10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the Fiscal Year Ended December 31, 2004
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 1-16463

Peabody Energy Corporation

(Exact name of registrant as specified in its charter)

Delaware	13-4004153
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
701 Market Street, St. Louis, Missouri	63101
(Address of principal executive offices)	(Zip Code)

(314) 342-3400

Registrant’s telephone number, including area code

Securities Registered Pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, par value $0.01 per share Preferred Share Purchase Rights	New York Stock Exchange New York Stock Exchange

Securities Registered Pursuant to Section 12(g) of the Act:

None

      Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes þ          No o

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

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the Peabody Energy Corporation (the “Company”) Annual Report for the year ended December 31, 2004 are incorporated by reference into Part II hereof. Portions of the Company’s Proxy Statement to be filed with the SEC in connection with the Company’s Annual Meeting of Stockholders to be held on May 6, 2005 (the “Company’s 2005 Proxy Statement”) are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K.

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

      This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, such statements in the section captioned “Outlook.” We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “will” or other similar words to identify forward-looking statements.

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

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

•  growth of domestic and international coal and power markets;

•  coal’s market share of electricity generation;

•  future worldwide economic conditions;

•  weather;

•  transportation performance and costs, including demurrage;

•  ability to renew sales contracts;

•  successful implementation of business strategies;

•  regulatory and court decisions;

•  future legislation;

•  changes in postretirement benefit and pension obligations;

•  labor relations and availability;

•  availability and costs of credit, surety bonds and letters of credit;

•  the effects of changes in currency exchange rates;

•  price volatility and demand, particularly in higher-margin products;

•  risks associated with customers;

•  reductions of purchases by major customers;

•  geology and equipment risks inherent to mining;

•  terrorist attacks or threats;

•  performance of contractors or third party coal suppliers;

•  replacement of reserves;

•  implementation of new accounting standards;

•  inflationary trends, including those impacting materials used in our business;

•  the effects of interest rate changes;

•  the effects of acquisitions or divestitures;

•  changes to contribution requirements to multi-employer benefit funds; and

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•  other factors, including those discussed in “Legal Proceedings,” set forth in Item 3 of this report and the “Risks Relating to Our Company” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” set forth in Item 7 of this report.

      When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and the documents incorporated by reference. We will not update these statements unless the securities laws require us to do so.

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TABLE OF CONTENTS

		Page
PART I.
Item 1.	Business		2
Item 2.	Properties		25
Item 3.	Legal Proceedings		30
Item 4.	Submission of Matters to a Vote of Security Holders		34
	Executive Officers of the Company		34
PART II.
Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		36
Item 6.	Selected Financial Data		37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		40
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		65
Item 8.	Financial Statements and Supplementary Data		67
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		67
Item 9A.	Controls and Procedures		67
Item 9B.	Other Information		72
PART III.
Item 10.	Directors and Executive Officers of the Registrant		72
Item 11.	Executive Compensation		72
Item 12.	Security Ownership of Certain Beneficial Owners and Management		72
Item 13.	Certain Relationships and Related Transactions		72
Item 14.	Principal Accounting Fees and Services		72
PART IV.
Item 15.	Exhibits, Financial Statement Schedules		73
Amended and Restated By-Laws
6 7/8% Senior Notes Indenture
5 7/8% Senior Notes
Amendment No.3 to Second Amended & Restated Credit Agreement
First Amendment to Deferred Compensation Plan
Portions of Annual Report to Stockholders
List of Subsidiaries
Consent of Ernst & Young LLP
Section 302 Certification
Section 302 Certification
Section 906 Certification
Section 906 Certification

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Notes:  The words “we,” “our,” or “the Company” as used in this report, refer to Peabody Energy Corporation or its applicable subsidiary or subsidiaries.

On March 2, 2005, we announced a two-for-one stock split on all shares of our common stock payable to shareholders of record at the close of business on March 16, 2005. The additional shares will be distributed on March 30, 2005. All share and per share amounts in this Annual Report on Form 10-K reflect the stock split.

PART I

Item 1. Business.

Overview

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

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

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

      In addition to our mining operations, we market, broker and trade coal. Our total tons traded were 33.4 million for the year ended December 31, 2004. Our other energy related businesses include the development of mine-mouth coal-fueled generating plants, the management of our vast coal reserve and real estate holdings, coalbed methane production and transportation services.

