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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, 2004
 
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.     Yes þ
      Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act)     Yes þ          No o
      Aggregate market value of the voting stock held by non-affiliates of the Registrant, calculated using the closing price on June 30, 2004: Common Stock, par value $0.01 per share, $2,777.9 million.
      Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 28, 2005: Common Stock, par value $0.01 per share, 65,327,329 shares outstanding, or 130,654,658 shares outstanding after giving retroactive effect to the registrant’s two-for-one stock split, effective March 30, 2005 for shareholders of record on March 16, 2005.
DOCUMENTS INCORPORATED BY REFERENCE
      Portions of the Peabody Energy Corporation (the “Company”) Annual Report for the year ended December 31, 2004 are incorporated by reference into Part II hereof. Portions of the Company’s Proxy Statement to be filed with the SEC in connection with the Company’s Annual Meeting of Stockholders to be held on May 6, 2005 (the “Company’s 2005 Proxy Statement”) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.
 
 


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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, including, without limitation, such statements in the section captioned “Outlook.” We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “will” or other similar words to identify forward-looking statements.
      Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks, and actual results may differ materially from those discussed in these statements.
      Among the factors that could cause actual results to differ materially are:
  •  growth of domestic and international coal and power markets;
 
  •  coal’s market share of electricity generation;
 
  •  future worldwide economic conditions;
 
  •  weather;
 
  •  transportation performance and costs, including demurrage;
 
  •  ability to renew sales contracts;
 
  •  successful implementation of business strategies;
 
  •  regulatory and court decisions;
 
  •  future legislation;
 
  •  changes in postretirement benefit and pension obligations;
 
  •  labor relations and availability;
 
  •  availability and costs of credit, surety bonds and letters of credit;
 
  •  the effects of changes in currency exchange rates;
 
  •  price volatility and demand, particularly in higher-margin products;
 
  •  risks associated with customers;
 
  •  reductions of purchases by major customers;
 
  •  geology and equipment risks inherent to mining;
 
  •  terrorist attacks or threats;
 
  •  performance of contractors or third party coal suppliers;
 
  •  replacement of reserves;
 
  •  implementation of new accounting standards;
 
  •  inflationary trends, including those impacting materials used in our business;
 
  •  the effects of interest rate changes;
 
  •  the effects of acquisitions or divestitures;
 
  •  changes to 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 Relating 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 document 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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TABLE OF CONTENTS
             
        Page
         
 PART I.
   Business     2  
   Properties     25  
   Legal Proceedings     30  
   Submission of Matters to a Vote of Security Holders     34  
     Executive Officers of the Company     34  
 PART II.
   Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     36  
   Selected Financial Data     37  
   Management’s Discussion and Analysis of Financial Condition and Results of Operations     40  
   Quantitative and Qualitative Disclosures About Market Risk     65  
   Financial Statements and Supplementary Data     67  
   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     67  
   Controls and Procedures     67  
   Other Information     72  
 PART III.
   Directors and Executive Officers of the Registrant     72  
   Executive Compensation     72  
   Security Ownership of Certain Beneficial Owners and Management     72  
   Certain Relationships and Related Transactions     72  
   Principal Accounting Fees and Services     72  
 PART IV.
   Exhibits, Financial Statement Schedules     73  
 Amended and Restated By-Laws
 6 7/8% Senior Notes Indenture
 5 7/8% Senior Notes
 Amendment No.3 to Second Amended & Restated Credit Agreement
 First Amendment to Deferred Compensation Plan
 Portions of Annual Report to Stockholders
 List of Subsidiaries
 Consent of Ernst & Young LLP
 Section 302 Certification
 Section 302 Certification
 Section 906 Certification
 Section 906 Certification

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Notes:  The words “we,” “our,” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries.
  On March 2, 2005, we announced a two-for-one stock split on all shares of our common stock payable to shareholders of record at the close of business on March 16, 2005. The additional shares will be distributed on March 30, 2005. All share and per share amounts in this Annual Report on Form 10-K reflect the stock split.
PART I
Item 1. Business.
Overview
      We are the largest private-sector coal company in the world. During the year ended December 31, 2004, we sold 227.2 million tons of coal. During this period, we sold coal to over 300 electricity generating and industrial plants in 16 countries. Our coal products fuel more than 10% of all U.S. electricity generation and 3% of worldwide electricity generation. At December 31, 2004, we had 9.3 billion tons of proven and probable coal reserves. The 9.3 billion tons of proven and probable coal reserves did not include approximately 300 million tons (based on Bureau of Land Management estimates) of Powder River Basin reserves we recently gained control of through a successful Federal Coal Lease bid.
      We own, through our subsidiaries, majority interests in 32 coal operations located throughout all major U.S. coal producing regions and in Australia. Additionally, we own interests in four mines through joint venture arrangements. We shipped 73% of our U.S. mining operations’ coal sales from the western United States during the year ended December 31, 2004 and the remaining 27% from the eastern United States. Most of our production in the western United States is low-sulfur coal from the Powder River Basin. Our overall western U.S. coal production has increased from 37.0 million tons in fiscal year 1990 to 142.6 million tons during 2004, representing a compounded annual growth rate of 10%. In the West, we own and operate mines in Arizona, Colorado, New Mexico and Wyoming. In the East, we own and operate mines in Illinois, Indiana, Kentucky and West Virginia. We own 4 mines in Queensland, Australia, one of which was acquired in 2002, two were acquired during April 2004 and a fourth that was opened after the 2004 acquisition. Most of our Australian production is low-sulfur, metallurgical coal. We generated 79% of our production for the year ended December 31, 2004 from non-union mines.
      For the year ended December 31, 2004, 90% of our sales were to U.S. electricity generators, 7% were to customers outside the United States and 3% were to the U.S. industrial sector. Approximately 90% of our coal sales during the year ended December 31, 2004 were under long-term (one year or greater) contracts. Our sales backlog, including backlog subject to price reopener and/or extension provisions, was over one billion tons as of December 31, 2004. The average volume weighted remaining term of our long-term contracts was approximately 3.4 years, with remaining terms ranging from one to 17 years. As of December 31, 2004, we had 5 to 10 million tons, 65 to 75 million tons and 130 to 140 million tons for 2005, 2006 and 2007, respectively, of expected production (including steam and metallurgical coal production) available for sale or repricing at market prices. We have an annual metallurgical coal production capacity of 12 to 14 million tons. Approximately 90% of our expected 2005 metallurgical coal production is priced, and our 2006 metallurgical production is mostly unpriced. The portion of 2006 that is priced primarily relates to tonnage committed at our Australian operations for delivery in the period from April 1, 2005 to March 31, 2006, the traditional contract year for many customers purchasing seaborne metallurgical coal. The metallurgical production we priced for 2005 and 2006 is priced, on average, at levels significantly above historical metallurgical coal prices.
      In addition to our mining operations, we market, broker and trade coal. Our total tons traded were 33.4 million for the year ended December 31, 2004. Our other energy related businesses include the development of mine-mouth coal-fueled generating plants, the management of our vast coal reserve and real estate holdings, coalbed methane production and transportation services.

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History
      Peabody, Daniels and Co. was founded in 1883 as a retail coal supplier, entering the mining business in 1888 as Peabody & Co. with the opening of our first coal mine in Illinois. In 1926, Peabody Coal Company was listed on the Chicago Stock Exchange and, beginning in 1949, on the New York Stock Exchange.
      In 1955, Peabody Coal Company, primarily an underground mine operator, merged with Sinclair Coal Company, a major surface mining company. Peabody Coal Company was acquired by Kennecott Copper Company in 1968. The company was then sold to Peabody Holding Company in 1977, which was formed by a consortium of companies.
      During the 1980s, Peabody grew through expansion and acquisition, opening the North Antelope Mine in Wyoming’s coal-rich Powder River Basin in 1983 and the Rochelle Mine in 1985, and completing the acquisitions of the West Virginia coal properties of ARMCO Steel and Eastern Associated Coal Corp., which included seven operating mines and substantial low-sulfur coal reserves in West Virginia.
      In July 1990, Hanson, PLC acquired Peabody Holding Company. In the 1990’s, Peabody continued to grow through expansion and acquisitions. In February 1997, Hanson spun off its energy-related businesses, including Eastern Group and Peabody Holding Company, into The Energy Group, plc. The Energy Group was a publicly traded company in the United Kingdom and its American Depository Receipts (ADR’s) were publicly traded on the New York Stock Exchange.
      In May 1998, Lehman Brothers Merchant Banking Partners II L.P. and affiliates (“Merchant Banking Fund”), an affiliate of Lehman Brothers Inc. (“Lehman Brothers”), purchased Peabody Holding Company and its affiliates, Peabody Resources Limited and Citizens Power LLC in a leveraged buyout transaction that coincided with the purchase by Texas Utilities of the remainder of The Energy Group.
      In August 2000, Citizens Power, our subsidiary that marketed and traded electric power and energy-related commodity risk management products, was sold to Edison Mission Energy.
      In January 2001, we sold our Peabody Resources Limited (in Australia) operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto Limited for $575 million (including debt assumed by the buyer).
      In April 2001, we changed our name to Peabody Energy Corporation (“Peabody”), reflecting our position as a premier energy supplier. In May 2001, after having reduced the debt incurred in the leveraged buyout by more than $1 billion, we completed an initial public offering of common stock, and the Company’s shares began trading on the New York Stock Exchange under the ticker symbol “BTU,” the globally recognized symbol for energy.
      In April 2004, we acquired three coal operations from RAG Coal International AG for a combined purchase price of $421 million, net of cash received in the transaction. The purchase included two mines in Queensland, Australia that produce a combined 7 to 8 million tons per year of metallurgical coal, and the Twentymile Mine in Colorado, which historically produced 7 to 8 million tons per year of low-sulfur, steam coal. In December 2004, we completed the purchase of a 25.5% equity interest in Carbones del Guasare, S.A. from RAG Coal International AG for a net purchase price of $32.5 million. Carbones del Guasare, a joint venture that also includes Anglo American plc and a Venezuelan governmental partner, operates the Paso Diablo surface mine in northwestern Venezuela, which produces approximately 7 million tons per year of coal for electricity generators and steel producers.
      From 1990 to 2004, Peabody redefined its business, as the company transformed itself into a more productive, low-cost, low-sulfur energy company, tripling its productivity and reducing costs 32% while improving safety performance 74%. In the 1990’s, we established our three core strategies: 1) managing safe, low-cost operations; 2) utilizing world-class sales and trading practices; and 3) creating value from our natural resource position.

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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. The maps below show the mines we operated in 2004.
(MINING OPERATIONS)
      Within the United States, we conduct operations in the Powder River Basin, Southwest, Colorado, Appalachia and Midwest regions. Internationally, we operate mines in Queensland, Australia and have a 25.5% interest in a mine in Venezuela. All of our operating segments are discussed in Note 26 to our consolidated financial statements.
      Included in the descriptions of our mining operations are discussions of the subsidiaries which manage the respective mining operation. The subsidiary that manages a particular mining operation is not necessarily indicative of the subsidiary or subsidiaries which own the assets utilized in that mining operation.
Powder River Basin Operations
      We control approximately 3.1 billion tons of proven and probable coal reserves in the Southern Powder River Basin, the largest and fastest growing major U.S. coal-producing region. Our subsidiaries, Powder River Coal Company and Caballo Coal Company, manage three low-sulfur, non-union surface mining complexes in Wyoming that sold 115.8 million tons of coal during the year ended December 31, 2004, or approximately 51% of our total coal sales volume. The North Antelope Rochelle and Caballo

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mines are serviced by both major western railroads, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway.
      Our Wyoming Powder River Basin reserves are classified as surface mineable, subbituminous coal with seam thickness varying from 70 to 105 feet. The sulfur content of the coal in current production ranges from 0.2% to 0.4% and the heat value ranges from 8,300 to 9,000 Btu’s per pound.
North Antelope Rochelle Mine
      The North Antelope Rochelle Mine is located 65 miles south of Gillette, Wyoming. This mine is one of the largest in North America, selling 82.5 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu) during 2004. The North Antelope Rochelle facility is capable of loading its production in up to 2,000 railcars per day. The North Antelope Rochelle Mine produces premium quality coal with a sulfur content averaging 0.2% and a heat value ranging from 8,500 to 8,900 Btu per pound. The North Antelope Rochelle Mine produces the lowest sulfur coal in the United States, using two draglines along with six truck-and-shovel fleets.
Caballo Mine
      The Caballo Mine is located 20 miles south of Gillette, Wyoming. During 2004, it sold 26.5 million tons of compliance coal. Caballo is a truck-and-shovel operation with a coal handling system that includes two 12,000-ton silos and two 11,000-ton silos.
Rawhide Mine
      The Rawhide Mine is located ten miles north of Gillette, Wyoming and uses truck-and-shovel mining methods. During 2004, it sold 6.9 million tons of compliance coal.
Southwest Operations
      We own and operate three mines in our Southwest operations — two in Arizona and one in New Mexico. The Arizona mines, which are managed by our Peabody Western Coal Company subsidiary, supply primarily bituminous compliance coal under long-term coal supply agreements to electricity generating stations in the region. In New Mexico, we own and manage, through our Peabody Natural Resources Company subsidiary, the Lee Ranch Mine, which mines and produces subbituminous medium sulfur coal. Together, these three mines sold 18.7 million tons of coal during 2004 and control 1.0 billion of proven and probable coal reserves.
Black Mesa Mine
      The Black Mesa Mine, which is located on the reservations of the Navajo Nation and Hopi Tribe in Arizona, uses two draglines and sold 4.7 million tons of coal during 2004. The Black Mesa Mine coal is crushed, mixed with water and then transported 273 miles through an underground pipeline owned by a third party. The coal is conveyed to the Mohave Generating Station near Laughlin, Nevada, which is operated and partially owned by Southern California Edison. The mine and pipeline were designed to deliver coal exclusively to the plant, which has no other source of coal. The Mohave Generating Station coal supply agreement extends until December 31, 2005. Further discussion of the issues surrounding the future of the Black Mesa Mine and Mohave Generating Station is provided in Item 3. Legal Proceedings of this report. Hourly workers at this mine are members of the United Mine Workers of America.
Kayenta Mine
      The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines in three mining areas. It sold approximately 8.4 million tons of coal during 2004. The Kayenta Mine coal is crushed, then carried 17 miles by conveyor belt to storage silos where it is loaded onto a private rail line and transported 83 miles to the Navajo Generating Station, operated by the Salt River Project near Page, Arizona. The

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mine and railroad were designed to deliver coal exclusively to the power plant, which has no other source of coal. The Navajo coal supply agreement extends until 2011. Hourly workers at this mine are members of the United Mine Workers of America.
Lee Ranch Mine
      The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 5.6 million tons of medium sulfur coal during 2004. Lee Ranch shipped the majority of its coal to two customers in Arizona and New Mexico under coal supply agreements extending until 2020 and 2014, respectively. Lee Ranch is a non-union surface mine that uses a combination of dragline and truck-and-shovel mining techniques and ships coal to its customers via the Burlington Northern Santa Fe Railway.
Colorado Operations
      We control approximately 0.3 billion tons of coal reserves and currently have two mines operating in the Colorado Region. Our Twentymile underground mine is managed by our Twentymile Coal Company subsidiary and our Seneca surface mine is managed by our Seneca Coal Company subsidiary. During 2004, these operations sold approximately 7.6 million tons of compliance, low-sulfur, steam coal of above average heat content to customers throughout the United States.
Twentymile Mine
      On April 15, 2004, we purchased the Twentymile Mine from RAG Coal International AG as discussed in Note 5 to our consolidated financial statements. The Twentymile Mine is located in Routt County, Colorado, and sold approximately 6.2 million tons of steam coal since the acquisition. This mine uses both longwall and continuous mining equipment and has perennially been one of the largest and most productive underground mines in the United States. The coal quality is high enough that only a small portion of the coal is washed, normally less than 15%. Approximately 95% all coal shipped is loaded on the Union Pacific railroad; the remainder is hauled by truck.
Seneca Mine
      The Seneca Mine near Hayden, Colorado shipped 1.5 million tons of compliance coal during 2004, operating with two draglines and a highwall miner in three separate mining areas. The mine’s coal is hauled by truck to the nearby Hayden Generating Station, operated by the Public Service of Colorado, under a coal supply agreement that extends until 2011. This mine is near the exhaustion of its economically recoverable reserves and upon closure (expected in late 2005) the Twentymile Mine is expected to supply the Hayden Generating Station. The mine’s closure is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. Hourly workers at Seneca are members of the United Mine Workers of America.
Appalachia Operations
      We manage five wholly-owned business units and related facilities in West Virginia and one in Western Kentucky. Our subsidiary, Pine Ridge Coal Company, manages the Big Mountain business unit, and our subsidiary, Rivers Edge Mining, Inc. manages our Rivers Edge Mine. Our Eastern Associated Coal Corp. subsidiary manages the remaining wholly-owned West Virginia facilities. In addition, Highland Mining manages the Highland Mine in Western Kentucky. During 2004, these operations sold approximately 19.2 million tons of compliance, medium-sulfur, high-sulfur steam and metallurgical coal to customers in the United States and abroad. Metallurgical coal accounted for 5.0 million tons of total sales for the year. All of the hourly workers at these subsidiaries are members of the United Mine Workers of America. In addition to our wholly-owned facilities, we own a 49% interest in Kanawha Eagle Mine, a joint venture which owns and manages underground mining operations. We control approximately 0.8 billion tons of proven and probable coal reserves in our Appalachia Operations.

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Big Mountain Business Unit and Contract Mines
      The Big Mountain business unit is based near Prenter, West Virginia. This business unit’s primary mine is Big Mountain No. 16, and includes a small amount of contract mine production from coal reserves we control. During 2004, the Big Mountain business unit sold approximately 1.9 million tons of steam coal. Big Mountain No. 16 is an underground mine using continuous mining equipment. Processed coal is loaded on the CSX railroad.
Harris Business Unit
      The Harris business unit consists of the Harris No. 1 Mine near Bald Knob, West Virginia, which sold approximately 3.1 million tons of primarily metallurgical product during 2004. This mine uses both longwall and continuous mining equipment.
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 2.0 million tons of steam and metallurgical coal sourced from the contract mines during 2004. Processed coal is loaded at the plant site on the CSX railroad or transferred via conveyor to our Kopperston loadout facility and loaded on the Norfolk Southern railroad.
Wells Business Unit and Contract Mines
      The Wells business unit, in Boone County, West Virginia, sold approximately 4.0 million tons of metallurgical and steam coal during 2004. The unit consists of the Wells preparation plant, which processes purchased coal and production from our River’s Edge Mine and contract mines. The preparation plant is located near Wharton, West Virginia and the processed coal is loaded on the CSX railroad.
Federal No. 2 Mine
      The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining methods and shipped approximately 4.8 million tons of steam coal during 2004. Coal shipped from the Federal No. 2 Mine has a sulfur content only slightly above that of medium sulfur coal and has above average heating content. As a result, it is more marketable than some other medium sulfur coals. The CSX and Norfolk Southern railroads jointly serve the mine.
Highland Business Unit
      The Highland No. 9 Mine, which is managed by our Highland Mining Company subsidiary, is located near Waverly, Kentucky, and produced 3.3 million tons during 2004. Hourly workers at these operations are members of the United Mine Workers of America.
Kanawha Eagle Coal Joint Venture
      We have a 49% interest in the Kanawha Eagle Joint Venture, which owns and manages underground mining operations, a preparation plant and barge-and-rail loading facilities near Marmet, West Virginia. The mines are non-union and use continuous mining equipment. They shipped 2.5 million tons during 2004.
Midwest Operations
      Our Midwest operations consist of 13 wholly-owned mines in the Illinois basin and are comprised of our Patriot Coal Company, Indian Hill Company and Black Beauty Coal Company subsidiaries. Our Midwest Operations control approximately 3.8 billion tons of proven and probable coal reserves. In 2004, these operations collectively sold 32.5 million tons of coal, more than any other midwestern coal producer.

