payout formulas are as follows:

  •  Threshold payouts (equal to 50% of the value of the performance units) begin for TSR performance at the 40th percentile of the Industry Peer Group or the 35th percentile of the S&P Industrial Index.
 
  •  Target payouts (equal to 100% of the value of the performance units) are based on performance at the 55th percentile of the Industry Peer Group and 50th percentile of the S&P Industrial Index.
 
  •  Maximum payouts (equal to 200% of the value of the performance units) are based on performance at the 80th percentile of the Industry Peer Group and the 75th percentile of the S&P Industrial Index.
 
  •  No payments will be made if TSR is negative and performance is below the 50th percentile of the Industry Peer Group. Also, the maximum payout cannot exceed 150% of the value of the performance units if TSR is negative and performance is above the 50th percentile of the Industry Peer Group.

  Performance units are issued at a price that equals the average closing price of the Company’s Common Stock during the four weeks of trading immediately following the date of grant. TSR for the Company at the end of the cycle is based on the average closing price during the last four weeks of trading in the performance cycle. Units vest over, and are payable subject to the achievement of performance goals at the conclusion of, the measurement period. Upon a change of control of the Company, a recapitalization event or the executive’s death, disability, retirement or termination without cause, payments by the Company will be paid in proportion to the number of vested performance units based upon the TSR performance as of the date the event occurs.
 
Other Plans

      The Company maintains a Deferred Compensation Plan pursuant to which certain executives can defer base, annual incentive and any cash-based long-term incentive compensation. The Company also maintains a defined contribution retirement plan, a defined benefit retirement plan (although the plan is being phased out) and other benefit plans for its employees. Executives participate in these plans on the

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same terms as other eligible employees, subject to any legal limits on the amount that may be contributed by or paid to executives under the plans. In addition, the Company maintains one excess defined benefit retirement plan and one excess defined contribution plan that provides retirement benefits to executives whose pay exceeds legislative limits for qualified benefit plans.
 
Policy on Deductibility of Compensation Expenses

      Pursuant to Section 162(m) under the Internal Revenue Code, certain compensation paid to executive officers in excess of $1 million is not tax deductible, except to the extent such excess constitutes performance-based compensation. Prior to May 2005, the limit on deductibility will not apply to plans in existence prior to the Company’s initial public offering in 2001. The Committee considers its primary goal to design compensation strategies that further the best interests of the Company and its stockholders. However, when the Section 162(m) exemption expires, to the extent they are not inconsistent with that goal, the committee will attempt to use compensation policies and programs that preserve the tax deductibility of compensation expenses.

 
Compensation of the Chief Executive Officer

      Mr. Engelhardt’s base salary is $950,000. A review of competitive market data conducted in June 2003 supports the competitiveness of this salary.

      For the fiscal year ended December 31, 2003, Mr. Engelhardt’s maximum incentive opportunity under the Company’s annual incentive compensation plan was 175% of his base salary, or $1,662,500. The maximum incentive opportunity for the other named executive officers was 150% of their base salary. Based on Company and individual performance for the fiscal year ended December 31, 2003, Mr. Engelhardt was awarded a bonus payout equal to 158% of his current annual base salary, or $1,500,000. The full Board of Directors evaluated Mr. Engelhardt’s performance during 2003, and the evaluation was a major consideration in setting the amount of his annual incentive compensation plan award. The Compensation Committee and the independent members and other non-management members of the Board of Directors approved Mr. Engelhardt’s salary and bonus.

      During the fiscal year ended December 31, 2003, Mr. Engelhardt also received long-term incentive awards consisting of stock options and performance units. These awards were made in accordance with the Compensation Committee’s long-term incentive guidelines described above. The specific terms of such awards are outlined in this report under the captions “Long Term Incentives,” “Stock Options” and “Performance Units,” and in the compensation tables above.