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History

      Peabody, Daniels and Co. was founded in 1883 as a retail coal supplier, entering the mining business in 1888 as Peabody & Co. with the opening of our first coal mine in Illinois. In 1926, Peabody Coal Company was listed on the Chicago Stock Exchange and, beginning in 1949, on the New York Stock Exchange.

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

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

      In July 1990, Hanson, PLC acquired Peabody Holding Company. In the 1990’s, Peabody continued to grow through expansion and acquisitions. In February 1997, Hanson spun off its energy-related businesses, including Eastern Group and Peabody Holding Company, into The Energy Group, plc. The Energy Group was a publicly traded company in the United Kingdom and its American Depository Receipts (ADR’s) were publicly traded on the New York Stock Exchange.

      In May 1998, Lehman Brothers Merchant Banking Partners II L.P. and affiliates (“Merchant Banking Fund”), an affiliate of Lehman Brothers Inc. (“Lehman Brothers”), purchased Peabody Holding Company and its affiliates, Peabody Resources Limited and Citizens Power LLC in a leveraged buyout transaction that coincided with the purchase by Texas Utilities of the remainder of The Energy Group.

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

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

      In April 2001, we changed our name to Peabody Energy Corporation (“Peabody”), reflecting our position as a premier energy supplier. In May 2001, after having reduced the debt incurred in the leveraged buyout by more than $1 billion, we completed an initial public offering of common stock, and the Company’s shares began trading on the New York Stock Exchange under the ticker symbol “BTU,” the globally recognized symbol for energy.

      In April 2004, we acquired three coal operations from RAG Coal International AG for a combined purchase price of $421 million, net of cash received in the transaction. The purchase included two mines in Queensland, Australia that produce a combined 7 to 8 million tons per year of metallurgical coal, and the Twentymile Mine in Colorado, which historically produced 7 to 8 million tons per year of low-sulfur, steam coal. In December 2004, we completed the purchase of a 25.5% equity interest in Carbones del Guasare, S.A. from RAG Coal International AG for a net purchase price of $32.5 million. Carbones del Guasare, a joint venture that also includes Anglo American plc and a Venezuelan governmental partner, operates the Paso Diablo surface mine in northwestern Venezuela, which produces approximately 7 million tons per year of coal for electricity generators and steel producers.

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

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Mining Operations

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

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

      Included in the descriptions of our mining operations are discussions of the subsidiaries which manage the respective mining operation. The subsidiary that manages a particular mining operation is not necessarily indicative of the subsidiary or subsidiaries which own the assets utilized in that mining operation.

Powder River Basin Operations

      We control approximately 3.1 billion tons of proven and probable coal reserves in the Southern Powder River Basin, the largest and fastest growing major U.S. coal-producing region. Our subsidiaries, Powder River Coal Company and Caballo Coal Company, manage three low-sulfur, non-union surface mining complexes in Wyoming that sold 115.8 million tons of coal during the year ended December 31, 2004, or approximately 51% of our total coal sales volume. The North Antelope Rochelle and Caballo

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mines are serviced by both major western railroads, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway.

      Our Wyoming Powder River Basin reserves are classified as surface mineable, subbituminous coal with seam thickness varying from 70 to 105 feet. The sulfur content of the coal in current production ranges from 0.2% to 0.4% and the heat value ranges from 8,300 to 9,000 Btu’s per pound.

North Antelope Rochelle Mine

      The North Antelope Rochelle Mine is located 65 miles south of Gillette, Wyoming. This mine is one of the largest in North America, selling 82.5 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu) during 2004. The North Antelope Rochelle facility is capable of loading its production in up to 2,000 railcars per day. The North Antelope Rochelle Mine produces premium quality coal with a sulfur content averaging 0.2% and a heat value ranging from 8,500 to 8,900 Btu per pound. The North Antelope Rochelle Mine produces the lowest sulfur coal in the United States, using two draglines along with six truck-and-shovel fleets.