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We ship coal from these mines primarily to electricity generators in the Midwestern United States, and to industrial customers that generate their own power.
Patriot Coal Company
      Patriot Coal Company, owns and manages three mines. Patriot, a surface mine, and Freedom, an underground mine, are located in Henderson County, Kentucky. The Big Run underground mine is located in Ohio County, Kentucky. These mines sold 1.4 million tons, 1.5 million tons and 1.3 million tons, respectively, in 2004. The underground mines use continuous mining equipment and the surface mine uses truck and shovel equipment. Patriot Coal Company also manages a preparation plant and a dock. Patriot Coal Company operations utilize a non-union workforce.
Indian Hill Company
      In late 2004, we purchased, through our wholly-owned subsidiary, Indian Hill Company, the remaining 55% interest of Dodge Hill Holding JV, LLC. Dodge Hill Holding manages Dodge Hill No. 1, an underground operation located in Union County, Kentucky which mined 1.2 million tons in 2004 utilizing non-union labor.
Black Beauty Coal Company
      Black Beauty Coal Company currently manages six mines in Indiana and three mines in Illinois. The Black Beauty mines produced and sold 27.1 million tons of compliance, medium sulfur and high sulfur steam coal during 2004.
      Black Beauty’s principal Indiana mines include Air Quality, Farmersburg, Francisco and Somerville. Air Quality is an underground coal mine located near Monroe City, Indiana that shipped 1.7 million tons of compliance coal during 2004. Farmersburg is a surface mine situated in Vigo and Sullivan counties in Indiana that sold 4.3 million tons of medium sulfur coal during 2004. The Francisco Mine, located in Gibson County, Indiana mines coal by utilizing both surface mining and underground mining methods and sold 3.1 million tons of medium sulfur coal during 2004. The Somerville mine complex, also located in Gibson County, shipped a total of 7.2 million tons of medium sulfur coal in 2004. Two other surface mines located in Indiana, Viking and Miller Creek, collectively shipped 2.3 million tons of medium sulfur coal during 2004.
      In east-central Illinois, Black Beauty’s Riola Complex is an underground mining facility with two active portals. The Riola Complex sold 2.3 million tons of medium sulfur coal during 2004. We operate the Cottage Grove surface mine and Willow Lake underground mining complex situated in Gallatin and Saline counties in southern Illinois. During 2004, these mines sold 2.7 million tons and 3.5 million tons, respectively, of medium sulfur coal that is primarily shipped by barge to downriver utility plants. Black Beauty provides a non-union contract workforce for the Arclar surface operation. The workforce at the Willow Lake underground mine is represented under a non-UMWA labor agreement that expires in late 2006. All other Black Beauty Coal Company operations utilize non-union labor.
      Black Beauty also owns a 75% interest in United Minerals Company, LLC (“United Minerals”). United Minerals, which utilizes non-union labor, currently acts as a contract miner for Black Beauty at part of the Somerville Mine Complex and as contract operator for Black Beauty at the Evansville River Terminal.
Australian Mining Operations
      We manage four mines in Queensland, Australia through our wholly-owned subsidiary, Peabody Pacific Pty Limited. In addition to our Wilkie Creek Mine acquired in August 2002, we purchased two coal mines, Burton and North Goonyella, on April 15, 2004 and recently opened our Eaglefield Mine, which is a surface operation adjacent to, and fulfilling contract tonnages in conjunction with, the North Goonyella underground mine. During 2004, these operations sold 6.1 million tons of coal, 4.4 millions tons

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of which were metallurgical coal. Coal from these mines is shipped via rail from the mine to the loading point at Dalrymple Bay, where the coal is loaded onto ocean-going vessels. All sales from our Australian mines are denominated in U.S. dollars. Our Australian mines operate with site-specific collective bargaining labor agreements. Our Australian operations control 0.2 billion tons of proven and probable reserves.
Wilkie Creek Mine
      Our Wilkie Creek Coal Mine is a surface, truck-and-shovel operation. For the year ended December 31, 2004, the mine’s contract workforce produced 1.3 million tons of steam coal, which was sold to the Asia export market.
Burton Mine
      Burton is a surface mine using the truck-and-shovel mining technique. From the date of acquisition in 2004, the Burton Mine sold 3.1 million tons of metallurgical coal. We own 95% of the Burton operation and the remaining five percent interest is owned by the contract miner operating on reserves that we control.
North Goonyella Mine
      The North Goonyella Mine is a longwall underground operation. From the date of acquisition in 2004, the North Goonyella Mine sold 1.7 million tons of coal.
Eaglefield Mine
      Our recently opened Eaglefield Mine is a surface operation utilizing truck-and-shovel mining methods. It is adjacent to, and fulfills contract tonnages in conjunction with, the North Goonyella underground mine. Coal is mined by a contractor from reserves that we control.
Venezuelan Mining Operations
      In December 2004, we acquired a 25.5% interest in Carbones del Guasare, S.A., a joint venture that includes Anglo American plc and a Venezuelan governmental partner. Carbones del Guasare operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine is a surface operation in northwestern Venezuela that produces approximately 7 million tons of steam coal annually for export primarily to the United States and Europe. We are responsible for our pro-rata share of sales from Paso Diablo; the joint venture is responsible for production, processing and transportation of coal to ocean-going vessels for delivery to customers.
Long-Term Coal Supply Agreements
      We currently have a sales backlog in excess of one billion tons of coal, including backlog subject to price reopener and/or extension provisions, and our coal supply agreements have remaining terms ranging from one to 17 years and an average volume-weighted remaining term of approximately 3.4 years. For 2004, we sold approximately 90% of our sales volume under long-term coal supply agreements. In 2004, we sold coal to over 300 electricity generating and industrial plants in 16 countries. Our primary customer base is in the United States, although customers in the Pacific Rim and other international locations represent an increasing portion of our revenue stream. Two of our largest coal supply agreements are the subject of ongoing litigation and arbitration, as discussed at Item 3. Legal Proceedings.
      We expect to continue selling a significant portion of our coal under long-term supply agreements. Our strategy is to selectively renew, or enter into new, long-term supply contracts when we can do so at prices we believe are favorable. As of December 31, 2004, we had 5 to 10 million tons, 65 to 75 million tons and 130 to 140 million tons for 2005, 2006 and 2007, respectively, of expected production (including steam and metallurgical coal production) available for sale or repricing at market prices. We have an

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annual metallurgical coal production capacity of 12 to 14 million tons. Approximately 90% of our expected 2005 metallurgical coal production is priced, and our 2006 metallurgical production is mostly unpriced. The portion of 2006 that is priced primarily relates to tonnage committed at our Australian operations for delivery in the period from April 1, 2005 to March 31, 2006, the traditional contract year for many customers purchasing seaborne metallurgical coal. The metallurgical production we priced for 2005 and 2006 is priced, on average, at levels significantly above historical metallurgical coal prices.
      Long-term contracts are attractive for regions where market prices are expected to remain stable, for cost-plus arrangements serving captive electricity generating plants and for the sale of high-sulfur coal to “scrubbed” generating plants. To the extent we do not renew or replace expiring long-term coal supply agreements, our future sales will be subject to market fluctuations, including unexpected downturns in market prices.
      Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices, while we seek stable sources of revenue to support the investments required to open, expand and maintain or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure, and termination and assignment provisions.
      Each contract sets a base price. Some contracts provide for a predetermined adjustment to base price at times specified in the agreement. Base prices may also be adjusted quarterly, annually or at other periodic intervals for changes in production costs and/or changes due to inflation or deflation. Changes in production costs may be measured by defined formulas that may include actual cost experience at the mine as part of the formula. The inflation/deflation adjustments are measured by public indices, the most common of which is the implicit price deflator for the gross domestic product as published by the U.S. Department of Commerce. In most cases, the components of the base price represented by taxes, fees and royalties which are based on a percentage of the selling price are also adjusted for any changes in the base price and passed through to the customer. Some contracts allow the base price to be adjusted to reflect the cost of capital.
      Most contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that impact our cost of performance of the agreement. Additionally, some contracts contain provisions that allow for the recovery of costs impacted by the modifications or changes in the interpretation or application of any existing statute by local, state or federal government authorities. Some agreements provide that if the parties fail to agree on a price adjustment caused by cost increases due to changes in applicable laws and regulations, the purchaser may terminate the agreement.
      Price reopener provisions are present in many of our multi-year coal contracts. These provisions may allow either party to commence a renegotiation of the contract price at various intervals. In a limited number of agreements, if the parties do not agree on a new price, the purchaser or seller has an option to terminate the contract. Under some contracts, we have the right to match lower prices offered to our customers by other suppliers.
      Quality and volumes for the coal are stipulated in coal supply agreements, and in some limited instances buyers have the option to vary annual or monthly volumes if necessary. Variations to the quality and volumes of coal may lead to adjustments in the contract price. Most coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat (Btu), sulfur, and ash content, grindability and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Coal supply agreements typically stipulate procedures for quality control, sampling and weighing. In the eastern United States, approximately half of our customers require that the coal is sampled and weighed at the destination, whereas in the western United States, samples and weights are usually taken at the shipping source.

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      Contract provisions in some cases set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions or serious transportation problems that affect the seller or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement. Buyers often negotiate similar clauses covering changes in environmental laws. We often negotiate the right to supply coal that complies with a new environmental requirement to avoid contract termination. Coal supply agreements typically contain termination clauses if either party fails to comply with the terms and conditions of the contract, although most termination provisions provide the opportunity to cure defaults.
      In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines, including third party production, as long as the replacement coal meets the contracted quality specifications and will be sold at the same delivered cost.
Sales and Marketing
      Our sales, trading, brokerage and marketing operations include COALSALES, LLC; COALSALES II, LLC (formerly Peabody COALSALES Company); COALTRADE, LLC (formerly Peabody COALTRADE, Inc.) and COALTRADE International, LLC. Through our sales, trading, brokerage and marketing, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and agent, trade coal and emission allowances, and provide transportation-related services. As of December 31, 2004, we had 74 employees in our sales, trading, brokerage, marketing and transportation operations, including personnel dedicated to performing market research, contract administration and risk/credit management activities. These operations also include seven employees at our COALTRADE Australia operation, which brokers coal in the Australia and Pacific Rim markets, and is based in Newcastle, Australia.
Transportation
      Coal consumed domestically is usually sold at the mine, and transportation costs are borne by the purchaser. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port, including any demurrage costs.
      The majority of our sales volume is shipped by rail, but a portion of our production is shipped by other modes of transportation, including barge and ocean-going vessels. Our transportation department manages the loading of trains and barges.
      Coal from our Black Mesa Mine in Arizona is transported by a 273-mile coal-water pipeline to the Mohave Generating Station in southern Nevada. Coal from the Seneca Mine in Colorado is transported by truck to the nearby Hayden Plant. All coal from our southern Powder River Basin mines in Wyoming is shipped by rail, and two competing railroads, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad, serve our North Antelope Rochelle and Caballo mines. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway. Approximately 12,000 unit trains are loaded each year to accommodate the coal shipped by our mines overall. A unit train generally consists of 100 to 150 cars, each of which can hold 100 to 120 tons of coal. We believe we enjoy good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators.
Suppliers
      The main types of goods we purchase are mining equipment and replacement parts, explosives, fuel, tires, steel-related products and lubricants. We have many long, established relationships with our key suppliers, and do not believe that we are dependent on any of our individual suppliers, except as noted below. The supplier base providing mining materials has been relatively consistent in recent years, although there has been some consolidation. Recent consolidation of suppliers of explosives has limited the number of sources for these materials. Although our current supply of explosives is concentrated with one supplier, alternative sources are available to us in the regions where we operate. Further, purchases of certain

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underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop. In the past year, demand for certain surface and underground mining equipment and off-the-road tires has increased. As a result, lead times for certain items have generally increased by up to several months, although no material impact is currently expected to our financial condition, results of operations or cash flows.
Technical Innovation
      We continue to place great emphasis on the application of technical innovation to improve new and existing equipment performance. This research and development effort is typically undertaken and funded by equipment manufacturers using our input and expertise. Our engineering, maintenance and purchasing personnel work together with manufacturers to design and produce equipment that we believe will add value to the business.
      A major effort has been under way to improve the performance of our draglines which move a third of the billion tons of overburden handled annually. The dragline improvement effort includes more efficient bucket design, faster cycle times, improved swing motion controls to increase component life and better monitors to enable increased payloads. A new digital drive design has been tested on an overburden shovel in the Powder River Basin with excellent results and will be installed on our other shovels. Blasting performance has improved through the use of new products including digital detonation, air decking, blast-hole sleeving and new blasting agents. Filtered used lubrication oils are also utilized in our blasting products.
      We plan to install a longwall system at our Twentymile Mine with state-of-the-art controls and software to enable increased mine output beginning in 2006. In addition, the North Goonyella Mine in Australia has purchased upgraded longwall components to widen the longwall face and improve operating performance. We have two state-of-the-art flexible coal train conveyor systems in operation at our Highland Mine that continuously transport coal from the continuous miner to the conveyor belt system. Upgrades at four preparation plants are scheduled in 2005 which will improve coal recovery and output.
      World-class maintenance standards based on condition-based maintenance practices are being implemented at all operations. Using these techniques allows us to increase equipment utilization and reduce capital through extending the equipment life while minimizing the risk of premature failures. Lubrication is replaced and work is scheduled on condition rather than time. Benefits from sophisticated lubrication analysis and quality control include lower lubrication consumption, optimum equipment performance and extended component life. We are upgrading our computerized maintenance management system to support our maintenance practices. Also, a remote data acquisition system is being installed to more efficiently dispatch mobile equipment and monitor equipment performance on a real-time basis.
      Our mines use sophisticated software to schedule and monitor trains, mine and pit blending, quality and customer shipments. The integrated software has been developed in-house and provides a competitive tool to differentiate our reliability and product consistency. We are the largest user of advanced coal quality analyzers among coal producers, according to the manufacturer of this sophisticated equipment. These analyzers allow continuous analysis of certain coal quality parameters, such as sulfur content. Their use helps ensure consistent product quality and helps customers meet stringent air emission requirements.
      We also support the Power Systems Development Facility, a highly efficient electricity generating plant using coal gasification generation technology, funded primarily through the U.S. Department of Energy and operated by an affiliate of Southern Company. Peabody is a member of the multi-company alliance working with the Department of Energy on FutureGen, a long-term project to develop near-zero emission power generation technology that will produce both power and hydrogen from coal and will capture and sequester carbon dioxide.

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Competition
      The markets in which we sell our coal are highly competitive. According to the National Mining Association’s “2003 Coal Producer Survey,” the top 10 coal companies in the United States produced approximately 69% of total domestic coal in 2003. Our principal U.S. competitors are other large coal producers, including Kennecott Energy Company, Arch Coal, Inc., Foundation Coal, CONSOL Energy Inc. and Massey Energy Company, which collectively accounted for approximately 41% of total U.S. coal production in 2003. Major international competitors include Rio Tinto, Anglo-American PLC, and BHP Billiton.
      A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on the coal consumption patterns of the electricity and steel industries in the United States, China, India and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear and hydroelectric. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations and technological developments. We compete on the basis of coal quality, delivered price, customer service and support and reliability.
Generation Development
      To best maximize our coal assets and land holdings for long-term growth, we are developing coal-fueled generating projects in areas of the country where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal.
      We are continuing to progress on the permitting processes, transmission access agreements and contractor-related activities for developing clean, low-cost mine-mouth generating plants using our surface lands and coal reserves. Because coal costs just a fraction of natural gas, mine-mouth generating plants can provide low-cost electricity to satisfy growing baseload generation demand. The plants will be designed to comply with all current clean air standards using advanced emissions control technologies.
      The plants described below are expected to be operational following a four-year construction phase, which is conditioned upon the company completing all necessary permitting, selection of partners, securing financing and selling the majority of the output of the plant. These plants will not be operational until at least 2010.
Prairie State Energy Campus
      Our Prairie State Energy Campus is a planned 1,500-megawatt coal-fueled electricity generation project located in Washington County, Illinois. Prairie State would be fueled by 6 million tons of coal each year produced from an adjacent underground mine. During August of 2004, Prairie State signed a letter of intent with Fluor Daniel Illinois, Inc. for engineering, design and construction of Prairie State’s power-related facilities. In January 2005, Prairie State achieved a major milestone when the State of Illinois issued the final air permit for the electric generating station and adjoining coal mine. In February 2005, a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire approximately 47% of the project. This group of investors is comprised of Soyland Power Cooperative, Inc, Kentucky Municipal Power Agency, Wolverine Power Cooperative, Northern Illinois Municipal Power Agency, Indiana Municipal Power Agency and the Missouri Joint Municipal Electric Utility Commission. In February 2005, certain parties filed an appeal with the Environmental Appeals Board in Washington, D.C. challenging the air permit issued by the Illinois Environmental Protection Agency. The appeal must be resolved before construction of the project can begin.
Thoroughbred Energy Campus
      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

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from the Commonwealth of Kentucky. We and the Commonwealth of Kentucky are defending the air permit granted in 2002 to Thoroughbred Energy Campus, as certain environmental groups are challenging the air permit. Hearings and final briefings were completed before year end and we now await the findings of the Administrative Law Judge.
Mustang Energy Project
      In October 2004, our Mustang Energy Project was awarded a $19.7 million Clean Coal Power Initiative grant from the Department of Energy to demonstrate technology to achieve ultra-low emissions at the proposed 300 megawatt generating station near Grants, New Mexico. The project is in the early stages of obtaining all necessary permits. If successfully completed, the Mustang Energy project would be located near our Lee Ranch Coal Company operations using lands and coal reserves controlled by us. The plant would be fueled by about 1 million tons of coal each year. The plant is expected to use proprietary technology to remove 99.5% of sulfur dioxide, 98% of nitrogen oxide and 90% of mercury from the plant’s emissions. By-products from the scrubbing process would be used to create high value, granular fertilizer.
Coalbed Methane
      We continue to evaluate the potential of the coalbed methane business and will make acquisitions, develop our properties, enter into partnerships with other companies or make property sales as appropriate. Our subsidiary, Peabody Natural Gas, LLC, produces coalbed methane from its operations in the Southern Powder River Basin near the Caballo Mine and North Antelope Rochelle Mine. At December 31, 2004, we operated 60 coalbed methane wells with net production of approximately 2.4 million cubic feet per day. We are also evaluating the coalbed methane resources in several deep coal seams on more than 27,000 acres in the Western Powder River Basin near Buffalo, Wyoming. We purchased these coalbed methane assets in January 2001 and are engaged in an ongoing drilling and testing program to continue to evaluate the property. In Southern Illinois, Peabody Natural Gas is continuing a five-well coalbed methane pilot program at its Broughton project. More than 15,000 net coal acres and coalbed methane leases covering property near the Broughton project were purchased in December 2003 and have been added to the project. In June 2004, we purchased operating rights and a 50% working interest in a five-well coalbed methane pilot program on over 9,400 acres in Gallatin County, Illinois. The test program is being conducted with AFS Development Company, LLC, an affiliate of Ameren Corporation. A coalbed methane testing program is also being conducted in Western Kentucky.
Certain Liabilities
      We have significant long-term liabilities for reclamation (also called asset retirement obligations), work-related injuries and illnesses, pensions and retiree health care. In addition, labor contracts with the United Mine Workers of America and voluntary arrangements with non-union employees include long-term benefits, notably health care coverage for retired and future retirees and their dependents. The majority of our existing liabilities relate to our past operations, which had more mines and employees than we currently have.
      Asset Retirement Obligations. Asset retirement obligations primarily represent the present value of future anticipated costs to restore surface lands to productivity levels equal to or greater than pre-mining conditions, as required by the Surface Mining Control and Reclamation Act. Our asset retirement obligations totaled approximately $396.0 million as of December 31, 2004. Expense for the years ended December 31, 2004, 2003 and 2002 was $42.4 million, $31.2 million and $11.0 million, respectively. Our method for accounting for reclamation activities changed on January 1, 2003 as a result of the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” The effect of the adoption of SFAS No. 143 is discussed in Note 6 to our consolidated financial statements. Total asset retirement obligations as of December 31, 2004 of $396.0 million consisted of $303.7 million related to locations with active mining operations and $92.3 million related to locations that are closed or inactive.

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      Workers’ Compensation. These liabilities represent the actuarial estimates for compensable, work-related injuries (traumatic claims) and occupational disease, primarily black lung disease (pneumoconiosis). The Federal Black Lung Benefits Act requires employers to pay black lung awards to former employees who filed claims after June 1973. These liabilities totaled approximately $268.9 million as of December 31, 2004, $41.4 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $59.2 million, $50.6 million and $55.4 million, respectively.
      Pension-Related Provisions. Pension-related costs represent the actuarially-estimated cost of pension benefits. Annual minimum contributions to the pension plans are determined by consulting actuaries based on the Employee Retirement Income Security Act minimum funding standards and an agreement with the Pension Benefit Guaranty Corporation. Pension-related liabilities totaled approximately $95.8 million as of December 31, 2004, $5.8 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $28.5 million, $20.7 million and $4.8 million, respectively.
      Retiree Health Care. Consistent with SFAS No. 106, we record a liability representing the estimated cost of providing retiree health care benefits to current retirees and active employees who will retire in the future. Provisions for active employees represent the amount recognized to date, based on their service to date; additional amounts are accrued periodically so that the total estimated liability is accrued when the employee retires.
      A second category of retiree health care obligations represents the liability for future contributions to certain multi-employer health funds. The United Mine Workers of America Combined Fund was created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of out of business companies who were receiving benefits as orphans prior to the 1992 law; no new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan also created by the same federal law in 1992 provides benefits to qualifying retired former employees of companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Fund was established through collective bargaining and provides benefits to qualifying retired former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business, however our liability is limited to our contractual commitment of $0.50 per hour worked.
      Our retiree health care liabilities totaled approximately $1,020.8 million as of December 31, 2004, $81.3 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $58.4 million, $83.6 million and $74.4 million, respectively. Obligations to the United Mine Workers of America Combined Fund totaled $39.8 million as of December 31, 2004, $6.4 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $4.9 million, $1.2 million and $16.7 million, respectively. The expense recorded during the year ended December 31, 2002 reflects the reassignment of certain beneficiaries to us as a result of an adverse U.S. Supreme Court decision in January 2003. Those beneficiaries had been deemed improperly assigned to us in a prior U.S. Circuit Court decision. The 1992 Fund and the 1993 Fund are expensed as payments are made and no liability was recorded other than amounts due and unpaid. Expense related to these funds was $4.4 million, $5.3 million and $4.1 million for the years ended December 31, 2004, 2003 and 2002 respectively.
Employees
      As of December 31, 2004, we and our subsidiaries had approximately 7,900 employees. As of December 31, 2004, approximately 60% of our hourly employees were non-union and they generated 79%

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of our 2004 coal production. Relations with our employees and, where applicable, organized labor are important to our success.
United States
      Approximately 63% of our U.S. miners are non-union and are employed in the states of Wyoming, Colorado, Indiana, New Mexico, Illinois and Kentucky. The United Mine Workers of America represented approximately 30% of our hourly employees, who generated 16% of our domestic production during the year ended December 31, 2004. An additional 6% of our hourly employees are represented by labor unions other than the United Mine Workers of America. These employees generated 2% of our production during the year ended December 31, 2004. Hourly workers at our mines in Arizona and one of our mines in Colorado are represented by the United Mine Workers of America under the Western Surface Agreement, which was ratified in 2000 and is effective through September 1, 2005. Our union labor east of the Mississippi River is primarily represented by the United Mine Workers of America and the majority of union mines are subject to the National Bituminous Coal Wage Agreement. The current five-year labor agreement was ratified in December 2001 and is effective through December 31, 2006.
Australia
      The Australian coal mining industry is highly unionized and the majority of workers employed at our Australian Mining Operations are members of trade unions. These employees are represented by three unions: the Construction Forestry Mining and Energy Union (“CFMEU”), which represents the production employees, and two unions that represent the other staff. Our Australian employees are approximately 4% of our entire workforce and generated 3% of our total production in the year ended December 31, 2004. The miners at Wilkie Creek operate under a labor agreement that expires in June 2006. The miners at Burton operate under a labor agreement that is currently under negotiation. The miners at North Goonyella operate under a labor agreement which expires in March 2008. The miners at Eaglefield operate under a labor agreement that expires in May 2007.
      The Australian Federal Government, as part of micro-economic reform, has long had a Workplace Relations Strategy that seeks structural reform to encourage an enterprise focus and to facilitate enterprise agreements. Further industrial reform is likely from July 1, 2005 when the Federal Government has control of both Houses of Parliament.
Regulatory Matters — United States
      Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment. These requirements could prove costly and time-consuming and could delay commencing or continuing exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, our activities may be more closely regulated. Such legislation and regulations, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.
      We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements,

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violations during mining operations occur from time to time in the industry. None of the violations to date or the monetary penalties assessed has been material.
Mine Safety and Health
      Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations.
      Most of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. While regulation has a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation.
      Our goal is to achieve excellent safety and health performance. We measure our success in this area primarily through the use of accident frequency rates. We believe that it is our responsibility to our employees to provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in establishing safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence. A portion of the annual performance incentives for our operating units is tied to their safety record.
Black Lung
      In the U.S., under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits by the federal government. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
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. Annual payments made by certain of our subsidiaries under the Coal Act totaled $19.3 million, $20.6 million and $11.1 million, respectively, during the years ended December 31, 2004, 2003 and 2002.
      In 1995, in a case filed by the National Coal Association on behalf of its members, a federal district court in Alabama ordered the Commissioner of Social Security to recalculate the per-beneficiary premium which the Combined Fund charges assigned operators. The Commissioner applied the recalculated, lower premium to all assigned operators, including our subsidiaries. As a result of separate litigation brought by the Combined Fund, a Washington, D.C. federal district court ruled on February 25, 2000 that the original, higher per beneficiary premium was proper and that decision was upheld on appeal. The Commissioner of Social Security issued a higher premium recalculation in 2003 to our subsidiaries and other coal companies. Other coal companies and our subsidiaries filed a lawsuit seeking a determination that the Commissioner’s 2003 premium recalculation was improper or not applicable to them and that lawsuit has been transferred to federal court in Maryland.