      MEMBERS OF THE COMPENSATION COMMITTEE:

  ROBERT B. KARN III (CHAIR)
  B. R. BROWN
  BLANCHE M. TOUHILL, PhD.
  H.E. LENTZ (prior to January 2004)
  ALAN H. WASHKOWITZ (prior to January 2004)

Compensation Committee Interlocks and Insider Participation

      Messrs. Brown and Karn and Dr. Touhill currently serve on the Compensation Committee. Messrs. Brown and Karn joined the Compensation Committee effective January 2004. Prior to that time, Messrs. Lentz and Washkowitz also served as members of the Compensation Committee. None of these current or former committee members is employed by the Company. Messrs. Lentz and Washkowitz are employed by Lehman Brothers, whose affiliates own 19% of the Company’s outstanding Common Stock. During the fiscal year ended December 31, 2003, Lehman Brothers engaged in certain transactions with the Company as described under the caption “Related Party Transactions” below. In 2003, the Board of Directors instituted procedures requiring the Audit Committee, which is comprised of nonaffiliated and independent members, to approve the use of Lehman Brothers (or its affiliates) for any services.

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Compensation of Directors

      Directors who are employees of the Company or Lehman Brothers receive no additional pay for serving as directors. Each director who is not an employee of the Company or Lehman Brothers (a “non-employee director”) is paid an annual cash retainer of $45,000. Committee chairpersons other than the Audit Committee Chair also receive an annual $3,500 cash retainer for committee service. The Audit Committee Chair receives a $10,000 annual cash retainer, and other Audit Committee members receive $5,000 annual cash retainers for committee service. Non-employee directors also receive $1,500 for each day that they attend Board and/or committee meetings. The Company pays the travel and accommodation expenses of directors to attend meetings and other corporate functions.

      Non-employee directors receive options to purchase 1,000 shares of Company Common Stock and a grant of restricted stock valued at $50,000 when they are first elected to the Board of Directors. Non-employee directors also receive annual stock option grants valued at $25,000 (based on Black-Scholes methodology). The shares subject to the restricted stock awards vest after three years if the recipient continues to serve on the Board of Directors. All non-employee director stock options are granted at an exercise price equal to the fair market value of the Company’s Common Stock on the date of grant. These options vest in one-third increments over three years and expire ten years after grant. In the event of a change of control of the Company, any previously unvested options will vest and all restrictions related to the restricted stock awards will lapse.

 
Item 12.      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

      The information required by Item 201(d) of Regulation S-K is included in Item 5 of this report.

Ownership of Company Securities

      The following table sets forth information as of February 17, 2004 with respect to persons or entities who are known to beneficially own more than 5% of the Company’s outstanding Common Stock, each

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director, each executive officer named in the Summary Compensation Table above, and all directors and executive officers as a group.

Beneficial Owners of More Than Five Percent,

Directors and Management
                   
Amount and Nature of Percent of
Name and Address Of Beneficial Owner Beneficial Ownership(1)(2) Class(3)



Lehman Brothers Merchant Banking Partners II
               
L. P. and affiliates
               
 
c/o Lehman Brothers Holdings Inc.
               
 
745 Seventh Avenue, 25th Floor
               
 
New York, New York 10019
    10,267,169       18.7 %
FMR Corp.
               
 
(Fidelity Management & Research Company)
    4,379,143       8.0 %
B. R. Brown
    1,334       *  
Irl F. Engelhardt
    648,540       1.2 %
William E. James(4)
    30,046       *  
Robert B. Karn III
    2,962       *  
Henry E. Lentz(4)
          *  
Richard A. Navarre
    82,636       *  
Fredrick D. Palmer
    31,403       *  
William C. Rusnack
    3,174       *  
James R. Schlesinger(4)
    3,178       *  
Blanche M. Touhill
    3,178       *  
Sandra Van Trease
    4,162       *  
Roger B. Walcott, Jr. 
    114,312       *  
Alan H. Washkowitz(4)
          *  
Richard M. Whiting
    144,249       *  
All directors and executive officers as a group (20 people)
    1,673,293       3.0 %


(1)  Beneficial ownership is determined in accordance with the rules of the Securities and Exchange Commission and includes voting and investment power with respect to shares. Unless otherwise indicated, the persons named in the table have sole voting and sole investment control with respect to all shares beneficially owned.
 