Caballo Mine

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

Rawhide Mine

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

Southwest Operations

      We own and operate three mines in our Southwest operations — two in Arizona and one in New Mexico. The Arizona mines, which are managed by our Peabody Western Coal Company subsidiary, supply primarily bituminous compliance coal under long-term coal supply agreements to electricity generating stations in the region. In New Mexico, we own and manage, through our Peabody Natural Resources Company subsidiary, the Lee Ranch Mine, which mines and produces subbituminous medium sulfur coal. Together, these three mines sold 18.7 million tons of coal during 2004 and control 1.0 billion of proven and probable coal reserves.

Black Mesa Mine

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

Kayenta Mine

      The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines in three mining areas. It sold approximately 8.4 million tons of coal during 2004. The Kayenta Mine coal is crushed, then carried 17 miles by conveyor belt to storage silos where it is loaded onto a private rail line and transported 83 miles to the Navajo Generating Station, operated by the Salt River Project near Page, Arizona. The

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mine and railroad were designed to deliver coal exclusively to the power plant, which has no other source of coal. The Navajo coal supply agreement extends until 2011. Hourly workers at this mine are members of the United Mine Workers of America.

Lee Ranch Mine

      The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 5.6 million tons of medium sulfur coal during 2004. Lee Ranch shipped the majority of its coal to two customers in Arizona and New Mexico under coal supply agreements extending until 2020 and 2014, respectively. Lee Ranch is a non-union surface mine that uses a combination of dragline and truck-and-shovel mining techniques and ships coal to its customers via the Burlington Northern Santa Fe Railway.

Colorado Operations

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

Twentymile Mine

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

Seneca Mine

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

Appalachia Operations

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

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Big Mountain Business Unit and Contract Mines

      The Big Mountain business unit is based near Prenter, West Virginia. This business unit’s primary mine is Big Mountain No. 16, and includes a small amount of contract mine production from coal reserves we control. During 2004, the Big Mountain business unit sold approximately 1.9 million tons of steam coal. Big Mountain No. 16 is an underground mine using continuous mining equipment. Processed coal is loaded on the CSX railroad.

Harris Business Unit

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

Rocklick Business Unit and Contract Mines

      The Rocklick preparation plant, located near Wharton, West Virginia, processes coal produced by the Harris No. 1 Mine and contract mining operations from coal reserves that we control. This preparation plant shipped approximately 2.0 million tons of steam and metallurgical coal sourced from the contract mines during 2004. Processed coal is loaded at the plant site on the CSX railroad or transferred via conveyor to our Kopperston loadout facility and loaded on the Norfolk Southern railroad.

Wells Business Unit and Contract Mines

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

Federal No. 2 Mine

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

Highland Business Unit

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

Kanawha Eagle Coal Joint Venture

      We have a 49% interest in the Kanawha Eagle Joint Venture, which owns and manages underground mining operations, a preparation plant and barge-and-rail loading facilities near Marmet, West Virginia. The mines are non-union and use continuous mining equipment. They shipped 2.5 million tons during 2004.

Midwest Operations

      Our Midwest operations consist of 13 wholly-owned mines in the Illinois basin and are comprised of our Patriot Coal Company, Indian Hill Company and Black Beauty Coal Company subsidiaries. Our Midwest Operations control approximately 3.8 billion tons of proven and probable coal reserves. In 2004, these operations collectively sold 32.5 million tons of coal, more than any other midwestern coal producer.

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We ship coal from these mines primarily to electricity generators in the Midwestern United States, and to industrial customers that generate their own power.

Patriot Coal Company

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

Indian Hill Company

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

Black Beauty Coal Company

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

      Black Beauty’s principal Indiana mines include Air Quality, Farmersburg, Francisco and Somerville. Air Quality is an underground coal mine located near Monroe City, Indiana that shipped 1.7 million tons of compliance coal during 2004. Farmersburg is a surface mine situated in Vigo and Sullivan counties in Indiana that sold 4.3 million tons of medium sulfur coal during 2004. The Francisco Mine, located in Gibson County, Indiana mines coal by utilizing both surface mining and underground mining methods and sold 3.1 million tons of medium sulfur coal during 2004. The Somerville mine complex, also located in Gibson County, shipped a total of 7.2 million tons of medium sulfur coal in 2004. Two other surface mines located in Indiana, Viking and Miller Creek, collectively shipped 2.3 million tons of medium sulfur coal during 2004.