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      Our subsidiaries have been billed a retroactive assessment in the amount of $7.4 million for periods prior to October 1, 2003 as well as an increase of $0.7 million for the period from October 1, 2003 through September 30, 2004 as a result of the Social Security Administration’s premium recalculation. These amounts were paid as required by the Combined Fund Trustees, but were paid under protest. If the Combined Fund is able to obtain a court decision that would confirm the applicability of the higher premium rate to our subsidiaries, our subsidiaries will not be able to seek a refund of the premiums paid under protest. In that event, the prospective annual premium would also increase by approximately 12%.
      Additionally, the Trustees assessed our subsidiaries a $1.1 million contribution for the period October 1, 2003 through September 30, 2004 related to an estimated shortfall in the amount necessary to fund the required unassigned orphaned beneficiary premium. This amount was also paid in twelve monthly installments as required by the Combined Fund Trustees, but was paid under protest.
Environmental Laws
      We are subject to various federal, state and foreign environmental laws. Some of these laws, discussed below, place many requirements on our coal mining operations. Federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance.
Surface Mining Control and Reclamation Act
      In the U.S., the Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of U.S. surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under the act, the state becomes the regulatory authority. Except for Arizona, states in which we have active mining operations have achieved primary control of enforcement through federal authorization. In Arizona, we mine on tribal lands and are regulated by OSM because the tribes do not have SMCRA authorization.
      SMCRA permit provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation.
      The U.S. mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required of the OSM’s Applicant Violator System.
      Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including through intervention in the courts.
      Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation obligations. The Abandoned Mine Land Fund, which

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is part of SMCRA, requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund. The fee, which expired on September 30, 2004 and was subsequently extended to June 30, 2005, is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. It is expected the fee will be renewed, although its purpose and the amount per ton are still to be determined as part of the United States government’s budget process.
      SMCRA stipulates compliance with many other major environmental programs. These programs include the Clean Air Act; Clean Water Act; Resource Conservation and Recovery Act (“RCRA”); Comprehensive Environmental Response, Compensation, and Liability Acts (“CERCLA”) superfund and employee right-to-know provisions. Besides OSM, other Federal regulatory agencies are involved in monitoring or permitting specific aspects of mining operations. The U.S. Environmental Protection Agency (“EPA”) is the lead agency for States or Tribes with no authorized programs under the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers (“COE”) regulates activities affecting navigable waters and the U.S. Bureau of Alcohol, Tobacco and Firearms (“ATF”) regulates the use of explosive blasting.
      We do not believe there are any substantial matters that pose a risk to maintaining our existing mining permits or hinder our ability to acquire future mining permits. It is our policy to comply in all material respects with the requirements of the Surface Mining Control and Reclamation Act and the state and tribal laws and regulations governing mine reclamation.
Clean Air Act
      The Clean Air Act and the corresponding state laws that regulate the emissions of materials into the air, affect U.S. coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxide, mercury and other compounds emitted by coal-based electricity generating plants.
      Title IV of the Clean Air Act places limits on sulfur dioxide emissions from electric power generation plants. The limits set baseline emission standards for these facilities. Reductions in emissions occurred in Phase I in 1995 and in Phase II in 2000 and apply to all coal-based power plants. The affected electricity generators have been able to meet these requirements by, among other ways, switching to lower sulfur fuels, installing pollution control devices, such as flue gas desulfurization systems, which are known as “scrubbers,” reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Emission sources receive these sulfur dioxide emission allowances, which can be traded or sold to allow other units to emit higher levels of sulfur dioxide. Title IV also required that certain categories of coal-based electric generating stations install certain types of nitrogen oxide controls. We cannot accurately predict the effect of these provisions of the Clean Air Act on us in future years. At this time, we believe that implementation of Phase II has resulted in an upward pressure on the price of lower sulfur coals, as additional coal-based electricity generating plants have complied with the restrictions of Title IV.
      In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for very fine particulate matter and ozone. As a result, some states will be required to change their existing implementation plans to attain and maintain compliance with the new air quality standards. Our mining operations and electricity generating customers are likely to be directly affected when the revisions to the air quality standards are implemented by the states. State and federal regulations relating to implementation of the new air quality standards may restrict our ability to develop new mines or could require us to modify our existing operations.
      In December 2003, EPA proposed the Clean Air Interstate Rule, which is designed to help bring the eastern half of the United States into compliance with the National Ambient Air Quality Standards for fine particulates and ozone. The rule became final in March 2005 and will require further reduction of

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sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 28 states. The rules will reduce sulfur dioxide and nitrogen oxide emissions by approximately 70% from current levels by 2015.
      The Clean Air Act also requires electricity generators that currently are major sources of nitrogen oxide in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxide, which is a precursor of ozone. In addition, the EPA promulgated the final “NOx SIP Call” rules that would require coal-fueled power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions. These regulations became fully effective for these states in May 2004. Portions of two additional states will complete their NOX SIPs in 2005 as the final installment of the requirement. Installation of additional control measures required under the final rules will make it more costly to operate coal-based electricity generating plants.
      The Justice Department, on behalf of the EPA, has filed a number of lawsuits since November 1999, alleging that 12 electricity generators violated the new source review provisions of the Clean Air Act Amendments at power plants in the midwestern and southern United States. Six electricity generators have announced settlements with the Justice Department requiring the installation of additional control equipment on selected generating units, and at least one generator has received a favorable court decision. If the remaining electricity generators are found to be in violation, they could be subject to civil penalties and be required to install the required control equipment or cease operations. Our customers are among the named electricity generators and if found not to be in compliance, our customers could be required to install additional control equipment at the affected plants or they could decide to close some or all of those plants. If our customers decide to install additional pollution control equipment at the affected plants, we have the ability to supply coal from various regions to meet any new coal requirements.
      In October 2003, EPA promulgated new regulations clarifying the types of plant modifications that electric generators could make without triggering best available control technology requirements. These regulations could affect the pending new source review cases and whether additional cases are brought. Various parties filed an appeal of these regulations in the United States Court of Appeals for the D.C. Circuit. The Court issued a stay of these regulations pending a decision on the merits.
      The Clean Air Act set a national goal of the prevention of any future, and the remedying of any existing, impairment of visibility in 156 national parks and wilderness areas across the U.S. Under regulations issued by the EPA in 1999, states are required to consider setting a goal of restoring natural visibility conditions in Class I areas in their states by 2064 and to explain their reasons to the extent they determine not to adopt this goal. The state plans must require the application of “Best Available Retrofit Technology” (“BART”) after 2010 on certain electric generating stations reasonably anticipated to cause or contribute to regional haze which impairs visibility in these areas. The extent and nature of these BART requirements have been the subject of litigation, with EPA expected to issue new regulations in the Spring of 2005. Five western states have elected an option offered by EPA of regulating visibility-impairing emissions through a regional rather than a source-by-source approach. However, this option is currently the subject of litigation, with a court decision expected over the next several months. EPA’s regional haze regulations, once finalized, could cause our customers to install equipment to control sulfur dioxide and nitrogen oxide emissions. The requirement to install control equipment could affect the amount of coal supplied to those customers if they decide to switch to other sources of fuel to lower emission of sulfur dioxide and nitrogen oxide.
      EPA recently issued proposed regulations setting forth two alternative approaches for regulating mercury emissions from electric generating stations. Under one approach, mercury emissions would be reduced by about 30 percent by 2007 from current emission rates. Under the other approach, mercury emissions would be reduced in two stages in 2010 and 2018, with an emissions reduction of 70 percent by the latter year. Implementation of either of these or similar proposals could cause our customers to switch to other fuels to the extent it would be economically preferable for them to do so, and could impact the completion or success of our generation development projects.
      Legislation supported by the Administration has been introduced in Congress that would reduce emissions of sulfur dioxide, nitrogen oxide and mercury in phases, with reductions of 70 percent by 2018.

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Other similar emission reduction proposals have been introduced in Congress, some of which propose to also regulate carbon dioxide. No such legislation has passed either house of the Congress. If this type of legislation were enacted into law, it could impact the amount of coal supplied to those electricity generating customers if they decide to switch to other sources of fuel whose use would result in lower emission of sulfur dioxide, nitrogen oxide, mercury and carbon dioxide.
      A small number of states have either proposed or adopted legislation or regulations limiting emissions of sulfur dioxide, nitrogen oxide and mercury from electric generating stations. A smaller number of states have also proposed to limit emissions of carbon dioxide from electric generating stations. Limitations imposed by states on emissions of any of these four substances from electric generating stations could result in fuel switching by the generators if they determined it to be economically preferable to do so.
Clean Water Act
      The Clean Water Act of 1972 affects U.S. coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water.
      Section 404 under the Clean Water Act requires mining companies to obtain permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities.
      On October 23, 2003, several citizens groups sued the COE in the U.S. District Court for the Southern District of West Virginia seeking to invalidate a “nationwide” permit utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs seek to enjoin the prospective approval of these nationwide permits and to enjoin some coal operators from additional filling under existing nationwide permit approvals until they obtain more detailed “individual” permits. On July 8, 2004, the U.S. District Court ruled in favor of the citizens groups. The court found the COE’s procedure in authorizing projects under the nationwide permit process was in violation of the Clean Water Act. The court enjoined the COE from using nationwide permits in the Southern District of West Virginia. The District Court’s decision has been appealed to the Fourth Circuit Court of Appeals. We believe our existing operations will not be significantly impacted. However, permits for new mines and permit revisions for existing mines may experience additional permit requirements and potential delays in permit approvals.
      Total Maximum Daily Load (“TMDL”) regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, will be required to meet new TMDL effluent standards for these stream segments. The adoption of new TMDL effluent limitations for our coal mines could require more costly water treatment and could adversely affect our coal production.
      States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality/exceptional use.” These regulations would prohibit the diminution of water quality in these streams. Waters discharged from coal mines to high quality/exceptional use streams will be required to meet or exceed new high quality/exceptional use standards. The designation of high quality streams at our coal mines could require more costly water treatment and could aversely affect our coal production.
Resource Conservation and Recovery Act
      The Resource Conservation and Recovery Act (“RCRA”), which was enacted in 1976, affects U.S. coal mining operations by establishing requirements for the treatment, storage and disposal of hazardous wastes. Coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management.

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      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 U.S. coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. Under the EPA’s Toxic Release Inventory process, companies are required annually to report listed toxic materials that exceed defined quantities. We report chemicals used in water treatment and ash received for disposal from power generation customers.
Regulatory Matters — Australia
      The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control and noise planning issues such as approvals to expand existing mines or to develop new mines, and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory rehabilitation.
      Mining and exploration in Australia is generally carried on under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.
Native Title and Cultural Heritage
      Since 1992, the Australian courts have recognized that native title to lands, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the Federal Native Title Act (NTA) which recognizes and protects native title, and under which a national register of native title claims has been established.
      Native title rights do not extend to minerals however, native title rights can be affected by the mining process unless those rights have previously been extinguished. Native title rights can be extinguished either by a valid act of Government (as set out in the NTA) or by the loss of connection between the land and the group of Aboriginal peoples concerned.
      The NTA provides that where native title rights still exist and the mining project will affect those native title rights, it will be necessary to consult with the relevant Aboriginal group and to come to an agreement on issues such as the preservation of sacred or important sites, the employment of members of the group by the mine operator, and the payment of compensation for the effect on native title of the

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mining project. In the absence of agreement with the relevant Aboriginal group, there is an arbitration provision in the NTA.
      There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archeological sites.
      The NTA and laws protecting Aboriginal cultural heritage and archeological sites have had no impact on our current operations.
Environmental
      The federal system requires an approval to be obtained for any activity which will have a significant impact on a matter of national environmental significance. Matters of national environmental significance include listed endangered species, nuclear actions, World Heritage areas, National Heritage areas and migratory species. An application for such an approval may require public consultation and may be approved, refused or granted subject to conditions. Otherwise, responsibility for environmental regulation in Australia is primarily vested in the states.
      Each state and territory in Australia has its own environmental and planning regime for the development of mines. In addition, each state and territory also has a specific act dealing with mining in particular, regulating the granting of mining licenses and leases. The mining legislation in each state and territory operates concurrently with environmental and planning legislation. The mining legislation governs mining licenses and leases, including the restoration of land, following the completion of mining activities. Apart from the grant of rights to mine itself (which are covered by the mining statutes), all licensing, permitting, consent and approval requirements are contained in the various state and territory environmental and planning statutes.
      The particular provisions of the various state and territory environmental and planning statutes vary depending upon the jurisdiction. Despite variation in details, each state and territory has a system involving at least two major phases. First, obtaining the developmental application and, if that is granted, obtaining the detailed operational pollution control licenses (which authorize emissions up to a maximum level); and second, obtaining pollution control approvals (which authorize the installation of pollution control equipment and devices). In the first regulatory phase, an application to a regulatory authority is filled. The relevant authority will either grant a conditional consent, an unconditional consent, or deny the application based on the details of the application and on any submissions or objections lodged by members of the public. If the developmental application is granted, the detailed pollution control license may then be issued and such license may regulate emissions to the atmosphere; emissions in waters; noise impacts, including impacts from blasting; dust impacts; the generation, handling, storage and transportation of waste; and requirements for the rehabilitation and restoration of land.
      Each state and territory in Australia also has either a specific statute or certain sections in other environmental and planning statutes relating to the contamination of land and vesting powers in the various regulatory authorities in respect of the remediation of contaminated land. Those statutes are based on varying policies — the primary difference between the statutes is that in certain states and territories, liability for remediation is placed upon the occupier of the land, regardless of the culpability of that occupier for the contamination. In other states and territories, primary liability for remediation is placed on the original polluter, whether or not the polluter still occupies the land. If the original polluter cannot itself carry out the remediation, then a number of the statutes contain provisions which enable recovery of the costs of remediation from the polluter as a debt.
      Many of the environmental planning statutes across the states and territories contain “third party” appeal rights in relation, particularly, to the first regulatory phase. This means that any party has a right to take proceedings for a threatened or actual breach of the statute, without first having to establish that any particular interest of that person (other than as a member of the public) stands to be affected by the threatened or actual breach.

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      Accordingly, in most states and territories throughout Australia, mining activities involve a number of regulatory phases. Following exploratory investigations pursuant to a mining lease, the activity proposed to be carried out must be the subject of an application for the activity or development. This phase of the regulatory process, as noted above, usually involves the preparation of extensive documents to constitute the application, addressing all of the environmental impacts of the proposed activity. It also generally involves extensive notification and consultation with other relevant statutory authorities and members of the public. Once a decision is made to allow a mine to be developed by the grant of a development consent, permit or other approval, then a formal mining lease can be obtained under the mining statute. In addition, operational licenses and approvals can then be applied for and obtained in relation to pollution control devices and emissions to the atmosphere, to waters and for noise. The obtaining of licenses and approvals, during the operational phase, generally does not involve any extensive notification or consultation with members of the public, as most of these issues are anticipated to be resolved in the first regulatory phase.
Occupational Health And Safety
      The combined effect of various state and federal statutes requires an employer to ensure that persons employed in a mine are safe from injury by providing a safe working environment and systems of work; safety machinery; equipment, plant and substances; and appropriate information, instruction, training and supervision.
      In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation that deals specifically with the coal mining industry. Mining employers, owners, directors and managers, persons in control of work places, mine managers, supervisors and employees are all subject to these duties.
      It is mandatory for an employer to have insurance coverage in respect of the compensation of injured workers; similar schemes are in effect throughout Australia which are of a no fault nature and which provide for benefits up to a prescribed level. The specific benefits vary from jurisdiction to jurisdiction, but generally include the payment of weekly compensation to an incapacitated employee, together with payment of medical, hospital and related expenses. The injured employee has a right to sue his or her employer for further damages if a case of negligence can be established.
Global Climate Change
      The United States, Australia and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which addresses emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place in the U.S., these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. According to the Department of Energy’s Energy Information Administration, “Emissions of Greenhouse Gases in the United States 2003,” coal accounts for 31% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. In March 2001, President Bush reiterated his opposition to the Kyoto Protocol and further stated that he did not believe that the government should impose mandatory carbon dioxide emission reductions on power plants. In February 2002, President Bush announced a new approach to climate change, confirming the Administration’s opposition to the Kyoto Protocol and proposing voluntary actions to reduce the greenhouse gas intensity of the United States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The President’s climate change initiative calls for a reduction in greenhouse gas intensity of 18% over the next 10 years which is approximately equivalent to the reduction that has occurred over each of the past two decades. Ratification and

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implementation of the Kyoto Protocol by the United States or other actions to limit carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by electric generators.
Additional Information
      We file annual, quarterly and current reports, and our amendments to those reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings without charge through our website, at www.peabodyenergy.com, or the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
      You may also request copies of our filings, at no cost, by telephone at (314) 342-3400 or by mail at: Peabody Energy Corporation, 701 Market Street, Suite 900, St. Louis, Missouri 63101, attention: Investor Relations.
Item 2. Properties.
Coal Reserves
      We had an estimated 9.3 billion tons of proven and probable coal reserves as of December 31, 2004. An estimated 9.1 billion tons of our proven and probable coal reserves are in the United States and 0.2 billion tons are in Australia. Forty-one percent of our reserves, or 3.8 billion tons, are compliance coal and 59% are non-compliance coal. We own approximately 43% of these reserves and lease property containing the remaining 57%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
      Below is a table summarizing the locations and reserves of our major operating regions.
                               
        Proven and Probable
        Reserves as of
        December 31, 2004(1)
         
        Owned   Leased   Total
Operating Regions   Locations   Tons   Tons   Tons
                 
        (Tons in millions)
Powder River Basin
  Wyoming and Montana     68       3,081       3,149  
Southwest
  Arizona and New Mexico     625       391       1,016  
Colorado
  Colorado     43       237       280  
Appalachia
  West Virginia, Ohio     250       401       651  
Midwest
  Illinois, Indiana and Kentucky     3,038       927       3,965  
Australia
  Queensland           218       218  
                       
 
Total Proven and Probable Coal Reserves
        4,024       5,255       9,279  
                       
 
(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.

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        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 generally have a much higher degree of reliability because of increased drilling density. Active surface reserves generally have points of observation as close as 330 feet to 660 feet.
      Our reserve estimates are prepared by our staff of geologists, whose experience ranges from 10 to 30 years. We also have a chief geologist of reserve reporting whose primary responsibility is to track changes in reserve estimates, supervise our other geologists and coordinate periodic third party reviews of our reserve estimates by qualified mining consultants.
      Our reserve estimates are predicated on information obtained from our ongoing drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal are determined. The density of the drill pattern determines whether the reserves will be classified as proven or probable. The reserve estimates are then input into our computerized land management system, which overlays the geological data with data on ownership or control of the mineral and surface interests to determine the extent of our reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserve and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.
      Our estimate of the economic recoverability of our reserves is based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to existing market prices for the quality of coal expected to be mined and taking into consideration typical contractual sales agreements for the region and product. Where possible, we also review production by competitors in similar mining areas. Only reserves expected to be mined economically and with an acceptable profit margin are included in our reserve estimates. Finally, our reserve estimates include reductions for recoverability factors to estimate a saleable product.
      We periodically engage independent mining and geological consultants to review estimates of our coal reserves. The most recent of these reviews, which was completed in April 2003, included a review of the procedures used by us to prepare our internal estimates, verification of the accuracy of selected property reserve estimates and retabulation of reserve groups according to standard classifications of reliability. This study confirmed that we controlled approximately 9.1 billion tons of proven and probable reserves as of December 31, 2002. After adjusting for acquisitions, divestitures, production and estimate refinements (through additional drilling and exploration) through December 31, 2004, proven and probable reserves totaled 9.3 billion tons.
      With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to

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move reserves from the probable to the proven classification. On a regional basis, the expected degree of variance from reserve estimate to tons produced is lower in the Powder River Basin, Southwest, and Illinois Basin due to the continuity of the coal seams as confirmed by the mining history. Appalachia, however, has a higher degree of risk due to the mountainous nature of the topography. Our recovered reserves in Appalachia are less predictable and may vary by an additional one to two percent above the threshold discussed above.
      We have numerous federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2004, we leased 11,922 acres of federal land in Colorado, 11,254 acres in Montana and 36,964 acres in Wyoming, for a total of 60,140 nationwide.
      Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 65,000 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments.
      Private coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments.
      The terms of our private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or these leases may be renewed periodically. With a portfolio of approximately 9.3 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our significant reserve holdings is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.
      Consistent with industry practice, we conduct only limited investigation of title to our coal properties prior to leasing. Title to lands and reserves of the lessors or grantors and the boundaries of our leased properties are not completely verified until we prepare to mine those reserves.