(2)  Includes shares issuable pursuant to stock options exercisable within 60 days after February 17, 2004, as follows: Mr. Engelhardt, 433,837; Mr. Navarre, 26,296; Mr. Palmer, 29,131; Mr. Walcott, 39,844; Mr. Whiting, 81,346; Mr. James, 28,166; Mr. Karn, 334; Mr. Rusnack, 1,266; Dr. Schlesinger, 1,266; Dr. Touhill, 1,266; Ms. Van Trease, 334 and all directors and executive officers as a group, 1,045,240. Also includes shares of restricted stock that remain unvested as of February 17, 2004 as follows: Mr. Brown, 1,334; Mr. James, 1,880; Mr. Karn, 1,828; Mr. Rusnack, 1,908; Dr. Schlesinger, 1,912; Dr. Touhill, 1,912; Ms. Van Trease, 1,828 and all directors and executive officers as a group, 22,602.
 
(3)  Asterisk (*) indicates that the applicable person owns less than one percent of the outstanding shares.
 
(4)  Messrs. James and Schlesinger are consultants of Lehman Brothers. Mr. Washkowitz is a Managing Director of Lehman Brothers and head of Lehman Brothers Merchant Banking Group. Mr. Lentz is an Advisory Director of Lehman Brothers. Messrs. James, Lentz, Schlesinger and Washkowitz disclaim beneficial ownership of the shares held or controlled by these entities or their affiliates.

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Item 13.      Certain Relationships and Related Transactions.

Transactions With Affiliates of Lehman Brothers

      As of February 17, 2004, the Merchant Banking Fund owned approximately 19% of the Company’s outstanding Common Stock. Messrs. Lentz and Washkowitz and Dr. Schlesinger, each being one of the Company’s directors, are investors in certain funds that comprise the Merchant Banking Fund. Mr. Lentz is an Advisory Director of, Dr. Schlesinger is a consultant to, and Mr. Washkowitz is a Managing Director of, Lehman Brothers.

      In connection with our debt refinancing, Lehman Brothers served as joint lead arranger and Lehman Commercial Paper Inc. served as syndication agent in connection with the Company’s $1,050,000,000 senior secured credit facility, which closed in March 2003. Lehman Brothers also served as joint book-running manager in connection with the Company’s issuance of 6 7/8% Senior Notes due 2013, which closed in March 2003. Lehman Brothers also served as the dealer manager in connection with a tender offer for the Company’s outstanding 8 7/8% senior notes due 2008 and 9 5/8% senior subordinated notes due 2008. Lehman Brothers received total fees of $7.4 million in connection with the refinancing; such fees were consistent with the fees paid to other parties to the refinancing for their respective services.

      In May 2003 the Company entered into four $25.0 million fixed to floating interest rate swaps as a hedge of the changes in fair value of the 6.875% Senior Notes due 2013. Lehman Brothers was chosen as one of the swap counterparties as part of a competitive bidding process among eight financial institutions.

      In May 2003 and July 2003, Lehman Brothers served as lead underwriter in connection with two separate public offerings of Company common stock by the Merchant Banking Fund and certain other selling stockholders. Lehman Brothers received customary fees, plus reimbursement of certain expenses, for those services.

      In December 2003, Lehman Brothers served as lead underwriter in connection with the Company’s sale in a public offering of limited partner interests in Penn Virginia Resource Partners, L.P. Lehman Brothers received customary fees, plus reimbursement of certain expenses, for those services.

Transactions With Management

      During the fiscal years ended March 31, 1999, 2000 and 2001, some of the Company’s executive officers and 18 other employees purchased or were granted shares of Class B common stock under the 1998 Stock Purchase and Option Plan for Key Employees. All such Class B shares subsequently converted into Company common stock on a one-for-one basis at the time of the Company’s initial public offering. In connection with these purchases and grants, the Company, affiliates of Lehman Brothers and the executives who received Class B Common Stock entered into stockholders agreements providing for certain rights relating to the registration of their shares in connection with certain sales of Company capital stock by affiliates of Lehman Brothers. The stockholders agreements provide the investors with the right to register and sell their unregistered stock in the event the Company conducts certain types of registered offerings.

      In conjunction with the purchases and grants of Class B Common Stock, the executive officers and employees executed term notes. The term notes related to the grants were due on May 19, 2003 and the term notes executed for purchases are due on February 1, 2006. All of the named executive officers have repaid their loans, and one executive officer’s note is outstanding as of February 17, 2004. All of the term notes bear interest at an applicable U.S. federal rate used by the Internal Revenue Service for loans to employees, and the maturity of the notes accelerate upon the occurrence of certain events, including six months following any termination of employment or disposition of the stock.

