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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, 2005
 
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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes þ          No o
      Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.     Yes o          No þ
      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes þ          No o
      Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.     þ
      Indicate by check mark whether the registrant is large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ          Accelerated filer o          Non-accelerated filer     o
      Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act)     Yes o          No þ
      Aggregate market value of the voting stock held by non-affiliates (shareholders who are not directors or executive officers) of the Registrant, calculated using the closing price on June 30, 2005: Common Stock, par value $0.01 per share, $6.7 billion.
      Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of February 24, 2006: Common Stock, par value $0.01 per share, 264,593,796 shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
      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 5, 2006 (the “Company’s 2006 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;
 
  •  prices of fuels which compete with or impact coal usage, such as oil or natural gas;
 
  •  future worldwide economic conditions;
 
  •  economic strength and political stability of countries in which we have operations or serve customers;
 
  •  weather;
 
  •  transportation performance and costs, including demurrage;
 
  •  ability to renew sales contracts;
 
  •  successful implementation of business strategies;
 
  •  regulatory and court decisions;
 
  •  legislation and regulation;
 
  •  the impact from provisions of The Energy Policy Act of 2005;
 
  •  variation in revenues related to synthetic fuel production;
 
  •  changes in postretirement benefit and pension obligations;
 
  •  negotiation of labor contracts, employee relations and workforce 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, including credit risk;
 
  •  availability and costs of key supplies or commodities such as diesel fuel, steel, explosives and tires;
 
  •  reductions of purchases by major customers;
 
  •  geology, equipment and other risks inherent to mining;
 
  •  terrorist attacks or threats;
 
  •  performance of contractors, third party coal suppliers or major suppliers of mining equipment or supplies;

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  •  replacement of coal reserves;
 
  •  the timing or direction of our BTU conversion or generation development initiatives;
 
  •  implementation of new accounting standards and Medicare regulations;
 
  •  inflationary trends, including those impacting materials used in our business;
 
  •  the effects of interest rate changes;
 
  •  litigation, including claims not yet asserted;
 
  •  the effects of acquisitions or divestitures;
 
  •  impacts of pandemic illness;
 
  •  changes to contribution requirements to multi-employer benefit funds; and
 
  •  other factors, including those discussed in “Legal Proceedings,” set forth in Item 3 of this report and “Risk Factors”, set forth in Item 1A of this report.
      When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (“SEC”) filings. We do not undertake any obligation to update these statements, except as required by federal securities laws.

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TABLE OF CONTENTS
             
        Page
         
 PART I.
   Business     2  
   Risk Factors     27  
   Unresolved Staff Comments     35  
   Properties     35  
   Legal Proceedings     40  
   Submission of Matters to a Vote of Security Holders     44  
     Executive Officers of the Company     44  
 PART II.
   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     46  
   Selected Financial Data     47  
   Management’s Discussion and Analysis of Financial Condition and Results of Operations     49  
   Quantitative and Qualitative Disclosures About Market Risk     69  
   Financial Statements and Supplementary Data     71  
   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     71  
   Controls and Procedures     71  
   Other Information     74  
 PART III.
   Directors and Executive Officers of the Registrant     74  
   Executive Compensation     74  
   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     74  
   Certain Relationships and Related Transactions     74  
   Principal Accounting Fees and Services     74  
 PART IV.
   Exhibits, Financial Statement Schedules     75  
 6 7/8% Senior Notes Due 2013
 5 7/8% Senior Notes Due 2016
 List of Subsidiaries
 Consent of Ernst & Young LLP
 Certification of CEO Pursuant to Section 302
 Certification of CFO Pursuant to Section 302
 Certification of CEO Pursuant to Section 906
 Certification of CFO Pursuant to Section 906

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Note:  The words “we,” “our,” “Peabody” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries.
 
       On February 22, 2006, we effected a two-for-one stock split on all shares of our common stock. Shareholders of record at the close of business on February 7, 2006 received a dividend of one share of stock for every share held. The stock began trading ex-split on February 23, 2006. All share and per share amounts in this Annual Report on Form 10-K reflect this 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, 2005, we sold 239.9 million tons of coal. During this period, we sold coal to over 350 electricity generating and industrial plants in 15 countries. Our coal products fuel approximately 10% of all U.S. electricity generation and 3% of worldwide electricity generation. At December 31, 2005, we had 9.8 billion tons of proven and probable coal reserves.
      We own, through our subsidiaries, majority interests in 34 coal operations located throughout all major U.S. coal producing regions and in Australia. Additionally, we own minority interests in two mines through joint venture arrangements. We shipped 75% of our U.S. mining operations’ coal sales from the western United States during the year ended December 31, 2005 and the remaining 25% from the eastern United States. Most of our production in the western United States is low-sulfur coal from the Powder River Basin. Our overall western U.S. coal production has increased from 37.0 million tons in fiscal year 1990 to 154.3 million tons during 2005, 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 5 mines in Queensland, Australia. One of the Australian mines was acquired in 2002, two were acquired during April 2004, a fourth was opened after the 2004 acquisition, and a fifth began mining operations in early 2006. Most of our Australian production is low-sulfur, metallurgical coal. We generated 81% of our production for the year ended December 31, 2005 from non-union mines.
      For the year ended December 31, 2005, 87% of our sales (by volume) were to U.S. electricity generators, 9% were to customers outside the United States and 4% were to the U.S. industrial sector. Approximately 90% of our coal sales during the year ended December 31, 2005 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, 2005. The average volume-weighted remaining term of our long-term contracts was approximately 3.2 years, with remaining terms ranging from one to 19 years. As of December 31, 2005, we had 15 to 25 million tons, 90 to 100 million tons and 155 to 165 million tons for 2006, 2007 and 2008, respectively, of expected production (including steam and metallurgical coal production) available for repricing at market prices. We have an annual metallurgical coal production capacity of 12 to 14 million tons.
      In addition to our mining operations, we market, broker and trade coal. Our total tons traded were 36.2 million for the year ended December 31, 2005. In 2005, we opened a business development, sales and marketing office in Beijing, China to pursue potential long-term growth opportunities in this market. Our other energy related commercial activities include the development of mine-mouth coal-fueled generating plants, the management of our vast coal reserve and real estate holdings, coalbed methane production, transportation services, and, more recently, BTU conversion. Our BTU conversion initiatives include participation in technologies that convert coal into natural gas, liquids and hydrogen.

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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 1990s, Peabody continued to grow through expansion and acquisitions. In February 1997, Hanson spun off its energy-related businesses, including Eastern Group and Peabody Holding Company, into The Energy Group, plc. The Energy Group was a publicly traded company in the United Kingdom and its American Depository Receipts (ADRs) were publicly traded on the New York Stock Exchange.
      In May 1998, Lehman Brothers Merchant Banking Partners II L.P. and affiliates (“Merchant Banking Fund”), an affiliate of Lehman Brothers Inc. (“Lehman Brothers”), purchased Peabody Holding Company and its affiliates, Peabody Resources Limited and Citizens Power LLC in a leveraged buyout transaction that coincided with the purchase by Texas Utilities of the remainder of The Energy Group.
      In August 2000, Citizens Power, our subsidiary that marketed and traded electric power and energy-related commodity risk management products, was sold to Edison Mission Energy.
      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 our shares began trading on the New York Stock Exchange under the ticker symbol “BTU,” the globally recognized symbol for energy.
      In April 2004, we acquired three coal operations from RAG Coal International AG. The purchase included two mines in Queensland, Australia and the Twentymile Mine in Colorado. In December 2004, we completed the purchase of a 25.5% equity interest in Carbones del Guasare, S.A. from RAG Coal International AG. 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.
      In March 2005, we purchased mining assets from Lexington Coal Company for $61.0 million. The purchased assets consisted of approximately 70 million tons of reserves, preparation plants, facilities, mining equipment and materials and supplies. We used the acquired assets to open a new mine that is expected to produce 2 to 3 million tons per year, after it reaches full capacity, and to provide other synergies to existing properties. In December 2005, we acquired rail, loadout and surface facilities as well as other mining assets from another major coal producer for $84.7 million and exchanged 60 million ton blocks of leased coal reserves in the Powder River Basin. We will utilize these reserves and infrastructure to accelerate the development of a new mine, which will include adjoining leased reserves.
      On January 1, 2006, Gregory H. Boyce assumed new responsibilities as our President and Chief Executive Officer, succeeding Irl F. Engelhardt who remains Chairman of the Board. Concurrent with the leadership transition, we have identified four key focus areas to accomplish our future growth: 1) executing

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the basics to secure safe, low-cost production; 2) capitalizing on organic growth opportunities; 3) expanding into global markets; and 4) participating in new Btu Conversion technologies that convert coal into natural gas, liquids and hydrogen.
Mining Operations
      The following describes the operating characteristics of the principal mines and reserves of each of our business units and affiliates. The maps below show mine locations for 2005.
(MINING OPERATION)
      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 27 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 the same as the subsidiary or subsidiaries which own the assets utilized in that mining operation.

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Powder River Basin Operations
      We control approximately 3.5 billion tons of proven and probable coal reserves in the Southern Powder River Basin, the largest and fastest growing major U.S. coal-producing region. Our subsidiaries, Powder River Coal, LLC and Caballo Coal Company, manage three low-sulfur, non-union surface mining complexes in Wyoming that sold 125.7 million tons of coal during the year ended December 31, 2005, or approximately 52% of our total coal sales volume. The North Antelope Rochelle and Caballo mines are serviced by both major western railroads, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway.
      Our Wyoming Powder River Basin reserves are classified as surface mineable, subbituminous coal with seam thickness varying from 70 to 105 feet. The sulfur content of the coal in current production ranges from 0.2% to 0.4% and the heat value ranges from 8,300 to 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 82.7 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu) during 2005. 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 2005, it sold 30.6 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 2005, it sold 12.4 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 17.8 million tons of coal during 2005. We control 1.0 billion tons of proven and probable coal reserves in our Southwest operations.
Black Mesa Mine
      The Black Mesa Mine, which is located on the reservations of the Navajo Nation and Hopi Tribe in Arizona, used two draglines and sold 4.6 million tons of coal during 2005. The Black Mesa Mine coal was crushed, mixed with water and then transported 273 miles through an underground pipeline owned by a third party. The coal was 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 had no other source of coal. The Mohave Generating Station coal supply agreement expired on December 31, 2005, and has not been extended. As a result, operations of the Black Mesa Mine have been suspended. Further discussion of the issues surrounding the future of the Black Mesa Mine and Mohave Generating Station is provided in Item 3.

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Legal Proceedings of this report. Hourly workers at this mine were members of the United Mine Workers of America (“UMWA”).
Kayenta Mine
      The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines in three mining areas. It sold approximately 8.2 million tons of coal during 2005. The Kayenta Mine coal is crushed, then carried 17 miles by conveyor belt to storage silos where it is loaded onto a private rail line and transported 83 miles to the Navajo Generating Station, operated by the Salt River Project near Page, Arizona. The mine and railroad were designed to deliver coal exclusively to the power plant, which has no other source of coal. The Navajo coal supply agreement extends until 2011. Hourly workers at this mine are members of the UMWA.
Lee Ranch Mine
      The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 5.0 million tons of medium sulfur coal during 2005. 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 0.2 billion tons of proven and probable coal reserves and currently have two mines in the Colorado Region. Our Twentymile underground mine is managed by our Twentymile Coal Company subsidiary. Our Seneca surface mine is managed by our Seneca Coal Company subsidiary and ceased mining operations at the end of 2005. During 2005, these operations sold approximately 10.7 million tons of compliance, low-sulfur, steam coal of above average heat content to customers throughout the United States.
Twentymile Mine
      The Twentymile Mine is located in Routt County, Colorado, and sold approximately 9.6 million tons of steam coal during 2005. This mine uses both longwall and continuous mining equipment. Our Twentymile Mine is non-union and has perennially been one of the largest and most productive underground mines in the United States. The coal quality is high, with less than 15% requiring washing. Approximately 90% of 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 1.1 million tons of compliance coal during 2005, operating with two draglines in two separate mining areas. The mine’s coal was 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 has exhausted its economically recoverable reserves and ceased mining operations at the end of 2005. Reclamation of the final cuts is underway. Grading and re-soiling are anticipated to be complete by the end of 2006. Our Twentymile Mine now supplies the Hayden Generating Station. The Seneca mine 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 UMWA.
Appalachia/ Highland Operations
      The Appalachia/ Highland Operations consist of a joint venture and five wholly-owned business units and related facilities in West Virginia and one business unit in western Kentucky. Our subsidiary, Pine Ridge Coal Company, LLC, manages the Big Mountain Business Unit, and our subsidiary, Rivers

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Edge Mining, Inc. manages our Rivers Edge Mine in our Wells Business Unit. Our Eastern Associated Coal, LLC subsidiary manages the remaining wholly-owned West Virginia facilities. In addition, Highland Mining manages the Highland No. 9 Mine in western Kentucky. During 2005, these operations sold approximately 17.9 million tons of compliance, medium-sulfur, high-sulfur steam and metallurgical coal to customers in the United States and abroad. Metallurgical coal from these operations accounted for 5.1 million tons of total sales for the year. 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 0.6 billion tons of proven and probable coal reserves in our Appalachia operations. Our Appalachia Operations also own a 30% interest in a partnership that leases a coal export terminal from the Peninsula Port Authority of Virginia and utilizes the terminal for exports.
Big Mountain Business Unit and Contract Mines
      The Big Mountain Business Unit is based near Prenter, West Virginia. This business unit’s primary source of coal is from the Big Mountain No. 16 operation. In addition, there is contract mine production (about 40% of the total shipped) from coal reserves we control processed at the business unit’s preparation facility. During 2005, 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. Hourly workers at the Big Mountain Business Unit are members of the UMWA.
Harris Business Unit
      The Harris Business Unit is based near Bald Knob, West Virginia. The business unit’s primary source of coal is the Harris No. 1 Mine. The business unit also has a small amount of contract mine production from a mine also located near Bald Knob, West Virginia. The Harris Business Unit sold approximately 2.1 million tons of primarily metallurgical product during 2005. This mine uses both longwall and continuous mining equipment. In 2006, the Harris Business Unit will transition to the James Creek reserves, allowing it to access additional metallurgical coal. Hourly workers at the Harris Business Unit are members of the UMWA.
Rocklick Business Unit and Contract Mines
      The Rocklick preparation plant, located near Wharton, West Virginia, processes metallurgical coal produced by the Harris Business Unit and steam coal produced from contract mining operations. This preparation plant shipped approximately 2.4 million tons of coal during 2005. Processed coal is loaded at the plant site on the CSX railroad or transferred via conveyor to our Kopperston loadout facility and loaded on the Norfolk Southern railroad. Hourly workers at the Rocklick preparation plant are members of the UMWA.
Wells Business Unit
      The Wells Business Unit, located near Wharton, West Virginia, sold approximately 3.5 million tons of metallurgical and steam coal during 2005. Wells operates a preparation plant and processes purchased coal production from the Rivers Edge Mine, and contract mines, using continuous mining equipment. The processed coal is loaded on the CSX railroad. Hourly workers at the Wells preparation plant are members of the UMWA.
Federal Business Unit
      The Federal Business Unit consists of the Federal No. 2 Mine, near Fairview, West Virginia, and uses longwall and continuous mining equipment to extract coal. The business unit operates a preparation plant which processed and shipped approximately 4.2 million tons of steam coal during 2005. Coal shipped from the Federal No. 2 Mine has sulfur content only slightly above that of medium sulfur coal and has above

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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 uses continuous mining equipment, is managed by our Highland Mining Company, LLC subsidiary and is located near Waverly, Kentucky. The mine sold 3.8 million tons of steam coal during 2005. This business unit also operates a preparation plant and barge loading facility. Hourly workers at the Highland No. 9 Mine are members of the UMWA.
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. The joint venture shipped 2.4 million tons during 2005.
Midwest Operations
      Our Midwest Operations consist of 14 wholly-owned mines in the Illinois Basin and are comprised of our Bluegrass Mine Services, LLC, Indian Hill Company, Coulterville Coal Company, LLC, Black Beauty Holding Company, LLC and Arclar Company LLC subsidiaries. We control approximately 4.2 billion tons of proven and probable coal reserves in the Midwest. In 2005, these operations collectively sold 34.6 million tons of coal, more than any other Midwestern coal producer. We ship coal from these mines primarily to electricity generators in the Midwestern United States and to industrial customers that generate their own power.
Bluegrass Coal Company
      Bluegrass Mine Services, LLC owns and manages three mines in western Kentucky. 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 1.3 million tons, 1.6 million tons and 1.3 million tons of steam coal, respectively, in 2005. The two underground mines use continuous mining equipment and the surface mine uses truck and shovel equipment. Bluegrass Mine Services, LLC also owns and operates a preparation plant and a coal loading dock. Bluegrass Mine Services, LLC employees are non-union.
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 mine located in Union County, Kentucky, which has non-union employees and sold 1.7 million tons of steam coal in 2005.
Coulterville Coal Company
      In 2005, our Coulterville Coal Company, LLC subsidiary acquired coal reserves and mining equipment from Lexington Coal Company and subsequently opened Gateway Mine in Randolph County, located in southwestern Illinois. The Gateway Mine began production in the second half of 2005 and sold 0.4 million tons of steam coal during 2005. The mine, which has non-union employees, is managed and operated by our wholly-owned subsidiary, Black Beauty Coal Company.
Black Beauty Coal Company
      The Black Beauty Holding Company, LLC mines sold 22.0 million tons of compliance, medium sulfur and high sulfur steam coal during 2005. Black Beauty’s principal Indiana mines include Air Quality,

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Farmersburg, Francisco and Somerville. Air Quality is an underground coal mine located near Monroe City, Indiana that sold 2.1 million tons of compliance coal during 2005. Farmersburg is a surface mine located in Vigo and Sullivan counties in Indiana that sold 3.9 million tons of medium sulfur coal during 2005. The Francisco Mine Complex, located in Gibson County, Indiana mines coal by utilizing both surface mining and underground mining methods and sold 2.9 million tons of medium sulfur coal during 2005. The Somerville Mine Complex, also located in Gibson County, sold a total of 8.1 million tons of medium sulfur coal in 2005. Two other surface mines located in Indiana, Viking and Miller Creek, collectively sold 2.6 million tons of medium sulfur coal during 2005.
      In east central Illinois, Black Beauty’s Riola Mine Complex is an underground mining facility. The Riola Mine Complex sold 2.4 million tons of medium sulfur coal during 2005. Due to unforeseen geologic conditions, and for the safety of our employees, Black Beauty is in the process of reorienting its mine plan. All Black Beauty Coal Company employees are non-union.
      Black Beauty owns a 75% interest in United Minerals Company, LLC. United Minerals, which utilizes a non-union workforce, currently acts as a contract miner for Black Beauty on a portion of the Somerville Mine Complex reserves and is a contract operator for Black Beauty at the Evansville River Terminal coal dock located on the Ohio River.
Arclar Company LLC
      We operate the Wildcat Hills surface mine and Willow Lake underground mining complex located in Gallatin and Saline counties in southern Illinois. During 2005, these mines sold 2.6 million tons and 3.7 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 to mine the surface reserves at Wildcat Hills. The hourly workforce at the Willow Lake underground mine, which is represented under an International Brotherhood of Boilermakers labor agreement that expires in October 2006, is supplied by our Big Ridge, Inc. subsidiary.
Australian Mining Operations
      We manage five mines in Queensland, Australia through our wholly-owned subsidiary, Peabody Pacific Pty Limited. In July 2005, we began development of the Baralaba coal mine, with coal sales to commence in early 2006. During 2005, these operations sold 8.3 million tons of coal, 5.8 millions tons of which were metallurgical coal. Coal from these mines is shipped via rail from the mine to the loading point at Dalrymple Bay and the Port of Brisbane, 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 0.3 billion tons of proven and probable coal reserves.
Wilkie Creek Mine
      Our Wilkie Creek Coal Mine is a surface, truck-and-shovel operation. In 2005, the Wilkie Creek Mine sold 2.0 million tons of steam coal, all of which was sold to the Asia export market.
Burton Mine
      Burton is a surface mine using the truck-and-shovel terrace mining technique. We own 95% of the Burton operation and the remaining 5% interest is owned by the contract miner that operates on reserves that we control. During 2005, we sold 3.8 million tons of metallurgical coal and 0.5 million tons of steam coal from the Burton Mine.