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      The following chart provides a summary, by mining complex, of production for the years ended December 31, 2004 and 2003 and 2002, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities. The chart below breaks down our assigned proven and probable reserves into the mining complexes located in a particular geographic region, and does not indicate the legal entity that owns or controls the reserves.
PRODUCTION AND ASSIGNED RESERVES(1)
(Tons in millions)
                                                                                                             
            Sulfur Content(2)       As of December 31, 2004
    Production                
            <1.2 lbs.   >1.2 to 2.5 lbs.   >2.5 lbs.   As   Assigned    
Geographic   Year Ended   Year Ended   Year Ended       Sulfur Dioxide   Sulfur Dioxide   Sulfur Dioxide   Received   Proven and    
Region/ Mining   Dec. 31,   Dec. 31,   Dec. 31,   Type of   per   per   per   Btu per   Probable    
Complex   2004   2003   2002   Coal   Million Btu   Million Btu   Million Btu   Pound(3)   Reserves   Owned   Leased   Surface   Underground
                                                     
Appalachia:
                                                                                                       
 
Federal
    4.9       4.1       5.0       Steam                   28       13,300       28       2       26             28  
 
Big Mountain
    1.9       1.5       1.0       Steam       2       22       1       12,800       25             25             25  
 
Harris
    3.0       3.0       3.2       Steam/Met.       6       4             13,600       10             10             10  
 
Rocklick
    2.0       2.5       3.4       Steam/Met.       7       12             13,200       19             19       6       13  
 
Rivers Edge
    2.6       2.4       2.4       Steam/Met.       6       2       1       13,500       9             9             9  
                                                                               
   
Total
    14.4       13.5       15.0               21       40       30               91       2       89       6       85  
Midwest:
                                                                                                       
 
Camps/ Highland
    3.2       1.7       3.0       Steam                   128       11,300       128       31       97             128  
 
Midwest Operating Unit
                1.4       Steam                   8       11,100       8       8             1       7  
 
Patriot
    4.1       4.2       2.7       Steam                   36       10,900       36             36       5       31  
 
Air Quality
    1.8       1.9       1.8       Steam             28       29       10,600       57       3       54             57  
 
Riola/ Vermilion Grove
    2.3       1.8       1.9       Steam                   23       10,500       23             23             23  
 
Miller Creek
    0.9       0.8       0.8       Steam             1       2       11,600       3             3       3        
 
Francisco Surface
    2.1       2.5       2.4       Steam                   10       10,500       10       2       8       10        
 
Francisco Underground
    0.9                                       15       10,700       15       2       13             15  
 
Farmersburg
    4.2       4.3       4.1       Steam                   19       10,600       19       10       9       19        
 
Somerville Central
    3.2       3.3       3.1       Steam                   11       10,300       11       7       4       11        
 
Somerville
    4.1       4.0       3.9       Steam                   13       10,000       13       6       7       13        
 
Viking
    1.5       1.4       1.3       Steam             2       10       10,700       12             12       12        
 
Cottage Grove
    2.7       2.5       2.0       Steam                   10       10,400       10       6       4       10        
 
Willow Lake
    3.4       2.8       2.4       Steam                   43       11,000       43       35       8             43  
 
Columbia
                0.4       Steam                         N/A                                
 
Dodge Hill
    1.2                   Steam                   14       11,700       14       6       8             14  
                                                                               
   
Total
    35.6       31.2       31.2                     31       371               402       116       286       84       318  
Powder River Basin:
                                                                                                       
 
Big Sky
          2.6       2.8       Steam             11       1       8,800       12             12       12        
 
North Antelope/ Rochelle
    82.5       80.1       74.8       Steam       1,299             32       8,800       1,331             1,331       1,331        
 
Caballo
    26.5       22.8       26.0       Steam       713       32             8,700       745             745       745        
 
Rawhide
    6.9       3.6       3.5       Steam       209       67       8       8,600       284             284       284        
                                                                               
   
Total
    115.9       109.1       107.1               2,221       110       41               2,372             2,372       2,372        
Southwest
                                                                                                       
 
Black Mesa
    4.8       4.4       4.6       Steam       17       1             10,900       18             18       18        
 
Kayenta
    8.2       7.8       8.2       Steam       203       80       2       11,000       285             285       285        
 
Lee Ranch
    5.8       6.9       6.4       Steam       21       132       12       10,000       165       89       76       165        
 
Twentymile
    6.4                   Steam       64             13       10,700       77       2       75             77  
 
Seneca
    1.5       1.5       1.8       Steam       8                   10,200       8             8       8        
                                                                               
   
Total
    26.7       20.6       21.0               313       213       27               553       91       462       476       77  
Australia
                                                                                                       
 
North Goonyella
    1.5                   Met       51                   10,830       51             51             51  
 
Eaglefield
    0.2                   Met       6                   10,300       6             6       6        
 
Burton
    3.2                   Steam/Met       18                   9,880       18             18       18        
 
Wilkie Creek
    1.4       1.3       0.4       Steam       22                   8,710       22             22       22        
                                                                               
   
Total
    6.3       1.3       0.4               97                           97             97       46       51  
                                                                               
Total
    198.9       175.7       174.7               2,652       394       469               3,515       209       3,306       2,984       531  
                                                                               

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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. The chart below breaks down our proven and probable reserves into geographic regions, and does not indicate the legal entity that owns or controls the reserves.
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES
As of December 31, 2004
(Tons in millions)
                                                                                                                   
                            Sulfur Content(2)                    
                                                 
                        <1.2 lbs.   >1.2 to 2.5 lbs.   >2.5 lbs.   As        
    Total Tons   Proven and               Sulfur Dioxide   Sulfur Dioxide   Sulfur Dioxide   Received   Reserve Control   Mining Method
Coal Seam       Probable           Type of   per   per   per   Btu per        
Location   Assigned   Unassigned   Reserves   Proven   Probable   Coal   Million Btu   Million Btu   Million Btu   pound(3)   Owned   Leased   Surface   Underground
                                                         
Northern Appalachia:
                                                                                                               
 
Ohio
          40       40       28       12       Steam                   40       11,100       30       10             40  
 
West Virginia
    28       220       248       88       160       Steam             117       131       12,700       166       82             248  
                                                                                     
 
Northern Appalachia
    28       260       288       116       172                     117       171               196       92             288  
Central Appalachia:
                                                                                                               
 
West Virginia
    63       300       363       242       121       Steam/Met.       145       134       84       13,200       54       309       16       347  
                                                                                     
 
Central Appalachia
    63       300       363       242       121               145       134       84               54       309       16       347  
Midwest:
                                                                                                               
 
Illinois
    77       2,325       2,402       1,130       1,272       Steam       5       65       2,332       10,300       2,206       196       74       2,328  
 
Indiana
    140       342       482       344       138       Steam             39       443       10,500       310       172       209       273  
 
Kentucky
    185       896       1,081       645       436       Steam             1       1,080       10,900       522       559       140       941  
                                                                                     
 
Midwest
    402       3,563       3,965       2,119       1,846               5       105       3,855               3,038       927       423       3,542  
Powder River Basin:
                                                                                                               
 
Montana
    12       151       163       159       4       Steam       15       127       21       8,600       67       96       163        
 
Wyoming
    2,360       626       2,986       2,906       80       Steam       2,772       102       112       8,700       1       2,985       2,986        
                                                                                     
 
Powder River Basin
    2,372       777       3,149       3,065       84               2,787       229       133               68       3,081       3,149        
Southwest:
                                                                                                               
 
Arizona
    303             303       303             Steam       220       81       2       11,000             303       303        
 
Colorado
    85       195       280       223       57       Steam       163             117       10,700       43       237       9       271  
 
New Mexico
    165       548       713       452       261       Steam       260       367       86       8,700       625       88       696       17  
                                                                                     
 
Southwest
    553       743       1,296       978       318               643       448       205               668       628       1,008       288  
Australia
                                                                                                               
 
Queensland
    97       121       218       132       86       Steam/Met.       218             0       10,130             218       167       51  
                                                                                     
Total Proven and Probable
    3,515       5,764       9,279       6,652       2,627               3,798       1,033       4,448               4,024       5,255       4,763       4,516  
                                                                                     

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(1)  Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2004. Unassigned reserves represent coal at suspended locations and coal that has not been committed. These reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property.
 
(2)  Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.
 
(3)  As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The following table reflects the average moisture content used in the determination of as-received Btu by region:
           
Northern Appalachia
    6.0 %
Central Appalachia
    7.0 %
Midwest:
       
 
Illinois
    14.0 %
 
Indiana
    15.0 %
 
Kentucky
    12.5 %
 
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 9.3 billion tons of proven and probable coal reserves and interest in approximately 400,000 acres of surface property. Our Resource Development group constantly reviews these reserves for opportunities to generate revenues through the sale of non-strategic coal reserves and surface land. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties, coalbed methane production and farm income from surface land under third party contracts.
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 our subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company (“Peabody Western”), with a complaint that had been filed in the U.S. District Court for the District of Columbia. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act, or RICO, violations and fraud and tortious interference with contractual relationships. The complaint alleges that the defendants

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jointly participated in unlawful activity to obtain favorable coal lease amendments. Plaintiff also alleges that defendants interfered with the fiduciary relationship between the United States and the Navajo Nation. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases for the Kayenta and Black Mesa mines have terminated due to Peabody Western’s breach of these leases and a reformation of the two coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted seven claims including fraud and is seeking various remedies including unspecified actual damages, punitive damages and reformation of its coal lease.
      On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States. The Court rejected the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments and was liable for money damages.
      On February 9, 2005, the U.S. District Court for the District of Columbia granted a consent motion to stay the litigation until further order of the Court. Peabody Western, the Navajo Nation, the Hopi Tribe and the customers purchasing coal from the Black Mesa and Kayenta mines are in mediation with respect to this litigation and other business issues.
      While the outcome of litigation is subject to uncertainties, based on our preliminary evaluation of the issues and their potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
Salt River Project Agricultural Improvement and Power District — Mine Closing and Retiree Health Care
      Salt River Project and the other owners of the Navajo Generating Station filed a lawsuit on September 27, 1996 in the Superior Court of Maricopa County in Arizona seeking a declaratory judgment that certain costs relating to final reclamation, environmental monitoring work and mine decommissioning and costs primarily relating to retiree health care benefits are not recoverable by our subsidiary, Peabody Western Coal Company, under the terms of a coal supply agreement dated February 18, 1977. The contract expires in 2011.
      Peabody Western filed a motion to compel arbitration of these claims, which was granted in part by the trial court. Specifically, the trial court ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. This ruling was subsequently upheld on appeal. As a result, Peabody Western, Salt River Project and the other owners of the Navajo Generating Station will arbitrate the mine decommissioning costs issue and will litigate the retiree health care costs issue.
      While the outcome of litigation and arbitration is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, and based on outcomes in similar proceedings, we believe that the matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
Navajo and Mohave Generating Stations — Legal Fees and Costs
      In 2003, Peabody Western Coal Company invoked arbitration and commenced two lawsuits in the Superior Court of Maricopa County, Arizona with respect to the failure of the owners of the Navajo and Mohave Generating Stations to pay for certain of Peabody Western’s legal fees and costs under two coal supply agreements. Peabody Western seeks reimbursement under the agreements for its legal fees and costs in the Navajo Nation litigation referenced above and related litigation. As of December 31, 2004, Peabody Western has billed the owners of the Navajo and Mohave Generating Station $18.1 million in fees and costs which remain unpaid.

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California Public Utilities Commission Proceedings Regarding the Future of the Mohave Generating Station
      Peabody Western has a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to the operation of the Mohave plant beyond 2005 or a temporary or permanent shutdown of the plant. In filings with the California Public Utilities Commission, the operator affirmed that the Mohave plant was not forecast to return to service as a coal-fueled resource until mid-2009 at the earliest if the plant is shutdown at December 31, 2005. On December 2, 2004, the California Public Utilities Commission issued an opinion authorizing Southern California Edison to make necessary expenditures at the Mohave plant to preserve the “Mohave-open” option while Southern California Edison continues to seek resolution of the water and coal issues. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline from Peabody Western’s Black Mesa Mine to the Mohave plant. As a part of the alternate dispute resolution referenced in the Navajo Nation litigation, Peabody Western has been participating in mediation with the owners of the Mohave Generating Station and the Navajo Generating Station, and the two tribes to resolve the complex issues surrounding the groundwater dispute and other disputes involving the two generating stations. Resolution of these issues is critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. If these issues are not resolved in a timely manner, the operation of the Mohave plant will cease or be suspended on December 31, 2005. Absent a satisfactory alternate dispute resolution, it is unlikely that the coal supply agreement for the Mohave plant will be renewed in time to avoid a shutdown of the mine in 2006. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 4.7 million tons in 2004. In 2004, the mine generated $25.2 million of Adjusted EBITDA, which represents 4.5% of our Adjusted EBITDA total of $559.2 million (reconciled to its most comparable GAAP measure in Note 26 to the financial statements).
West Virginia Flooding Litigation
      Three of our subsidiaries have been named in five separate complaints filed in Boone, Kanawha and Wyoming Counties, West Virginia. These cases collectively include 622 plaintiffs who are seeking damages for property damage and personal injuries arising out of flooding that occurred in southern West Virginia in July of 2001. The plaintiffs have sued coal, timber, railroad and land companies under the theory that mining, construction of haul roads and removal of timber caused natural surface waters to be diverted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that these four cases, along with over 10 additional flood damage cases not involving our subsidiaries, be handled pursuant to the Court’s Mass Litigation rules. All discovery has been stayed. On December 9, 2004, the West Virginia Supreme Court answered questions that were certified to it by the Mass Litigation Panel. The Panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts.
      While the outcome of litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
Citizens Power
      In connection with the August 2000 sale of our former subsidiary, Citizens Power LLC (“Citizens Power”), we have indemnified the buyer, Edison Mission Energy, from certain losses resulting from specified power contracts and guarantees. Other than those discussed below, there are no known issues with any of the specified power contracts and guarantees.
      During the period that Citizens Power was owned by us, Citizens Power guaranteed the obligations of two affiliates to make payments to third parties for power delivered under fixed-priced power sales

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agreements with terms that extend through 2008. Edison Mission Energy has stated and we believe there will be sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers. To our knowledge, the power purchasers have made timely payments to the Citizens Power affiliates and Edison Mission Energy has not made a claim against us under the indemnity.
Environmental
      Superfund and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under that legislation and many state Superfund statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault.
      Environmental claims have been asserted against a subsidiary of ours, Gold Fields Mining Corporation (“Gold Fields”), at 22 sites in the United States and remediation has been completed or substantially completed at four of those sites. Gold Fields is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, a predecessor owner of ours. In the February 1997 spin-off of its energy businesses, Hanson PLC combined Gold Fields with the Company. These sites are related to activities of Gold Fields or its former subsidiaries. Some of these claims are based on the Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, and on similar state statutes.
      Our policy is to accrue environmental cleanup-related costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures requires an assessment of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. For certain sites, we also assess the financial capability of other potentially responsible parties and, where allegations are based on tentative findings, the reasonableness of our apportionment. We have not anticipated any recoveries from insurance carriers or other potentially responsible third parties in the estimation of liabilities recorded on its consolidated balance sheets. Undiscounted liabilities for environmental cleanup-related costs included in other non-current liabilities totaled $40.5 million as of December 31, 2004 and $38.9 million at December 31, 2003, $15.1 million and $6.9 million of which was a current liability, respectively. These amounts represent those costs that we believe are probable and reasonably estimable. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than this provision.
      Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of Superfund and similar legislation, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed by the statute. Thus, coal mines currently or previously owned or operated by us, and sites to which we have sent waste materials, may be subject to liability under Superfund and similar state laws.
Oklahoma Lead Litigation
      Gold Fields was named in June 2003 as a defendant, along with five other companies, in a class action lawsuit filed in the U.S. District Court for the Northern District of Oklahoma. The plaintiffs have asserted nuisance and trespass claims predicated on allegations of intentional lead exposure by the defendants, including Gold Fields, and are seeking compensatory damages for diminution of property value, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950’s. The plaintiff classes include all persons who have resided or owned property in the towns of Cardin and Picher within a specified time period. Gold Fields has agreed to indemnify one of the other defendants, which is a former subsidiary of Gold Fields. Gold Fields is also a defendant, along with other companies, in five individual lawsuits arising out of the same lead mill operations involved in the class

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action. Plaintiffs in these actions are seeking compensatory and punitive damages for alleged personal injuries from lead exposure. In December 2003, the Quapaw Indian tribe and certain Quapaw owners of interests in land filed a class action lawsuit against Gold Fields and five other companies in U.S. District Court for the Northern District of Oklahoma. The plaintiffs are seeking compensatory and punitive damages based on public and private nuisance, trespass, unjust enrichment, CERCLA RCRA, strict liability and deceit claims. Gold Fields has denied liability to the plaintiffs, has filed counterclaims against the plaintiffs seeking indemnification and contribution and has filed a third-party complaint against the United States, owners of interests in chat and real property in the Picher area. The Quapaw tribe also filed a notice of intent to sue Gold Fields and the other mining companies under CERCLA regarding alleged damages to natural resources held in trust by the Tribe and RCRA for an alleged abatement of an imminent and substantial endangerment to health and the environment.
      In February 2004, the town of Quapaw filed a class action lawsuit against Gold Fields and other mining companies asserting claims similar to those asserted by the towns of Picher and Cardin as well as natural resource damage claims. In July 2004, two lawsuits were filed, one in the U.S. District Court for the Northern District of Oklahoma and one in Ottawa County, Oklahoma (subsequently removed to the U.S. District Court for the Northern District of Oklahoma), against Gold Fields and three other companies in which 48 individuals are seeking compensatory and punitive damages and injunctive relief from alleged personal injuries resulting from lead exposure. The allegations relate to the same two lead mills located near Picher, Oklahoma. The trials for a few of the individual plaintiffs have been set for November 2005.
      While the outcome of litigation is subject to uncertainties, based on our preliminary evaluation of the issues and their potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
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, 2004.
Executive Officers of the Company
      Set forth below are the names, ages as of March 1, 2005 and current positions of our executive officers. Executive officers are appointed by, and hold office at, the discretion of our Board of Directors.
             
Name   Age   Position
         
Irl F. Engelhardt
    58     Chairman, Chief Executive Officer and Director
Gregory H. Boyce
    50     President and Chief Operating Officer
Sharon D. Fiehler
    48     Executive Vice President — Human Resources and Administration
Richard A. Navarre
    44     Executive Vice President and Chief Financial Officer
Fredrick D. Palmer
    60     Senior Vice President — Government Relations
Roger B. Walcott, Jr. 
    48     Executive Vice President — Corporate Development
Richard M. Whiting
    50     Executive Vice President — Sales, Marketing and Trading
Jeffery L. Klinger
    57     Vice President — General Counsel and Secretary
      Irl F. Engelhardt has been a director of ours since 1998. He is our Chairman and Chief Executive Officer, a position he has held since 1998. He served as Chief Executive Officer of a predecessor of ours from 1990 to 1998. He also served as Chairman of a predecessor of ours from 1993 to 1998 and as President from 1990 to 1995. Since joining our predecessor in 1979, he has held various officer level positions in the executive, sales, business development and administrative areas, including serving as Chairman of Peabody Resources Ltd. (Australia) and Chairman of Citizens Power LLC. Mr. Engelhardt

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also served as Co-Chief Executive Officer and executive director of The Energy Group from February 1997 to May 1998, Chairman of Cornerstone Construction & Materials, Inc. from September 1994 to May 1995 and Chairman of Suburban Propane Company from May 1995 to February 1996. He also served as a director and Group Vice President of Hanson Industries from 1995 to 1996. Mr. Engelhardt is Co-Chairman of the Coal-Based Generation Stakeholders Group. He has previously served as Chairman of the National Mining Association, the Coal Industry Advisory Board of the International Energy Agency, and the Coal Utilization Research Council. He also serves on the Board of Directors of The Federal Reserve Bank of St. Louis. It was announced on March 1, 2005 that Mr. Engelhardt will continue his duties as Chairman and Chief Executive Officer for the duration of 2005 and will remain employed as Chairman of the Board as of January 1, 2006.
      Gregory H. Boyce was elected by our Board of Directors to the position of President and Chief Executive Officer, effective January 1, 2006. Mr. Boyce also was elected to the Board of Directors of the Company, and named Chairman of the Executive Committee of the Board, effective March 1, 2005. He continues to serve as our President and Chief Operating Officer, a position he has held since October 2003. Mr. Boyce had served as Chief Executive Officer — Energy of Rio Tinto PLC from 2000 to 2003. His prior positions include President and Chief Executive Officer of Kennecott Energy Company from 1994 to 1999 and President of Kennecott Minerals Company from 1993 to 1994. He has extensive engineering and operating experience with Kennecott and also served as Executive Assistant to the Vice Chairman of Standard Oil from 1983 to 1984. Mr. Boyce is a member of the Coal Industry Advisory Board of the International Energy Agency. He is a past board member of the Center for Energy and Economic Development, the National Mining Association, Western Regional Council, National Coal Council, Mountain States Employers Council and Wyoming Business Council. He also serves on the board of directors of the St. Louis Regional Chamber and Growth Association.
      Sharon D. Fiehler has been our Executive Vice President of Human Resources and Administration since April 2002, with executive responsibility for information services, employee development, benefits, compensation, employee relations and affirmative action programs. She joined Peabody in 1981 as Manager — Salary Administration and has held a series of employee relations, compensation and salaried benefits positions. Ms. Fiehler, holds degrees in social work and psychology and an MBA, and prior to joining Peabody was a personnel representative for Ford Motor Company. Ms. Fiehler is the chair of the Benefits Committee of the Bituminous Coal Operators’ Association, on the Executive Committee and Board of Directors of Junior Achievement of St. Louis and is a member of the National Mining Association’s Human Resource Committee.
      Richard A. Navarre became our Executive Vice President and Chief Financial Officer in February 2001. Prior to that, he was our Vice President and Chief Financial Officer since October 1999. He was President of Peabody COALSALES Company from January 1998 to October 1999 and previously served as President of Peabody Energy Solutions, Inc. Prior to his roles in sales and marketing, he was Vice President of Finance and served as Vice President and Controller. He joined our predecessor company in 1993 as Director of Financial and Strategic Planning. Prior to joining us, Mr. Navarre was a senior manager with KPMG Peat Marwick. Mr. Navarre is Chairman of the Bituminous Coal Operators’ Association. He serves on the Board of Advisors to the College of Business for Southern Illinois University at Carbondale. He is a member of Financial Executives International and the NYMEX Coal Advisory Council.
      Fredrick D. Palmer became our Senior Vice President — Government Relations in February 2005. He is responsible for our governmental affairs. Prior to that he was our Executive Vice President — Legal and External Affairs since February 2001. Prior to joining Peabody in 2001, he served for 15 years as chief executive officer and five years as general counsel of Western Fuels Association, Inc. For a short period in 2001, he also was of counsel in the Washington, D.C. office of Shook Hardy & Bacon, a Kansas City-based law firm. He received a BA and a JD from the University of Arizona.