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      The following table sets forth certain information regarding the term notes for the Company’s executive officers with aggregate indebtedness in excess of $60,000, since January 1, 2003.

                 
Largest Aggregate Indebtedness
Outstanding Indebtedness During Fiscal Year Ended
Name at February 17, 2004 December 31, 2003



Irl F. Engelhardt
  $     $ 669,061  
Roger B. Walcott, Jr. 
        $ 161,766  
Richard M. Whiting
        $ 159,366  
 
Item 14.      Principal Accounting Fees and Services.

Appointment Of Independent Auditors And Fees

      Ernst & Young LLP served as the Company’s independent auditors for the fiscal year ended December 31, 2003 and has been appointed to serve in that capacity again for fiscal 2004, subject to ratification by the Company’s stockholders.

      The following fees were paid to Ernst & Young for services rendered during the Company’s last two fiscal years:

  •  Audit Fees: $1,043,000 (for the fiscal year ended December 31, 2003) and $797,000 (for the fiscal year ended December 31, 2002) for professional services rendered for the audit of the Company’s annual financial statements, review of financial statements included in the Company Forms 10-Q and services that are normally provided by Ernst & Young in connection with statutory and regulatory filings or engagements for those fiscal years.
 
  •  Audit-Related Fees: $185,000 (for the fiscal year ended December 31, 2003) and $191,000 (for the fiscal year ended December 31, 2002) for assurance related services for audits of employee benefit plans, due diligence services related to acquisitions or divestitures and consultation services related to proposed or newly released accounting standards.
 
  •  Tax Fees: $551,000 (for the fiscal year ended December 31, 2003) and $813,000 (for the fiscal year ended December 31, 2002) for tax compliance, tax advice and tax planning services.
 
  •  All Other Fees: $0 (for the fiscal year ended December 31, 2003) and $142,000 (for the fiscal year ended December 31, 2002). Other services in 2002 related to internal audit and arbitration support services incurred prior to the release of the new rules and regulations governing such services.

      Under procedures established by the Board of Directors, the Audit Committee is required to pre-approve all audit and non-audit services performed by the Company’s independent auditor to ensure that the provisions of such services do not impair the auditor’s independence. The Audit Committee may delegate its pre-approval authority to one or more of its members, but not to management. The member or members to whom such authority is delegated shall report any pre-approval decisions to the Audit Committee at its next scheduled meeting

      Each fiscal year, the Audit Committee reviews with management and the independent auditor the types of services that are likely to be required throughout the year. Those services are comprised of four categories, including audit services, audit-related services, tax services and all other permissible services. At that time, the Audit Committee pre-approves a list of specific services that may be provided within each of these categories, and sets fee limits for each specific service or project. Management is then authorized to engage the independent auditor to perform the pre-approved services as needed throughout the year, subject to providing the Audit Committee with regular updates. The Audit Committee reviews all billings submitted by the independent auditor on a regular basis to ensure that their services do not exceed pre-defined limits. The Audit Committee must review and approve in advance, on a case-by-case basis, all other projects, services and fees to be performed by or paid to the independent auditor. The Audit

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Committee also must approve in advance any fees for pre-approved services that exceed the pre-established limits, as described above.

      Under Company policy and/or applicable rules and regulations, since April 2003 the independent auditor is prohibited from providing the following types of services to the Company: (1) bookkeeping or other services related to the Company’s accounting records or financial statements, (2) financial information systems design and implementation, (3) appraisal or valuation services, fairness opinions or contribution-in-kind reports, (4) actuarial services, (5) internal audit outsourcing services, (6) management functions, (7) human resources, (8) broker-dealer, investment advisor or investment banking services, (9) legal services, and (10) expert services unrelated to audit.

      During the fiscal year ended December 31, 2003, 76% of the services described under the headings “Audit-Related Fees,” “Tax Fees” and “All Other Fees” were approved by the Audit Committee pursuant to the procedures described above, which were adopted by the Board of Directors effective April 15, 2003. Fees incurred prior to that date, while not subject to these procedures, were also reviewed and approved by the Audit Committee upon adoption of the procedures noted above.