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North Goonyella Mine
      The North Goonyella Mine is a longwall underground operation. The North Goonyella Mine operates in a difficult geologic environment and produces a unique metallurgical coal product. During 2005, the North Goonyella Mine sold 0.7 million tons of metallurgical coal.
Eaglefield Mine
      The 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. During 2005, the Eaglefield mine sold 1.3 million tons of metallurgical coal.
Baralaba Mine
      The recently opened Baralaba Mine is a contractor operated surface operation utilizing truck-and-shovel mining methods. The mine will produce a pulverized coal injection (“PCI”) product, a substitute for metallurgical coal used primarily by steel makers, and steam coal. All production will be shipped through the Port of Gladstone with shipments scheduled to commence in the first quarter of 2006. We anticipate production of approximately 0.6 million tons in 2006. We own 62.5% interest in the Baralaba Mine and manage the operations utilizing a contractor for overburden removal and coal mining.
Venezuelan Mining Operations
      We own a 25.5% interest in Carbones del Guasare, S.A., a joint venture that includes Anglo American plc and a Venezuelan governmental partner. Carbones del Guasare operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine is a surface operation in northwestern Venezuela that produces approximately 6 to 8 million tons of steam coal annually for export primarily to the United States and Europe. We are responsible for our pro-rata share of sales from Paso Diablo; the joint venture is responsible for production, processing and transportation of coal to ocean-going vessels for delivery to customers.
Long-Term Coal Supply Agreements
      We currently have a sales backlog in excess of one billion tons of coal, including backlog subject to price reopener and/or extension provisions, and our coal supply agreements have remaining terms ranging from one to 19 years and an average volume-weighted remaining term of approximately 3.2 years. For 2005, we sold approximately 90% of our sales volume under long-term coal supply agreements. In 2005, we sold coal to over 350 electricity generating and industrial plants in 15 countries. Our primary customer base is in the United States, although customers in the Pacific Rim and other international locations represent an increasing portion of our revenue stream. One of our largest coal supply agreements is the subject of ongoing litigation and arbitration, as discussed in Item 3. Legal Proceedings.
      We expect to continue selling a significant portion of our coal under long-term supply agreements. Our strategy is to selectively renew, or enter into new, long-term coal supply contracts when we can do so at prices we believe are favorable. Long-term contracts are attractive for regions where market prices are expected to remain stable, for cost-plus arrangements serving captive electricity generating plants and for the sale of high-sulfur coal to “scrubbed” generating plants. To the extent we do not renew or replace expiring long-term coal supply agreements, our future sales will be subject to market fluctuations.
      In January 2006 we signed a 19-year, 65-million-ton coal supply agreement with Arizona Public Service Company (“APS”). The contract is expected to generate revenue in excess of $1 billion. We plan to open the El Segundo Mine to serve APS’s Cholla Generating Station near Joseph City, Arizona, in addition to other customers. The El Segundo Mine is expected to begin coal production in 2008 and will have the capacity to produce 6 million tons of coal annually.

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      Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices, while we seek stable sources of revenue to support the investments required to open, expand and maintain or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, 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, either party may terminate the agreement.
      Price reopener provisions are present in many of our multi-year coal contracts. These provisions may allow either party to commence a renegotiation of the contract price at various intervals. In a limited number of agreements, if the parties do not agree on a new price, the purchaser or seller has an option to terminate the contract. Under some contracts, we have the right to match lower prices offered to our customers by other suppliers.
      Quality and volumes for the coal are stipulated in coal supply agreements, and in some limited instances buyers have the option to vary annual or monthly volumes if necessary. Variations to the quality and volumes of coal may lead to adjustments in the contract price. Most coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat (Btu), sulfur, and ash content, grindability and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Coal supply agreements typically stipulate procedures for quality control, sampling and weighing. In the eastern United States, approximately half of our customers require that the coal is sampled and weighed at the destination, whereas in the western United States, samples and weights are usually taken at the shipping source.
      Contract provisions in some cases set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions or serious transportation problems that affect the seller or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement. Buyers often negotiate similar clauses covering changes in environmental laws. We often negotiate the right to supply coal that complies with a new environmental requirement to avoid contract termination. Coal supply agreements typically contain termination clauses if either party fails to comply with the terms and conditions of the contract, although most termination provisions provide the opportunity to cure defaults.
      In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines, including third party production, as long as the replacement coal meets the contracted quality specifications and will be sold at the same delivered cost.

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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 departments, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and agent, trade coal and emission allowances, and provide transportation-related services. We have opened a business development, sales and marketing office in Beijing, China to pursue potential long-term growth opportunities in this market. As of December 31, 2005, we had 75 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 our COALTRADE Australia operation, which brokers coal in the Australia and Pacific Rim markets, and is based in Newcastle, Australia.
Transportation
      Usually coal consumed domestically is sold at the mine, and transportation costs are borne by the purchaser. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port, including any demurrage costs.
      The majority of our sales volume is shipped by rail, but a portion of our production is shipped by other modes of transportation, including barge, truck and ocean-going vessels. Our transportation department manages the loading of coal via these transportation modes.
      Approximately 12,000 unit trains are loaded each year to accommodate the coal shipped by our mines overall. A unit train generally consists of 100 to 150 cars, each of which can hold 100 to 120 tons of coal. We believe we have good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators.
Suppliers
      The main types of goods we purchase are mining equipment and replacement parts, explosives, fuel, tires, steel-related (including roof control) products and lubricants. Although we have many long, well-established relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers, except as noted below. The supplier base providing mining materials has been relatively consistent in recent years, although there 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, some alternative sources are available to us in the regions where we operate. Further, purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop. In the past year, demand for certain surface and underground mining equipment and off-the-road tires has increased. As a result, lead times for certain items have generally increased, although no material impact is currently expected to our financial condition, results of operations or cash flows.
Technical Innovation
      To support the continued growth and globalization of our businesses, our Board of Directors approved a project to convert our existing information systems across the major business processes to an integrated information technology system provided by SAP AG. The project will begin in the first half of 2006 and is expected to be completed in approximately two years.
      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.

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      A major effort has been underway to improve the performance of our draglines systems, 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. In 2005, work began to relocate a dragline from Central Missouri to the North Antelope Rochelle Mine in Wyoming. The dragline is being refurbished and upgraded in Wyoming with many new design features including a new trapezoidal boom, larger bucket, larger hoist motors and additional drag and swing motors. The upgrade modifications are expected to increase the dragline system capacity by 20% over the original capacity.
      Technology to capture, analyze and transfer information regarding safety, performance and maintenance conditions quickly at our operations is a priority. A wireless data acquisition system has been installed at the North Antelope Rochelle Mine to more efficiently dispatch mobile equipment and monitor all major mining equipment performance and condition on a real-time basis. The system is being evaluated for potential rollout to other mining operations. Proprietary software for hand-held Personal Digital Assistant (“PDA”) devices has been developed and is being tested for safety observations, audits and front-line supervisor reports. All draglines are equipped with stress and performance monitoring equipment.
      We have recently purchased a longwall system at our Twentymile Mine with state-of-the-art controls and software expected to increase mine output beginning in 2006. In addition, the North Goonyella Mine in Australia has purchased upgraded longwall components to widen the longwall face and maximize 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.
      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 spending by extending the equipment life, while minimizing the risk of premature failures. Lubrication is replaced and work is scheduled on condition rather than time. Benefits from sophisticated lubrication analysis and quality-control include lower lubrication consumption, optimum equipment performance and extended component life. We are upgrading our computerized maintenance management system to support our maintenance practices.
      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 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 support the Power Systems Development Facility, a research and development facility that is focused on developing a highly efficient electricity generating plant using advanced emissions reduction technology funded primarily through the U.S. Department of Energy and operated by an affiliate of Southern Company. Peabody is also a member of the multi-company alliance working with the Department of Energy on FutureGen, a long-term project to develop near-zero emission power generation technology that will produce both power and hydrogen from coal and will capture and sequester carbon dioxide.
Competition
      The markets in which we sell our coal are highly competitive. According to the National Mining Association’s “2004 Coal Producer Survey,” the top 10 coal companies in the United States produced approximately 69% of total domestic coal in 2004. Our principal U.S. competitors are other large coal producers, including Arch Coal, Inc., Kennecott Energy Company, CONSOL Energy Inc, Foundation Coal Corporation and Massey Energy Company, which collectively accounted for approximately 41% of

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total U.S. coal production in 2004. Major international competitors include Rio Tinto, Anglo-American PLC and BHP Billiton.
      A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on the coal consumption patterns of the electricity and steel industries in the United States, China, India and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear and hydroelectric. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations, and technological developments. We compete on the basis of coal quality, delivered price, customer service and support, and reliability.
Generation Development
      To maximize our coal assets and land holdings for long-term growth, we are continuing to pursue the development of coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. The projects we are currently pursuing, as further detailed below, include the 1,500-megawatt Prairie State Energy Campus in Washington County, Illinois; the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky; and the 300-megawatt Mustang Energy Project near Grants, New Mexico. These projects involve mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to equity partner, contract miner or coal lessor.
      We are continuing to progress on the permitting processes, transmission access agreements and contractor-related activities for developing clean, low-cost mine-mouth generating plants using our surface lands and coal reserves. Because coal costs just a fraction of natural gas, mine-mouth generating plants can provide low-cost electricity to satisfy growing baseload generation demand. The plants will be designed to comply with all current clean air standards using advanced emissions control technologies. The plants, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, could be operational following a four-year construction phase. The first of these plants would not be operational earlier than mid-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 six million tons of coal each year produced from an adjacent underground mine. During August 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. After an initial appeal, the Illinois Environmental Protection Agency reissued the air permit on April 28, 2005. The same parties who filed the earlier permit challenge filed a new appeal on June 8, 2005. We believe the permit was appropriately issued and expect to prevail in the appeal process. Various other required permits are in process and may also be subject to challenge.
Thoroughbred Energy Campus
      In 2003, the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky received a conditional Certificate to Construct from the Commonwealth of Kentucky. We and the Commonwealth of Kentucky are defending the air permit granted in 2002 to Thoroughbred Energy

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Campus, as certain environmental groups are challenging the air permit. The project is currently awaiting a final decision by the Secretary of the Kentucky Environmental Protection cabinet. On September 2, 2005, an extension of the permit was granted through April 9, 2007. If successfully completed, the Thoroughbred Energy project is expected to utilize approximately six million tons of coal each year.
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. 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 and would be fueled by about one million tons of coal each year. The project is in the early stages of obtaining all necessary permits.
FutureGen Industrial Alliance
      We are a founding member of the FutureGen Industrial Alliance, a non-profit company that is partnering with the U.S. Department of Energy to facilitate the design, construction and operation of the world’s first near-zero emission coal-fueled power plant. FutureGen will demonstrate advanced coal-based technologies to generate electricity and also produce hydrogen to power fuel cells for transportation and other energy needs. The technology also will integrate the capture of carbon emissions with carbon sequestration, helping to address the issue of climate change as energy demand continues to grow worldwide. The alliance announced in December 2005 that it entered into a cooperative agreement with the U.S. Department of Energy to develop and site in the United States the cleanest coal-fueled power plant in the world with a target of zero emissions, hydrogen production and carbon dioxide sequestration capabilities.
BTU Conversion
      With the increase in demand in our country for natural gas and oil based commodities, significant attention has been placed on determining how we can participate in technologies to economically convert our coal resources. Over the last twenty years, technology has advanced to convert coal to natural gas as well as liquids, such as diesel fuel, gasoline and jet fuel.
      In October 2005, we reached an agreement to acquire a 30% interest in Econo-Power International Corporation (“EPICTM”). We will invest up to $6 million for the 30% interest and will assist in developing coal supply options for customers of that technology. As of December 31, 2005, we have funded $2 million under this agreement. EPICTM systems use air-blown gasifiers to convert coal into a synthetic gas that is ideal for industrial applications.
      In November 2005, we announced that we had entered into a memorandum of understanding with ArcLight Capital Partners, LLC to advance project development of a commercial-scale coal gasification project in Illinois. This project would transform coal into pipeline quality natural gas. The project would require approximately three million tons of coal per year and is expected to begin the permitting process in early 2006.
Coalbed Methane
      We continue to evaluate the potential of the coalbed methane business and will make acquisitions, develop our properties, enter into joint operating agreements and ventures with other companies or make property sales as appropriate. Our subsidiary, Peabody Natural Gas, LLC, produces coalbed methane from its operations in the Southern Powder River Basin near the Caballo Mine and North Antelope Rochelle Mine. At December 31, 2005, we operated 73 coalbed methane wells with net production of approximately 2.6 million cubic feet per day. We are evaluating the coalbed methane resources in several deep coal seams in the Powder River Basin and continue to evaluate coalbed methane and shale gas opportunities in western Kentucky, southern Indiana and West Virginia.

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Certain Liabilities
      We have significant long-term liabilities for reclamation (also called asset retirement obligations), work-related injuries and illnesses, pensions and retiree health care. In addition, labor contracts with the UMWA and voluntary arrangements with non-union employees include long-term benefits, notably health care coverage for retired employees and future retirees and their dependents. The majority of our existing liabilities relate to our past operations.
      Asset Retirement Obligations. Asset retirement obligations primarily represent the present value of future anticipated costs to restore surface lands to productivity levels equal to or greater than pre-mining conditions, as required by the Surface Mining Control and Reclamation Act. Expense (which includes liability accretion and asset amortization) for the years ended December 31, 2005, 2004 and 2003 was $35.9 million, $42.4 million, and $31.2 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” (“SFAS No. 143”). The effect of the adoption of SFAS No. 143 is discussed in Note 7 to our consolidated financial statements. Total asset retirement obligations as of December 31, 2005 of $399.2 million consisted of $340.7 million related to locations with active mining operations and $58.5 million related to locations that are closed or inactive.
      Workers’ Compensation. These liabilities represent the actuarial estimates for compensable, work-related injuries (traumatic claims) and occupational disease, primarily black lung disease (pneumoconiosis). The Federal Black Lung Benefits Act requires employers to pay black lung awards to former employees who filed claims after June 1973. These liabilities totaled approximately $271.9 million as of December 31, 2005, $34.3 million of which was a current liability. Expense for the years ended December 31, 2005, 2004 and 2003 was $56.9 million, $65.4 million and $50.6 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 $123.3 million as of December 31, 2005, $7.9 million of which was a current liability. Expense for the years ended December 31, 2005, 2004 and 2003 was $38.7 million, $28.5 million and $20.7 million, respectively.
      Retiree Health Care. Consistent with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” we record a liability representing the estimated cost of providing retiree health care benefits to current retirees and active employees who will retire in the future. Provisions for active employees represent the amount recognized to date, based on their service to date; additional amounts are accrued periodically so that the total estimated liability is accrued when the employee retires.
      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 bankrupt companies who were receiving benefits as orphans prior to the 1992 law. No new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan created by the same federal law in 1992, provides benefits to qualifying retired former employees of bankrupt companies who have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers default in providing their former employees with retiree medical benefits, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Fund, was established through collective bargaining and provides benefits to qualifying retired former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business, however our liability is

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limited to our contractual commitment of $0.50 per hour worked. The collective bargaining agreement with UMWA expires on December 31, 2006.
      Our retiree health care liabilities totaled approximately $1,034.3 million as of December 31, 2005, $75.0 million of which was a current liability. Expense for the years ended December 31, 2005, 2004 and 2003 was $99.0 million, $58.4 million and $83.7 million, respectively. Obligations to the United Mine Workers of America Combined Fund totaled $36.7 million as of December 31, 2005, $8.8 million of which was a current liability. Expense for the years ended December 31, 2005, 2004 and 2003 was $0.9 million, $4.9 million and $1.2 million, respectively. 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 $4.0 million, $4.4 million and $5.3 million for the years ended December 31, 2005, 2004 and 2003, respectively.
Employees
      As of December 31, 2005, we and our subsidiaries had approximately 8,300 employees. As of December 31, 2005, approximately 61% of our hourly employees were non-union and they generated 81% of our 2005 coal production. Relations with our employees and, where applicable, organized labor are important to our success.
      Recently, we opened a training center in the eastern region of the United States under our “Workforce of the Future” initiative and we will soon open centers in the midwest and western regions. Due to our current employee demographics, a significant portion of our current hourly employees will retire over the next decade. Our training centers are educating our workforce, particularly our most recent hires, in our rigorous safety standards, the latest in mining techniques and equipment, and the centers serve as centers for dissemination of mining best practices across all of our operations. Our training efforts exceed minimum government standards for safety and technical expertise with the intent of developing and retaining a world-class workforce.
United States
      Approximately 64% of our U.S. miners are non-union and are employed in the states of Wyoming, Colorado, Indiana, New Mexico, Illinois and Kentucky. The UMWA represented approximately 30% of our subsidiaries’ hourly employees, who generated 14% of our domestic production during the year ended December 31, 2005. An additional 6% of our hourly employees are represented by labor unions other than the UMWA. These employees generated 2% of our production during the year ended December 31, 2005. Hourly workers at our mines in Arizona and one of our mines in Colorado are represented by the UMWA under the Western Surface Agreement of 2000, which is effective through September 1, 2007. Our union labor east of the Mississippi River is primarily represented by the UMWA 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. The Construction Forestry Mining and Energy Union (“CFMEU”) represents our hourly production employees. Our Australian hourly employees are approximately 4% of our hourly workforce and generated 4% of our total production in the year ended December 31, 2005. Negotiations are underway to renew the labor agreement at our Wilkie Creek Mine, which expires in June 2006. The Eaglefield Mine operates under a labor agreement that expires in May 2007. The Burton and North Goonyella Mines operate under agreements due to expire in 2008.
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,

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plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment. These requirements could prove costly and time-consuming and could delay commencing or continuing exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, our activities may be more closely regulated. Such legislation and regulations, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.
      We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of the violations to date or the monetary penalties assessed has been material.
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. See risks inherent to mining in Item 1A. Risk Factors.
      Most of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. Several states are reevaluating their safety regulations, and in February 2006 the Mine Safety and Health Administration adopted emergency rules. 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 progress in this area primarily through the use of accident frequency rates. We believe that it is our responsibility to our employees to provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in the establishment of safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence. A portion of the annual performance incentives for our operating units is tied to their safety record.
      Our safety performance in 2005, as measured by accident frequency rates, was 45% better than the U.S. average for our industry. During 2005, we achieved our rate of zero accidents at four of our operations, which contributed to a 30% improvement in safety compared to the previous year. We received multiple safety awards during the year, including our second consecutive Safe Sam award at our North Antelope Rochelle Mine, Wyoming’s safest mine and our most productive, and the Mountaineer Guardian Award from the West Virginia Office of Miners’ Health, Safety and Training and the West Virginia Coal Association for outstanding safety achievement at our Federal No. 2 underground mine. Our training centers educate our employees in safety best practices and reinforce our company-wide belief that productivity and profitability follow when safety is a cornerstone of all of our operations. See “Employees” above for a discussion of our Workforce of the Future initiative.