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      Roger B. Walcott, Jr. became our Executive Vice President — Corporate Development in February 2001. Prior to that, he was Executive Vice President since joining us in June 1998. From 1987 to 1998, he was a Senior Vice President and a director with The Boston Consulting Group where he served a variety of clients in strategy and operational assignments. He joined Boston Consulting Group in 1981, and was Chairman of The Boston Consulting Group’s Human Resource Capabilities Committee. Mr. Walcott holds an MBA with high distinction from the Harvard Business School.
      Richard M. Whiting became our Executive Vice President — Sales, Marketing and Trading in October 2002. Previously, Mr. Whiting served as our President and Chief Operating Officer and President of Peabody COALSALES Company. He joined a our predecessor in 1976 and has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Mr. Whiting is currently a member of the Board of Directors of Penn Virginia Resource GP, LLC, the general partner of Penn Virginia Resource Partners, L.P. He is the former Chairman of the National Mining Association’s Safety and Health Committee, the former Chairman of the Bituminous Coal Operators’ Association, a past board member of the National Coal Council and is a member of the Visiting Committee of West Virginia University College of Engineering and Mineral Resources.
      Jeffery L. Klinger was named our Vice President — General Counsel and Secretary in February 2005. Previously, he was our Vice President — Legal Services since May 1998. He was Vice President, Secretary and Chief Legal Officer from October 1990 to May 1998. He served from 1986 to October 1990 as Eastern Regional Counsel for Peabody Holding Company, from 1982 to 1986 as Director of Legal and Public Affairs, Eastern Division of Peabody Coal Company and from 1978 to 1982 as Director of Legal and Public Affairs, Indiana Division of Peabody Coal Company. He is a past President of the Indiana Coal Council and is currently a trustee of the Energy and Mineral Law Foundation and a past Treasurer and member of its Executive Committee. Mr. Klinger is also a member of the National Mining Association’s Legal Affairs Committee.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
      Our common stock is listed on the New York Stock Exchange, under the symbol “BTU.” As of February 28, 2005, there were approximately 307 holders of record of our common stock.
      The table below sets forth the range of quarterly high and low sales prices for our common stock (after giving retroactive effect to a two-for-one stock split effective March 30, 2005) on the New York Stock Exchange during the calendar quarters indicated.
                   
    High   Low
         
2003
               
 
First Quarter
  $ 14.80     $ 12.26  
 
Second Quarter
    17.56       13.36  
 
Third Quarter
    16.82       14.31  
 
Fourth Quarter
    21.50       15.68  
2004
               
 
First Quarter
  $ 25.30     $ 18.21  
 
Second Quarter
    28.01       20.88  
 
Third Quarter
    30.22       25.37  
 
Fourth Quarter
    43.40       27.01  

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Dividend Policy
      After giving retroactive effect to a two-for-one stock split effective March 30, 2005, the quarterly dividend rate for Common Stock was increased by the Board of Directors to $0.075 per share effective November 3, 2004. We paid quarterly dividends totaling $0.26 per share during the year ended December 31, 2004 and $0.23 per share during the year ended December 31, 2003. On January 25, 2005, a dividend of $0.075 per share was declared on Common Stock, payable on March 1, 2005 to stockholders of record on February 8, 2005. The declaration and payment of dividends and the amount of dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt instruments and other factors deemed relevant by our Board of Directors; however, we presently expect that dividends will continue to be paid. Limitations on our ability to pay dividends imposed by our debt instruments are discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Stock Split
      On March 2, 2005, we announced that our Board of Directors had authorized a two-for-one stock split on all shares of our common stock. Shareholders of record at the close of business on March 16, 2005 will be entitled to a dividend of one share of stock for every share held. The additional shares will be distributed on March 30, 2005, and the stock will begin trading ex-split on March 31, 2005. All share and per share amounts in this Annual Report on Form 10-K reflect the two-for-one stock split.
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 2004 and 2003 in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, includes references to, and analysis of, our Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.
      Beginning with the year ended December 31, 2004, our equity in earnings of affiliates and all gains on asset disposals were classified separately as a component of operating income. Prior periods have been restated to conform with current presentation.
      On April 15 2004, we acquired three coal operations from RAG Coal International AG. Our results of operations for the year ended December 31, 2004 include the results of operations of the two mines in Queensland, Australia and the results of operations of the Twentymile Mine in Colorado from the April 15, 2004 purchase date. The acquisition was accounted for as a purchase.
      Results of operations for the year ended December 31, 2003 include early debt extinguishment costs of $53.5 million pursuant to our debt refinancing in the first half of 2003. In addition, results included expense relating to the cumulative effect of accounting changes, net of income taxes, of $10.1 million. This amount represents the aggregate amount of the recognition of accounting changes pursuant to the adoption of SFAS No. 143, the change in method of amortization of actuarial gains and losses related to net periodic postretirement benefit costs and the effect of the rescission of EITF No. 98-10. These accounting changes are further discussed in Note 6 to our financial statements.
      In July 2001, we changed our fiscal year end from March 31 to December 31. The change was first effective with respect to the nine months ended December 31, 2001.
      On May 22, 2001, concurrent with our initial public offering, we converted our Class A common stock and Class B common stock into a single class of common stock, all on a one-for-one basis.

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      Results of operations for the year ended March 31, 2001 included a $171.7 million pretax gain on the sale of our Peabody Resources Limited operations in Australia. Capital expenditures of $151.4 million for this period do not include Peabody Resources Limited capital expenditures.
      In anticipation of the sale of Citizens Power, which occurred in August 2000, we classified Citizens Power as a discontinued operation as of March 31, 2000. Results in 2004 include a $2.8 million loss, net of taxes, from discontinued operations related to the settlement of a Citizens Power indemnification claim. Citizens Power is presented as a discontinued operation for all periods presented.
      We have derived the selected historical financial data for the years ended and as of December 31, 2004, 2003 and 2002, the nine months ended and as of December 31, 2001, and for the year ended and as of March 31, 2001 from our audited financial statements. All share and per share amounts included in the following consolidated financial data have been retroactively adjusted to reflect a two-for-one stock split, effective March 30, 2005. You should read the following table in conjunction with the financial statements, the related notes to those financial statements, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
      The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, the “Risks Relating To Our Company” section of Item 7 of this report includes a discussion of risk factors that could impact our future results of operations.
                                             
                Nine Months    
    Year Ended   Year Ended   Year Ended   Ended   Year Ended
    December 31,   December 31,   December 31,   December 31,   March 31,
    2004   2003   2002   2001   2001
                     
    (Dollars in thousands, except share and per share data)
Results of Operations Data
                                       
Revenues
                                       
 
Sales
  $ 3,545,027     $ 2,729,323     $ 2,630,371     $ 1,869,321     $ 2,534,964  
 
Other revenues
    86,555       85,973       89,267       57,029       94,487  
                               
   
Total revenues
    3,631,582       2,815,296       2,719,638       1,926,350       2,629,451  
Costs and expenses
                                       
 
Operating costs and expenses
    2,969,209       2,335,800       2,225,344       1,588,596       2,123,526  
 
Depreciation, depletion and amortization
    270,159       234,336       232,413       171,020       240,968  
 
Asset retirement obligation expense
    42,387       31,156                    
 
Selling and administrative expenses
    143,025       108,525       101,416       73,553       99,267  
 
Gain on sale of Australian operations
                            (171,735 )
 
Other operating income:
                                       
   
Net gain on disposal of assets
    (23,829 )     (32,772 )     (15,763 )     (22,160 )     (5,737 )
   
(Income) loss from equity affiliates
    (16,067 )     (6,535 )     2,540       (190 )     1,323  
                               
Operating profit
    246,698       144,786       173,688       115,531       341,839  
 
Interest expense
    96,793       98,540       102,458       88,686       197,686  
 
Early debt extinguishment costs
    1,751       53,513             38,628       11,025  
 
Interest income
    (4,917 )     (4,086 )     (7,574 )     (2,155 )     (8,741 )
                               
Income (loss) before income taxes and minority interests
    153,071       (3,181 )     78,804       (9,628 )     141,869  
 
Income tax provision (benefit)
    (26,437 )     (47,708 )     (40,007 )     (7,193 )     40,210  
 
Minority interests
    1,282       3,035       13,292       7,248       7,524  
                               
Income (loss) from continuing operations
    178,226       41,492       105,519       (9,683 )     94,135  
 
Income (loss) from discontinued operations
    (2,839 )                       12,925  
                               
Income (loss) before accounting changes
    175,387       41,492       105,519       (9,683 )     107,060  
 
Cumulative effect of accounting changes
          (10,144 )                  
                               
Net income (loss)
  $ 175,387     $ 31,348     $ 105,519     $ (9,683 )   $ 107,060  
                               

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                Nine Months    
    Year Ended   Year Ended   Year Ended   Ended   Year Ended
    December 31,   December 31,   December 31,   December 31,   March 31,
    2004   2003   2002   2001   2001
                     
    (Dollars in thousands, except share and per share data)
Basic earnings (loss) per share from continuing operations(1)
  $ 1.43     $ 0.39     $ 1.01     $ (0.10 )        
Diluted earnings (loss) per share from continuing operations(1)
  $ 1.40     $ 0.38     $ 0.98     $ (0.10 )        
Basic and diluted earnings per Class A/B share from continuing operations(1)
                                  $ 1.36  
Weighted average shares used in calculating basic earnings (loss) per share(1)
    124,366,372       106,819,042       104,331,470       97,492,888       55,049,252  
Weighted average shares used in calculating diluted earnings (loss) per share(1)
    127,406,316       109,671,256       107,643,520       97,492,888       55,049,252  
Dividends declared per share
  $ 0.26     $ 0.23     $ 0.20     $ 0.10        
Other Data
                                       
Tons sold (in millions)
    227.2       203.2       197.9       146.5       192.4  
Net cash provided by (used in):
                                       
 
Operating activities
  $ 283,760     $ 188,861     $ 234,804     $ 99,492     $ 111,980  
 
Investing activities
    (705,030 )     (192,280 )     (144,078 )     (172,989 )     388,462  
 
Financing activities
    693,404       48,598       (58,398 )     49,396       (503,337 )
Adjusted EBITDA(2)
    559,244       410,278       406,101       286,551       582,807  
Capital expenditures
    266,597       156,443       208,562       194,246       151,358  
Balance Sheet Data (at period end)
                                       
 
Total assets
  $ 6,178,592     $ 5,280,265     $ 5,125,949     $ 5,150,902     $ 5,209,487  
 
Total debt
    1,424,965       1,196,539       1,029,211       1,031,067       1,405,621  
 
Total stockholders’ equity
    1,724,592       1,132,057       1,081,138       1,035,472       631,238  
 
(1)  All per share and share amounts reflect the two-for-one stock split effected on March 30, 2005 for shareholders of record on March 16, 2005.
 
(2)  Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.
      Adjusted EBITDA is calculated as follows, in thousands (unaudited):
                                         
                Nine Months    
    Year Ended   Year Ended   Year Ended   Ended   Year Ended
    December 31,   December 31,   December 31,   December 31,   March 31,
    2004   2003   2002   2001   2001
                     
Income (loss) from continuing operations
  $ 178,226     $ 41,492     $ 105,519     $ (9,683 )   $ 94,135  
Income tax provision (benefit)
    (26,437 )     (47,708 )     (40,007 )     (7,193 )     40,210  
Depreciation, depletion and amortization
    270,159       234,336       232,413       171,020       240,968  
Asset retirement obligation expense
    42,387       31,156                    
Interest expense
    96,793       98,540       102,458       88,686       197,686  
Early debt extinguishment costs
    1,751       53,513             38,628       11,025  
Interest income
    (4,917 )     (4,086 )     (7,574 )     (2,155 )     (8,741 )
Minority interests
    1,282       3,035       13,292       7,248       7,524  
                               
Adjusted EBITDA
  $ 559,244     $ 410,278     $ 406,101     $ 286,551     $ 582,807  
                               

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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 32 active coal operations located throughout all major U.S. coal producing regions and internationally in Australia. In 2004, we sold 227.2 million tons of coal that accounted for an estimated 20% of all U.S. coal sales, and were more than 85% 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 2004 and expects domestic consumption of coal by electricity generators to grow at a rate of 1.6% per year through 2025. Coal-fueled generation is used in most cases to meet baseload electricity requirements, and coal use generally grows at the pace of electricity growth. In 2004, coal’s share of electricity generation was approximately 52%, which was more than all other fuels used to generate electricity combined.
      Our primary customers are U.S. utilities, which accounted for 90% of our sales in 2004. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2004, approximately 90% of our sales were under long-term contracts. As of December 31, 2004, we had priced more than 95% of our expected 2005 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, unforeseen geologic conditions or equipment problems at mining locations, and by the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections.
      We conduct business through four principal operating segments: Eastern U.S. Mining, Western U.S. Mining, Australian Mining, and Trading and Brokerage. 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, Southwest and Colorado operations. The principal business of the Western U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities. The principal business of the Eastern U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities, as well as the mining of some metallurgical coal, sold to steel and coke producers.
      Geologically, Eastern operations mine bituminous and Western operations mine bituminous and subbituminous coal deposits. Our Western U.S. Mining operations are characterized by predominantly surface extraction processes, lower sulfur content and Btu of coal, and higher customer transportation costs (due to longer shipping distances). Our Eastern U.S. Mining operations are characterized by predominantly underground extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances).
      Our Australian Mining operations consist of our Wilkie Creek Mine, two additional mines acquired in April 2004, Burton and North Goonyella, and our recently opened Eaglefield Mine, which is a surface operation adjacent to, and fulfilling contract tonnages in conjunction with, the North Goonyella underground mine. Australian Mining operations are characterized by both surface and underground extraction processes, mining low-sulfur, high Btu coal sold to an international customer base. Primarily metallurgical coal is produced from our Australian mines. Metallurgical coal is approximately 4% of our total sales volume and approximately 3% of U.S. sales volume. In December 2004, we purchased a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine produces approximately 7 million tons of steam coal annually for export to the United States and Europe. Each of our mining operations is described in Item 1 of this report.

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      In addition to our mining operations, which comprised 87% of revenues in 2004, we also generate revenues from brokering and trading coal (12% of revenues), and by creating value from our vast natural resource position by selling non-core land holdings and mineral interests to generate additional cash flows.
      We are developing coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. These projects involve mine-mouth generating plants using our surface lands and coal reserves. Three projects are currently being evaluated — the 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky, the 1,500 megawatt Prairie State Energy Campus in Washington County, Illinois and the 300 megawatt Mustang Energy Project near Grants, N.M. During 2004, one of our subsidiaries and Fluor Daniel Illinois, Inc. signed a letter of intent for engineering, design and construction of Prairie State’s power-related facilities. In January 2005, we achieved a major milestone in the development of the Prairie State Energy Campus when the state of Illinois issued an air permit for the electric generating station and coal mine campus. In January 2005, a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire 47% of the project. In February 2005, certain parties filed an appeal with the Environmental Appeals Board in Washington, D.C. challenging the air permit issued by the Illinois Environmental Protection Agency. The appeal must be resolved before construction of the project can begin. In October 2004, our Mustang Energy Project was awarded a $19.7 million Clean Coal Power Initiative Grant from the Department of Energy to demonstrate technology to achieve ultra low emissions. 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, secured financing and sold the majority of the output of the plant. These plants will not be operational until at least 2010.
Results of Operations
Adjusted EBITDA
      The discussion of our results of operations below includes references to, and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under generally accepted accounting principles, in Note 26 to our consolidated financial statements.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Summary
      Our 2004 revenues of $3.63 billion was an increase of 29.0% over prior year, led by improved pricing and an industry-record sales volume of 227.2 million tons. Mines acquired in April 2004 contributed $335.0 million of sales and 11.0 million tons to our current year results.
      Segment Adjusted EBITDA for the full year totaled $773.9 million, a 28.1% increase over $604.0 million in the prior year. Segment Adjusted EBITDA was higher in the current year due to increased sales volumes and price.
      Net income in 2004 was $175.4 million, or $1.38 per share, an increase of 459.5% over 2003 net income of $31.3 million, or $0.29 per share. The increase in net income was primarily due to improved operating results and acquisitions in 2004, and the impact in 2003 of $53.5 million in pretax early debt extinguishment charges and a $10.1 million after tax charge for the cumulative effect of accounting changes.

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Revenues
                                   
            Increase (Decrease)
    Year Ended   Year Ended   to Revenues
    December 31,   December 31,    
    2004   2003   $   %
                 
    (dollars in thousands)
Sales
  $ 3,545,027     $ 2,729,323     $ 815,704       29.9 %
Other revenues
    86,555       85,973       582       0.7 %
                         
 
Total revenues
  $ 3,631,582     $ 2,815,296     $ 816,286       29.0 %
                         
      Revenues increased by 29.0%, or $816.3 million, over the prior year. The acquisition of three mines in April 2004 contributed $335.0 million of total revenue and 11.0 million tons during the year. Excluding revenues from current year acquisitions, U.S. Mining revenues increased $375.4 million, and revenues from our brokerage operations increased $110.9 million on higher pricing and volume worldwide. Our average sales price per ton increased 14.6% during 2004 due to increased overall demand, which has driven pricing higher, most notably in Appalachia, and a change in sales mix. The sales mix has benefited from the increase in sales from the Australian segment, where per ton prices are higher than in domestic markets. In addition to geographic mix changes, our 2004 revenues included a greater proportion of higher priced metallurgical coal sales (our highest value product). Pricing of metallurgical coal has been responding to increased international demand for the product. We sell metallurgical coal from our Eastern U.S. and Australian Mining operations. Other revenues were relatively unchanged from prior year.
      In our Eastern U.S. Mining operations, revenues increased $302.8 million, or 25.3%, as a result of higher pricing and volumes from strong steam and metallurgical coal demand. Production increases at most eastern mines more than offset lower than expected production at certain of our mines and contract sources as a result of geologic difficulties, congestion-related shipping delays and hurricane-related production disruptions and delays. Appalachian revenues led the Eastern U.S. increase, benefiting the most from price increases while also increasing production and sales volumes. Revenues in Appalachia increased $188.1 million, or 37.0%, while in the Midwest, revenues increased by $114.7 million, or 16.6%. Revenues in our Western U.S. Mining operations increased $171.6 million, or 14.0% on both increased volumes and prices. However, the primary driver of increased revenues in the West was a 12.6 million ton increase in sales volume. Growth in volumes were primarily in the Powder River Basin operations, where revenues were up $58.6 million, or 7.5%, and from the addition of the Twentymile Mine in April which added $99.0 million to sales. Powder River Basin production and sales volumes were up as a result of stronger demand for the mines’ low-sulfur product, which overcame difficulties with rail service, downtime at the North Antelope Rochelle Mine to upgrade the loading facility and poor weather, which impaired production early in the year. Revenues in our Australian Mining operations increased $241.5 million compared to 2003 due primarily to the acquisition of two operating mines during 2004 and benefiting from higher overall pricing for our products there.

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Segment Adjusted EBITDA
      Our total segment Adjusted EBITDA of $773.9 million for the full year was $169.9 million higher than 2003 segment Adjusted EBITDA of $604.0 million, and was composed of the following:
                                   
            Increase (Decrease) to
            Segment Adjusted
    Year Ended   Year Ended   EBITDA
    December 31,   December 31,    
    2004   2003   $   %
                 
    (Dollars in thousands)
Western U.S. Mining
  $ 402,131     $ 357,021     $ 45,110       12.6 %
Eastern U.S. Mining
    280,357       198,964       81,393       40.9 %
Australian Mining
    50,372       2,225       48,147       2163.9 %
Trading and Brokerage
    41,039       45,828       (4,789 )     (10.4 )%
                         
 
Total Segment Adjusted EBITDA
  $ 773,899     $ 604,038     $ 169,861       28.1 %
                         
      Western U.S. Mining operations Adjusted EBITDA increased $45.1 million during 2004, margin per ton increased $0.07, or 2.5%, while sales volume increased 12.6 million tons. The April 2004 acquisition of the Twentymile Mine contributed to $31.2 million of Adjusted EBITDA increase and sales volume, adding 6.2 million tons of the volume increase in 2004. An increase of $20.0 million in Adjusted EBITDA in the Powder River Basin, due primarily to increases in sales volume, contributed most of the remaining improvement in the West. Our Powder River Basin operations continued to benefit from strong demand, leading to record shipping levels which overcame the effects of a planned outage earlier in the year to increase throughput at our North Antelope Rochelle Mine, rail service problems throughout the year and the shutdown of our Big Sky Mine at the end of 2003. Results in the Southwest approximated prior year levels, as pricing improvements generally offset higher costs for fuel and explosives.
      Adjusted EBITDA from our Eastern U.S. Mining operations increased $81.4 million, or 40.9%, compared to prior year due to an increase in margin per ton of $1.11, or 25.8%, and an increase in volume of 5.4 million tons, or 11.7%. Improved pricing led to increased margins in our Eastern operations, despite higher processing costs incurred to upgrade from steam to metallurgical quality, the cost of substitute coal purchases to enable production to be sold in higher-value metallurgical coal markets, hurricane-related transportation and production interruption and increased fuel and steel costs. Appalachia operations drove the improvement in the East with a $101.5 million increase in Adjusted EBITDA. The Appalachia region benefited from strong demand driven pricing and volume and increased higher-priced metallurgical coal sales. Our operations in Appalachia also benefited during the current year from $21.0 million in insurance recoveries and a $9.6 million increase in earnings from our equity interest in a joint venture, more than offsetting higher costs due to equipment and geologic difficulties at a mine in Kentucky. Adjusted EBITDA in the Midwest was $20.1 million less than prior year as increased production and sales, as well as higher overall sales prices, did not overcome poor geologic conditions at certain mines, higher equipment repair costs and higher fuel and steel costs.
      Our Australian Mining operations Adjusted EBITDA increased $48.1 million in the current year. Our acquisition of two mines in April 2004 added 4.8 million tons and increased overall sales volume to 6.1 million tons. Most of the increase in sales tonnage was in higher margin metallurgical coal sales, driving a margin per ton increase of $6.55, or nearly 400%. The current year acquisitions contributed $43.1 million of Adjusted EBITDA in 2004.
      Trading and Brokerage Adjusted EBITDA decreased $4.8 million from the prior year primarily due to higher brokerage results in the prior year. Adjusted EBITDA from trading activities increased over prior year due to improved pricing on our long position.