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, 2003 Annual Report to Stockholders are incorporated by reference:

  Report of Independent Auditors
 
  Consolidated Statements of Operations — Years Ended December 31, 2003 and 2002 and the Nine Months Ended December 31, 2001
 
  Consolidated Balance Sheets — December 31, 2003 and December 31, 2002
 
  Consolidated Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2003 and 2002 and the Nine Months Ended December 31, 2001
 
  Consolidated Statements of Cash Flows — Years Ended December 31, 2003 and 2002 and the Nine Months Ended December 31, 2001
 
  Notes to Consolidated Financial Statements

        (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 December 1, 2003, we filed a Form 8-K under Item 5, Other Events and Regulation FD Disclosure, announcing that it has signed a memorandum of understanding with RAG Coal

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  International AG to purchase two high-quality metallurgical coal operations in Queensland, Australia, and more than 100 million metric tonnes of coal reserves.
 
        On December 29, 2003, we filed a Form 8-K under Item 5, Other Events and Regulation FD Disclosure, announcing that we had signed memoranda of understanding with RAG Coal International AG to purchase coal assets in Colorado and a 25 percent interest in a coal operation in Venezuela.

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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 4, 2004

      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

Irl F. Engelhardt
  Chairman, Chief Executive Officer and Director (principal executive officer)   March 4, 2004
 
/s/ RICHARD A. NAVARRE

Richard A. Navarre
  Executive Vice President and Chief Financial Officer (principal financial and accounting officer)   March 4, 2004
 
/s/ B.R. BROWN

B.R. Brown
  Director   March 4, 2004
 
/s/ WILLIAM E. JAMES

William E. James
  Director   March 4, 2004
 
/s/ ROBERT B. KARN III

Robert B. Karn III
  Director   March 4, 2004
 
/s/ HENRY E. LENTZ

Henry E. Lentz
  Director   March 4, 2004
 
/s/ WILLIAM C. RUSNACK

William C. Rusnack
  Director   March 4, 2004
 
/s/ JAMES R. SCHLESINGER

James R. Schlesinger
  Director   March 4, 2004
 
/s/ BLANCHE M. TOUHILL

Blanche M. Touhill
  Director   March 4, 2004
 
/s/ SANDRA VAN TREASE

Sandra Van Trease
  Director   March 4, 2004
 
/s/ ALAN H. WASHKOWITZ

Alan H. Washkowitz
  Director   March 4, 2004

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REPORT OF INDEPENDENT AUDITORS

Board of Directors

Peabody Energy Corporation

      We have audited the consolidated financial statements of Peabody Energy Corporation as of December 31, 2003 and 2002, and for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001, and have issued our report thereon dated January 23, 2004. 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.

  /S/ ERNST & YOUNG LLP

St. Louis, Missouri

January 23, 2004

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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, 2003
                                       
 
Reserves deducted from asset accounts:
                                       
   
Advance royalty recoupment reserve
  $ 13,585     $ (181 )   $     $ 1,061 (2)   $ 14,465  
   
Reserve for materials and supplies
    9,065             (1,504 )     2       7,563  
   
Allowance for doubtful accounts
    1,331       30                   1,361  
YEAR ENDED DECEMBER 31, 2002
                                       
 
Reserves deducted from asset accounts:
                                       
   
Advance royalty recoupment reserve
  $ 12,836     $ 154     $     $ 595 (2)   $ 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:
                                       
   
Advance royalty recoupment reserve
  $ 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  


(1)  Reserves utilized, unless otherwise indicated.
 
(2)  Balances transferred from other accounts.

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REPORT OF MANAGEMENT

      Management of Peabody Energy Corporation is responsible for the preparation and presentation of the financial statements included in this annual report. Management is also responsible for the reasonableness of estimates and judgments inherent in the preparation of the financial statements. These statements have been prepared in conformity with generally accepted accounting principles and include amounts based on management’s best estimates and judgments.