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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 pay federal black lung benefits and medical expenses to claimants who are current and former employees and last worked for the operator after July 1, 1973. Coal mine operators must also make payments to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.
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 UMWA retirees. The Coal Act established the Combined Fund into which “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. The Coal Act also created a second benefit fund, the 1992 Benefit Plan, for miners who retired between July 21, 1992, and September 30, 1994, and whose former employers are no longer in business. Annual payments made by certain of our subsidiaries under the Coal Act totaled $6.3 million, $19.3 million $20.6 million, respectively, during the years ended December 31, 2005, 2004 and 2003.
      Our subsidiaries have been billed a retroactive assessment in the amount of $7.4 million for periods prior to October 1, 2003 as well as an increase of $0.7 million for the period from October 1, 2003 through September 30, 2004 and $0.6 million from October 2004 through August 15, 2005 as a result of the Social Security Administration’s premium recalculation. These amounts were paid as required by the Combined Fund Trustees, but were paid under protest. In August 2005, a federal court in Maryland ruled in favor of our subsidiaries, and we suspended payments to the Combined Fund to recoup our overpayment. On December 2, 2005, the same federal court granted a stay of payment recoupment and we paid to the Combined Fund the amount we recouped.
      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 12 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

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grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation.
      The U.S. mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required of the OSM’s Applicant Violator System.
      Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including public hearings and through intervention in the courts.
      Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund. The fee, which expires on June 30, 2006, 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”, commonly known as “Superfund”) 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. The Clean Air Act indirectly, but more significantly, affects the coal industry by extensively regulating the air emissions of sulfur dioxide, nitrogen oxide, mercury and other compounds emitted by coal-based electricity generating plants.

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      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 the Title IV sulfur dioxide 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, the EPA proposed the Clean Air Interstate Rule (“CAIR”), which is designed to help bring the eastern half of the United States into compliance with the National Ambient Air Quality Standards for fine particulates and ozone. The rule became final in March 2005 and will require further reduction of sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 28 states and the District of Columbia although it is being challenged. Once fully implemented, the rule will reduce sulfur dioxide from power plants by approximately 73% from 2003 levels and, by 2015, nitrogen oxide emissions by approximately 61% from 2003 levels.
      The Clean Air Act also requires electricity generators that currently are major sources of nitrogen oxide in moderate or higher ozone non-attainment areas (areas where the air quality does not meet acceptable standards) to install reasonably available control technology for nitrogen oxide, which is a precursor of ozone. In 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 states were required to submit their Phase II SIPs by April 2005. Two additional states, Georgia and Missouri, were required to submit a complete NOx SIP by April 2005 to address affected portions of their states. EPA has proposed to stay the applicability of the SIP Call to Georgia in response to a petition to reconsider whether Georgia should be covered. Installation of additional control measures required under the final rules have made and will continue to make it more costly to operate coal-based electricity generating plants.
      The Justice Department, on behalf of the EPA, has filed a number of lawsuits since November 1999, alleging that 12 electricity generators violated the new source review provisions of the Clean Air Act Amendments at power plants in the midwestern and southern United States. Six electricity generators have announced settlements with the Justice Department requiring the installation of additional control equipment on selected generating units, and at least one generator has received a favorable court decision. If the remaining electricity generators are found to be in violation, they could be subject to civil penalties and be required to install the required control equipment or cease operations. 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.

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      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 were required to consider setting a goal of restoring natural visibility conditions in Class I areas in their states by 2064 and to explain their reasons to the extent they determine not to adopt this goal. The state plans must require the application of “Best Available Retrofit Technology” (“BART”) after 2010 on certain electric generating stations reasonably anticipated to cause or contribute to regional haze which impairs visibility in these areas. The extent and nature of these BART requirements have been the subject of litigation. As a result of the litigation, EPA finalized amendments to the 1999 BART regulations in June 2005. EPA included in the amendments guidelines for states to use in determining which facilities must install controls and the types of controls the facilities must use. States are required to develop their implementation plans by December 2007. For states subject to CAIR that adopt the CAIR cap and trade program for sulfur dioxide and NOx, the state is allowed to apply CAIR controls as a substitute for those required by BART. Five western states have elected an option offered by the EPA of regulating visibility-impairing emissions through a regional rather than a source-by-source approach. However, this option was litigated and the states’ rules were invalidated. The EPA’s regional haze regulations could cause our customers to install equipment to control sulfur dioxide and nitrogen oxide emissions. The requirement to install control equipment could affect the amount of coal supplied to those customers if they decide to switch to other sources of fuel to lower emission of sulfur dioxide and nitrogen oxide.
      On March 15, 2005, EPA adopted the Clean Air Mercury Rule (“CAMR”) to permanently cap and reduce mercury emissions from coal-fired power plants. When fully implemented, and after the appeals have been resolved, the rule will reduce mercury emissions by nearly 70%. CAMR establishes standards of performance limiting mercury emissions from new and existing power plants and creates a cap-and-trade program, which will reduce emissions in two phases. When fully implemented, the cap on mercury emissions will be 15 tons per year. Some states are considering rules that are more stringent than the federal program. Implementation of the federal program or the more stringent state programs could cause our customers to switch to other fuels to the extent it would be economically preferable for them to do so, and could impact the completion or success of our generation development projects.
      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% by 2018. Other similar emission reduction proposals have been introduced in Congress, some of which propose to also regulate carbon dioxide. No such legislation has passed either house of 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 requiring effluent limitations and treatment standards for waste water discharge through the National Pollutant Discharge Elimination

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System (“NPDES”). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water.
      States are empowered to develop and enforce “in stream” water quality standards. These standards are subject to change and must be approved by the EPA. Discharges must either meet state water quality standards or be authorized through available regulatory processes such as alternate standards or variances. “In stream” standards vary from state to state. Additionally, through the Clean Water Act section 401 certification program, states have approval authority over federal permits or licenses that might result in a discharge to their waters. States consider whether the activity will comply with its water quality standards and other applicable requirements in deciding whether or not to certify the activity.
      Section 404 under the Clean Water Act requires mining companies to obtain COE permits to place material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. These permits have been the subject of multiple recent court cases, the results of which may affect permitting costs or result in permitting delays.
      Total Maximum Daily Load (“TMDL”) regulations established a process by which states designate stream segments as impaired (not meeting present water quality standards). Industrial dischargers, including coal mines, may be required to meet new TMDL effluent standards for these stream segments. States are also adopting anti-degradation regulations in which a state designates certain water bodies or streams as “high quality/exceptional use.” These regulations would restrict the diminution of water quality in these streams. Waters discharged from coal mines to high quality/exceptional use streams may be required to meet additional conditions or provide additional demonstrations and/or justification. In general, these Clean Water Act requirements could result in higher water treatment and permitting costs or permit delays, which could adversely affect our coal production costs or efforts.
Resource Conservation and Recovery Act
      RCRA, which was enacted in 1976, affects U.S. coal mining operations by establishing “cradle to grave” requirements for the treatment, storage and disposal of hazardous wastes. Typically, the only hazardous materials found on a mine site are those contained in products used in vehicles and for machinery maintenance. Coal mine wastes, such as overburden and coal cleaning wastes, are not considered hazardous waste materials under RCRA.
      Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion materials generated at electric utility and independent power producing facilities. In May 2000, the EPA concluded that coal combustion materials do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these materials. The EPA is evaluating national non-hazardous waste guidelines for coal combustion materials placed at a mine. National guidelines for mine-fills may affect the cost of ash placement at mines.
CERCLA (Superfund)
      CERCLA affects U.S. coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. Under the EPA’s Toxic Release Inventory process, companies are required annually to report the use, manufacture or processing of listed toxic materials that exceed defined thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers.

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The Energy Policy Act of 2005
      The Domenici-Barton Energy Policy Act of 2005 (“EPACT”) was signed by President Bush in August 2005. EPACT contains tax incentives and directed spending totaling an estimated $14.1 billion intended to stimulate supply-side energy growth and increased efficiency.
      In addition to rules affecting the leasing process of federal coal properties, EPACT programs and incentives include:
  •  the Clean Coal Power Initiative, authorizing $200 million annually from 2006 — 2014 to demonstrate advanced coal technologies, including coal gasification;
 
  •  the Clean Air Coal Program, which contains a $2.5 billion grant and loan guarantee program to encourage deployment of advanced clean coal-based power generation technologies, including integrated gasification combined cycle (“IGCC”);
 
  •  a federal loan guarantee program for up to 80% of the cost of advanced fossil energy projects, including coal gasification;
 
  •  a $1.9 billion authorization over the 2007 — 2009 period for the Department of Energy to conduct energy research, development, demonstration and commercial application programs relating to coal and power systems; and
 
  •  tax incentives for IGCC, industrial gasification and other advanced coal-based generation projects, as well as for coal sold from Indian lands.
      Finally, certain sections of EPACT are potentially applicable to the area of Btu Conversion, such as the aforementioned fossil energy project loan guarantee program as well as a provision allowing taxpayers to capitalize 50% of the cost of refinery investments which increase the total throughput of qualified fuels — including synthetic fuels produced from coal — by at least 25%. In addition, EPACT requires the Secretary of Defense to develop a strategy to use fuel produced from coal, oil shale and tar sands (“covered fuel”) to assist in meeting the fuel requirements of the U.S. Department of Defense (“DOD”). The law authorizes the DOD to enter into multi-year contracts to procure a covered fuel to meet one or more of its fuel requirements and to carry out an assessment of potential locations for covered fuel sources.
Regulatory Matters — Australia
      The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control, noise, planning issues (such as approvals to expand existing mines or to develop new mines), and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory reclamation is completed.
      Mining and exploration in Australia is generally carried on under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.
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.

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      Native title rights do not extend to minerals; however, native title rights can be affected by the mining process unless those rights have previously been extinguished. Native title rights can be extinguished either by a valid act of Government (as set out in the NTA) or by the loss of connection between the land and the group of Aboriginal peoples concerned.
      The NTA provides that where native title rights still exist and the mining project will affect those native title rights, it will be necessary to consult with the relevant Aboriginal group and to come to an agreement on issues such as the preservation of sacred or important sites, the employment of members of the group by the mine operator, and the payment of compensation for the effect on native title of the mining project. In the absence of agreement with the relevant Aboriginal group, there is an arbitration provision in the NTA.
      There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archeological sites. The NTA and laws protecting Aboriginal cultural heritage and archeological sites have had no impact on our current operations.
Environmental
      The federal system requires that approval is obtained for any activity which will have a significant impact on a matter of national environmental significance. Matters of national environmental significance include listed endangered species, nuclear actions, World Heritage areas, National Heritage areas, and migratory species. An application for such an approval may require public consultation and may be approved, refused or granted subject to conditions. Otherwise, responsibility for environmental regulation in Australia is primarily vested in the states.
      Each state and territory in Australia has its own environmental and planning regime for the development of mines. In addition, each state and territory also has a specific act dealing with mining in particular, regulating the granting of mining licenses and leases. The mining legislation in each state and territory operates concurrently with environmental and planning legislation. The mining legislation governs mining licenses and leases, including the restoration of land following the completion of mining activities. Apart from the grant of rights to mine (which are covered by the mining statutes), all licensing, permitting, consent and approval requirements are contained in the various state and territory environmental and planning statutes.
      The particular provisions of the various state and territory environmental and planning statutes vary depending upon the jurisdiction. Despite variation in details, each state and territory has a system involving at least two major phases. First, obtaining the developmental application and, if that is granted, obtaining the detailed operational pollution control licenses, which authorize emissions up to a maximum level; and second, obtaining pollution control approvals, which authorize the installation of pollution control equipment and devices. In the first regulatory phase, an application to a regulatory authority is 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.

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      Many of the environmental planning statutes across the states and territories contain “third party” appeal rights in relation, particularly, to the first regulatory phase. This means that any party has a right to take proceedings for a threatened or actual breach of the statute, without first having to establish that any particular interest of that person (other than as a member of the public) stands to be affected by the threatened or actual breach.
      Accordingly, in most states and territories throughout Australia, mining activities involve a number of regulatory phases. Following exploratory investigations pursuant to a mining lease, the activity proposed to be carried out must be the subject of an application for the activity or development. This phase of the regulatory process, as noted above, usually involves the preparation of extensive documents to constitute the application, addressing all of the environmental impacts of the proposed activity. It also generally involves extensive notification and consultation with other relevant statutory authorities and members of the public. Once a decision is made to allow a mine to be developed by the grant of a development consent, permit or other approval, then a formal mining lease can be obtained under the mining statute. In addition, operational licenses and approvals can then be applied for and obtained in relation to pollution control devices and emissions to the atmosphere, to waters and for noise. The obtaining of licenses and approvals, during the operational phase, generally does not involve any extensive notification or consultation with members of the public, as most of these issues are anticipated to be resolved in the first regulatory phase.
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 with respect to the compensation of injured workers; similar coverage is in effect throughout Australia which is of a no fault nature and which provide for benefits up to a prescribed level. The specific benefits vary from jurisdiction to jurisdiction, but generally include the payment of weekly compensation to an incapacitated employee, together with payment of medical, hospital and related expenses. The injured employee has a right to sue his or her employer for further damages if a case of negligence can be established.
Global Climate Change
      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

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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. 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. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. Passage of regulations regarding greenhouse gas emissions by the United States or other actions to limit carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by electric generators.
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 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
      You may also request copies of our filings, 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 1A. Risk Factors.
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.
      Most of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. For the year ended December 31, 2005, 90% of our sales volume was sold under long-term coal supply agreements. At December 31, 2005, our coal supply agreements had remaining terms ranging from one to 19 years and an average volume-weighted remaining term of approximately 3.2 years.
      Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times. We may adjust these contract prices based on inflation or deflation and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. We sometimes experience a reduction in coal prices in new long-term coal supply agreements replacing some of our expiring contracts. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of specified events beyond the control of the affected party. Most coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements permit the customer to terminate the contract if transportation costs, which our customers typically bear, increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.
      The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find

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alternate buyers for our coal at the same level of profitability. Market prices for coal vary by mining region and country. As a result, we cannot predict the future strength of the coal market overall or by mining region and cannot assure you that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, one of our largest coal supply agreements is the subject of ongoing litigation and arbitration.
The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues.
      For the year ended December 31, 2005, we derived 21% of our total coal revenues from sales to our five largest customers. At December 31, 2005, we had 79 coal supply agreements with these customers expiring at various times from 2006 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.
      We had been supplying coal to the Mohave Generating Station pursuant to a long-term coal supply agreement through our Black Mesa Mine. The mine suspended its operations on December 31, 2005, and the coal supply agreement expired on that date. As a part of an alternate dispute resolution, 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 groundwater and other disputes involving the two generating stations. Resolution of these issues is critical to the operation of the Mohave Generating Station after December 31, 2005. There is no assurance that these issues will be resolved. The Mohave plant was the sole customer of the Black Mesa Mine, which sold 4.6 million tons of coal in 2005. During 2005, the mine generated $29.8 million of Adjusted EBITDA (reconciled to its most comparable measure under generally accepted accounting principles in Note 27 of the consolidated financial statements), which represented 3.4% of our total EBITDA of $870.4 million.
Our financial performance could be adversely affected by our debt.
      Our financial performance could be affected by our indebtedness. As of December 31, 2005, our total indebtedness was approximately $1,405.5 million, and we had $493.3 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

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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 indentures 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, infrastructure damage, strikes, lock-outs, lack of fuel or maintenance items, transportation delays or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations. For example, two primary lines serve the Powder River Basin mines. Due to the high volume of coal shipped from all Powder River Basin mines, the loss of one, or both, of those lines due to damage or labor strike could create temporary congestion on the rail systems servicing that region.
      Continued increases in coal demand, combined with inventories at electricity generators that are lower than historical averages, created periodic regional rail and port congestion in 2005. 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 that can impact the safety of our workforce, or delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include fires and explosions from methane gas or coal dust; accidental minewater discharges; weather, flooding and natural disasters; unexpected maintenance problems; key equipment failures; variations in coal seam thickness; variations in the amount of rock and soil overlying the coal deposit; variations in rock and other natural materials and variations in geologic conditions. We maintain insurance policies that provide limited coverage for some of these risks, although there can be no assurance that these risks would be fully covered by our insurance policies. Despite our efforts, significant mine accidents could occur and have a substantial impact.
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,

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the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production. The possibility exists that new legislation and/or regulations and orders related to the environment or employee health and safety may be adopted and may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or judicial interpretations of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations.
      In addition, 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. Further developments in connection with regulations or other limits on carbon dioxide emissions could have a material adverse effect on our financial condition or results of operations.
Our expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.
      We provide postretirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation under SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” which we estimate had a present value of $1,034.3 million as of December 31, 2005, $75.0 million of which was a current liability. We have estimated these unfunded obligations based on assumptions described in the notes to our consolidated financial statements. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher. Moreover, regulatory changes could increase our obligations to provide these or additional benefits.
      We are party to an agreement with the Pension Benefit Guaranty Corporation (the “PBGC”) and TXU Europe Limited, an affiliate of our former parent corporation, under which we are required to make specified contributions to two of our defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If we or the PBGC give notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if we fail to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guaranty in place from TXU Europe Limited in favor of the

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PBGC before it draws on our letter of credit. On November 19, 2002 TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the United States) and continues under this process as of December 31, 2005.
      In addition, certain of our subsidiaries participate in two defined benefit multi-employer pension funds that were established as a result of collective bargaining with the UMWA pursuant to the National Bituminous Coal Wage Agreement as periodically negotiated. The UMWA 1950 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked prior to January 1, 1976. This is a closed group of beneficiaries with no new entrants. The UMWA 1974 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked after December 31, 1975.
      Contributions to these funds could increase as a result of future collective bargaining with the UMWA, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to these funds, lower than expected returns on pension fund assets, higher medical and drug costs or other funding deficiencies.
      The United Mine Workers of America Combined Fund was created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of bankrupt companies who were receiving benefits as orphans prior to the 1992 law. No new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan created by the same federal law in 1992, provides benefits to qualifying retired former employees of bankrupt companies who have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers default in providing their former employees with retiree medical benefits, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Fund, was established through collective bargaining and provides benefits to qualifying retired former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business.
      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 postretirement benefit obligations and related expense. Failure to achieve these assumed future savings under all benefit plans could adversely affect our financial condition, results of operations and cash flows.
A decrease in the availability or increase in costs of key supplies or commodities such as diesel fuel, steel, explosives and tires could decrease our anticipated profitability.
      Our mining operations require a reliable supply of replacement parts, explosives, fuel, tires, steel-related products (including roof control) and lubricants. If the cost of any of these inputs increased significantly, or if a source for these supplies or mining equipment were unavailable to meet our replacement demands, our profitability could be reduced from our current expectations. Recent consolidation of suppliers of explosives has limited the number of sources for these materials, and our current supply of explosives is concentrated with one supplier. Further, our purchases of some items of underground mining equipment are concentrated with one principal supplier. In the past year, industry-wide demand growth has exceeded supply growth for certain surface and underground mining equipment and off-the-road tires. As a result, lead times for some items has generally increased by up to several months.