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

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

Australian Mining Operations

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

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of which were metallurgical coal. Coal from these mines is shipped via rail from the mine to the loading point at Dalrymple Bay, where the coal is loaded onto ocean-going vessels. All sales from our Australian mines are denominated in U.S. dollars. Our Australian mines operate with site-specific collective bargaining labor agreements. Our Australian operations control 0.2 billion tons of proven and probable reserves.

Wilkie Creek Mine

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

Burton Mine

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

North Goonyella Mine

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

Eaglefield Mine

      Our recently opened Eaglefield Mine is a surface operation utilizing truck-and-shovel mining methods. It is adjacent to, and fulfills contract tonnages in conjunction with, the North Goonyella underground mine. Coal is mined by a contractor from reserves that we control.

Venezuelan Mining Operations

      In December 2004, we acquired a 25.5% interest in Carbones del Guasare, S.A., a joint venture that includes Anglo American plc and a Venezuelan governmental partner. Carbones del Guasare operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine is a surface operation in northwestern Venezuela that produces approximately 7 million tons of steam coal annually for export primarily to the United States and Europe. We are responsible for our pro-rata share of sales from Paso Diablo; the joint venture is responsible for production, processing and transportation of coal to ocean-going vessels for delivery to customers.

Long-Term Coal Supply Agreements

      We currently have a sales backlog in excess of one billion tons of coal, including backlog subject to price reopener and/or extension provisions, and our coal supply agreements have remaining terms ranging from one to 17 years and an average volume-weighted remaining term of approximately 3.4 years. For 2004, we sold approximately 90% of our sales volume under long-term coal supply agreements. In 2004, we sold coal to over 300 electricity generating and industrial plants in 16 countries. Our primary customer base is in the United States, although customers in the Pacific Rim and other international locations represent an increasing portion of our revenue stream. Two of our largest coal supply agreements are the subject of ongoing litigation and arbitration, as discussed at Item 3. Legal Proceedings.

      We expect to continue selling a significant portion of our coal under long-term supply agreements. Our strategy is to selectively renew, or enter into new, long-term supply contracts when we can do so at prices we believe are favorable. As of December 31, 2004, we had 5 to 10 million tons, 65 to 75 million tons and 130 to 140 million tons for 2005, 2006 and 2007, respectively, of expected production (including steam and metallurgical coal production) available for sale or repricing at market prices. We have an

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

      Long-term contracts are attractive for regions where market prices are expected to remain stable, for cost-plus arrangements serving captive electricity generating plants and for the sale of high-sulfur coal to “scrubbed” generating plants. To the extent we do not renew or replace expiring long-term coal supply agreements, our future sales will be subject to market fluctuations, including unexpected downturns in market prices.

      Typically, customers enter into coal supply agreements to secure reliable sources of coal at predictable prices, while we seek stable sources of revenue to support the investments required to open, expand and maintain or improve productivity at the mines needed to supply these contracts. The terms of coal supply agreements result from competitive bidding and extensive negotiations with customers. Consequently, the terms of these contracts vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, permitted sources of supply, treatment of environmental constraints, extension options, force majeure, and termination and assignment provisions.

      Each contract sets a base price. Some contracts provide for a predetermined adjustment to base price at times specified in the agreement. Base prices may also be adjusted quarterly, annually or at other periodic intervals for changes in production costs and/or changes due to inflation or deflation. Changes in production costs may be measured by defined formulas that may include actual cost experience at the mine as part of the formula. The inflation/deflation adjustments are measured by public indices, the most common of which is the implicit price deflator for the gross domestic product as published by the U.S. Department of Commerce. In most cases, the components of the base price represented by taxes, fees and royalties which are based on a percentage of the selling price are also adjusted for any changes in the base price and passed through to the customer. Some contracts allow the base price to be adjusted to reflect the cost of capital.

      Most contracts contain provisions to adjust the base price due to new statutes, ordinances or regulations that impact our cost of performance of the agreement. Additionally, some contracts contain provisions that allow for the recovery of costs impacted by the modifications or changes in the interpretation or application of any existing statute by local, state or federal government authorities. Some agreements provide that if the parties fail to agree on a price adjustment caused by cost increases due to changes in applicable laws and regulations, the purchaser may terminate the agreement.