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Reconciliation of Segment Adjusted EBITDA to Income (Loss) Before Income Taxes and Minority Interests
                                 
            Increase (Decrease)
    Year Ended   Year Ended   to Income
    December 31,   December 31,    
    2004   2003   $   %
                 
    (Dollars in thousands)
Total Segment Adjusted EBITDA
  $ 773,899     $ 604,038     $ 169,861       28.1 %
Corporate and Other Adjusted EBITDA
    (214,655 )     (193,760 )     (20,895 )     (10.8 )%
Depreciation, depletion and amortization
    (270,159 )     (234,336 )     (35,823 )     (15.3 )%
Asset retirement obligation expense
    (42,387 )     (31,156 )     (11,231 )     (36.0 )%
Early debt extinguishment costs
    (1,751 )     (53,513 )     51,762       96.7 %
Interest expense
    (96,793 )     (98,540 )     1,747       1.8 %
Interest income
    4,917       4,086       831       20.3 %
                         
Income (loss) before income taxes and minority interests
  $ 153,071     $ (3,181 )   $ 156,252       n/a  
                         
      Total segment Adjusted EBITDA of $773.9 million for the current year is compared with $604.0 million from the prior year in the discussion above. Corporate and Other Adjusted EBITDA results include selling and administrative expenses, net gains on asset disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development, resource management and our Venezuelan mining operations. The increase in Corporate and Other Adjusted EBITDA (net expense) in 2004 compared to 2003 was primarily due to:
  •  net gains on asset sales were $8.8 million higher in the prior year. The prior year includes gains of $18.8 million on the sale of land, coal reserves and oil and gas rights, $6.4 million of other asset disposals, and $7.6 million from the sale of 1.15 million units of Penn Virginia Resource Partners LP (“Penn Virginia”), while the current year includes gains of only $8.0 million from other asset disposals and a $15.8 million gain from the sale of a total of 0.775 million units of Penn Virginia in two separate transactions;
 
  •  increased costs in 2004 for generation development ($5.3 million) related to the further development of the Prairie State and Thoroughbred Energy campuses;
 
  •  higher selling and administrative expenses of $34.5 million, primarily associated with higher long-term incentive costs ($17.8 million), pensions, an increase in outside services costs (including costs related to compliance with the Sarbanes-Oxley Act) and the impact of current year acquisitions; and
 
  •  a $2.9 million increase in our accrual for future environmental obligations.
      These increased costs compared to prior year were partially offset by:
  •  lower costs ($29.0 million) in 2004 associated with past mining obligations, primarily lower retiree health care costs from the passage of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 and lower closed and suspended mine spending;
 
  •  contributions ($1.2 million) to Adjusted EBITDA from the December 2004 acquisition of a 25.5% interest in the Paso Diablo Mine in Venezuela.
      Depreciation, depletion and amortization increased $35.8 million during 2004 due to higher volume and acquisitions. Asset retirement obligation expense increased $11.2 million during the year due to increased or accelerated reclamation work at certain closed mine sites and the acquisition of additional mining operations during the year.

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      Debt extinguishment costs were $51.8 million higher in the prior year due to the significant prepayment premiums associated with the March 2003 refinancing, discussed in Note 13 to our consolidated financial statements.
Net Income
                                   
            Increase (Decrease)
    Year Ended   Year Ended   to Income
    December 31,   December 31,    
    2004   2003   $   %
                 
    (Dollars in thousands)
Income (loss) before income taxes and minority interests
  $ 153,071     $ (3,181 )   $ 156,252       n/a  
 
Income tax benefit
    26,437       47,708       (21,271 )     (44.6 )%
 
Minority interests
    (1,282 )     (3,035 )     1,753       57.8 %
                         
Income from continuing operations
    178,226       41,492       136,734       329.5 %
 
Loss from discontinued operations
    (2,839 )           (2,839 )     n/a  
                         
Income before accounting changes
    175,387       41,492       133,895       322.7 %
 
Cumulative effect of accounting changes
          (10,144 )     10,144       n/a  
                         
Net income
  $ 175,387     $ 31,348     $ 144,039       459.5 %
                         
      The increase of $144.0 million in net income from 2003 to 2004 was due to the increase in income (loss) before income taxes and minority interests ($156.3 million) discussed above and the impacts of the following:
  •  a $21.3 million lower tax benefit in 2004. The tax benefit recorded in 2004 differs from the benefit in 2003 primarily as a result of significantly higher pre-tax income, partially offset by the higher permanent benefit of percentage depletion. The 2004 tax benefit also included a net $25.9 million reduction in the valuation allowance on those net operating loss carry-forwards (“NOL’s”) and alternative minimum tax credits. We evaluated and assessed the expected near-term utilization of NOL’s, book and taxable income trends, available tax strategies and the overall deferred tax position to determine the amount and timing of valuation allowance adjustments;
 
  •  a $2.8 million loss, net of tax, from discontinued operations in the current year due to costs to resolve a contract indemnification claim related to our former Citizens Power subsidiary;
 
  •  lower minority interests during 2004 due to the acquisition in April 2003 of the remaining 18.3% of Black Beauty Coal Company; and
 
  •  a charge in 2003 for the cumulative effect of accounting changes, net of income taxes, of $10.1 million, relating to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations,” the change in method of amortization of actuarial gains and losses related to net periodic postretirement benefit costs and the effect of the recession of EITF No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as discussed in Note 6 to the consolidated financial statements.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
Summary
      In 2003, our revenues rose to $2.82 billion, a 3.5% 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.

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      Our segment Adjusted EBITDA totaled $604.0 million for the full year, compared with $616.3 million in the prior year. Excluding $37.1 million in contract settlements from Western U.S. Mining’s 2002 results, segment Adjusted EBITDA improved $24.8 million. The improvement was due to higher Western U.S. Mining and Trading and Brokerage results, which more than offset a decrease in Eastern U.S. Mining Adjusted EBITDA results.
      Net income in 2003 totaled $31.3 million, or $0.29 per share, compared with $105.5 million, or $0.98 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.
Revenues
                                   
            Increase (Decrease)
    Year Ended   Year Ended   to Revenues
    December 31,   December 31,    
    2003   2002   $   %
                 
    (Dollars in thousands)
Sales
  $ 2,729,323     $ 2,630,371     $ 98,952       3.8 %
Other revenues
    85,973       89,267       (3,294 )     (3.7 )%
                         
 
Total revenues
  $ 2,815,296     $ 2,719,638     $ 95,658       3.5 %
                         
      Overall, our revenues increased 3.5% 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 (Wilkie Creek) 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 5.4% 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. 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.

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Segment Adjusted EBITDA
      Our total segment Adjusted EBITDA was $604.0 million for the year ended December 31, 2003, compared with $616.3 million for the full year 2002, broken down as follows:
                                   
            Increase (Decrease)
            Segment Adjusted
    Year Ended   Year Ended   EBITDA
    December 31,   December 31,    
    2003   2002   $   %
                 
    (Dollars in thousands)
Western U.S. Mining
  $ 357,021     $ 356,392     $ 629       0.2 %
Eastern U.S. Mining
    198,964       219,940       (20,976 )     (9.5 )%
Australian Mining
    2,225       3,007       (782 )     (26.0 )%
Trading and Brokerage
    45,828       36,984       8,844       23.9 %
                         
 
Total Segment Adjusted EBITDA
  $ 604,038     $ 616,323     $ (12,285 )     (2.0 )%
                         
      Adjusted EBITDA from our Western U.S. Mining operations increased $0.6 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 $37.7 million, and our margin per ton improved $0.27, 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 Eastern operations decreased $21.0 million (margin per ton decreased $0.27, or 6%) as a result of a $32.9 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 $12.0 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 and ramp-up issues at the new Vermilion Grove portal of the Riola Mine.
      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 is expected to 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 was converted to cash during 2004.

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Reconciliation of Segment Adjusted EBITDA to Income (Loss) Before Income Taxes and Minority Interests
                                 
            Increase (Decrease)
    Year Ended   Year Ended   to Income
    December 31,   December 31,    
    2003   2002   $   %
                 
    (Dollars in thousands)
Total Segment Adjusted EBITDA
  $ 604,038     $ 616,323     $ (12,285 )     (2.0 )%
Corporate and Other Adjusted EBITDA
    (193,760 )     (210,222 )     16,462       7.8 %
Depreciation, depletion and amortization
    (234,336 )     (232,413 )     (1,923 )     (0.8 )%
Asset retirement obligation expense
    (31,156 )           (31,156 )     n/a  
Early debt extinguishment costs
    (53,513 )           (53,513 )     n/a  
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 )     n/a  
                         
      Our total segment Adjusted EBITDA was $604.0 million for the full year, compared with $616.3 million in the prior year (discussed above). Corporate and Other Adjusted EBITDA results include selling and administrative expenses, net gains on asset 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 results 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;
 
  •  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 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 13 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 6 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.

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Net Income
                                   
            Increase (Decrease)
    Year Ended   Year Ended   to Income
    December 31,   December 31,    
    2003   2002   $   %
                 
    (Dollars in thousands)
Income (loss) before income taxes and minority interests
  $ (3,181 )   $ 78,804     $ (81,985 )     n/a  
 
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 )     n/a  
                         
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 6 to the consolidated financial statements.
Outlook
      Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as there continues to be growth in the U.S., Chinese, Pacific Rim and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. Published indices also show improved year-over-year coal prices in most U.S. and global coal markets, and world-wide coal supply/demand fundamentals remain tight due to market demand and transportation and production infrastructure limitations in most countries. Metallurgical coal is generally selling at a significant premium to steam coal. We expect our recently acquired Australian operations, which produce primarily metallurgical coal, to further enable us to capitalize on the strong global coal markets.
      In the United States, we expect coal demand to remain strong in 2005, assuming continued economic strength, normal weather, and available transportation for coal. Strong demand for coal and coal-based electricity generation is being driven by the strengthening economy, low customer stockpiles, production difficulties for some producers, capacity constraints of nuclear generation and high prices of natural gas and oil. The high price of natural gas is leading coal-fueled generating plants to operate at increasing levels. We expect that high costs and unpredictable supplies of oil and natural gas are likely to remain for the foreseeable future. Current average inventories at U.S. generators are estimated to be below five-year averages and coal-fueled electricity generation is expected to increase to record levels. Generation from nuclear power is currently constrained by capacity.
      We expect the Powder River Basin to remain the largest and fastest-growing region in the United States for coal production due to its abundant coal reserves, low sulfur content and low mining costs. Year-to-year fluctuations in demand will occur based on weather and the strength of the economy. A

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number of customers plan test burns and increased use of blending to reduce the supply/demand imbalance of Central Appalachian coals. Strong demand is also expected for coals from Colorado, the Midwest and Northern Appalachia.
      We are targeting 2005 production of 210 million to 220 million tons and total sales volume of 240 million to 250 million tons, including 12 to 14 million tons of metallurgical coal. Over 95% of our total production in 2005 has been priced (including 90% of our metallurgical coal production).
      Management expects strong market conditions and operating performance to overcome external cost pressures and adverse rail and port performance. We are experiencing increases in operating costs related to fuel, explosives, steel and healthcare, and have taken measures to mitigate the increases in these 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, lower third party contract miner or brokerage source performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating difficulties, 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 our employees’ 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, 2004 for these liabilities totaled $146.0 million, while payments were $194.2 million, including a $50.0 million voluntary pre-funding of one pension plan.
      Each of these liabilities is 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 injury and illness 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)
  $ 7,960     $ (5,462 )
Effect on total postretirement benefit obligation(1)
  $ 138,793     $ (116,488 )
      Discount rate (dollars in thousands):
                 
    One Half   One Half
    Percentage-Point   Percentage-Point
    Increase   Decrease
         
Effect on total service and interest cost components(1)
  $ 987     $ (1,150 )
Effect on total postretirement benefit obligation(1)
  $ (65,051 )   $ 71,496  
 
(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, 2004.
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.” Our asset retirement obligations primarily consist of spending estimates related to surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mining permit.
      The asset retirement obligation is determined by mine and we use various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2004 was $42.4 million, and payments totaled $45.8 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, 2004 were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials, and one percent of our contracts were valued based on similar market transactions. As of December 31, 2004, one hundred percent of the estimated future value of our trading portfolio was scheduled to be realized by the end of 2005.

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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 our annual evaluation of the need for a valuation allowance, we take into account various factors, including the expected level of future book and taxable income trends, available tax planning strategies and the overall deferred tax position. If actual results differ from the assumptions made in our annual evaluation of our valuation allowance, we may record a change in valuation allowance through income tax expense in the period such determination is made.
      We establish reserves for tax contingencies when, despite the belief that our tax return positions are fully supported, certain positions are likely to be challenged and may not be fully sustained. The tax contingency reserves are analyzed on a quarterly basis and adjusted based upon changes in facts and circumstances, such as the progress of federal and state audits, case law and emerging legislation. Our effective tax rate includes the impact of tax contingency reserves and changes to the reserves, including related interest, as considered appropriate by management. We establish the reserves based upon management’s assessment of exposure associated with permanent tax differences (i.e. tax depletion expense, etc.) and certain tax sharing agreements. We are subject to federal audits for several open years due to our previous inclusion in multiple consolidated groups and the various parties involved in finalizing those years.
Revenue Recognition
      In general, we recognize revenues when they are realizable and earned. We generated 98% of our revenue in 2004 from the sale of coal to our customers. Revenue from coal sales is realized and earned when risk of loss passes to the customer. Coal sales are made to our customers under the terms of supply agreements, most of which are long-term (greater than one year). Under the typical terms of these agreements, risk of loss transfers to the customers at the mine or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source(s) that delivers coal to its destination.
      With respect to other revenues, other operating income, or gains on asset sales recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and apply the relevant accounting literature as appropriate, and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller’s price to the buyer is fixed or determinable; and collectibility is reasonably assured.
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, sales of non-core assets and debt and equity offerings related to significant transactions. Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs, costs related to past mining obligations and planned acquisitions and development activities. 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 during 2004 and 2003 have had no borrowings outstanding under our $900.0 million Revolving Credit Facility, which we use primarily for standby letters of credit. This provides us with available borrowing capacity ($554.1 million as of December 31, 2004) to use to fund strategic acquisitions or meet other financing needs.
      Operating activities provided $283.8 million of cash in 2004, an increase of $94.9 million compared with prior year. A $136.7 million increase in net income from continuing operations was the primary contributor to the improvement. Partially offsetting this increase was higher pension plan funding of

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$44.6 million. During the second quarter of 2004, we electively funded $50.0 million to one pension plan, the remaining $12.1 million of current year pension funding was toward minimum funding obligations for our pension plans. By contrast, contributions were $17.5 million in the prior year, $9.9 million of which was voluntary.
      Net cash used in investing activities was $705.0 million in 2004, $512.8 million more than prior year. Investment spending in 2004 includes $421.3 million for the acquisition of the Twentymile Mine in Colorado and two mines in Australia. In the prior year, we spent $90.0 million to acquire the remaining 18.3% of Black Beauty Coal Company. Capital spending of $266.6 million in the current year was $110.2 million more than prior year expenditures of $156.4 million. Current year spending included a large loading facility upgrade in our Powder River Basin operations, $114.7 million of initial payments related to the successful acquisition of a total of 621 million tons of Powder River Basin coal reserves, and equipment purchases in the Midwest and at Australian mines acquired during 2004. In December 2004, we acquired a 25.5% interest in Carbones del Guasare, which owns and manages the Paso Diablo mine in Venezuela, for a net purchase price of $32.5 million. Proceeds from property and equipment disposals were $30.2 million lower than prior year primarily due to the sale of oil and gas rights, land and coal reserves and surplus surface land in Appalachia in 2003, with no comparable transactions in 2004.
      Financing activities provided $693.4 million in 2004 compared with $48.6 million in the prior year, an increase of $644.8 million. The current year included net proceeds from our March 2004 debt and equity offerings of $627.8 million. We issued 17.65 million common shares at $22.50 per share, raising $383.1 million after deducting underwriting discounts, commissions and other expenses, and $250 million from our issuance of 5.875% Senior Notes due in 2016. During the fourth quarter of 2004, we completed a repricing of our Senior Secured Credit Facility, consisting of an amended $450 million Term Loan and a $900 million Revolving Credit Facility. As a result of the repricing, the previous term loan was extinguished and a new loan with nearly identical terms, but a lower interest rate, was issued. The previous Term Loan had been repriced during the first quarter of 2004 concurrent with a $300 million increase in capacity of the revolving loan. Additional payments on long-term debt in 2004 were $36.3 million. During the first half of 2003, we refinanced our debt utilizing proceeds from long-term debt of $1.1 billion to, among other things, repay line of credit borrowings of $121.6 million and 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 prior year included other debt repayments of $37.4 million. Securitized interest in accounts receivable increased $110.0 million in 2004 compared to a decrease of $46.4 million in the prior year. Financing cash flows in the current and prior year periods included dividends of $32.6 million and $24.1 million, respectively. A detailed discussion of our debt instruments and refinancing activity is included in Note 13 to our consolidated financial statements. Dividends are subject to limitations imposed by our 6.875% Senior Notes, 5.875% Senior Notes and Senior Secured Credit Facility covenants.
      As of December 31, 2004 and 2003, our total indebtedness consisted of the following (dollars in thousands):
                   
    December 31,
     
    2004   2003
         
Term Loan under Senior Secured Credit Facility
  $ 448,750     $ 446,625  
6.875% Senior Notes due 2013
    650,000       650,000  
5.875% Senior Notes due 2016
    239,525        
Fair value of interest rate swaps — 6.875% Senior Notes
    5,189       4,239  
5.0% Subordinated Notes
    73,621       79,412  
Other
    7,880       16,263  
             
 
Total
  $ 1,424,965     $ 1,196,539  
             
      We filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission in October 2003, which was declared effective in March 2004, allowing us to offer and sell from time to time

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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. The 2004 debt and equity offerings noted above were made under this universal shelf registration statement, which remains in effect. The shelf registration statement has a remaining capacity of $602.9 million. Related proceeds could 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, 2004, there were no outstanding borrowings under our Revolving Credit Facility. We had letters of credit outstanding under the facility of $345.9 million, leaving $554.1 million available for borrowing. We were in compliance with all of the covenants of the Senior Secured Credit Facility, the 6.875% Senior Notes, the 5.875% Senior Notes, and the 5.0% Subordinated Notes as of December 31, 2004.
      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, we pay 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 receive a fixed rate of 6.875%. The average applicable floating rate of the four swaps was 5.14% as of December 31, 2004. At current LIBOR levels, we would realize annualized savings of approximately $1.7 million over the term of the swaps.
      In September 2003, we 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 designated as a hedge of changes in expected cash flows on the term loan under the Senior Secured Credit Facility. Under this swap we pay a fixed rate of 6.764% and receive a floating rate of LIBOR plus 2.5% (4.99% at December 31, 2004) that resets each March 15, June 15, September 15 and December 15 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, we pay a floating rate of LIBOR plus 1.97% (4.46% at December 31, 2004) that resets each March 15, June 15, September 15 and December 15 based upon the three-month LIBOR rate and receive a fixed rate of 6.875%. The swaps will lower our overall borrowing costs on $400.0 million of debt principal by 0.64% over the term of the floating-to-fixed swap. This results in annual interest savings of $2.6 million over the term of the fixed-to-floating swap.
      The following is a summary of specified types of commercial commitments available to us as of December 31, 2004 (dollars 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
  $ 900,000                       $ 900,000  
      In October 2004, our board of directors approved a 20% increase in the regular quarterly dividend on common stock, to $0.075 per share.

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Contractual Obligations
      The following is a summary of our significant contractual obligations as of December 31, 2004 (dollars in thousands):
                                   
    Payments Due by Year
     
    Within       After
    1 Year   2-3 Years   4-5 Years   5 Years
                 
Long-term debt obligations (principal and interest)
  $ 95,126     $ 243,516     $ 460,966     $ 1,234,582  
Capital lease obligations
    892       790       38        
Operating leases obligations
    92,817       138,097       69,960       49,417  
Unconditional purchase obligations(1)
    141,822       5,677              
Coal reserve lease and royalty obligations
    79,035       274,562       207,656       52,996  
Other long-term liabilities(2)
    172,582       344,892       355,376       908,744  
                         
 
Total contractual cash obligations
  $ 582,274     $ 1,007,534     $ 1,093,996     $ 2,245,739  
                         
 
(1)  We have purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material. The commitments in the table above relate to significant capital purchases.
 
(2)  Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans and mine reclamation and end of mine closure costs.
      We had $147.5 million of purchase obligations related to future capital expenditures at December 31, 2004. Commitments for coal reserve-related expenditures, including Federal Coal Leases, are included in “Coal reserve lease and royalty obligations” in the table above. The contractual commitments detailed in the table above do not include expenditures related to the Federal Coal Lease bid that was won in February 2005 and the related tons are not included in our reserves.
      Total capital expenditures for 2005 are expected to range from $450 million to $500 million. Approximately 50% of projected 2005 capital expenditures relates to the Federal Coal Leases and longwall equipment at the Twentymile Mine and longwall replacement components in Australia, and the remainder is expected be used to purchase or develop reserves, replace or add equipment, fund cost reduction initiatives and upgrade equipment and facilities at the operations we recently acquired. We anticipate funding these capital expenditures primarily 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 2005 is reduced by our high level of sales commitments (over 95% of 2005 planned production), improved pricing 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.