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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, 2005, we leased a total of 62,330 acres from the federal government. The limit could restrict our ability to lease additional federal lands. For additional discussion of our federal leases see Item 2. Properties.
      Our planned mine development projects and acquisition activities may not result in significant additional reserves and we may not have continuing success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because title to most of our leased properties and mineral rights are not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we must receive various governmental permits. We cannot predict whether we will continue to receive the permits necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties 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 have annual capacity to produce approximately 12 to 14 million tons of metallurgical coal. Prices for metallurgical coal at the end of 2005 were at historically high levels. We have committed approximately 7 million tons of our projected 2006 metallurgical coal production at prices that carry significant premiums to historical pricing. 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 the future. To the extent we experience either production or transportation difficulties that impair our ability to ship metallurgical coal to our customers at anticipated levels, our profitability will be reduced in 2006.
      After 2006, 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 2006.
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. Recently, certain of our brokerage sources and contract miners have experienced adverse geologic mining and/or financial difficulties that have made their delivery of coal to us at the contractual price difficult or uncertain. Our profitability or exposure to loss on transactions or relationships such as

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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, 2005, we and our subsidiaries had approximately 8,300 employees. As of December 31, 2005, approximately 39% of our hourly employees were represented by unions and they generated 19% of our 2005 coal production. Relations with our employees and, where applicable, organized labor are important to our success. The labor contract for the majority of our represented employees expires on December 31, 2006. We could incur the risk of strikes and higher labor costs if the labor negotiations are not completed on mutually acceptable terms.
      Due to the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our competitors who operate without union labor may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs.
United States
      Approximately 64% of our U.S. miners are non-union and are employed in the states of Wyoming, Colorado, Indiana, New Mexico, Illinois and Kentucky. The UMWA represented approximately 30% of our subsidiaries’ hourly employees, who generated 14% of our domestic production during the year ended December 31, 2005. An additional 6% of our hourly employees are represented by labor unions other than the UMWA. These employees generated 2% of our production during the year ended December 31, 2005. Hourly workers at our mines in Arizona and one of our mines in Colorado are represented by the UMWA under the Western Surface Agreement of 2000, which is effective through September 1, 2007. Our union labor east of the Mississippi River is primarily represented by the UMWA 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. The CFMEU represents our hourly production employees. Our Australian hourly employees are approximately 4% of our hourly workforce and generated 4% of our total production in the year ended December 31, 2005. Negotiations are underway to renew the labor agreement at our Wilkie Creek Mine, which expires in June 2006. The Eaglefield Mine operates under a labor agreement that expires in May 2007. The Burton and North Goonyella Mines operate under agreements due to expire in 2008.

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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, 2005, we had $674.7 million of self bonds in place primarily for our reclamation obligations. As of December 31, 2005, we also had outstanding surety bonds with third parties of $642.0 million, of which $323.6 million was for post-mining reclamation, $258.8 million was for lease obligations and $45.3 million was for workers’ compensation and other obligations. 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 alternative 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.
      Due to the current demographics of our mining workforce, a high portion of our current hourly employees are eligible to retire over the next decade. Failure to attract new employees to the mining workforce could have a material adverse effect on us.
Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.
      Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations.

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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 1B. Unresolved Staff Comments.
      None.
Item 2. Properties.
Coal Reserves
      We had an estimated 9.8 billion tons of proven and probable coal reserves as of December 31, 2005. An estimated 9.5 billion tons of our proven and probable coal reserves are in the United States and 0.3 billion tons are in Australia. Forty-two percent of our reserves, or 4.1 billion tons, are compliance coal and 58% are non-compliance coal. We own approximately 42% of these reserves and lease property containing the remaining 58%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.
      Below is a table summarizing the locations and reserves of our major operating regions.
                                   
        Proven and Probable
        Reserves as of
        December 31, 2005(1)
         
        Owned   Leased   Total
Operating Regions   Locations   Tons   Tons   Tons
                 
        (Tons in millions)
Powder River Basin
    Wyoming and Montana       67       3,422       3,489  
Southwest
    Arizona and New Mexico       608       372       980  
Colorado
    Colorado       37       215       252  
Appalachia
    West Virginia, Ohio       272       312       584  
Midwest
    Illinois, Indiana and Kentucky       3,163       1,011       4,174  
Australia
    Queensland             289       289  
                         
 
Total Proven and Probable Coal Reserves
            4,147       5,621       9,768  
                         
 
(1)  Reserves have been adjusted to take into account estimated losses involved in producing a saleable product.

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      Reserves are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proven and probable coal reserves are defined by SEC Industry Guide 7 as follows:
        Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.
 
        Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) 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 reserves and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.
      Our estimate of the economic recoverability of our reserves is based upon a comparison of unassigned reserves to assigned reserves currently in production in the same geologic setting to determine an estimated mining cost. These estimated mining costs are compared to existing market prices for the quality of coal expected to be mined and taking into consideration typical contractual sales agreements for the region and product. Where possible, we also review production by competitors in similar mining areas. Only reserves expected to be mined economically 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

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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, and after adjusting for acquisitions, exchanges, divestitures, production and estimate refinements (through additional drilling and engineering analysis) through December 31, 2005, proven and probable reserves totaled 9.8 billion tons.
      With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to move reserves from the probable to the proven classification. On a regional basis, the expected degree of variance from reserve estimate to tons produced is lower in the Powder River Basin, Southwest and Illinois Basin due to the continuity of the coal seams as confirmed by the mining history. Appalachia, however, has a higher degree of risk due to the mountainous nature of the topography which makes exploration drilling more difficult. Our recovered reserves in Appalachia are less predictable and may vary by an additional one to two percent above the threshold discussed above.
      We have numerous federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents on surface land under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2005, we leased 10,903 acres of federal land in Colorado, 11,254 acres in Montana and 40,173 acres in Wyoming, for a total of 62,330 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 9.8 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 geographic region and mining complex, of production for the years ended December 31, 2005 and 2004 and 2003, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities.
PRODUCTION AND ASSIGNED RESERVES(1)
(Tons in millions)
                                                                                                             
            Sulfur Content(2)       As of December 31, 2005
    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   2005   2004   2003   Coal   Million Btu   Million Btu   Million Btu   Pound(3)   Reserves   Owned   Leased   Surface   Underground
                                                     
Appalachia:
                                                                                                       
 
Federal
    4.1       4.9       4.1       Steam                   28       13,300       28       4       24             28  
 
Big Mountain
    1.9       1.9       1.5       Steam       3       23       1       12,500       27             27             27  
 
Harris
    2.0       3.0       3.0       Steam/Met.       1       7             13,300       8             8             8  
 
Rocklick
    2.6       2.0       2.5       Steam/Met.       13       4             13,300       17             17       2       15  
 
Wells
    2.6       2.6       2.4       Steam/Met.       20       23       1       13,200       44             44             44  
                                                                               
   
Total
    13.2       14.4       13.5               37       57       30               124       4       120       2       122  
Midwest:
                                                                                                       
 
Camps/ Highland
    3.8       3.2       1.7       Steam                   90       11,000       90       31       59             90  
 
Patriot
    4.2       4.1       4.2       Steam                   46       10,900       46       5       41       7       39  
 
Air Quality
    2.1       1.8       1.9       Steam             30       32       10,700       62       5       57             62  
 
Riola/ Vermilion Grove
    2.3       2.3       1.8       Steam                   21       10,500       21             21             21  
 
Miller Creek
    1.0       0.9       0.8       Steam             3       29       10,500       32       31       1       32        
 
Francisco Surface
    1.8       2.1       2.5       Steam                   8       10,500       8       2       6       8        
 
Francisco Underground
    1.2       0.9             Steam                   22       10,700       22       4       18             22  
 
Farmersburg
    3.8       4.2       4.3       Steam       1       12       97       10,400       110       76       34       110        
 
Somerville Central
    3.4       3.2       3.3       Steam                   8       10,300       8       4       4       8        
 
Somerville
    4.8       4.1       4.0       Steam                   24       10,100       24       16       8       24        
 
Viking
    1.5       1.5       1.4       Steam             2       9       10,700       11             11       11        
 
Wildcat Hills
    2.6       2.7       2.5       Steam                   12       10,300       12       7       5       12        
 
Willow Lake
    3.7       3.4       2.8       Steam                   48       11,000       48       36       12             48  
 
Gateway
    0.5                   Steam                   22       10,300       22       21       1             22  
 
Dodge Hill
    1.2       1.2             Steam                   10       11,700       10       3       7             10  
                                                                               
   
Total
    37.9       35.6       31.2               1       47       478               526       241       285       212       314  
Powder River Basin:
                                                                                                       
 
Big Sky
                2.6       Steam                         NA                                
 
North Antelope/ Rochelle
    82.7       82.5       80.1       Steam       1,234                   8,800       1,234             1,234       1,234        
 
Caballo
    30.5       26.5       22.8       Steam       790       133       27       8,600       950             950       950        
 
Rawhide
    12.4       6.9       3.6       Steam       262       58       68       8,600       388             388       388        
                                                                               
   
Total
    125.6       115.9       109.1               2,286       191       95               2,572             2,572       2,572        
Southwest/ Colorado:
                                                                                                       
 
Black Mesa
    3.9       4.8       4.4       Steam       13       1             10,800       14             14       14        
 
Kayenta
    8.2       8.2       7.8       Steam       201       72       2       11,000       275             275       275        
 
Lee Ranch
    5.3       5.8       6.9       Steam       21       128       11       10,000       160       88       72       160        
 
Twentymile
    9.4       6.4             Steam       72                   11,000       72       7       65             72  
 
Seneca
    1.1       1.5       1.5       Steam                         NA                                
                                                                               
   
Total
    27.9       26.7       20.6               307       201       13               521       95       426       449       72  
Australia:
                                                                                                       
 
North Goonyella
    0.7       1.5             Met       50                   12,760       50             50             50  
 
Eaglefield
    1.4       0.2             Met       5                   12,760       5             5       5        
 
Burton
    4.4       3.2             Steam/Met       13                   12,380       13             13       13        
 
Wilkie Creek
    1.9       1.4       1.3       Steam       21                   10,770       21             21       21        
 
Baralaba
                      Steam/Met       2                   12,220       2             2       2        
                                                                               
   
Total
    8.4       6.3       1.3               91                           91             91       41       50  
                                                                               
Total
    213.0       198.9       175.7               2,722       496       616               3,834       340       3,494       3,276       558  
                                                                               

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      The following chart provides a summary of the amount of our proven and probable coal reserves in each U.S. state and Australia, the predominant type of coal mined in the applicable location, our property interest in the reserves and other characteristics of the facilities.
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES
As of December 31, 2005
(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
          34       34       24       10       Steam                   34       11,100       26       8             34  
 
West Virginia
    28       184       212       68       144       Steam             76       136       12,900       189       23             212  
                                                                                     
 
Northern Appalachia
    28       218       246       92       154                     76       170               215       31             246  
Central Appalachia:
                                                                                                               
 
West Virginia
    96       242       338       233       105       Steam/Met.       146       126       66       13,200       57       281       12       326  
                                                                                     
 
Central Appalachia
    96       242       338       233       105               146       126       66               57       281       12       326  
Midwest:
                                                                                                               
 
Illinois
    103       2,296       2,399       1,212       1,187       Steam       5       38       2,356       10,400       2,096       303       86       2,313  
 
Indiana
    277       245       522       385       137       Steam       1       47       474       10,400       354       168       275       247  
 
Kentucky
    146       1,107       1,253       714       539       Steam             1       1,252       10,800       713       540       134       1,119  
                                                                                     
 
Midwest
    526       3,648       4,174       2,311       1,863               6       86       4,082               3,163       1,011       495       3,679  
Powder River Basin:
                                                                                                               
 
Montana
          162       162       158       4       Steam       15       117       30       8,600       67       95       162        
 
Wyoming
    2,572       755       3,327       3,013       314       Steam       3,019       191       117       8,700             3,327       3,327        
                                                                                     
 
Powder River Basin
    2,572       917       3,489       3,171       318               3,034       308       147               67       3,422       3,489        
Southwest/ Colorado:
                                                                                                               
 
Arizona
    289             289       289             Steam       214       73       2       11,000             289       289        
 
Colorado
    72       180       252       200       52       Steam       164             88       10,900       37       215             252  
 
New Mexico
    160       531       691       430       261       Steam       259       346       86       8,700       608       83       691        
                                                                                     
 
Southwest
    521       711       1,232       919       313               637       419       176               645       587       980       252  
Australia:
                                                                                                               
 
Queensland
    91       198       289       132       157       Steam/Met.       289                   11,840             289       239       50  
                                                                                     
Total Proven and Probable
    3,834       5,934       9,768       6,858       2,910               4,112       1,015       4,641               4,147       5,621       5,215       4,553  
                                                                                     

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(1)  Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2005. 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 %
 
Australia
    10.0 %
Resource Development
      We hold approximately 9.8 billion tons of proven and probable coal reserves and more than 420,000 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.
Oklahoma Lead Litigation
      Gold Fields Mining, LLC (“Gold Fields”), one of our subsidiaries, 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 transferred ownership of Gold Fields to us,

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despite the fact that Gold Fields had no ongoing operations and we had no prior involvement in its past operations. We have agreed to indemnify a former affiliate of Gold Fields for certain claims.
      Gold Fields and two other companies are defendants in two class action lawsuits filed in the U.S. District Court for the Northern District of Oklahoma (Betty Jean Cole, et al. v. Asarco Inc., et al. and Darlene Evans, et al. v. Asarco Inc., et al.). The plaintiffs have asserted claims predicated on allegations of intentional lead exposure by the defendants 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 1950s and mined, in accordance with lease agreements and permits, approximately 1.5% of the total amount of the ore mined in the county.
      Gold Fields is also a defendant, along with other companies, in several personal injury lawsuits involving over 50 children, pending in the U.S. District Court for the Northern District of Oklahoma, arising out of the same lead mill operations. Plaintiffs in these actions are seeking compensatory and punitive damages for alleged personal injuries from lead exposure. Previously scheduled trials for some of these plaintiffs have been postponed.
      In December 2003, the Quapaw Indian tribe and certain Quapaw land owners filed a class action lawsuit against Gold Fields and five other companies in the U.S. District Court for the Northern District of Oklahoma. The plaintiffs are seeking compensatory and punitive damages based on a variety of theories. Gold Fields has filed a third-party complaint against the United States, and other parties. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other companies regarding a possible natural resources damage claim.
      The outcome of litigation and these claims are subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any potential loss cannot be estimated. However, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.
Navajo Nation
      On June 18, 1999, the Navajo Nation served three of our subsidiaries, including 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 (“RICO”) violations and fraud. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. 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 have terminated due to Peabody Western’s breach of these leases and a reformation of these leases to adjust the royalty rate to 20%. Subsequently, the court allowed the Hopi Tribe to intervene in this lawsuit and the Hopi Tribe is also seeking 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 rejecting the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments.
      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.
      The outcome of litigation, or the current mediation, is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any potential loss cannot be estimated. However, we believe this matter is likely to be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

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The Future of the Mohave Generating Station and Black Mesa Mine
      We had been supplying coal to the Mohave Generating Station pursuant to a long-term coal supply agreement through our Black Mesa Mine. The mine suspended its operations on December 31, 2005, and the coal supply agreement expired on that date. 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 groundwater and other disputes involving the two generating stations. Resolution of these issues is critical to the operation of the Mohave Generating Station after December 31, 2005. There is no assurance that these issues will be resolved. The Mohave plant was the sole customer of the Black Mesa Mine, which sold 4.6 million tons of coal in 2005. During 2005, the mine generated $29.8 million of Adjusted EBITDA (reconciled to its most comparable measure under generally accepted accounting principles in Note 27 of the consolidated financial statements), which represented 3.4% of our total Adjusted EBITDA of $870.4 million.
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, under the terms of a coal supply agreement dated February 18, 1977. The contract expires in 2011. The trial court subsequently ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. We have recorded a receivable for mine decommissioning costs of $74.2 million and $68.6 million included in “Investments and other assets” in the consolidated balance sheets at December 31, 2005, and December 31, 2004, respectively.
      The outcome of litigation is subject to numerous uncertainties. Based on our evaluation of the issues and their potential impact, the amount of any potential loss cannot be estimated. However, we believe this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.
West Virginia Flooding Litigation
      Three of our subsidiaries have been named in six separate complaints filed in Boone, Kanawha, Wyoming, and McDowell Counties, West Virginia seeking compensation for property damage and personal injury arising out of flooding that occurred in southern West Virginia during heavy rainstorms in July of 2001. These cases, along with approximately 50 similar cases not involving our subsidiaries, include approximately 3,500 plaintiffs and 77 defendants engaged in the extraction of natural resources. Plaintiffs have alleged that timbering, mining and disturbances of surface land by the defendants in the extraction of natural resources caused natural surface waters to be diverted in unnatural ways, thereby resulting in flooding which would not have occurred absent the defendants’ use and disturbance of surface lands.
      These cases have been consolidated pursuant to the Court’s Mass Litigation Rules. The Mass Litigation Panel has ordered that the cases be tried based upon the six geographic watersheds in which the flooding occurred. The first such trial is scheduled for early March 2006; however, our subsidiaries held no active mining permits in the geographic area which is the focus of the first trial. Trials involving two additional watersheds are scheduled for the second half of 2006. No trials are scheduled for the remaining three watersheds. Certain of our defendant subsidiaries did hold multiple active permits in the five remaining geographic watersheds. Our insurance carrier has acknowledged our tender of these claims and is currently providing a defense under applicable policies of insurance.
      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 ultimately will be resolved without a material adverse effect on our financial condition, results of operations or cash flows.