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

      Quality and volumes for the coal are stipulated in coal supply agreements, and in some limited instances buyers have the option to vary annual or monthly volumes if necessary. Variations to the quality and volumes of coal may lead to adjustments in the contract price. Most coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as heat (Btu), sulfur, and ash content, grindability and ash fusion temperature. Failure to meet these specifications can result in economic penalties, suspension or cancellation of shipments or termination of the contracts. Coal supply agreements typically stipulate procedures for quality control, sampling and weighing. In the eastern United States, approximately half of our customers require that the coal is sampled and weighed at the destination, whereas in the western United States, samples and weights are usually taken at the shipping source.

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      Contract provisions in some cases set out mechanisms for temporary reductions or delays in coal volumes in the event of a force majeure, including events such as strikes, adverse mining conditions or serious transportation problems that affect the seller or unanticipated plant outages that may affect the buyer. More recent contracts stipulate that this tonnage can be made up by mutual agreement. Buyers often negotiate similar clauses covering changes in environmental laws. We often negotiate the right to supply coal that complies with a new environmental requirement to avoid contract termination. Coal supply agreements typically contain termination clauses if either party fails to comply with the terms and conditions of the contract, although most termination provisions provide the opportunity to cure defaults.

      In some of our contracts, we have a right of substitution, allowing us to provide coal from different mines, including third party production, as long as the replacement coal meets the contracted quality specifications and will be sold at the same delivered cost.

Sales and Marketing

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

Transportation

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

      The majority of our sales volume is shipped by rail, but a portion of our production is shipped by other modes of transportation, including barge and ocean-going vessels. Our transportation department manages the loading of trains and barges.

      Coal from our Black Mesa Mine in Arizona is transported by a 273-mile coal-water pipeline to the Mohave Generating Station in southern Nevada. Coal from the Seneca Mine in Colorado is transported by truck to the nearby Hayden Plant. All coal from our southern Powder River Basin mines in Wyoming is shipped by rail, and two competing railroads, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad, serve our North Antelope Rochelle and Caballo mines. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway. Approximately 12,000 unit trains are loaded each year to accommodate the coal shipped by our mines overall. A unit train generally consists of 100 to 150 cars, each of which can hold 100 to 120 tons of coal. We believe we enjoy good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators.

Suppliers

      The main types of goods we purchase are mining equipment and replacement parts, explosives, fuel, tires, steel-related products and lubricants. We have many long, established relationships with our key suppliers, and do not believe that we are dependent on any of our individual suppliers, except as noted below. The supplier base providing mining materials has been relatively consistent in recent years, although there has been some consolidation. Recent consolidation of suppliers of explosives has limited the number of sources for these materials. Although our current supply of explosives is concentrated with one supplier, alternative sources are available to us in the regions where we operate. Further, purchases of certain

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underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop. In the past year, demand for certain surface and underground mining equipment and off-the-road tires has increased. As a result, lead times for certain items have generally increased by up to several months, although no material impact is currently expected to our financial condition, results of operations or cash flows.

Technical Innovation

      We continue to place great emphasis on the application of technical innovation to improve new and existing equipment performance. This research and development effort is typically undertaken and funded by equipment manufacturers using our input and expertise. Our engineering, maintenance and purchasing personnel work together with manufacturers to design and produce equipment that we believe will add value to the business.

      A major effort has been under way to improve the performance of our draglines which move a third of the billion tons of overburden handled annually. The dragline improvement effort includes more efficient bucket design, faster cycle times, improved swing motion controls to increase component life and better monitors to enable increased payloads. A new digital drive design has been tested on an overburden shovel in the Powder River Basin with excellent results and will be installed on our other shovels. Blasting performance has improved through the use of new products including digital detonation, air decking, blast-hole sleeving and new blasting agents. Filtered used lubrication oils are also utilized in our blasting products.

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

      World-class maintenance standards based on condition-based maintenance practices are being implemented at all operations. Using these techniques allows us to increase equipment utilization and reduce capital through extending the equipment life while minimizing the risk of premature failures. Lubrication is replaced and work is scheduled on condition rather than time. Benefits from sophisticated lubrication analysis and quality control include lower lubrication consumption, optimum equipment performance and extended component life. We are upgrading our computerized maintenance management system to support our maintenance practices. Also, a remote data acquisition system is being installed to more efficiently dispatch mobile equipment and monitor equipment performance on a real-time basis.