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      We use a combination of surety bonds, corporate guarantees (i.e. self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement benefits and coal lease obligations as follows as of December 31, 2004 (dollars in millions):
                                                 
            Workers’   Retiree        
    Reclamation   Lease   Compensation   Healthcare        
    Obligations   Obligations   Obligations   Obligations   Other(1)   Total
                         
Self Bonding
  $ 653.3     $     $     $     $     $ 653.3  
Surety Bonds
    294.5       134.3       91.7             27.6       548.1  
Letters of Credit
    0.4       25.1       72.9       120.1       130.7       349.2  
                                     
    $ 948.2     $ 159.4     $ 164.6     $ 120.1     $ 158.3     $ 1,550.6  
                                     
 
(1)  Includes financial guarantees primarily related to joint venture debt, the Pension Benefit Guarantee Corporation and collateral for surety companies.
      We have guaranteed $9.2 million of debt of an affiliate in which we have a 49% equity investment, as described in Note 22 to our consolidated financial statements. Our remaining guarantees and indemnifications are discussed in Note 22 to our consolidated financial statements.
      In March 2000, we established an accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been contributed to the Seller are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (“Conduit”). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We used proceeds from the sale of our accounts receivable in lieu of drawing down on our revolving credit facility or to repay long-term debt, effectively reducing our overall borrowing costs. On September 16, 2004, we and our wholly-owned, bankruptcy-remote subsidiary closed on an expansion of the accounts receivable securitization facility. Under the terms of the amended agreement, the total facility capacity was increased from $140 million to $225 million and the receivables of additional wholly-owned subsidiaries of ours are now eligible to participate in the facility. The maturity of the facility was also extended to September 2009. All other terms and conditions remain substantially unchanged. The funding cost of the securitization program was $1.7 million and $2.3 million for the year ended December 31, 2004 and 2003, respectively. 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 $200.0 million and $90.0 million as of December 31, 2004 and 2003, respectively. A detailed description of our $225.0 million accounts receivable securitization is included in Note 4 to our consolidated financial statements.
Accounting Pronouncements Not Yet Implemented
      On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004), Share-Based Payment, or “SFAS No. 123(R),” which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends FASB Statement No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.
      SFAS No. 123(R) must be adopted no later than July 1, 2005 (for calendar year companies), and we expect to adopt the standard on that date, using one of the two methods permitted by SFAS No. 123(R), described below:
  •  A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments

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  granted after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date.
 
  •  A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.
      As permitted by SFAS No. 123, we currently account for share-based payments to employees using APB Opinion No. 25’s intrinsic value method and, as such, generally recognize no compensation cost for employee stock options. Accordingly, the adoption of SFAS No. 123(R)’s fair value method will have an impact on our results of operations, although it will have no impact on our overall financial position. Had we adopted SFAS No. 123(R) in prior periods, the impact of that standard would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in Note 1 to our consolidated financial statements. The precise impact of the adoption of SFAS No. 123(R) on us in 2005 and beyond cannot be predicted at this time because it will depend on levels of equity-based compensation granted in the future. However, because we make our annual equity-based compensation grants in January, prior to the issuance of our financial statements, an estimate of the impact of the adoption of SFAS No. 123(R) on 2005 net income can be made. Based on stock option grants made in January 2005, considering option grants outstanding in 2005 made prior to 2005, and assuming no additional stock option grants in 2005 beyond January 2005, we anticipate (assuming the modified prospective method is used) recognizing expense for stock options for the period from July 1, 2005 to December 31, 2005 of $2.3 million, net of taxes. It should be noted that annual equity-based compensation grants in years prior to 2005 consisted of a higher number of stock options than the grant made in 2005. For the January 2005 grant, we delivered comparable equity-based compensation value by granting a combination of stock options and restricted stock. Prior to January 2005, we had not previously granted restricted stock as part of our annual compensation strategy. Expense related to restricted stock (which vests over five years, and assuming no grants beyond January 2005) is anticipated to be approximately $0.8 million, net of taxes, in 2005.
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, 2004, 90% of our sales volume was sold under long-term coal supply agreements. At December 31, 2004, our coal supply agreements had remaining terms ranging from one to 17 years and an average volume-weighted remaining term of approximately 3.4 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

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could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements permit the customer to terminate the contract if transportation costs, which our customers typically bear, increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.
      The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Market prices for coal decreased in most regions in 2002. In 2003, pricing improved for eastern coal regions and moved slightly higher for western coal regions, and in 2004 pricing was substantially higher for the eastern coal regions and slightly higher for western coal regions. As a result, we cannot predict the future strength of the coal market and cannot assure you that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, two of our largest 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, 2004, we derived 25% of our total coal revenues from sales to our five largest customers. At December 31, 2004, we had 45 coal supply agreements with these customers expiring at various times from 2005 to 2011. 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. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to the operation of the Mohave plant beyond 2005 or the temporary or permanent shutdown of the plant. In a July 2003 filing with the California Public Utilities Commission, the operator affirmed that the Mohave plant was not forecast to return to service as a coal-fueled resource until mid-2009 at the earliest if the plant is shutdown at December 31, 2005. Southern California Edison has subsequently reaffirmed this forecast to the Commission. On December 2, 2004, the California Public Utilities Commission issued an opinion authorizing Southern California Edison to make necessary expenditures at the Mohave plant to preserve the “Mohave-open” option while Southern California Edison continues to seek resolution of the water and coal issues. The opinion stated that its goal was to return the Mohave plant to service with as short of a shut-down period as possible. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline from Peabody Western’s Black Mesa Mine to the Mohave plant. As a part of the alternate dispute resolution referenced in the Navajo Nation litigation, Peabody Western has been negotiating with the owners of the Mohave Generating Station and the Navajo Generating Station, and the two tribes to resolve the complex issues surrounding the groundwater dispute and other disputes involving the two generating stations. Resolution of these issues is critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. If these issues are not resolved in a timely manner, the operation of the Mohave plant will cease or be suspended on December 31, 2005. Absent a satisfactory alternate dispute resolution, it is unlikely that the coal supply agreement for the Mohave plant will be renewed in time to avoid a shutdown of the mine in 2006. The Mohave plant is the sole customer of the Black Mesa Mine,

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which sold 4.7 million tons in 2004. In 2004, the mine generated $25.2 million of Adjusted EBITDA, which represents 4.5% of our total of $559.2 million.
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, 2004, our total indebtedness was approximately $1,425.0 million, and we had $554.1 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
 
  •  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 sufficient 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 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, which account for less than 5% of our tons sold, permit the customer to terminate the contract if the cost of transportation increases by an amount ranging from 10% to 20% in any given 12-month period.
      Coal producers depend upon rail, barge, trucking, overland conveyor, pipeline and ocean-going vessels to deliver coal to markets. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, strikes, lock-outs, transportation delays or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations. For

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example, the high volume of coal shipped from all Powder River Basin mines could create temporary congestion on the rail systems servicing that region.
      Continued increases in coal demand, combined with many customers’ inventories that are lower than historical averages, created periodic regional rail and port congestion in 2004. To the extent rail or port congestion constrains our operations’ ability to successfully ship coal to our customers, our operating results will be reduced.
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.
Our mining operations are extensively regulated, 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 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, which took effect in February 2005. 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 Department of Energy’s Energy Information Administration Emissions of Greenhouse Gases in the United States 2003, coal accounts for 31% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. 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.

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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 $1,020.8 million as of December 31, 2004, $81.3 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 guarantee 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 guarantee.
      In addition, certain of our subsidiaries participate in two defined benefit multi-employer pension funds that were established as a result of collective bargaining with the United Mine Workers of America (UMWA) pursuant to the National Bituminous Coal Wage Agreement as periodically negotiated. The UMWA 1950 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked prior to January 1, 1976. This is a closed group of beneficiaries with no new entrants. The UMWA 1974 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked after December 31, 1975.
      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 funding deficiencies.
      The United Mine Workers of America Combined Fund was created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of out of business companies who were receiving benefits as orphans prior to the 1992 law; no new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan also created by the same federal law in 1992 provides benefits to qualifying retired former employees of companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. Another fund, the 1993 Benefit Fund was established through collective bargaining and provides retiree medical benefits to qualifying retired former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business.

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      Based upon the enactment of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, we assumed future cash savings which allowed us to reduce our projected post-retirement benefit obligations and related expense. Failure to achieve these assumed future savings under all benefit plans could adversely affect our financial condition, results of operations and cash flow.
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, 2004, we leased a total of 60,140 acres from the federal government and added an additional 17,598 through February 2005. The limit could restrict our ability to lease additional federal lands. For additional discussion of our federal leases see Item 2. Properties of this Annual Report on Form 10-K.
      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.
A decrease in the production of our metallurgical coal (or other high-margin products) or a decrease in the price of metallurgical coal (or other high-margin products) could decrease our anticipated profitability.
      We more than doubled our sales of metallurgical coal in 2004, primarily as a result of the acquisition of coal operations in Australia in April 2004. Our current annual capacity for metallurgical coal production is approximately 12 to 14 million tons. Prices for metallurgical coal in late 2004 and early 2005 have reached historically high levels. We have committed 90% of our projected 2005 metallurgical coal production at significantly higher prices than in the past. As a result, our projected margins from these sales have increased significantly, and will represent a larger percentage of our overall revenues and profits in 2005. To the extent we experience either production or transportation difficulties that impair our ability to ship metallurgical coal to our customers at anticipated levels, our profitability will be reduced in 2005.
      After 2005, we have metallurgical coal production that has not yet been priced. As a result, a decrease in metallurgical coal prices could decrease our profitability beyond 2005.

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An inability of contract miner or brokerage sources to fulfill the delivery terms of their contracts with us could reduce our profitability.
      In conducting our trading, brokerage and mining operations, we utilize third party sources of coal production, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon the reliability (including financial viability) and price of the third-party supply, our obligation to supply coal to customers in the event that adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market, and other factors.
If the coal industry experiences overcapacity in the future, our profitability could be impaired.
      During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in added production capacity throughout the industry, all of which led to increased competition and lower coal prices. Similarly, continued increases 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.
We could be negatively affected if we fail to maintain satisfactory labor relations.
      As of December 31, 2004, we and our subsidiaries had approximately 7,900 employees. As of December 31, 2004, approximately 40% of our hourly employees were represented by unions and they generated 21% of our 2004 coal production. Relations with our employees, and where applicable, organized labor, are important to our success.
United States
      The United Mine Workers of America represented approximately 30% of our hourly employees, who generated 16% of our production during the year ended December 31, 2004. An additional 6% of our hourly employees are represented by labor unions other than the United Mine Workers of America. These employees generated 2% of our production during the year ended December 31, 2004. Hourly workers at our mines in Arizona and one of our mines in Colorado are represented by the United Mine Workers of America under the Western Surface Agreement, which was ratified in 2000 and is effective through September 1, 2005. Our union labor east of the Mississippi River is primarily represented by the United Mine Workers of America and the majority of union mines are subject to the National Bituminous Coal Wage Agreement. The current five-year labor agreement was ratified in December 2001 and is effective through December 31, 2006.
Australia
      The Australian coal mining industry is highly unionized and the majority of workers employed at our Australian Mining Operations are members of trade unions. These employees are represented by three unions: the Construction Forestry Mining and Energy Union (“CFMEU”), which represents the production employees, and two unions that represent the other staff. Our Australian employees are approximately 4% of our entire workforce and generated 3% of our total production in the year ended December 31, 2004. The miners at Wilkie Creek operate under a labor agreement that expires in June 2006. The miners at Burton operate under a labor agreement that is currently under negotiation. The miners at North Goonyella operate under a labor agreement which expires in March 2008. The miners at Eaglefield operate under a labor agreement that expires in May 2007.

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      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 competitors who operate without union labor may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. The 10-month United Mine Workers of America strike in 1993 had a material adverse effect on us.
Our operations could be adversely affected if we fail to appropriately secure our obligations.
      U.S. federal and state laws and Australian laws require us to secure certain of our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. The primary method for us to meet those obligations is to post a corporate guarantee (i.e. self bond) or to provide a third party surety bond. As of December 31, 2004, we had $653.3 million of self bonds in place for our reclamation obligations. As of December 31, 2004, we also had outstanding surety bonds with third parties for post-mining reclamation totaling $294.5 million. We had an additional $91.7 million of surety bonds in place for workers’ compensation obligations and $134.3 million of surety bonds securing coal leases. All other bonding, including performance and infrastructure bonds, totaled $27.6 million. 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. 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 or to provide a suitable alternatives 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.
      Our ability to self bond reduces our costs of providing financial assurances. To the extent we are unable to maintain our current level of self bonding, due to legislative or regulatory changes or changes in our financial condition, our costs would increase.
Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.
      We manage our business with a number of key personnel, the loss of a number of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot assure you that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. We do not have “key person” life insurance to cover our executive officers. Failure to retain or attract key personnel could have a material adverse effect on us.
Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.
      Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations. As a result, there could be delays or losses in transportation and deliveries of coal to

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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 or other customers may have credit ratings that are below investment grade. If deterioration of the creditworthiness of our customers occurs, our $225.0 million accounts receivable securitization program and our business could be adversely affected.
Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.
      Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. For example, a change of control of our company may be delayed or deterred as a result of the stockholders’ rights plan adopted by our board of directors. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
      The potential for changes in the market value of our coal trading, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading portfolio is evaluated using a value at risk analysis (described below). Value at risk analysis is not used to evaluate our non-trading interest rate and currency portfolios. A description of each market risk category is set forth below. We attempt to manage market risks through diversification, controlling position sizes, and executing hedging strategies. Due to lack of quoted market prices and the long term, illiquid nature of the positions, we have not quantified market risk related to our non-trading, long-term coal supply agreement portfolio.
Coal Trading Activities and Related Commodity Price Risk
      We engage in over-the-counter and direct trading of coal. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure, in value at risk terms, that we may assume at any point in time.
      We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, options, and swaps, at market value in our consolidated financial statements. Our trading portfolio included forwards and swaps at December 31, 2004 and included forwards, futures and options at December 31, 2003. 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 coal trading portfolio, which includes over-the-counter and brokerage trading of coal. The use of value at risk allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. Value at risk represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon (liquidation

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period) within a specified confidence level. Our value at risk model is based on the industry standard variance/co-variance approach. This captures our exposure related to both option and forward positions. Our value at risk model assumes a 15-day holding period and a 95% one-tailed confidence interval. This means that there is a one in 20 statistical chance that the portfolio would lose more than the value at risk estimates during the liquidation period.
      The use of value at risk allows management to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. Due to the subjectivity in the choice of the liquidation period, reliance on historical data to calibrate the models and the inherent limitations in the value at risk methodology, we perform regular stress and scenario analysis to estimate the impacts of market changes on the value of the portfolio. The results of these analyses are used to supplement the value at risk methodology and identify additional market-related risks.
      We use historical data to estimate our value at risk and to better reflect current asset and liability volatilities. Given our reliance on historical data, value at risk is effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. An inherent limitation of value at risk is that past changes in market risk factors may not produce accurate predictions of future market risk. Value at risk should be evaluated in light of this limitation.
      During the year ended December 31, 2004, the actual low, high, and average values at risk for our coal trading portfolio were $0.5 million, $6.1 million, and $2.9 million, respectively. During the year ended December 31, 2003, the actual low, high, and average values at risk for our coal trading portfolio were $0.4 million, $3.2 million, and $1.4 million, respectively. As of December 31, 2004, one hundred percent of the value of our trading portfolio was 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 (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties. Counterparty risk with respect to interest rate swap and foreign currency forwards and options transactions is not considered to be significant based upon the creditworthiness of the participating financial institutions.
Foreign Currency Risk
      We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2005 involves hedging approximately 70% of our anticipated, non-capital Australian dollar-denominated expenditures. As of December 31, 2004, we had in place forward contracts designated as cash flows hedges with notional amounts outstanding totaling $515.0 million of which $285.0 million, $170.0 million and $60.0 million will expire in 2005, 2006 and 2007, respectively. The accounting for these derivatives is discussed in Note 2 to our consolidated financial statements. Our current expectation for 2005 non-capital, Australian dollar-denominated cash expenditures is approximately $600 million. A change in the Australian dollar/ U.S. dollar exchange rate of US$0.01

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(ignoring the effects of hedging) would result in an increase or decrease in our “Operating costs and expenses” of $6.0 million per year.
Interest Rate Risk
      Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed rate debt as a percent of net debt through the use of various hedging instruments, which are discussed in detail in Note 13 to our consolidated financial statements. As of December 31, 2004, after taking into consideration the effects of interest rate swaps, we had $872.9 million of fixed-rate borrowings and $552.1 million of variable-rate borrowings outstanding. A one percentage point 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 in interest rates would result in a $60.7 million decrease in the estimated fair value of these borrowings.
Other Non-trading Activities
      We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 90% of our sales volume under long-term coal supply agreements during 2004 and 2003. As of December 31, 2004, we had sales commitments for over 95% of our 2005 production, leaving 5 to 10 million tons unpriced. Also as of December 31, 2005, we had 65 to 75 million tons and 130 to 140 million tons of expected production available for sale or repricing at market prices for 2006 and 2007, respectively. We have an annual metallurgical coal production capacity of 12 to 14 million tons, all of which is priced for 2005 and none of which is priced beyond March 2006.
      Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage this risk, we use a combination of forward contracts with our suppliers and financial derivative contracts, primarily swap contracts with financial institutions. In addition, we utilize derivative contracts to hedge our commodity price exposure. As of December 31, 2004, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel. Notional amounts outstanding under these contracts, scheduled to expire through 2007, were 76.7 million gallons of heating oil and 28.7 million gallons of crude oil. Overall, we have fixed prices for approximately 90% of our anticipated diesel fuel requirements in 2005.
      We expect to consume approximately 95 million gallons of fuel per year. Based on this usage, a change in fuel prices of one cent per gallon (ignoring the effects of hedging) would result in an increase or decrease in our “Operating costs and expenses” of approximately $1 million per year.
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, 2004 Annual Report to Stockholders.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
      None.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
      As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures

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were effective in timely alerting them to material information relating to our company and its consolidated subsidiaries required to be included in our periodic SEC filings.
Changes in Internal Control Over Financial Reporting
      There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that was conducted during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
      Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance to management and the Board of Directors regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
      Management recognizes its responsibility for establishing a strong ethical culture so that our affairs are conducted according to the highest standards of personal and corporate conduct.
      Our internal control over financial reporting includes those policies and procedures that:
  •  pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
 
  •  provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Directors; and
 
  •  provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the consolidated financial statements.
      Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changing conditions, effectiveness of internal control over financial reporting may vary over time.
      Management assessed the effectiveness of our internal control over financial reporting and concluded that, as of December 31, 2004, such internal control is effective. Management’s assessment of internal control over financial reporting excludes the Australian operations acquired during 2004, as allowed by current SEC regulations related to internal controls involving recently acquired entities. These operations constituted $309.3 million and $251.0 million of total and net assets, respectively; and $235.9 million and $31.2 million of revenues and operating profit, respectively; and such amounts are included in our consolidated financial statements as of and for the year ended December 31, 2004. Management did not assess the effectiveness of internal control over financial reporting at these operations because we continue to integrate these operations into our control environment, thus making it impractical to complete an assessment as of December 31, 2004.
      In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control — Integrated Framework.
      Our Independent Registered Public Accounting Firm, Ernst & Young LLP, with direct access to our Board of Directors through its Audit Committee, have audited the consolidated financial statements we prepared. Their report on the consolidated financial statements is incorporated by reference from our December 31, 2004 Annual Report to Stockholders as referenced in Part II, Item 8. Financial Statements

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and Supplementary Data. Ernst & Young LLP has audited management’s assessment of our internal control over financial reporting, as stated in their report included herein.
Management’s Process to Assess the Effectiveness of Internal Control Over Financial Reporting
      Management’s conclusion on the effectiveness of internal control over financial reporting is based on a thorough and comprehensive evaluation and analysis of the five elements of COSO (shown in italics below), and is based on, but not limited to, the following:
  •  Documentation of entity-wide controls establishing the culture and “tone-at-the-top” of the organization, in support of our Control Environment, Risk Assessment Process, Information and Communication policies and the ongoing Monitoring of these control processes and systems.
 
  •  An evaluation of Control Activities by work process. Key controls and compensating controls were documented and tested by each of our work processes, including controls over all relevant financial statement assertions related to all significant accounts and disclosures. Internal control deficiencies were identified and prioritized, and appropriate remediation action plans were defined, implemented and retested.
 
  •  A centralized review and analysis of all internal control deficiencies across the enterprise to determine whether such deficiencies, either separately or in the aggregate, represented a significant deficiency or material weakness.
 
  •  An evaluation of any changes in work processes, systems, organization or policy that could materially impact internal control over financial reporting.
 
  •  Certifications regarding financial results and internal control conclusions from managers and work process owners.
      In addition, we maintain an internal auditing program that independently assesses the effectiveness of internal control over financial reporting, including testing of the five COSO elements.
     
/s/ IRL F. ENGELHARDT
  /s/ RICHARD A. NAVARRE
Irl F. Engelhardt
  Richard A. Navarre
Chairman and Chief Executive Officer
  Executive Vice President and Chief Financial Officer
March 7, 2005

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Report of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders
Peabody Energy Corporation
      We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Peabody Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Peabody Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
      As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls over the Australian operations acquired in 2004, which are included in the December 31, 2004, consolidated financial statements of Peabody Energy Corporation and constituted $309.3 million and $251.0 million of total and net assets, respectively, as of December 31, 2004, and $235.9 million and $31.2 million of revenues and operating profit, respectively, for the year then ended. Our audit of internal control over financial reporting of Peabody Energy Corporation also did not include an evaluation of the internal control over financial reporting of the Company’s Australian operations acquired in 2004.
      In our opinion, management’s assessment that Peabody Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Peabody Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

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      We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Peabody Energy Corporation as of December 31, 2004 and 2003, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004, and our report dated March 7, 2005, expressed an unqualified opinion thereon.
  /s/ Ernst & Young LLP
St. Louis, Missouri
March 7, 2005

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Item 9B. Other Information.
      The Board of Directors amended Section 1.6 of the Company’s Amended and Restated By-Laws on March 15, 2005 to confirm the voting requirement for the election of directors as a plurality vote. The amendment became effective on the same day. Because this Annual Report on Form 10-K is being filed within four business days from March 15, the amendment is being disclosed hereunder rather than under Item 5.03 of Form 8-K. The amended By-Laws are attached hereto as Exhibit 3.2 pursuant to Item 601(b)(3) of Regulation S-K.
PART III
Item 10. Directors and Executive Officers of the Registrant.
      The information required by Item 401 of Regulation S-K is included under the caption “Election of Directors” in our 2005 Proxy Statement and in Part I Item 4 of this report under the caption “Executive Officers of the Company.” Such information is incorporated herein by reference. The information required by Item 405 of Regulation S-K is included under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in our 2005 Proxy Statement and is incorporated herein by reference.
Item 11. Executive Compensation.
      The information required by Item 402 of Regulation S-K is included under the caption “Executive Compensation” in our 2005 Proxy Statement and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management.
      The information required by Item 403 of Regulation S-K is included under the caption “Ownership of Company Securities” in our 2005 Proxy Statement and is incorporated herein by reference.
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, 2004:
                         
            Number of Securities
    (a)       Remaining Available for
    Number of Securities       Future Issuance Under
    to be Issued upon   Weighted-Average   Equity Compensation
    Exercise of   Exercise Price of   Plans (Excluding
    Outstanding Options,   Outstanding Options,   Securities Reflected in
Plan Category   Warrants and Rights   Warrants and Rights   Column (a))
             
Equity compensation plans approved by security holders
    7,234,168     $ 11.80       8,051,438  
Equity compensation plans not approved by security holders
                 
                   
Total
    7,234,168     $ 11.80       8,051,438  
                   
Item 13. Certain Relationships and Related Transactions.
      The information required by Item 404 of Regulation S-K is included under the caption “Related Party Transactions” in our 2005 Proxy Statement and is incorporated herein by reference.
Item 14. Principal Accounting Fees and Services.
      The information required by Item 9(e) of Schedule 14A is included under the caption “Principal Accountant Fees and Services” in our 2005 Proxy Statement and is incorporated herein by reference.