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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. During the period that Citizens Power was owned by us, Citizens Power guaranteed the obligations of two affiliates to make payments to third parties for power delivered under fixed-priced power sales agreements with terms that extend through 2008. Edison Mission Energy has stated and we believe there will be sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers.
Environmental
      We are subject to federal, state and local environmental laws and regulations, including CERCLA (also known as Superfund), the Superfund Amendments and Reauthorization Act of 1986, the Clean Air Act, the Clean Water Act and the Conservation and Recovery Act. 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. These regulations could require us to do some or all of the following:
  •  remove or mitigate the effects on the environment at various sites from the disposal or release of certain substances;
 
  •  perform remediation work at such sites; and
 
  •  pay damages for loss of use and non-use values.
      Environmental claims have been asserted against Gold Fields related to activities of Gold Fields or its former affiliates. Gold Fields is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, a predecessor owner of ours. We have been named a potentially responsible party (“PRP”) based on CERCLA at five sites, and claims have been asserted at 17 other sites. The number of PRP sites in and of itself is not a relevant measure of liability, because the nature and extent of environmental concerns varies by site, as does our estimated share of responsibility.
      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 the nature and extent of contamination, the timing, extent and method of the remedial action, 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. We also assess the financial capability and proportional share of costs of other PRPs and, where allegations are based on tentative findings, the reasonableness of our apportionment. We have not anticipated any recoveries from insurance carriers in the estimation of liabilities recorded in our consolidated balance sheets. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above totaled $42.5 million at December 31, 2005, and $40.5 million at December 31, 2004, $23.6 million and $15.1 million of which was a current liability, respectively. These amounts represent those costs that we believe are probable and reasonably estimable. In September 2005, Gold Fields and other PRPs received a letter from the U.S. Department of Justice alleging that the PRPs’ mining operations caused the EPA to incur approximately $125 million in residential yard remediation costs at Picher, Oklahoma and will cause the EPA to incur additional remediation costs relating to historic mining sites. Gold Fields has participated in the ongoing settlement discussions. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950s and mined, in accordance with lease agreements and permits, approximately 1.5% of the total amount of the ore mined in the county. Gold Fields believes it has meritorious defenses to these claims. Gold Fields is involved in other litigation in the Picher area, and we have agreed to indemnify one of the defendants in this litigation as discussed under the “Oklahoma Lead Litigation” caption above.

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      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.
Other
      In addition to the matters described above, we are party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. Management believes that the ultimate resolution of pending or threatened proceedings is not likely to have a material adverse effect on our financial condition, results of operations or cash flows.
      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 these matters 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, 2005.
Executive Officers of the Company
      Set forth below are the names, ages as of February 15, 2006 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
         
Gregory H. Boyce
    51     President and Chief Executive Officer, Director
Sharon D. Fiehler
    49     Executive Vice President — Human Resources and Administration
Richard A. Navarre
    45     Executive Vice President and Chief Financial Officer
Roger B. Walcott, Jr. 
    49     Executive Vice President — Resource Management and Strategic Planning
Richard M. Whiting
    51     Executive Vice President — Sales, Marketing and Trading
Ian S. Craig
    52     Managing Director — Australia Operations
Jiri Nemec
    49     Group Vice President — U.S. Eastern Operations
Kemal Williamson
    46     Group Vice President — U.S. Western Operations
      In March 2005, Gregory H. Boyce was elected our President and Chief Executive Officer (effective January 1, 2006), after joining us in October 2003 as President and Chief Operating Officer. 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, Board of Directors of The Center for Energy and Economic Development, National Mining Association, National Coal Council and is on the Board of Directors of the American Coal Foundation. He is a past board member of the Western Regional Council, Mountain States Employers

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Council and Wyoming Business Council. He also serves on the Board of Directors of the St. Louis 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 us 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 on the Executive Committee and Board of Directors of Junior Achievement of St. Louis.
      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 Planning. Prior to joining us, Mr. Navarre was a senior manager with KPMG Peat Marwick. Mr. Navarre is former 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. Mr. Navarre is on the Board of Directors of the Missouri Historical Society.
      Roger B. Walcott, Jr. became Executive Vice President — Resource Management and Strategic Planning in July 2005. Prior to that, he was our Executive Vice President — Corporate Development since February 2001. He joined us in June 1998 as Executive Vice President. From 1987 to 1998, he was a Senior Vice President and a director with The Boston Consulting Group, where he served a variety of clients in strategy and operational assignments. He joined Boston Consulting Group in 1981, and was Chairman of The Boston Consulting Group’s Human Resource Capabilities Committee. Mr. Walcott holds an MBA with high distinction from the Harvard Business School.
      Richard M. Whiting became Executive Vice President — Sales, Marketing and Trading in October 2002. Previously, Mr. Whiting served as our President and Chief Operating Officer and President of Peabody COALSALES Company. He joined our predecessor company in 1976 and has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Mr. Whiting is 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.
      Ian S. Craig was named our Managing Director — Australia Operations in September 2004. From May 2004 to August 2004, Mr. Craig served as Group Executive — Technical Services. He was Group Executive — Powder River Basin Operations from July 2001 to April 2004. Prior to that, he was Managing Director of a former Peabody subsidiary in Australia. Mr. Craig also held a number of management positions within the subsidiary company and other Australian mining organizations. He holds a Bachelor of Applied Science Degree in Mineral Engineering from the South Australian Institute of Technology. Mr. Craig is a Fellow of The Australasian Institute of Mining and Metallurgy.
      Jiri Nemec has been our Group Vice President — U.S. Eastern Operations since July 2005. Previously, Mr. Nemec was Group Executive of Appalachia and Highland Operations from April 2004 to July 2005; Appalachia Operations from January 2001 to April 2004; Midwest Operations from August 1999 to January 2001; and Northern Appalachia Operations from July 1998 to August 1999. He has extensive experience in mining engineering and operations, primarily with a Peabody subsidiary in West Virginia. He holds a Bachelor of Science Degree in Engineering from Pennsylvania State University and an MBA from Washington University.

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      Kemal Williamson became our Group Vice President — U.S. Western Operations in July 2005. After joining us in September 2000, Mr. Williamson served as Group Executive — Midwest Operations until April 2004, and then was Group Executive — Powder River Basin Operations until July 2005. He has extensive mining engineering and operations experience in the United States and Australia. Mr. Williamson holds a Bachelor of Science Degree in Mining Engineering from Pennsylvania State University and an MBA from Kellogg Graduate School of Management, Northwestern University.
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 15, 2006, there were approximately 490 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 the two-for-one stock split effective February 22, 2006) on the New York Stock Exchange during the calendar quarters indicated.
                   
    High   Low
         
2004
               
 
First Quarter
  $ 12.65     $ 9.11  
 
Second Quarter
    14.01       10.44  
 
Third Quarter
    15.11       12.69  
 
Fourth Quarter
    21.70       13.51  
2005
               
 
First Quarter
  $ 25.47     $ 18.38  
 
Second Quarter
    28.23       19.68  
 
Third Quarter
    43.03       26.01  
 
Fourth Quarter
    43.48       35.22  
Dividend Policy
      The quarterly dividend rate for Common Stock was increased by the Board of Directors to $0.0475 per share (from $0.0375 per share) effective August 4, 2005. We paid quarterly dividends totaling $0.17 per share during the year ended December 31, 2005, and $0.13 per share during the year ended December 31, 2004. The quarterly dividend was again increased (26%) on January 23, 2006, when a dividend of $0.06 per share was declared on Common Stock, payable on February 22, 2006, to stockholders of record on February 7, 2006. 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 February 22, 2006, we effected a two-for-one stock split on all shares of our common stock. Shareholders of record at the close of business on February 7, 2006, received a dividend of one share of stock for every share held. The stock began trading ex-split on February 23, 2006. On March 30, 2005, we effected 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 received a dividend of one share of stock for every share held. The stock

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began trading ex-split on March 31, 2005. All share and per share amounts in this Annual Report on Form 10-K reflect both two-for-one stock splits.
Item 6. Selected Financial Data.
      The following table presents selected financial and other data about us for the most recent five fiscal years. The following table and the discussion of our results of operations in 2005 and 2004 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.
      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 7 to our financial statements.
      In July 2001, we changed our fiscal year end from March 31 to December 31. The change was first effective with respect to the nine months ended December 31, 2001.
      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, 2005, 2004, 2003 and 2002 and the nine months ended and as of December 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 the two-for-one stock splits, effective February 22, 2006, and March 30, 2005. You should read the following table in conjunction with the financial statements, the related notes to those financial statements and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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      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 Risk Factors section of Item 1A 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   Year Ended   Ended
    December 31,   December 31,   December 31,   December 31,   December 31,
    2005   2004   2003   2002   2001
                     
    (Dollars in thousands, except share and per share data)
Results of Operations Data
                                       
Revenues
                                       
 
Sales
  $ 4,545,323     $ 3,545,027     $ 2,729,323     $ 2,630,371     $ 1,869,321  
 
Other revenues
    99,130       86,555       85,973       89,267       57,029  
                               
   
Total revenues
    4,644,453       3,631,582       2,815,296       2,719,638       1,926,350  
Costs and expenses
                                       
 
Operating costs and expenses
    3,715,836       2,965,541       2,332,137       2,225,344       1,588,596  
 
Depreciation, depletion and amortization
    316,114       270,159       234,336       232,413       171,020  
 
Asset retirement obligation expense
    35,901       42,387       31,156              
 
Selling and administrative expenses
    189,802       143,025       108,525       101,416       73,553  
 
Other operating income:
                                       
   
Net gain on disposal of assets
    (101,487 )     (23,829 )     (32,772 )     (15,763 )     (22,160 )
   
(Income) loss from equity affiliates
    (30,096 )     (12,399 )     (2,872 )     2,540       (190 )
                               
Operating profit
    518,383       246,698       144,786       173,688       115,531  
 
Interest expense
    102,939       96,793       98,540       102,458       88,686  
 
Early debt extinguishment costs
          1,751       53,513             38,628  
 
Interest income
    (10,641 )     (4,917 )     (4,086 )     (7,574 )     (2,155 )
                               
Income (loss) before income taxes and minority interests
    426,085       153,071       (3,181 )     78,804       (9,628 )
 
Income tax provision (benefit)
    960       (26,437 )     (47,708 )     (40,007 )     (7,193 )
 
Minority interests
    2,472       1,282       3,035       13,292       7,248  
                               
Income (loss) from continuing operations
    422,653       178,226       41,492       105,519       (9,683 )
 
Loss from discontinued operations
          (2,839 )                  
                               
Income (loss) before accounting changes
    422,653       175,387       41,492       105,519       (9,683 )
 
Cumulative effect of accounting changes
                (10,144 )            
                               
Net income (loss)
  $ 422,653     $ 175,387     $ 31,348     $ 105,519     $ (9,683 )
                               
Basic earnings (loss) per share from continuing operations
  $ 1.62     $ 0.72     $ 0.19     $ 0.51     $ (0.05 )
Diluted earnings (loss) per share from continuing operations
  $ 1.58     $ 0.70     $ 0.19     $ 0.49     $ (0.05 )
Weighted average shares used in calculating basic earnings (loss) per share
    261,519,424       248,732,744       213,638,084       208,662,940       194,985,776  
Weighted average shares used in calculating diluted earnings (loss) per share
    268,013,476       254,812,632       219,342,512       215,287,040       194,985,776  
Dividends declared per share
  $ 0.17     $ 0.13     $ 0.11     $ 0.10     $ 0.05  
Other Data
                                       
Tons sold (in millions)
    239.9       227.2       203.2       197.9       146.5  
Net cash provided by (used in):
                                       
 
Operating activities
  $ 702,759     $ 283,760     $ 188,861     $ 234,804     $ 99,492  
 
Investing activities
    (584,202 )     (705,030 )     (192,280 )     (144,078 )     (172,989 )
 
Financing activities
    (4,915 )     693,404       48,598       (58,398 )     49,396  
Adjusted EBITDA(1)
    870,398       559,244       410,278       406,101       286,551  
Additions to property, plant, equipment and mine development
    384,304       151,944       156,443       208,562       194,246  
Federal coal lease expenditures
    118,364       114,653                    
Purchase of mining and related assets
    141,195                          
Balance Sheet Data (at period end)
                                       
 
Total assets
  $ 6,852,006     $ 6,178,592     $ 5,280,265     $ 5,125,949     $ 5,150,902  
 
Total debt
    1,405,506       1,424,965       1,196,539       1,029,211       1,031,067  
 
Total stockholders’ equity
    2,178,467       1,724,592       1,132,057       1,081,138       1,035,472  
 
(1)  Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation 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

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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   Year Ended   Ended
    December 31,   December 31,   December 31,   December 31,   December 31,
    2005   2004   2003   2002   2001
                     
Income (loss) from continuing operations
  $ 422,653     $ 178,226     $ 41,492     $ 105,519     $ (9,683 )
Income tax provision (benefit)
    960       (26,437 )     (47,708 )     (40,007 )     (7,193 )
Depreciation, depletion and amortization
    316,114       270,159       234,336       232,413       171,020  
Asset retirement obligation expense
    35,901       42,387       31,156              
Interest expense
    102,939       96,793       98,540       102,458       88,686  
Early debt extinguishment costs
          1,751       53,513             38,628  
Interest income
    (10,641 )     (4,917 )     (4,086 )     (7,574 )     (2,155 )
Minority interests
    2,472       1,282       3,035       13,292       7,248  
                               
Adjusted EBITDA
  $ 870,398     $ 559,244     $ 410,278     $ 406,101     $ 286,551  
                               
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 34 active coal operations located throughout all major U.S. coal producing regions and internationally in Australia. In 2005, we sold 239.9 million tons of coal that accounted for an estimated 21.5% of all U.S. coal sales, and were more than 69% greater than the sales of our closest domestic competitor and 49% more than our closest international competitor. Based on Energy Information Administration (“EIA”) estimates, demand for coal in the United States was more than 1.1 billion tons in 2005. Domestic consumption of coal is expected to grow at a rate of 1.7% per year through 2030 when U.S. coal demand is forecasted to be 1.8 billion tons. The EIA expects demand for coal use at coal-to-liquids (“CTL”) plants to grow to 190 million tons by 2030. Coal-fueled generation is used in most cases to meet baseload electricity requirements, and coal use generally grows at the approximate rate of electricity growth, which is expected to average 1.6% annually through 2025. Coal production from west of the Mississippi River is projected to provide most of the incremental growth as Western production increases to a 63% share of total production in 2030. In 2004, coal’s share of electricity generation was approximately 51%, a share that the EIA projects will grow to 57% by 2030.
      Our primary customers are U.S. utilities, which accounted for 87% of our sales in 2005. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2005, approximately 90% of our sales were under long-term contracts. As of December 31, 2005, our unpriced volumes for 2006 were 15 to 25 million tons on expected production of 230 to 240 million tons and total sales of 255 to 265 million tons. As discussed more fully in Item 1A. Risks Factors, our results of operations in the near term could 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

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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 North Goonyella underground mine and our Wilkie Creek, Burton and Eaglefield surface mines. Eaglefield is a surface operation adjacent to, and fulfilling contract tonnages in conjunction with, the North Goonyella underground mine. In the first quarter of 2006, we will begin production at the 0.6 million ton per year Baralaba Mine, of which we own a 62.5% interest. The Baralaba Mine will produce PCI, a substitute for metallurgical coal, and steam coal. 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 5% of our total sales volume and approximately 2% of U.S. sales volume.
      We own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine produces approximately 6 to 8 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.
      In addition to our mining operations, which comprised 85% of revenues in 2005, we also generate revenues from brokering and trading coal (15% 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 as well as other ventures described below.
      We continue to pursue the development of coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. The projects involve mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to equity partner, contract miner or coal lessor. The projects we are currently pursuing are as follows: the 1,500-megawatt Prairie State Energy Campus in Washington County, Illinois; the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky; and the 300-megawatt Mustang Energy Project near Grants, New Mexico. The plants, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, could be operational following a four-year construction phase. The first of these plants would not be operational earlier than mid-2010.
      In February 2005, a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire 47% of the Prairie State Energy Campus project. After an initial appeal, the Illinois Environmental Protection Agency reissued the air permit on April 28, 2005. The same parties who filed the earlier permit challenge filed a new appeal on June 8, 2005. We believe the permit was appropriately issued and expect to prevail in the appeal process. Various other required permits