      Our mines use sophisticated software to schedule and monitor trains, mine and pit blending, quality and customer shipments. The integrated software has been developed in-house and provides a competitive tool to differentiate our reliability and product consistency. We are the largest user of advanced coal quality analyzers among coal producers, according to the manufacturer of this sophisticated equipment. These analyzers allow continuous analysis of certain coal quality parameters, such as sulfur content. Their use helps ensure consistent product quality and helps customers meet stringent air emission requirements.

      We also support the Power Systems Development Facility, a highly efficient electricity generating plant using coal gasification generation technology, funded primarily through the U.S. Department of Energy and operated by an affiliate of Southern Company. Peabody is a member of the multi-company alliance working with the Department of Energy on FutureGen, a long-term project to develop near-zero emission power generation technology that will produce both power and hydrogen from coal and will capture and sequester carbon dioxide.

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Competition

      The markets in which we sell our coal are highly competitive. According to the National Mining Association’s “2003 Coal Producer Survey,” the top 10 coal companies in the United States produced approximately 69% of total domestic coal in 2003. Our principal U.S. competitors are other large coal producers, including Kennecott Energy Company, Arch Coal, Inc., Foundation Coal, CONSOL Energy Inc. and Massey Energy Company, which collectively accounted for approximately 41% of total U.S. coal production in 2003. Major international competitors include Rio Tinto, Anglo-American PLC, and BHP Billiton.

      A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on the coal consumption patterns of the electricity and steel industries in the United States, China, India and elsewhere around the world; the availability, location, cost of transportation and price of competing coal; and other electricity generation and fuel supply sources such as natural gas, oil, nuclear and hydroelectric. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations and technological developments. We compete on the basis of coal quality, delivered price, customer service and support and reliability.

Generation Development

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

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

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

Prairie State Energy Campus

      Our Prairie State Energy Campus is a planned 1,500-megawatt coal-fueled electricity generation project located in Washington County, Illinois. Prairie State would be fueled by 6 million tons of coal each year produced from an adjacent underground mine. During August of 2004, Prairie State signed a letter of intent with Fluor Daniel Illinois, Inc. for engineering, design and construction of Prairie State’s power-related facilities. In January 2005, Prairie State achieved a major milestone when the State of Illinois issued the final air permit for the electric generating station and adjoining coal mine. In February 2005, a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire approximately 47% of the project. This group of investors is comprised of Soyland Power Cooperative, Inc, Kentucky Municipal Power Agency, Wolverine Power Cooperative, Northern Illinois Municipal Power Agency, Indiana Municipal Power Agency and the Missouri Joint Municipal Electric Utility Commission. In February 2005, certain parties filed an appeal with the Environmental Appeals Board in Washington, D.C. challenging the air permit issued by the Illinois Environmental Protection Agency. The appeal must be resolved before construction of the project can begin.

Thoroughbred Energy Campus

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

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

Mustang Energy Project

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

Coalbed Methane

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

Certain Liabilities

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

      Asset Retirement Obligations. Asset retirement obligations primarily represent the present value of future anticipated costs to restore surface lands to productivity levels equal to or greater than pre-mining conditions, as required by the Surface Mining Control and Reclamation Act. Our asset retirement obligations totaled approximately $396.0 million as of December 31, 2004. Expense for the years ended December 31, 2004, 2003 and 2002 was $42.4 million, $31.2 million and $11.0 million, respectively. Our method for accounting for reclamation activities changed on January 1, 2003 as a result of the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.” The effect of the adoption of SFAS No. 143 is discussed in Note 6 to our consolidated financial statements. Total asset retirement obligations as of December 31, 2004 of $396.0 million consisted of $303.7 million related to locations with active mining operations and $92.3 million related to locations that are closed or inactive.

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      Workers’ Compensation. These liabilities represent the actuarial estimates for compensable, work-related injuries (traumatic claims) and occupational disease, primarily black lung disease (pneumoconiosis). The Federal Black Lung Benefits Act requires employers to pay black lung awards to former employees who filed claims after June 1973. These liabilities totaled approximately $268.9 million as of December 31, 2004, $41.4 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $59.2 million, $50.6 million and $55.4 million, respectively.