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PART IV
Item 15. Exhibits, Financial Statement Schedules.
      (a) Financial Statements
        (1) The following consolidated financial statements (included in Exhibit 13) of Peabody Energy Corporation, as released in pages 49 to 91 of our December 31, 2004 Annual Report to Stockholders, are incorporated by reference:
         
    Exhibit 13
    Page(s)
     
Report of Independent Registered Public Accounting Firm
    1  
Consolidated Statements of Operations — Years Ended December 31, 2004, 2003 and 2002
    2  
Consolidated Balance Sheets — December 31, 2004 and December 31, 2003
    3  
Consolidated Statements of Cash Flows — Years Ended December 31, 2004, 2003 and 2002
    4  
Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2004, 2003 and 2002
    5  
Notes to Consolidated Financial Statements
    6  
Summary Quarterly Financial Information (unaudited)
    48  
Segment Information
    49  
           (2) Financial Statement Schedule.
        The following financial statement schedule of Peabody Energy Corporation, and the report thereon of the independent registered public accounting firm, are at the pages indicated:
         
    Page
     
Report of Independent Registered Public Accounting Firm 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.

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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 16, 2005
      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 16, 2005
 
/s/ RICHARD A. NAVARRE
 
Richard A. Navarre
  Executive Vice President and Chief Financial Officer (principal financial and accounting officer)   March 16, 2005
 
/s/ GREGORY H. BOYCE
 
Gregory H. Boyce
  President and Chief Operating Officer   March 16, 2005
 
/s/ B.R. BROWN
 
B.R. Brown
  Director   March 16, 2005
 
/s/ WILLIAM A. COLEY
 
William A. Coley
  Director   March 16, 2005
 
/s/ HENRY GIVENS, JR., PHD
 
Henry Givens, Jr., PhD
  Director   March 16, 2005
 
/s/ WILLIAM E. JAMES
 
William E. James
  Director   March 16, 2005
 
/s/ ROBERT B. KARN III
 
Robert B. Karn III
  Director   March 16, 2005
 
/s/ HENRY E. LENTZ
 
Henry E. Lentz
  Director   March 16, 2005
 
/s/ WILLIAM C. RUSNACK
 
William C. Rusnack
  Director   March 16, 2005
 
/s/ JAMES R. SCHLESINGER
 
James R. Schlesinger
  Director   March 16, 2005

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Signature   Title   Date
         
 
/s/ BLANCHE M. TOUHILL
 
Blanche M. Touhill
  Director   March 16, 2005
 
/s/ SANDRA VAN TREASE
 
Sandra Van Trease
  Director   March 16, 2005
 
/s/ ALAN H. WASHKOWITZ
 
Alan H. Washkowitz
  Director   March 16, 2005

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Peabody Energy Corporation
      We have audited the consolidated financial statements of Peabody Energy Corporation as of December 31, 2004 and 2003, and for the three years in the period ended December 31, 2004, and have issued our report thereon dated March 7, 2005. 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
March 7, 2005

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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(2)   of Period
                     
YEAR ENDED DECEMBER 31, 2004
                                       
 
Reserves deducted from asset accounts:
                                       
   
Advance royalty recoupment reserve
  $ 14,465     $     $ (101 )   $ 3,860     $ 18,224  
   
Reserve for materials and supplies
    7,563       796       (4,742 )     802       4,419  
   
Allowance for doubtful accounts
    1,361                         1,361  
YEAR ENDED DECEMBER 31, 2003
                                       
 
Reserves deducted from asset accounts:
                                       
   
Advance royalty recoupment reserve
  $ 13,585     $ (181 )   $     $ 1,061     $ 14,465  
   
Reserve for materials and supplies
    9,065             (992 )     (510 )     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     $ 13,585  
   
Reserve for materials and supplies
    9,893             (912 )     84       9,065  
   
Allowance for doubtful accounts
    1,496       (165 )                 1,331  
 
(1)  Reserves utilized, unless otherwise indicated.
 
(2)  Balances transferred (to) from other accounts or reserves recorded as part of a property or business acquisition.

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EXHIBIT INDEX
      The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.
         
Exhibit    
No.   Description of Exhibit
     
  3 .1   Third Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
  3 .2†   Amended and Restated By-Laws of the Registrant.
  4 .1   Rights Agreement, dated as of July 24, 2002, between the Company and EquiServe Trust Company, N.A., as Rights Agent (which includes the form of Certificate of Designations of Series A Junior Preferred Stock of the Company as Exhibit A, the form of Right Certificate as Exhibit B and the Summary of Rights to Purchase Preferred Shares as Exhibit C) (Incorporated herein by reference to Exhibit 4.1 to the Company’s Registration Statement on Form 8-A, filed on July 24, 2002).
 
  4 .2   Certificate of Designations of Series A Junior Participating Preferred Stock of the Company, filed with the Secretary of State of the State of Delaware on July 24, 2002 (Incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form 8-A, filed on July 24, 2002).
 
  4 .3   Specimen of stock certificate representing the Registrant’s common stock, $.01 par value (Incorporated by reference to Exhibit 4.13 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  4 .4   67/8% Senior Notes Due 2013 Indenture dated as of March 21, 2003 between the Registrant and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.27 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, filed on May 13, 2003).
 
  4 .5   67/8% Senior Notes Indenture Due 2013 First Supplemental Indenture dated as of May 7, 2003 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.3 of the Registrant’s Form S-4 Registration Statement No. 333-106208).
 
  4 .6   67/8% Senior Notes Indenture Due 2013 Second Supplemental Indenture dated as of September 30, 2003 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.198 of the Registrant’s Form S-3 Registration Statement No. 333-109906, filed on October 22, 2003).
 
  4 .7   67/8% Senior Notes Indenture Due 2013 Third Supplemental Indenture, dated as of February 24, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.211 of the Registrant’s Form S-3/ A Registration Statement No. 333-109906, filed on March 4, 2004).
 
  4 .8   67/8% Senior Notes Indenture Due 2013 Fourth Supplemental Indenture, dated as of April 22, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (incorporated by reference to Exhibit 10.57 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 filed on August 6, 2004).
 
  4 .9†   67/8% Senior Notes Indenture Due 2013 Fifth Supplemental Indenture, dated as of October 18, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee.
 
  4 .10   57/8% Senior Notes Due 2016 Indenture dated as of March 19, 2004 between the Registrant and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.12 of the Registrant’s Quarterly Report on Form 10-Q for the Quarter ended March 31, 2004, filed on May 10, 2004).
 
  4 .11   57/8% Senior Notes Due 2016 First Supplemental Indenture dated as of March 23, 2004 between the Registrant and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K dated March 23, 2004).
 
  4 .12   57/8% Senior Notes Due 2016 Second Supplemental Indenture, dated as of April 22, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (incorporated by reference to Exhibit 10.58 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 filed on August 6, 2004).
 
  4 .13†   57/8% Senior Notes Due 2016 Third Supplemental Indenture, dated as of October 18, 2004, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee.


Table of Contents

         
Exhibit    
No.   Description of Exhibit
     
  10 .1   Second Amended and Restated Credit Agreement dated as of March 21, 2003 among the Registrant, as Borrower, the several lenders from time to time parties hereto, Wachovia Bank, National Association and Lehman Commercial Paper Inc., as Syndication Agents, Fleet Securities, Inc., Wachovia Securities, Inc. and Lehman Brothers Inc., as Arrangers, Fleet National Bank as Administrative Agent and Morgan Stanley Senior Funding, Inc. and US Bank National Association, as Documentation Agents (Incorporated by reference to Exhibit 10.43 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003, filed on May 13, 2003).
 
  10 .2   Amendment No. 1 to Second Amended and Restated Credit Agreement, dated as of May 8, 2003, among the Registrant, the Lenders named therein, and Fleet National Bank, as Administrative Agent (Incorporated by reference to Exhibit 10.46 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2003, filed on August 14, 2003).
 
  10 .3   Amendment No. 2 to Second Amended and Restated Credit Agreement, dated as of March 8, 2004, among Registrant, the Lenders named therein, Fleet National Bank, as administrative agent, and Wachovia Bank, National Association and Lehman Commercial Paper Inc., as syndication agents. (Incorporated by reference to Exhibit 10.54 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, filed on May 10, 2004).
 
  10 .4†   Amendment No. 3 to Second Amended and Restated Credit Agreement, dated as of October 27, 2004, among Registrant, the Lenders named therein, Fleet National Bank, as administrative agent, and Wachovia Bank, National Association and Lehman Commercial Paper Inc., as syndication agents.
 
  10 .5   Amended and Restated Guarantee and Collateral Agreement dated as of March 21, 2003 among the Registrant and the Guarantors (as defined therein) in favor of Fleet National Bank, as Administrative Agent for the several lenders from time to time parties to the Second Amended and Restated Credit Agreement dated as of March 21, 2003 (Incorporated by reference to Exhibit 10.2 of the Registrant’s Form S-4 Registration Statement No. 333-106208).
 
  10 .6   Subordination Agreement dated as of March 21, 2003 among the Registrant and its Subsidiaries (as defined therein) (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form S-4 Registration Statement No. 333-106208).
 
  10 .7   Federal Coal Lease WYW0321779: North Antelope/ Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant’s Form S-4 Registration Statement No. 333-59073).
 
  10 .8   Federal Coal Lease WYW119554: North Antelope/ Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant’s Form S-4 Registration Statement No. 333-59073).
 
  10 .9   Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant’s Form S-4 Registration Statement No. 333-59073).
 
  10 .10   Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant’s Form S-4 Registration Statement No. 333-59073).
 
  10 .11   Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant’s Form S-4 Registration Statement No. 333-59073).
 
  10 .12   Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 of the Registrant’s Form S-4 Registration Statement No. 333-59073).
 
  10 .13   Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (Incorporated by reference to Exhibit 10.9 of the Registrant’s Form 10-Q for the second quarter ended September 30, 1998, filed on November 13, 1998).
 
  10 .14   Federal Coal Lease WYW154001: North Antelope Rochelle South (Incorporated by reference to Exhibit 10.68 of the Registrant’s Form 10-Q for the third quarter ended September 30, 2004, filed on December 10, 2004).
 
  10 .15*   1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 4.9 of the Registrant’s Form S-8 Registration Statement No. 333-105456 filed on May 21, 2003).
 
  10 .16*   Long-Term Equity Incentive Plan of the Registrant (Incorporated by reference to Exhibit 99.2 of the Registrant’s Form S-8 Registration Statement No. 333-61406 filed on May 22, 2001).
 
  10 .17*   Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Annex A to the Registrant’s Proxy Statement for the 2004 Annual Meeting of Stockholders, filed on April 2, 2004).


Table of Contents

         
Exhibit    
No.   Description of Exhibit
     
  10 .18*   Amendment No. 1 to the Peabody Energy Corporation 2004 Long Term Incentive Plan (Incorporated by reference to Exhibit 10.67 of the Registrant’s Form 10-Q for the third quarter ended September 30, 2004, filed on December 10, 2004).
 
  10 .19*   Equity Incentive Plan for Non-Employee Directors of the Registrant (Incorporated by reference to Exhibit 99.3 of the Registrant’s Form S-8 Registration Statement No. 333-61406 filed on May 22, 2001).
 
  10 .20*   Form of Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.15 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .21*   Form of Amendment to Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.16 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .22*   Form of Amendment, dated as of June 15, 2004, to Non-Qualified Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.65 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 filed on August 6, 2004).
 
  10 .23*   Form of Incentive Stock Option Agreement under the Registrant’s 1998 Stock Purchase and Option Plan for Key Employees (Incorporated by reference to Exhibit 10.17 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .24*   Form of Non-Qualified Stock Option Agreement under the Registrant’s Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .25*   Form of Non-Qualified Stock Option Agreement under the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, dated January 3, 2005).
 
  10 .26*   Form of Performance Units Agreement under the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, dated January 3, 2005).
 
  10 .27*   Form of Performance Unit Award Agreement under the Registrant’s Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .28*   Form of Non-Qualified Stock Option Agreement under the Registrant’s Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .29*   Form of Restricted Stock Agreement under the Registrant’s Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.21 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .30*   Employee Stock Purchase Plan of the Registrant (Incorporated by reference to Exhibit 99.1 of the Registrant’s Form S-8 Registration Statement No. 333-61406 filed on May 22, 2001).
 
  10 .31*   First Amendment to Registrant’s Employee Stock Purchase Plan, dated as of February 7, 2002 (Incorporated by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .32*   Employment Agreement between Irl F. Engelhardt and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.11 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  10 .33*   First Amendment to the Employment Agreement between Irl F. Engelhardt and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.21 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  10 .34*   Second Amendment to the Employment Agreement between Irl F. Engelhardt and the Registrant dated as of June 15, 2004 (incorporated by reference to Exhibit 10.59 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 filed on August 6, 2004).
 
  10 .35*   Employment Agreement between Gregory H. Boyce and the Registrant dated as of October 1, 2003 (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K for the Fiscal Year Ended December 31, 2003).


Table of Contents

         
Exhibit    
No.   Description of Exhibit
     
  10 .36*   First Amendment to the Employment Agreement between Gregory H. Boyce and the Registrant dated as of June 15, 2004 (incorporated by reference to Exhibit 10.64 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 filed on August 6, 2004).
 
  10 .37*   Employment Agreement between Richard M. Whiting and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.12 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  10 .38*   First Amendment to the Employment Agreement between Richard M. Whiting and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.22 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  10 .39*   Second Amendment to the Employment Agreement between Richard M. Whiting and the Registrant dated as of June 15, 2004 (incorporated by reference to Exhibit 10.60 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 filed on August 6, 2004).
 
  10 .40*   Employment Agreement between Richard A. Navarre and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.13 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  10 .41*   First Amendment to the Employment Agreement between Richard A. Navarre and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.23 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  10 .42*   Second Amendment to the Employment Agreement between Richard A. Navarre and the Registrant dated as of June 15, 2004 (incorporated by reference to Exhibit 10.61 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 filed on August 6, 2004).
 
  10 .43*   Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.14 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  10 .44*   First Amendment to the Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.24 of the Registrant’s Form S-1 Registration Statement No. 333-55412).
 
  10 .45*   Second Amendment to the Employment Agreement between Roger B. Walcott and the Registrant dated as of June 15, 2004 (Incorporated by reference to Exhibit 10.62 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 filed on August 6, 2004).
 
  10 .46*   Agreement between the Registrant and Richard A. Navarre dated August 29, 2003 (Incorporated by reference to Exhibit 10.47 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2003, filed on November 13, 2003).
 
  10 .47*   Agreement between the Registrant and Richard M. Whiting dated September 24, 2003 (Incorporated by reference to Exhibit 10.48 of the Registrant’s Quarterly Report on Form  10-Q for the quarter ended September 30, 2003, filed on November 13, 2003).
 
  10 .48*   Peabody Energy Corporation Deferred Compensation Plan (Incorporated by reference to Exhibit 10.30 of the Registrant’s Form 10-Q for the quarter ended September 30, 2001, filed on October 30, 2001).
 
  10 .49*†   First Amendment to the Peabody Energy Corporation Deferred Compensation Plan.
 
  10 .50*   Amendment No. 1 to the Peabody Energy Corporation 2004 Long Term Incentive Plan.
 
  10 .51*   Performance Units Agreement, dated as of August 1, 2004, by and between Registrant and Irl F. Engelhardt (Incorporated by reference to Exhibit 10.72 of the Registrant’s Quarterly Report on Form 10-Q/ A for the third quarter ended September 30, 2004, filed on December 10, 2004).
 
  10 .52*   Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Irl F. Engelhardt (Incorporated by reference to Exhibit 10.31 of the Registrant’s Form 10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .53*   Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and William E. James (Incorporated by reference to Exhibit 10.34 of the Registrant’s Form 10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .54*   Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Henry E. Lentz (Incorporated by reference to Exhibit 10.35 of the Registrant’s Form 10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .55*   Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and William C. Rusnack (Incorporated by reference to Exhibit 10.36 of the Registrant’s Form 10-K for the year ended December 31, 2002, filed on March 7, 2003).


Table of Contents

         
Exhibit    
No.   Description of Exhibit
     
  10 .56*   Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Dr. James R. Schlesinger (Incorporated by reference to Exhibit 10.37 of the Registrant’s Form  10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .57*   Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Dr. Blanche M. Touhill (Incorporated by reference to Exhibit 10.38 of the Registrant’s Form 10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .58*   Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Alan H. Washkowitz (Incorporated by reference to Exhibit 10.39 of the Registrant’s Form 10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .59*   Indemnification Agreement, dated as of December 5, 2002, by and between Registrant and Richard A. Navarre (Incorporated by reference to Exhibit 10.40 of the Registrant’s Form 10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .60*   Indemnification Agreement, dated as of January 16, 2003, by and between Registrant and Robert B. Karn III (Incorporated by reference to Exhibit 10.41 of the Registrant’s Form 10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .61*   Indemnification Agreement, dated as of January 16, 2003, by and between Registrant and Sandra A. Van Trease (Incorporated by reference to Exhibit 10.42 of the Registrant’s Form  10-K for the year ended December 31, 2002, filed on March 7, 2003).
 
  10 .62*   Indemnification Agreement, dated as of December 9, 2003, by and between Registrant and B. R. Brown (Incorporated by reference to Exhibit 10.48 of the Company’s Annual Report on Form  10-K for the Fiscal Year Ended December 31, 2003, filed on March 4, 2004).
 
  10 .63*   Indemnification Agreement, dated as of March 22, 2004, by and between Registrant and Henry Givens, Jr. (Incorporated by reference to Exhibit 10.52 of the Company’s Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2004, filed on May 10, 2004).
 
  10 .64*   Indemnification Agreement, dated as of March 22, 2004, by and between Registrant and William A. Coley (Incorporated by reference to Exhibit 10.53 of the Company’s Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2004, filed on May 10, 2004).
 
  10 .65*   Letter Agreement, dated as of March 1, 2005, by and between the Company and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K, dated February 28, 2005).
 
  10 .66*   Letter Agreement, dated as of March 1, 2005, by and between the Company and Irl F. Engelhardt (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K, dated February 28, 2005).
 
  10 .67*   Amended and Restated Employment Agreement, dated as of January 1, 2006, by and between the Company and Gregory H. Boyce (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K, dated February 28, 2005).
 
  10 .68*   Amended and Restated Employment Agreement, dated as of January 1, 2006, by and between the Company and Irl F. Engelhardt (Incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K, dated February 28, 2005).
 
  10 .69   Receivables Purchase Agreement dated as of February 20, 2002, by and among Seller, the Registrant, Market Street Funding Corporation, and PNC Bank, National Association, as Administrator. (Incorporated by reference to Exhibit 10.28 of the Registrant’s Form 10-K for the nine months ended December 31, 2001, filed on March 12, 2002).
 
  10 .70   First Amendment to Receivables Purchase Agreement, dated as of February 27, 2003, by and among Seller, Registrant, the Sub-Servicers named therein, Market Street Funding Corporation, as Issuer, and PNC Bank, National Association, as Administrator (Incorporated by reference to Exhibit 10.69 of the Registrant’s Form 10-Q for the third quarter ended September 30, 2004, filed on December 10, 2004).
 
  10 .71   Second Amendment to Receivables Purchase Agreement, dated as of February 18, 2004, by and among Seller, Registrant, the Sub-Servicers named therein, Market Street Funding Corporation, as Issuer, and PNC Bank, National Association, as Administrator (Incorporated by reference to Exhibit 10.70 of the Registrant’s Form 10-Q for the third quarter ended September 30, 2004, filed on December 10, 2004).


Table of Contents

         
Exhibit    
No.   Description of Exhibit
     
  10 .72   Third Amendment to Receivables Purchase Agreement, dated as of September 16, 2004, by and among Seller, Registrant, the Sub-Servicers named therein, Market Street Funding Corporation, as Issuer, and PNC Bank, National Association, as Administrator (Incorporated by reference to Exhibit 10.71 of the Registrant’s Form 10-Q for the third quarter ended September 30, 2004, filed on December 10, 2004).
 
  10 .73   Purchase And Sale Agreement by and among Peabody Energy Corporation, Eastern Associated Coal Corp., Peabody Natural Resources Company, and Penn Virginia Resource Partners, L.P. dated December 19, 2002 (Incorporated by reference to Exhibit 10.30 to the Registrant’s Form 8-K, filed on December 23, 2002).
 
  10 .74   Stock Purchase Agreement among RAG Coal International AG, RAG American Coal Company, BTU Worldwide, Inc. and Peabody Energy Corporation dated as of February 29, 2004 (incorporated by reference to Exhibit 2.1 of the Company’s Form 8-K Current Report filed on February 29, 2004).
 
  10 .75   Share Purchase Agreement among RAG Coal International AG, Peabody Energy Corporation and Peabody Energy Australia Pty Limited dated as of February 29, 2004 (incorporated by reference to Exhibit 2.2 of the Company’s Form 8-K Current Report filed on February 29, 2004).
 
  10 .76   Share Purchase Agreement dated as of June 10, 2004, among RAG Coal International AG, BTU International B.V. and Peabody Energy Corporation (Incorporated by reference to Exhibit 2.1 of the Company’s Form 8-K Current Report filed on December 8, 2004).
 
   13†     Portions of the Company’s Annual Report to Stockholders for the year ended December 31, 2004.
 
   21†     List of Subsidiaries.
 
   23†     Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm.
 
  31 .1†   Certification of periodic financial report by the Registrant’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
  31 .2†   Certification of periodic financial report by the Registrant’s Executive Vice President and Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
  32 .1†   Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Chief Executive Officer.
 
  32 .2†   Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by the Registrant’s Executive Vice President and Chief Financial Officer.
 
These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 15(c) of this report.
†  Filed herewith.