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are in process and may also be subject to challenge. If successfully completed, the Prairie State Energy Campus project would utilize approximately six million tons of coal each year.
      During 2005, we engaged in several BTU conversion projects which are designed to expand the uses of coal through various technologies. We are a founding member of the FutureGen Industrial Alliance, a non-profit company that is partnering with the U.S. Department of Energy to facilitate the design, construction and operation of the world’s first near-zero emission coal-fueled power plant. FutureGen will demonstrate advanced coal-based technologies to generate electricity and also produce hydrogen to power fuel cells for transportation and other energy needs. The technology also will integrate the capture of carbon emissions with carbon sequestration, helping to address the issue of climate change as energy demand continues to grow worldwide. We also entered into an agreement to acquire a 30% interest in Econo-Power International Corporation (“EPICtm”), which owns and markets modular coal gasifiers for industrial applications. The EPIC Clean Coal Gasification Systemtm uses air-blown gasifiers to convert coal into a synthetic gas that is ideal for industrial applications. In late 2005, we entered into a memorandum of understanding with ArcLight Capital Partners, LLC to advance project development of a commercial-scale coal gasification project in Illinois that would transform coal into pipeline-quality synthetic natural gas. The initial project would be designed with ConocoPhillips’ “E-Gastm” Technology. When completed, the plant would be one of the largest coal-to-natural-gas plants in the United States and would require at least three million tons of Illinois Basin coal per year to fuel two gasifier trains that could produce more than 35 billion cubic feet of synthetic natural gas.
      Effective January 1, 2006, Gregory H. Boyce became our President and Chief Executive Officer after we completed an orderly succession planning process. Irl F. Engelhardt, our former Chief Executive Officer, remains employed as Chairman of the Board. Effective March 1, 2005, Mr. Boyce was also elected to the Board of Directors and Chairman of the Executive Committee of the Board.
      Effective March 30, 2005, we implemented a two-for-one stock split on all shares of our common stock. Subsequently, on February 22, 2006, we implemented another two-for-one stock split on all shares of our then outstanding common stock. All share and per share amounts in this annual report on Form 10-K reflect both stock splits. During July 2005, we increased our quarterly dividend 27% to $0.0475 per share and our Board of Directors authorized a share repurchase program of up to 5% of the outstanding shares of our common stock. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. On January 23, 2006, our Board of Directors authorized a 26% increase in our dividend, to $0.06 per share, to shareholders of record on February 7, 2006.
      In July 2005, the Board of Directors elected John F. Turner as an independent director who serves on the Board’s Nominating and Corporate Governance Committee. Turner is former U.S. Assistant Secretary of State for Oceans and International Environmental and Scientific Affairs (“OES”) within the State Department and is the past President and Chief Executive Officer of the Conservation Fund, a national nonprofit organization dedicated to public-private partnerships to protect land and water resources. He has also served as the Director of the U.S. Fish and Wildlife Service, with responsibility for increasing wetland protection and establishing 55 National Wildlife Refuges, the most of any administration in the nation’s history.
Results of Operations
Adjusted EBITDA
      The discussion of our results of operations in 2005 and 2004 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

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measure, under generally accepted accounting principles, in Note 27 to our consolidated financial statements included in this report.
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Summary
      Our 2005 revenues of $4.64 billion increased 27.9% over the prior year. Revenues were driven higher by improved pricing in all of our mining operations and another year of industry-record sales volume with 239.9 million tons sold compared to 227.2 million tons in 2004.
      For the year, Segment Adjusted EBITDA of $1.08 billion was a 39.5% increase over the prior year. Segment Adjusted EBITDA was higher in the current year due to increases in sales volumes and prices at our U.S. and Australian Mining Operations. Results in our Western U.S. Mining Operations segment include amounts for our April 15, 2004, acquisition of the Twentymile Mine in Colorado. Results in our Australian Mining Operations segment include amounts for our April 15, 2004, acquisition of the Burton and North Goonyella Mines as well as the opening of the Eaglefield Mine adjacent to the North Goonyella Mine in the fourth quarter of 2004. Our Corporate and Other segment includes results from our December 2004 acquisition of a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. In addition, higher gains on property transactions contributed to higher year over year results.
      Net income was $422.7 million in 2005, or $1.58 per share, an increase of 141.0% over 2004 net income of $175.4 million, or $0.69 per share. The increase in net income was primarily due to improved Segment Adjusted EBITDA discussed above.
Tons Sold
      The following table presents tons sold by operating segment for the years ended December 31, 2005 and 2004:
                                   
    Year Ended   Increase
    December 31,   (Decrease)
         
    2005   2004   Tons   %
                 
    (Tons in millions)
Western U.S. Mining Operations
    154.3       142.2       12.1       8.5 %
Eastern U.S. Mining Operations
    52.5       51.7       0.8       1.5 %
Australian Mining Operations
    8.3       6.1       2.2       36.1 %
Trading and Brokerage Operations
    24.8       27.2       (2.4 )     (8.8 )%
                         
 
Total
    239.9       227.2       12.7       5.6 %
                         
Revenues
      The table below presents revenues for the years ended December 31, 2005 and 2004:
                                   
            Increase
    Year Ended   Year Ended   to Revenues
    December 31,   December 31,    
    2005   2004   $   %
                 
    (Dollars in thousands)
Sales
  $ 4,545,323     $ 3,545,027     $ 1,000,296       28.2 %
Other revenues
    99,130       86,555       12,575       14.5 %
                         
 
Total revenues
  $ 4,644,453     $ 3,631,582     $ 1,012,871       27.9 %
                         
      Our revenues increased by $1.01 billion, or 27.9%, to $4.64 billion compared to prior year. The three mines we acquired in the second quarter of 2004 contributed $365.2 million of revenue growth due to the additional 105 days of operations in 2005 compared to the prior year. The remaining $647.7 million

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of revenue growth was driven by higher sales prices and volumes across all mining segments and improved volumes in our brokerage operations.
      Sales increased 28.2% to $4.55 billion in 2005, reflecting increases in every operating segment. Western U.S. Mining sales increased $222.2 million, Eastern U.S. Mining sales were $224.0 million higher, sales in Australia Mining improved $328.0 million and sales from our brokerage operations increased $226.0 million. Sales in every segment increased on improved pricing, and volumes were higher in every segment other than Trading and Brokerage. Our average sales price per ton increased 17.4% during 2005 due to increased demand for all of our coal products, which drove pricing higher, particularly in the regions where we produce metallurgical coal. Prices for metallurgical coal and our ultra-low sulfur Powder River Basin coal have been the subject of increasing demand. We sell metallurgical coal from our Eastern U.S. and Australian Mining operations. We sell ultra-low sulfur Powder River Basin coal from our Western U.S. Mining operations. The sales mix also improved due to an increase in sales from our Australian Mining segment, where per ton prices are higher than in domestic markets due primarily to a higher proportion of metallurgical coal production in the Australian segment sales mix.
      The increase in Eastern U.S. Mining operations sales was primarily due to improved pricing for both steam and metallurgical coal from the region. Sales in Appalachia increased $118.6 million, or 17.1% and sales in the Midwest increased $105.4 million, or 13.6%. On average, prices in our Eastern U.S. Mining operations increased 14.1% to $33.10 per ton. Production increases in the Midwest were partially offset by lower production in Appalachia compared to the prior year. Most of the decrease in production in Appalachia occurred during the fourth quarter as our largest metallurgical coal mine worked to develop a new section and relocate its longwall. Sales increased in our Western U.S. Mining operations due to higher demand-driven volumes and prices. Overall, prices in our Western U.S. Mining operations increased 6.6% to $10.45 per ton. In the West, sales increased the most in the Powder River Basin, which improved $149.8 million due to increased sales prices and volumes. Powder River Basin production and sales volumes were up as a result of increasingly strong demand for the mines’ low-sulfur product, which continues to expand its market area geographically. Powder River Basin operations were able to ship record volumes during 2005 by overcoming train derailments and weather and track maintenance disruptions on the main shipping line out of the basin. Our Twentymile Mine, acquired in April of 2004, helped our Colorado operations contribute an additional $67.3 million to sales compared to prior year due to an additional four months of ownership, higher prices and increased mine productivity. Sales from our Southwestern operations, where the Black Mesa Mine closed at the end of 2005, were comparable to prior year. Sales from our Australian Mining operations were $328.0 million, or 122.1%, higher than in 2004. The increase in Australian sales was due primarily to a 63.3% increase in per ton sales prices largely due to higher international metallurgical coal prices, an increase in volumes which included the opening of our Eaglefield surface mine at the end of 2004, and $197.6 million of incremental sales from the two mines we acquired in April 2004 due to 105 additional days of operations in 2005 compared to 2004. Our Trading and Brokerage operations sales increased $226.0 million in 2005 compared to prior year due to an increase in average per ton prices and higher eastern U.S. and international brokerage volumes.
      Other revenues increased $12.6 million, or 14.5%, compared to prior year primarily due to proceeds from a purchase contract restructuring and higher synthetic fuel revenues in the Midwest.

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Segment Adjusted EBITDA
      Our total segment Adjusted EBITDA of $1.08 billion for 2005 was $305.5 million higher than 2004 segment Adjusted EBITDA of $773.8 million, and was composed of the following:
                                   
            Increase to Segment
    Year Ended   Year Ended   Adjusted EBITDA
    December 31,   December 31,    
    2005   2004   $   %
                 
    (Dollars in thousands)
Western U.S. Mining
  $ 459,039     $ 402,052     $ 56,987       14.2 %
Eastern U.S. Mining
    374,628       280,357       94,271       33.6 %
Australian Mining
    202,582       50,372       152,210       302.2 %
Trading and Brokerage
    43,058       41,039       2,019       4.9 %
                         
 
Total Segment Adjusted EBITDA
  $ 1,079,307     $ 773,820     $ 305,487       39.5 %
                         
      Adjusted EBITDA from our Western U.S. Mining operations increased $57.0 million during 2005 due to a margin per ton increase of $0.15, or 5.3%, and a sales volume increase of 12.1 million tons. The Twentymile Mine, acquired in April of 2004, contributed $25.4 million more to Adjusted EBITDA in 2005 than in 2004, due to four months of incremental ownership and a 22.2% increase in per ton margin. The remaining increase in Adjusted EBITDA was driven by our Powder River Basin operations, which improved by $53.5 million and earned 12.3% higher per ton margins while increasing volumes 8.5% in response to greater demand for our low-sulfur products. Improved revenues overcame increased unit costs that resulted from higher fuel costs, lower than anticipated volume due to rail difficulties and an increase in revenue-based royalties and production taxes. Improvements in the Powder River Basin and Colorado overcame a decrease in Adjusted EBITDA of $13.5 million for our Southwest operations primarily due to lower volume and higher fuel costs. Pricing improvements in the Powder River Basin generally offset higher costs for fuel and explosives.
      Eastern U.S. Mining operations’ Adjusted EBITDA increased $94.3 million, or 33.6%, compared to prior year primarily due to an increase in margin per ton of $1.71, or 31.5%. Our Appalachia operations’ Adjusted EBITDA increased $44.2 million, or 29.8%, as a result of sales price increases, partially offset by lower production at two of our mines and higher costs related to geologic issues, contract mining and roof support. Results in our Midwest operations were improved $50.1 million, or 37.9%, compared to prior year as benefits of higher volumes and prices were partially offset by higher costs due to higher fuel, repair and maintenance costs and the impact of heavy rainfall on surface operations early in the year.
      Our Australian Mining operations’ Adjusted EBITDA increased $152.2 million in the current year, a 302.2% increase compared to prior year due to an increase of $16.23, or 197.4%, in margin per ton and 2.2 million additional tons shipped. Our Australian operations produce mostly (75% to 85%) high margin metallurgical coal. The two mines we acquired in April 2004 added $87.4 million to Adjusted EBITDA compared to eight months of ownership in 2004. The remaining increase of $64.8 million was primarily due to an increase in volume, including tonnage from our surface operation opened at the end of the prior year, and an increase of 63.3% in average per ton sale price. While current year margins benefited from strong sales prices, margin growth was limited by the impact of port congestion, related demurrage costs and higher costs due to geological problems at the underground mine.
      Trading and Brokerage operations’ Adjusted EBITDA increased $2.0 million from the prior year primarily due to higher brokerage results. Results in 2005 included a net charge of $4.0 million, primarily related to the breach of a coal supply contract by a producer (see Note 3).

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Reconciliation of Segment Adjusted EBITDA to Income Before Income Taxes and Minority Interests
                                 
            Increase (Decrease)
    Year Ended   Year Ended   to Income
    December 31,   December 31,    
    2005   2004   $   %
                 
    (Dollars in thousands)
Total Segment Adjusted EBITDA
  $ 1,079,307     $ 773,820     $ 305,487       39.5 %
Corporate and Other Adjusted EBITDA
    (208,909 )     (214,576 )     5,667       2.6 %
Depreciation, depletion and amortization
    (316,114 )     (270,159 )     (45,955 )     (17.0 )%
Asset retirement obligation expense
    (35,901 )     (42,387 )     6,486       15.3 %
Early debt extinguishment costs
          (1,751 )     1,751       n/a  
Interest expense
    (102,939 )     (96,793 )     (6,146 )     (6.3 )%
Interest income
    10,641       4,917       5,724       116.4 %
                         
Income before income taxes and minority interests
  $ 426,085     $ 153,071     $ 273,014       178.4 %
                         
      Income before income taxes and minority interest of $426.1 million for the current year is $273.0 million, or 178.4%, higher than prior year primarily due to improved segment Adjusted EBITDA as discussed above. Increases in depreciation, depletion and amortization expense and interest expense offset improvements in Corporate and Other Adjusted EBITDA, asset retirement obligation expense, debt extinguishment costs and interest income.
      Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our Venezuelan joint venture, net gains on asset disposals or exchanges, 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. The $5.7 million improvement in Corporate and Other Adjusted EBITDA (net expense) in 2005 compared to 2004 included:
  •  net gains on asset sales that were $77.7 million higher than prior year primarily due to a $37.4 million gain from a property exchange related to settlement of a contract dispute with a third-party coal supplier (see Note 3), sales of Penn Virginia Resource Partners, L.P. (“PVR”) units ($31.1 million) (see Note 11), resource sales involving non-strategic coal assets and properties ($12.5 million), and an asset exchange in which we acquired Illinois Basin coal reserves ($6.2 million). The gain from PVR unit sales in 2005 was from the sale of all of our remaining 0.838 million units compared to a gain of $15.8 million on the sale of 0.775 million units in two separate transactions during 2004. All other gains on asset disposals in 2005 and 2004 were $14.3 million and $8.0 million, respectively;
 
  •  higher equity income of $18.7 million from our 25.5% interest in Carbones del Guassare (acquired in December 2004), which owns and operates the Paso Diablo Mine in Venezuela, and;
 
  •  lower net expenses related to generation development of $5.1 million, primarily due to reimbursements from the Prairie State Energy Campus partnership group.
      These improvements were partially offset by:
  •  a $36.0 million increase in past mining obligations expense, primarily related to higher retiree health care costs. The increase in retiree health care costs was actuarially driven by higher trend rates, and lower interest discount assumptions and higher amortization of actuarial losses in 2005, and;
 
  •  an increase of $46.8 million in selling and administrative expenses primarily related to accruals for higher short-term and long-term performance-based incentive plans ($32.2 million). These incentives are principally long-term plans that are driven by total shareholder returns. Our share price increased 104% during 2005, significantly outperforming industrial benchmarks and our coal

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  peer group average. The remaining increase in selling and administrative expenses was due to higher personnel and outside services costs needed to advance our growth initiatives in areas such as China and BTU conversion, acquisitions and regulatory costs (e.g. Sarbanes-Oxley), and an increase in advertising costs related to an industry awareness campaign launched in late 2005.
      Depreciation, depletion and amortization increased $46.0 million during 2005. Approximately 56% of the increase was due to acquisitions completed during 2004 and the remainder was from increased volumes at existing mines and operations opened during 2005. Asset retirement obligation expense decreased $6.5 million in 2005 due to additional expenses incurred in 2004 to accelerate the planned reclamation of certain closed mine sites. Interest expense increased $6.1 million primarily related to a full year of interest in 2005 on $250 million of 5.875% Senior Notes issued in late March of 2004 and increases in the cost of floating rate debt due to higher interest rates. Interest income improved $5.7 million due to higher yields on short-term interest rates and an increase in invested balances due to improved cash flows during 2005.
Net Income
                                   
            Increase (Decrease) to
    Year Ended   Year Ended   Income
    December 31,   December 31,    
    2005   2004   $   %
                 
    (Dollars in thousands)
Income before income taxes and minority interests
  $ 426,085     $ 153,071     $ 273,014       178.4 %
 
Income tax benefit (provision)
    (960 )     26,437       (27,397 )     (103.6 )%
 
Minority interests
    (2,472 )     (1,282 )     (1,190 )     (92.8 )%
                         
Income from continuing operations
    422,653       178,226       244,427       137.1 %
 
Loss from discontinued operations
          (2,839 )     2,839       n/a  
                         
Net income
  $ 422,653     $ 175,387     $ 247,266       141.0 %
                         
      Net income increased $247.3 million, or 141.0%, compared to the prior year due to the increase in income before income taxes and minority interests discussed above, partially offset by increases in our income tax provision. The income tax benefit in 2004 included a $25.9 million reduction in the valuation allowance on net operating loss carry-forwards (“NOLs”) and alternative minimum tax credits. The income tax provision in 2005 was higher based on the increase in pretax income which was partially offset by the higher permanent benefit of percentage depletion and the partial benefit of tax loss from a deemed liquidation of a subsidiary arising as an indirect consequence of a comprehensive and strategic internal restructuring we completed during 2005. This restructuring resulted from efforts to better align corporate ownership of subsidiaries on a geographic and functional basis.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Summary
      In 2004, our revenues increased to $3.63 billion, 29.0% higher than 2003, 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 2004 results.
      Segment Adjusted EBITDA for 2004 totaled $773.8 million, a 28.1% increase over $603.9 million in the prior year. Segment Adjusted EBITDA was higher in 2004 due to increased sales volumes and prices.
      Net income in 2004 was $175.4 million, or $0.69 per share, an increase of 459.5% over 2003 net income of $31.3 million, or $0.14 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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Tons Sold
      The following table presents tons sold by operating segment for the years ended December 31, 2004 and 2003:
                                   
    Year Ended    
    December 31,   Increase
         
    2004   2003   Tons   %
                 
    (Tons in millions)
Western U.S. Mining Operations
    142.2       129.6       12.6       9.7 %
Eastern U.S. Mining Operations
    51.7       46.3       5.4       11.7 %
Australian Mining Operations
    6.1       1.3       4.8       369.2 %
Trading and Brokerage Operations
    27.2       26.0       1.2       4.6 %
                         
 
Total
    227.2       203.2       24.0       11.8 %
                         
Revenues
      The table below presents revenues for the years ended December 31, 2004 and 2003:
                                   
            Increase to
    Year Ended   Year Ended   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 2003. 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 acquisitions during 2004, 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. Pricing of metallurgical coal responded 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 2003.
      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 from contract sources as a result of geologic difficulties and from congestion-related shipping delays and hurricane-related production disruptions and delays to rail and export shipments. 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 2004, 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

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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.
Segment Adjusted EBITDA
      Our total segment Adjusted EBITDA of $773.8 million for 2004 was $169.9 million higher than 2003 segment Adjusted EBITDA of $603.9 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
  $ 402,052     $ 356,898     $ 45,154       12.7 %
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
  $ 773,820     $ 603,915     $ 169,905       28.1 %
                         
      Western U.S. Mining operations Adjusted EBITDA increased $45.2 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 2003 levels. 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 2003 due to an increase in margin per ton of $1.11, or 25.8%, and an increase in volume by 5.4 million, 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, more than offsetting higher costs due to equipment and geologic difficulties at a mine in Kentucky and a $9.6 million increase in earnings from our equity interest in a joint venture. Adjusted EBITDA in the Midwest was $20.1 million less than 2003 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 2004. 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 acquisitions in 2004 contributed $43.1 million of Adjusted EBITDA to results for the year.
      Trading and Brokerage Adjusted EBITDA decreased $4.8 million from 2003 primarily due to higher brokerage results in 2003. Adjusted EBITDA from trading activities increased over 2003 due to improved pricing on our long position, and pure brokerage results improved on higher pricing and volumes, particularly in international brokerage.