      Management is responsible for establishing and maintaining adequate internal controls and procedures for financial reporting. Management has established and maintains a system of internal control and procedures for financial reporting designed to provide reasonable assurance that errors or irregularities that could be material to the financial statements are prevented or would be detected within a timely period. The Company’s internal controls are designed not only to ensure reliable and transparent financial recordkeeping and reporting, but also for the protection of the Company’s assets and the efficient utilization of Company resources. The system of internal control includes widely communicated statements of policies and business practices which are designed to require all employees to maintain high ethical standards in the conduct of Company affairs. The internal controls are augmented by organizational arrangements that provide for appropriate delegation of authority and division of responsibility and by a program of internal audit with management follow-up. Management believes that the Company’s internal controls and procedures for financial reporting are adequate and operating effectively as of December 31, 2003.

      The financial statements have been audited by Ernst & Young LLP, independent certified public accountants. Their audit was conducted in accordance with generally accepted auditing standards and included a review of internal controls and selective tests of transactions.

      Management maintains a strong awareness of the importance of full and open presentation of our financial position and results of operations and utilizes a system of disclosure controls and procedures to ensure such presentation. To facilitate this, the Company maintains a Disclosure Committee, which includes senior executives who possess exceptional knowledge of the Company’s business.

      The Audit Committee of the Board of Directors, composed of independent directors, meets periodically with the independent certified public accountants, our internal audit service providers and management to review accounting, auditing, internal accounting controls and financial reporting matters. The independent certified public accountants and our internal audit service providers have free access to and separately meet on a periodic basis with the Audit Committee.

/s/ IRL F. ENGELHARDT


Irl F. Engelhardt
Chairman & Chief Executive Officer
March 2, 2004

/s/ RICHARD A. NAVARRE


Richard A. Navarre
Executive Vice President & Chief Financial Officer
March 2, 2004

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REPORT OF INDEPENDENT AUDITORS

The Board of Directors
Peabody Energy Corporation

      We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation as of December 31, 2003 and 2002, and the related consolidated statements of operations, changes in stockholders’ equity and cash flows of the Company for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

      We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

      In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Peabody Energy Corporation as of December 31, 2003 and 2002, and the consolidated results of its operations and its cash flows for the years ended December 31, 2003 and 2002, and the nine months ended December 31, 2001 in conformity with accounting principles generally accepted in the United States.

      As discussed in Note 7 to the consolidated financial statements, on January 1, 2003, the Company changed its methods of accounting for asset retirement obligations, non-derivative trading contracts, and actuarial gains and losses related to net periodic postretirement benefit costs.

  /s/ Ernst & Young LLP

St. Louis, Missouri

January 23, 2004

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PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

                             
Nine Months
Year Ended Year Ended Ended
December 31, December 31, December 31,
2003 2002 2001



(Dollars in thousands, except share data)
Revenues
                       
 
Sales
  $ 2,729,323     $ 2,630,371     $ 1,869,321  
 
Other revenues
    100,157       86,727       68,619  
     
     
     
 
   
Total revenues
    2,829,480       2,717,098       1,937,940  
Costs and Expenses
                       
 
Operating costs and expenses
    2,335,800       2,225,344       1,588,596  
 
Depreciation, depletion and amortization
    234,336       232,413       174,587  
 
Asset retirement obligation expense
    31,156              
 
Selling and administrative expenses
    108,525       101,416       73,553  
 
Net gain on property and equipment disposals
    (25,123 )     (15,763 )     (14,327 )
     
     
     
 
Operating Profit
    144,786       173,688       115,531  
 
Interest expense
    98,540       102,458       88,686  
 
Early debt extinguishment costs
    53,513             38,628  
 
Interest income
    (4,086 )     (7,574 )     (2,155 )
     
     
     
 
Income (Loss) Before Income Taxes and Minority Interests
    (3,181 )     78,804       (9,628 )
 
Income tax benefit
    (47,708 )     (40,007 )     (7,193 )
 
Minority interests
    3,035       13,292       7,248  
     
     
     
 
Income (Loss) Before Accounting Changes
    41,492       105,519       (9,683 )
 
Cumulative effect of accounting changes, net of taxes
    (10,144 )            
     
     
     
 
   
Net Income (Loss)
  $ 31,348     $ 105,519     $ (9,683 )
     
     
     
 
Basic Earnings (Loss) Per Share
                       
 
Income (loss) before accounting changes
  $ 0.78     $ 2.02     $ (0.20 )
 
Cumulative effect of accounting changes, net of taxes
    (0.19 )            
     
     
     
 
   
Net income (loss)
  $ 0.59     $ 2.02     $ (0.20 )