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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
  $ 773,820     $ 603,915     $ 169,905       28.1 %
Corporate and Other Adjusted EBITDA
    (214,576 )     (193,637 )     (20,939 )     (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 $773.8 million for 2004 is compared with $603.9 million from 2003 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 2003, which included 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 PVR, while 2004 included 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 PVR 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 acquisitions during 2004; and
 
  •  a $2.9 million increase in our accrual for future environmental obligations.
      These increased costs compared to 2003 were partially offset by the gain on sale of PVR units discussed above and:
  •  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 2004 due to increased or accelerated reclamation work at certain closed mine sites and the acquisition of additional mining operations.

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      Debt extinguishment costs were $51.8 million higher in 2003 due to the significant prepayment premiums associated with the March 2003 refinancing, discussed in Note 14 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 NOLs and alternative minimum tax credits. We evaluated and assessed the expected near-term utilization of NOLs, 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 2004 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 Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“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 recession of Emerging Issues Task Force (“EITF”) No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as discussed in Note 7 to the consolidated financial statements.
Outlook
Events Impacting Near-Term Operations
      Despite setting new industry records, shipments from our Powder River mines were lower than expected during 2005 due to a remedial maintenance program undertaken by the two railroad companies serving the Powder River Basin. The maintenance and repairs are expected to continue into 2006. We

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expect these repairs may restrict shipments from our Powder River operations during 2006, but continue to anticipate higher shipment levels than 2005.
      Metallurgical coal production from our Appalachia operations is expected to be lower than prior year periods through the first quarter of 2006 as a metallurgical coal mine in our Appalachia segment continues development work and moves to new reserves. The longwall at the existing mine has depleted the final panel of available reserves in its current location and is relocating to a reserve extension in the first half of 2006. Following the longwall move, production of domestic metallurgical coal is expected to improve and finish the year with production equal to, or greater than, that of 2005.
      Our North Goonyella Mine in Australia has experienced difficult geologic conditions in 2005 and experienced a roof fall that interrupted production for portions of the third and fourth quarters. In the first quarter of 2006, we plan to install new longwall equipment to maximize operating performance under these adverse geologic conditions. We plan to meet our shipping commitments from this mine by supplementing its output with production from our newly-opened, adjacent surface operation. In May 2005, we were notified of a reduced port allocation that is aimed at improving the loading of vessels and reducing demurrage at the main port for our Australian coal operations. Although port congestion has been reduced, high demurrage costs and unpredictable timing of vessel loading could continue to impact future results.
Outlook Overview
      Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as growth continues in the U.S., Asia and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. The U.S. economy grew at an annual rate of 4.1% in the third quarter of 2005 as reported by the U.S. Commerce Department, and China’s economy grew 9.4% as published by the National Bureau of Statistics of China. Strong demand for coal and coal-based electricity generation in the U.S. is being driven by the growing economy, low customer stockpiles, favorable weather, capacity constraints of nuclear generation and high prices of natural gas and oil. The high price of natural gas is leading some coal-fueled generating plants to operate at increased levels. The Energy Information Administration (“EIA”) projects that the high price of oil will lead to an increase in demand for unconventional sources of transportation fuel, including coal-to-liquids (“CTL”), and that coal will begin to displace natural gas-fired generation of electricity, including the addition of CTL plants. At year end, U.S. electricity generator coal inventories were at the lowest level in the past five years.
      Demand for Powder River Basin coal is increasing, particularly for our ultra-low sulfur products. The Powder River Basin represents more than half of our production, and the published reference price for high-Btu, ultra-low sulfur Powder River Basin coal has increased substantially, tripling during 2005. We control approximately 3.5 billion tons of proven and probable reserves in the Southern Powder River Basin and sold 125.7 million tons of coal from this region during the year ended December 31, 2005. Customers have indicated that demand for Powder River Basin coal could increase by 15% or more during 2006, although the railroads expect that they will be able to accommodate only about half of the expected increase in demand. Metallurgical coal continues to sell at a significant premium to steam coal and metallurgical markets remain strong as global steel production grew 6% to 7% in 2005. We expect to capitalize on the strong global market for metallurgical coal primarily through production and sales of metallurgical coal from our Appalachia operations and our Australian operations.
      We are targeting 2006 production of 230 million to 240 million tons and total sales volume of 255 million to 265 million tons, including 12 to 14 million tons of metallurgical coal. As of December 31, 2005, our unpriced volumes for produced tonnage for 2006 were 15 to 25 million tons.
      Management expects strong market conditions and operating performance to overcome external cost pressures, geologic conditions and potentially adverse port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel, tires, contract mining and healthcare, and have taken measures to mitigate the increases in these costs. In addition, historically low long-term interest

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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 or transportation difficulties, our operating margins would be negatively impacted. See “Cautionary Notice Regarding Forward-Looking Statements” for additional considerations regarding our outlook.
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 Notes 16, 17 and 18 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, 2005, for these liabilities totaled $193.8 million, while payments were $147.1 million.
      Each of these liabilities are actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. Our discount rate is determined by utilizing a hypothetical bond portfolio model which approximates the future cash flows necessary to service our liabilities.
      We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injuries and illnesses obligations. Our medical trend assumption is developed by annually examining the historical trend of our cost per claim data. 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.
      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)
  $ 8,789     $ (6,961 )
Effect on total postretirement benefit obligation(1)
  $ 161,903     $ (135,501 )

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      Discount rate (dollars in thousands):
                 
    One Half-   One Half-
    Percentage-Point   Percentage-Point
    Increase   Decrease
         
Effect on total service and interest cost components(1)
  $ 1,183     $ (1,563 )
Effect on total postretirement benefit obligation(1)
  $ (68,900 )   $ 75,878  
 
(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 8.99 years at December 31, 2005.
Asset Retirement Obligations
      Our asset retirement obligations primarily consist of spending estimates for 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. Asset retirement obligations are determined for each mine using 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 obligation and asset are revised to reflect the new estimate after applying 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, 2005, was $35.9 million, and payments totaled $33.6 million. See detailed information regarding our asset retirement obligations in Note 15 to our consolidated financial statements.
Income Taxes
      We account for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS No. 109”), 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 taxable income and available tax planning strategies. 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. Additional details regarding the effect of income taxes on our consolidated financial statements is available in Note 13.

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Revenue Recognition
      In general, we recognize revenues when they are realizable and earned. We generated 98% of our revenue in 2005 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 vessels, 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.
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, “Accounting for Derivative Instruments and Hedging Activities.” 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, 2005 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, 2005, 76% of the estimated future value of our trading portfolio was scheduled to be realized by the end of 2006. See Note 4 to our consolidated financial statement for additional details regarding assets and liabilities from our coal trading activities.
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 financing transactions, including the sale of our accounts receivable through our securitization program. Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs and costs related to past mining obligations as well as planned acquisitions. 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. Future dividends, among other things, are subject to limitations imposed by our 6.875% Senior Notes, 5.875% Senior Notes and Senior Secured Credit Facility covenants. We typically fund all of our capital expenditure requirements with cash generated from operations, and during 2005 and 2004 we had no borrowings outstanding under our $900.0 million revolving line of credit, which we use primarily for standby letters of credit.
      Net cash provided by operating activities was $702.8 million in 2005, an increase of $419.0 million, or 147.6%, from 2004. The increase was primarily driven by stronger operational performance in 2005, as net income increased $247.3 million from the prior year. Also contributing to the increase was lower funding of pension plans in 2005, as we voluntarily pre-funded $50.0 million in the prior year. The remainder of the increase was primarily due to higher working capital cash flows of $85.5 million.
      Net cash used in investing activities was $584.2 million during 2005 compared to $705.0 million used in 2004. Total capital expenditures were $643.9 million in 2005, an increase of $377.3 million over prior year. In 2005, we purchased mining and related assets of $141.2 million, which included $56.5 million for

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the acquisition of coal reserves in Illinois and Indiana along with surface property and equipment and $84.7 million for the acquisition of mining and transportation infrastructure in the Powder River Basin. Our $118.4 million in federal coal lease expenditures in 2005 were similar to the 2004 expenditures. Other capital expenditures of $384.3 million were $232.4 million higher than the prior year. The 2005 other capital expenditures included the longwall equipment and mine development at our Australian mines, longwall replacement at our Twentymile mine, the opening of new mines and upgrading of existing mines in the Midwest and Appalachia, and expansion equipment. In 2005, we were able to make several acquisitions of strategic coal reserves and mining assets due to the strong operating results that we experienced in 2005. Proceeds from the disposal of assets increased $36.9 million primarily due to higher proceeds in 2005 from the sale of PVR units and non-strategic property, reserves and equipment. In 2004, we acquired the Twentymile mine in Colorado and two mines in Australia for $421.3 million and made a $5.0 million earn-out payment related to our April 2003 acquisition of the remaining minority interest in Black Beauty Coal Company. 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.
      Net cash used in financing activities was $4.9 million in 2005 compared to cash provided by financing activities of $693.4 million in the prior year, with the decrease primarily related to the 2004 issuance of 35.3 million shares of common stock at $11.25 per share, netting proceeds of $383.1 million; issuance of $250 million of 5.875% Senior Notes due in 2016; and the payment of debt issuance costs of $12.9 million in connection with the acquisition of the three mines discussed above. During 2004, we also completed a repricing of our Senior Secured Credit Facility, consisting of an amended $450.0 million Term Loan and the $900 million Revolving Credit Facility. During 2005 and 2004, we made scheduled payments on our long-term debt of $20.2 and $36.3 million, respectively. Securitized interest in accounts receivable increased by $25.0 million in 2005 compared to an increase of $110.0 million in 2004. We paid dividends of $44.5 million and $32.6 million in 2005 and 2004, respectively. In 2005, we issued $11.5 million in notes payable as part of an asset exchange in which we acquired additional Illinois Basin coal reserves.
      A detailed discussion of our debt instruments is included in Note 14 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, 2005 and 2004, our total indebtedness consisted of the following (dollars in thousands):
                   
    December 31,
     
    2005   2004
         
Term Loan under Senior Secured Credit Facility
  $ 442,500     $ 448,750  
6.875% Senior Notes due 2013
    650,000       650,000  
5.875% Senior Notes due 2016
    239,525       239,525  
Fair value of interest rate swaps — 6.875% Senior Notes
    (8,879 )     5,189  
5.0% Subordinated Note
    66,693       73,621  
Other
    15,667       7,880  
             
 
Total
  $ 1,405,506     $ 1,424,965  
             
      On May 9, 2005, we filed a shelf registration statement on Form S-3 with the SEC, which was declared effective in June 2005. The universal shelf registration statement permits us to offer and sell from time to time up to an aggregate maximum of $3 billion of securities, including common stock, preferred stock, debt securities, warrants and units. 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, 2005, no securities had been issued under the universal shelf registration statement, which remains effective.
      As of December 31, 2005, we had letters of credit outstanding under our Revolving Credit Facility of $406.7 million, leaving $493.3 million available for borrowing. This provides us with available borrowing capacity under the line of credit to fund strategic acquisitions or meet other financing needs. We were in

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compliance with all of the covenants of the Senior Secured Credit Facility, the 6.875% Senior Notes and the 5.875% Senior Notes as of December 31, 2005.
      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 receives a fixed rate of 6.875%. The average applicable floating rate of the four swaps was 7.09% as of December 31, 2005.
      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% (6.99% at December 31, 2005) 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% (6.46% at December 31, 2005) 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 annualized interest savings of $2.6 million over the term of the fixed-to-floating swap.
Contractual Obligations
      The following is a summary of our significant contractual obligations as of December 31, 2005 (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)
  $ 108,189     $ 252,518     $ 538,730     $ 1,048,169  
Capital lease obligations
    790       763              
Operating leases obligations
    84,031       139,905       75,435       103,506  
Unconditional purchase obligations(1)
    129,522       8,993              
Coal reserve lease and royalty obligations
    203,840       398,423       149,996       44,094  
Other long-term liabilities(2)
    168,775       327,754       370,093       961,997  
                         
 
Total contractual cash obligations
  $ 695,147     $ 1,128,356     $ 1,134,254     $ 2,157,766  
                         
 
(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 $138.5 million of purchase obligations related to future capital expenditures at December 31, 2005. Commitments for coal reserve-related capital expenditures, including Federal Coal Leases, are included in “Coal reserve lease and royalty obligations” in the table above.
      Total capital expenditures for 2006 are expected to range from $450 million to $525 million, excluding Federal Coal Lease payments. Approximately 60% of projected 2006 capital expenditures relates to replacement, improvement, or expansion of existing mines, particularly in Appalachia and the Midwest. The remainder of the expenditures relate to growth initiatives such as increasing capacity in the Powder

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River Basin. 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 2006 is reduced by our high level of sales commitments, 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.
      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, 2005 (dollars in millions):
                                                 
            Workers’   Retiree        
    Reclamation   Lease   Compensation   Healthcare        
    Obligations   Obligations   Obligations   Obligations   Other(1)   Total
                         
Self Bonding
  $ 671.8     $     $     $     $ 2.9     $ 674.7  
Surety Bonds
    335.6       258.8       19.2             28.4       642.0  
Letters of Credit
    0.1       22.7       144.6       120.1       119.7       407.2  
                                     
    $ 1,007.5     $ 281.5     $ 163.8     $ 120.1     $ 151.0     $ 1,723.9  
                                     
 
(1)  Includes financial guarantees primarily related to joint venture debt, the Pension Benefit Guarantee Corporation and collateral for surety companies.
      We have guaranteed $9.8 million of debt of an affiliate in which we have a 49% equity investment. We have also provided guarantees to small coal mining companies in order to facilitate their efforts to obtain bonding or financing. These guarantees arose as part of exclusive sales representation agreements with the small coal mining companies and totaled $5.5 million as of December 31, 2005. See Note 23 to our consolidated financial statements for a more detailed description of guarantees and indemnifications.
      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 our wholly-owned, bankruptcy-remote subsidiary 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 the accounts receivable to repay long-term debt, effectively reducing our overall borrowing costs. The securitization program is scheduled to expire in September 2009, and the maximum amount of undivided interests in accounts receivable that may be sold to the Conduit is $225.0 million. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheet. The funding cost of the securitization program was $2.5 million and $1.7 million for the years ended December 31, 2005 and 2004, respectively. In the third quarter of 2005, we renegotiated certain terms of the program, including lowering the program pricing, removing a minimum balance requirement and adding the ability to issue letters of credit under the program. The amount of undivided interests in accounts receivable sold to the Conduit was $225.0 million and $200.0 million as of December 31, 2005 and 2004, respectively. A detailed description of our $225.0 million accounts receivable securitization is included in Note 5 to our consolidated financial statements.

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      The following is a summary of specified types of commercial commitments available to us as of December 31, 2005 (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        
Accounting Pronouncements Not Yet Implemented
      In March 2005, the EITF issued EITF Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry,” which states “that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred.” Advance stripping costs include those costs necessary to remove overburden above an unmined coal seam as part of the surface mining process, and are included as the “work-in-process” component of “Inventories” in the consolidated balance sheets ($245.5 million and $197.2 million as of December 31, 2005, and December 31, 2004, respectively - see Note 10). This is consistent with the concepts embodied in Accounting Research Bulletin No. 43, “Restatement and Revision of Accounting Research Bulletins,” which provides that “the term inventory embraces goods awaiting sale. . ., goods in the course of production (work-in-process), and goods to be consumed directly or indirectly in production. . . .” At the June 15-16, 2005 EITF meeting, the Task Force clarified that the intended meaning of “inventory produced” is “inventory extracted.” Based on this clarification, stripping costs incurred during a period will be attributed only to the inventory costs of the coal that is extracted during that same period. Due to physical loadout constraints and potential combustion issues, coal in most of our operations is not removed from the open pit until it is ready to ship; therefore, we will have little inventory on our balance sheet after implementing this interpretation. We expect this accounting treatment will introduce volatility in our earnings as costs associated with preparing coal for sale may be expensed before the coal is sold, and likewise, sales may be made with little to no cost matched to the sale.
      EITF Issue No. 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006 for us). At the June 2005 EITF meeting, the Task Force modified the transition provisions of EITF Issue No. 04-6, indicating that companies that adopt in periods beginning after June 29, 2005 may utilize a cumulative effect adjustment approach where the cumulative effect adjustment is recorded directly to retained earnings in the year of adoption. If we had implemented the cumulative effect adjustment approach at December 31, 2005, the reduction to retained earnings, net of tax, would have been $150.6 million. We adopted EITF Issue No. 04-6 on January 1, 2006.
      On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 1239(R)), which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). SFAS No. 123(R) supersedes Accounting Principles Board (“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. Income tax benefits from stock options exercised will be included in financing activities in the statement of cash flows rather than operating activities.
      In 2005, the Securities and Exchange Commission deferred the adoption date of SFAS No. 123(R) to fiscal years beginning after June 15, 2005. We adopted this standard on January 1, 2006, and used the 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 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. Based on stock

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option grants made in 2005 (and years prior) and currently anticipated for 2006, we estimate we will recognize stock option expense for the year ending December 31, 2006, of $5.6 million, net of taxes. We began utilizing restricted stock as part of our equity-based compensation strategy in January 2005. Based on the restricted stock grants made in 2005 and years prior, we recognized expense related to restricted stock of $1.0 million, net of taxes, in 2005. Accounting for restricted stock awards is not affected by the adoption of SFAS 123(R).
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 at December 31, 2005, and included forwards and swaps at December 31, 2004. 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 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, 2005, the actual low, high and average values at risk for our coal trading portfolio were $1.2 million, $3.9 million and $2.3 million, respectively. During the year ended

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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. As of December 31, 2005, the timing of the estimated future realization of the value of our trading portfolio was as follows:
         
    Percentage
Year of Expiration   of Portfolio
     
2006
    76 %
2007
    23 %
2008
    1 %
       
      100 %
       
      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 to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2006 involves hedging approximately 70% of our anticipated, non-capital Australian dollar-denominated expenditures. As of December 31, 2005, we had in place forward contracts designated as cash flow hedges with notional amounts outstanding totaling A$915.8 million of which A$434.8 million, A$300.0 million and A$181.0 million will expire in 2006, 2007 and 2008, respectively. The accounting for these derivatives is discussed in Note 2 to our consolidated financial statements. Our current expectation for 2006 non-capital, Australian dollar-denominated cash expenditures is approximately $633 million. A change in the Australian dollar/ U.S. dollar exchange rate of US$0.01 (ignoring the effects of hedging) would result in an increase or decrease in our “Operating costs and expenses” of $6.3 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 14 to our consolidated financial statements. As of December 31, 2005, after taking into consideration the effects of interest rate swaps, we had $860.7 million of fixed-rate borrowings and $544.8 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $5.4 million on our variable-rate

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borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a $52.1 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 2005 and 2004. As of December 31, 2005, we had 15 to 25 million tons, 90 to 100 million tons and 155 to 165 million tons for 2006, 2007 and 2008, 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.
      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, 2005, 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 44.5 million gallons of heating oil and 24.4 million gallons of crude oil. Overall, we have fixed prices for approximately 50% of our anticipated diesel fuel requirements in 2006.
      We expect to consume 95 to 100 million gallons of fuel per year. On a per gallon basis, 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 of approximately $1 million per year. Alternatively, a one dollar per barrel change in the price of crude oil would increase or decrease our annual fuel costs (ignoring the effects of hedging) by approximately $2.3 million.
Item 8. Financial Statements and Supplementary Data.
      See Part IV, Item 15 of this report for information required by this Item.
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 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.

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Management’s Report on Internal Control Over Financial Reporting
      Management is responsible for maintaining and establishing adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with U.S. generally accepted accounting principles.
      Because of inherent limitations, any system of 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.
      Management conducted an assessment of the effectiveness of our internal control over financial reporting using the criteria set by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control — Integrated Framework. Based on this assessment, management concluded that the company’s internal control over financial reporting was effective as of December 31, 2005. Our Independent Registered Public Accounting Firm, Ernst & Young LLP, has audited this assessment of our internal control over financial reporting, as stated in their attestation report included herein.
     
/s/ GREGORY H. BOYCE   /s/ RICHARD A. NAVARRE
Gregory H. Boyce   Richard A. Navarre
President and Chief Executive Officer   Executive Vice President and Chief Financial Officer
February 21, 2006

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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 Controls, that Peabody Energy Corporation maintained effective internal control over financial reporting as of December 31, 2005, 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.
      In our opinion, management’s assessment that Peabody Energy Corporation maintained effective internal control over financial reporting as of December 31, 2005, 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, 2005, based on the COSO criteria.
      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, 2005 and 2004, 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, 2005, and our report dated February 21, 2006, expressed an unqualified opinion thereon.
  /s/ Ernst & Young LLP
St. Louis, Missouri
February 21, 2006

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Item 9B. Other Information.
      None.
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 2006 Proxy Statement and in Part I 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 2006 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 2006 Proxy Statement and is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
      The information required by Item 403 of Regulation S-K is included under the caption “Ownership of Company Securities” in our 2006 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, 2005:
                         
            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
    10,783,786     $ 6.37       15,853,254  
Equity compensation plans not approved by security holders
                 
                   
Total
    10,783,786     $ 6.37       15,853,254  
                   
Item 13. Certain Relationships and Related Transactions.
      The information required by Item 404 of Regulation S-K is included under the caption “Certain Transactions and Relationships” in our 2006 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 “Appointment of Independent Registered Public Accounting Firm and Fees” in our 2006 Proxy Statement and is incorporated herein by reference.

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PART IV
Item 15. Exhibits, Financial Statement Schedules.
      (a) Documents Filed as Part of the Report
        (1) Financial Statements.
 
        The following consolidated financial statements of Peabody Energy Corporation are included herein on the pages indicated:
         
    Page
     
Report of Independent Registered Public Accounting Firm
    F-1  
Consolidated Statements of Operations — Years Ended December 31, 2005, 2004 and 2003
    F-2  
Consolidated Balance Sheets — December 31, 2005 and December 31, 2004
    F-3  
Consolidated Statements of Cash Flows — Years Ended December 31, 2005, 2004 and 2003
    F-4  
Consolidated Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2005, 2004 and 2003
    F-5  
Notes to Consolidated Financial Statements
    F-6  
        (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-67  
Valuation and Qualifying Accounts
    F-68  
        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/ GREGORY H. BOYCE
 
 
  Gregory H. Boyce
  President, Chief Executive Officer and Director
Date: March 3, 2006
      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/ GREGORY H. BOYCE

Gregory H. Boyce
  President, Chief Executive Officer and Director (principal executive officer)   March 3, 2006
 
/s/ RICHARD A. NAVARRE

Richard A. Navarre
  Executive Vice President and Chief Financial Officer (principal financial and accounting officer)   March 3, 2006
 
/s/ IRL F. ENGELHARDT

Irl F. Engelhardt
  Chairman   March 3, 2006
 
/s/ B.R. BROWN

B.R. Brown
  Director   March 3, 2006
 
/s/ WILLIAM A. COLEY

William A. Coley
  Director   March 3, 2006
 
/s/ HENRY GIVENS, JR., PHD

Henry Givens, Jr., PhD
  Director   March 3, 2006
 
/s/ WILLIAM E. JAMES

William E. James
  Director   March 3, 2006
 
/s/ ROBERT B. KARN III

Robert B. Karn III
  Director   March 3, 2006
 
/s/ HENRY E. LENTZ

Henry E. Lentz
  Director   March 3, 2006
 
/s/ WILLIAM C. RUSNACK

William C. Rusnack
  Director   March 3, 2006
 
/s/ JAMES R. SCHLESINGER, PHD

James R. Schlesinger, PhD
  Director   March 3, 2006

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Signature   Title   Date
         
 
/s/ BLANCHE M. TOUHILL, PHD

Blanche M. Touhill, PhD
  Director   March 3, 2006
 
/s/ JOHN F. TURNER

John F. Turner
  Director   March 3, 2006
 
/s/ SANDRA VAN TREASE

Sandra Van Trease
  Director   March 3, 2006
 
/s/ ALAN H. WASHKOWITZ

Alan H. Washkowitz
  Director   March 3, 2006

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Peabody Energy Corporation
      We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation as of December 31, 2005 and 2004, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows of the Company for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
      We conducted our audits in accordance with 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 the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
      In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Peabody Energy Corporation at December 31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
      We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Peabody Energy Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 21, 2006, expressed an unqualified opinion thereon.
  /s/ ERNST & YOUNG LLP
St. Louis, Missouri
February 21, 2006

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PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
                             
    Year Ended December 31,
     
    2005   2004   2003
             
    (Dollars in thousands, except share and per share data)
Revenues
                       
 
Sales
  $ 4,545,323     $ 3,545,027     $ 2,729,323  
 
Other revenues
    99,130       86,555       85,973  
                   
   
Total revenues
    4,644,453       3,631,582       2,815,296  
Costs and Expenses
                       
 
Operating costs and expenses
    3,715,836       2,965,541       2,332,137  
 
Depreciation, depletion and amortization
    316,114       270,159       234,336  
 
Asset retirement obligation expense
    35,901       42,387       31,156  
 
Selling and administrative expenses
    189,802       143,025       108,525  
 
Other operating income:
                       
   
Net gain on disposal or exchange of assets
    (101,487 )     (23,829 )     (32,772 )
   
Income from equity affiliates
    (30,096 )     (12,399 )     (2,872 )
                   
Operating Profit
    518,383       246,698       144,786  
 
Interest expense
    102,939       96,793       98,540  
 
Early debt extinguishment costs
          1,751       53,513  
 
Interest income
    (10,641 )     (4,917 )     (4,086 )
                   
Income (Loss) From Continuing Operations Before Income Taxes and Minority Interests
    426,085       153,071       (3,181 )
 
Income tax provision (benefit)
    960       (26,437 )     (47,708 )
 
Minority interests
    2,472       1,282       3,035  
                   
Income From Continuing Operations
    422,653       178,226       41,492  
 
Loss from discontinued operations, net of income tax benefit of $1,893
          (2,839 )      
                   
Income Before Accounting Changes
    422,653       175,387       41,492  
 
Cumulative effect of accounting changes, net of income tax benefit of $6,762
                (10,144 )
                   
Net Income
  $ 422,653     $ 175,387     $ 31,348  
                   
Basic Earnings Per Share
                       
 
Income from continuing operations
  $ 1.62     $ 0.72     $ 0.19  
 
Loss from discontinued operations
          (0.01 )      
 
Cumulative effect of accounting changes
                (0.04 )
                   
   
Net income
  $ 1.62     $ 0.71     $ 0.15  
                   
Weighted Average Shares Outstanding — Basic
    261,519,424       248,732,744       213,638,084  
                   
Diluted Earnings Per Share
                       
 
Income from continuing operations
  $ 1.58     $ 0.70     $ 0.19  
 
Loss from discontinued operations
          (0.01 )      
 
Cumulative effect of accounting changes
                (0.05 )
                   
   
Net income
  $ 1.58     $ 0.69     $ 0.14  
                   
Weighted Average Shares Outstanding — Diluted
    268,013,476       254,812,632       219,342,512  
                   
Dividends Declared Per Share
  $ 0.17     $ 0.13     $ 0.11  
                   
See accompanying notes to consolidated financial statements

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PEABODY ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
                       
    December 31,
     
    2005   2004
         
    (Dollars in thousands, except
    share and per share data)
ASSETS
Current assets
               
 
Cash and cash equivalents
  $ 503,278     $ 389,636  
 
Accounts receivable, net of allowance for doubtful accounts of $10,853 and $1,361 at December 31, 2005 and 2004, respectively
    221,541       193,784  
 
Inventories
    389,771       323,609  
 
Assets from coal trading activities
    146,596       89,165  
 
Deferred income taxes
    9,027       15,461  
 
Other current assets
    54,431       42,947  
             
   
Total current assets
    1,324,644       1,054,602  
Property, plant, equipment and mine development
               
 
Land and coal interests
    4,775,126       4,512,893  
 
Buildings and improvements
    793,254       718,803  
 
Machinery and equipment
    1,237,184       883,380  
 
Less accumulated depreciation, depletion and amortization
    (1,627,856 )     (1,333,645 )
             
Property, plant, equipment and mine development, net
    5,177,708       4,781,431  
Investments and other assets
    349,654       342,559  
             
   
Total assets
  $ 6,852,006     $ 6,178,592  
             
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
               
 
Current maturities of long-term debt
  $ 22,585     $ 18,979  
 
Liabilities from coal trading activities
    132,373       63,565  
 
Accounts payable and accrued expenses
    867,965       691,600  
             
   
Total current liabilities
    1,022,923       774,144  
Long-term debt, less current maturities
    1,382,921       1,405,986  
Deferred income taxes
    338,488       393,266  
Asset retirement obligations
    399,203       396,022  
Workers’ compensation obligations
    237,574       227,476  
Accrued postretirement benefit costs
    959,222       939,503  
Other noncurrent liabilities
    330,658       315,694  
             
   
Total liabilities
    4,670,989       4,452,091  
Minority interests
    2,550       1,909  
Stockholders’ equity
               
 
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of December 31, 2005 or 2004
           
 
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of December 31, 2005 or 2004
           
 
Series A Junior Participating Preferred Stock — 1,500,000 shares authorized, no shares issued or outstanding as of December 31, 2005 or 2004
           
 
Common Stock — $0.01 per share par value; 400,000,000 shares authorized, 263,879,762 shares issued and 263,357,402 shares outstanding as of December 31, 2005 and 150,000,000 shares authorized, 259,658,268 shares issued and 259,135,908 shares outstanding as of December 31, 2004
    2,638       2,596  
 
Additional paid-in capital
    1,503,397       1,436,021  
 
Retained earnings
    729,086       350,968  
 
Unearned restricted stock awards
    (5,943 )     (459 )
 
Accumulated other comprehensive loss
    (46,795 )     (60,618 )
 
Treasury shares, at cost: 522,360 shares as of December 31, 2005 and 2004
    (3,916 )     (3,916 )
             
   
Total stockholders’ equity
    2,178,467       1,724,592  
             
     
Total liabilities and stockholders’ equity
  $ 6,852,006     $ 6,178,592  
             
See accompanying notes to consolidated financial statements

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PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
                             
    Year Ended December 31,
     
    2005   2004   2003
             
    (Dollars in thousands)
Cash Flows From Operating Activities
                       
Net income
  $ 422,653     $ 175,387     $ 31,348  
 
Loss from discontinued operations
          2,839        
 
Cumulative effect of accounting changes, net of taxes
                10,144  
                   
   
Income from continuing operations
    422,653       178,226       41,492  
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
                       
 
Depreciation, depletion and amortization
    316,114       270,159       234,336  
 
Deferred income taxes
    (24,962 )     (31,925 )     (48,259 )
 
Early debt extinguishment costs
          1,751       53,513  
 
Amortization of debt discount and debt issuance costs
    6,938       8,330       8,158  
 
Net gain on disposal or exchange of assets
    (101,487 )     (23,829 )     (32,772 )
 
Income from equity affiliates
    (30,096 )     (12,399 )     (2,872 )
 
Dividends received from equity affiliates
    7,552       13,614       4,781  
 
Changes in current assets and liabilities, net of acquisitions:
                       
   
Accounts receivable, net of sale
    (52,757 )     (34,649 )     (21,279 )
   
Inventories
    (67,125 )     (57,781 )     (16,805 )
   
Net assets from coal trading activities
    11,377       (3,583 )     (22,771 )
   
Other current assets
    (10,769 )     (1,438 )     (3,621 )
   
Accounts payable and accrued expenses
    173,919       66,576       34,423  
 
Asset retirement obligations
    (981 )     (6,571 )     (9,563 )
 
Workers’ compensation obligations
    11,390       10,479       156  
 
Accrued postretirement benefit costs
    19,719       (32,499 )     3,705  
 
Contributions to pension plans
    (7,162 )     (62,082 )     (17,490 )
 
Other, net
    28,436       1,381       (16,271 )
                   
   
Net cash provided by operating activities
    702,759       283,760       188,861  
                   
Cash Flows From Investing Activities
                       
Additions to property, plant, equipment and mine development
    (384,304 )     (151,944 )     (156,443 )
Federal coal lease expenditures
    (118,364 )     (114,653 )      
Purchase of mining and related assets
    (141,195 )            
Additions to advance mining royalties
    (14,566 )     (16,239 )     (14,010 )
Acquisitions, net
          (429,061 )     (90,000 )
Investments in joint ventures
    (2,000 )     (32,472 )     (1,400 )
Proceeds from disposal of assets
    76,227       39,339       69,573  
                   
   
Net cash used in investing activities
    (584,202 )     (705,030 )     (192,280 )
                   
Cash Flows From Financing Activities
                       
Net change in revolving lines of credit
                (121,584 )
Proceeds from long-term debt
    11,734       700,013       1,102,735  
Payments of long-term debt
    (20,198 )     (482,924 )     (868,386 )
Net proceeds from equity offering
          383,125        
Proceeds from stock options exercised
    22,573       27,266       31,329  
Proceeds from employee stock purchases
    3,009       2,343       1,737  
Increase (decrease) of securitized interests in accounts receivable
    25,000       110,000       (46,400 )
Payment of debt issuance costs
          (12,875 )     (23,700 )
Distributions to minority interests
    (2,498 )     (1,007 )     (4,186 )
Dividends paid
    (44,535 )     (32,568 )     (24,058 )
Other
          31       1,111  
                   
   
Net cash provided by (used in) financing activities
    (4,915 )     693,404       48,598  
Effect of exchange rate changes on cash and cash equivalents
                1,113  
                   
Net increase in cash and cash equivalents
    113,642       272,134       46,292  
Cash and cash equivalents at beginning of year
    389,636       117,502       71,210  
                   
Cash and cash equivalents at end of year
  $ 503,278     $ 389,636     $ 117,502  
                   
See accompanying notes to consolidated financial statements

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Table of Contents

PEABODY ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
                                                                     
            Unearned       Accumulated            
        Additional   Restricted   Other   Other           Total
    Common   Paid-in   Stock   Employee   Comprehensive   Retained   Treasury   Stockholders’
    Stock   Capital   Awards   Stock Loans   Loss   Earnings   Stock   Equity
                                 
    (Dollars in thousands)
December 31, 2002
  $ 2,096     $ 956,995     $     $ (1,142 )   $ (77,627 )   $ 200,859     $ (43 )   $ 1,081,138  
 
Comprehensive income:
                                                               
   
Net income
                                  31,348             31,348  
   
Foreign currency translation adjustment
                            3,138                   3,138  
   
Decrease in fair value of cash flow hedges (net of $4,694 tax benefit)
                            (7,041 )                 (7,041 )
   
Minimum pension liability adjustment (net of $27 tax benefit)
                            (42 )                 (42 )
                                                 
 
Comprehensive income
                                                            27,403  
 
Dividends paid
                                  (24,058 )           (24,058 )
 
Loan repayments
                      1,111                         1,111  
 
Stock options exercised
    90       35,245                                     35,335  
 
Income tax benefits from stock options exercised
          12,925                                     12,925  
 
Employee stock purchases
    4       1,733                                     1,737  
 
Stock grants to non-employee directors
          100                                     100  
 
Employee stock grants
          368       (368 )                              
 
Deferred compensation earned
                10                               10  
 
Shares repurchased
                                        (3,644 )     (3,644 )
                                                 
December 31, 2003
    2,190       1,007,366       (358 )     (31 )     (81,572 )     208,149       (3,687 )     1,132,057  
 
Comprehensive income:
                                                               
   
Net income
                                  175,387             175,387  
   
Increase in fair value of cash flow hedges (net of $9,945 tax provision)
                            14,915                   14,915  
   
Minimum pension liability adjustment (net of $4,026 tax provision)
                            6,039                   6,039  
                                                 
 
Comprehensive income
                                                            196,341  
 
Issuance of common stock in connection with equity offering, net of expenses
    352       382,773                                     383,125  
 
Dividends paid
                                  (32,568 )           (32,568 )
 
Loan repayments
                      31                         31  
 
Stock options exercised
    54       27,621                                     27,675  
 
Income tax benefits from stock options exercised