      Pension-Related Provisions. Pension-related costs represent the actuarially-estimated cost of pension benefits. Annual minimum contributions to the pension plans are determined by consulting actuaries based on the Employee Retirement Income Security Act minimum funding standards and an agreement with the Pension Benefit Guaranty Corporation. Pension-related liabilities totaled approximately $95.8 million as of December 31, 2004, $5.8 million of which was a current liability. Expense for the years ended December 31, 2004, 2003 and 2002 was $28.5 million, $20.7 million and $4.8 million, respectively.

      Retiree Health Care. Consistent with SFAS No. 106, we record a liability representing the estimated cost of providing retiree health care benefits to current retirees and active employees who will retire in the future. Provisions for active employees represent the amount recognized to date, based on their service to date; additional amounts are accrued periodically so that the total estimated liability is accrued when the employee retires.

      A second category of retiree health care obligations represents the liability for future contributions to certain multi-employer health funds. The United Mine Workers of America Combined Fund was created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of out of business companies who were receiving benefits as orphans prior to the 1992 law; no new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan also created by the same federal law in 1992 provides benefits to qualifying retired former employees of companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. A third fund, the 1993 Benefit Fund was established through collective bargaining and provides benefits to qualifying retired former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business, however our liability is limited to our contractual commitment of $0.50 per hour worked.

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

Employees

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

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

United States

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

Australia

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

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

Regulatory Matters — United States

      Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment. These requirements could prove costly and time-consuming and could delay commencing or continuing exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, our activities may be more closely regulated. Such legislation and regulations, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.

      We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements,

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violations during mining operations occur from time to time in the industry. None of the violations to date or the monetary penalties assessed has been material.

Mine Safety and Health

      Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations.

      Most of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. While regulation has a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation.

      Our goal is to achieve excellent safety and health performance. We measure our success in this area primarily through the use of accident frequency rates. We believe that it is our responsibility to our employees to provide a superior safety and health environment. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in establishing safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence. A portion of the annual performance incentives for our operating units is tied to their safety record.

Black Lung

      In the U.S., under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each U.S. coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. Historically, less than 7% of the miners currently seeking federal black lung benefits are awarded these benefits by the federal government. The trust fund is funded by an excise tax on U.S. production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

Coal Industry Retiree Health Benefit Act of 1992

      The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) provides for the funding of health benefits for certain United Mine Workers of America retirees. The Coal Act established the Combined Fund into which “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. The Coal Act also created a second benefit fund for miners who retired between July 21, 1992 and September 30, 1994 and whose former employers are no longer in business. Annual payments made by certain of our subsidiaries under the Coal Act totaled $19.3 million, $20.6 million and $11.1 million, respectively, during the years ended December 31, 2004, 2003 and 2002.

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

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      Our subsidiaries have been billed a retroactive assessment in the amount of $7.4 million for periods prior to October 1, 2003 as well as an increase of $0.7 million for the period from October 1, 2003 through September 30, 2004 as a result of the Social Security Administration’s premium recalculation. These amounts were paid as required by the Combined Fund Trustees, but were paid under protest. If the Combined Fund is able to obtain a court decision that would confirm the applicability of the higher premium rate to our subsidiaries, our subsidiaries will not be able to seek a refund of the premiums paid under protest. In that event, the prospective annual premium would also increase by approximately 12%.

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

Environmental Laws

      We are subject to various federal, state and foreign environmental laws. Some of these laws, discussed below, place many requirements on our coal mining operations. Federal and state regulations require regular monitoring of our mines and other facilities to ensure compliance.

Surface Mining Control and Reclamation Act

      In the U.S., the Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of U.S. surface mining as well as many aspects of deep mining. Mine operators must obtain SMCRA permits and permit renewals for mining operations from the OSM. Where state regulatory agencies have adopted federal mining programs under the act, the state becomes the regulatory authority. Except for Arizona, states in which we have active mining operations have achieved primary control of enforcement through federal authorization. In Arizona, we mine on tribal lands and are regulated by OSM because the tribes do not have SMCRA authorization.

      SMCRA permit provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation.

      The U.S. mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of SMCRA, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land and documents required of the OSM’s Applicant Violator System.

      Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Public notice of the proposed permit is given for a comment period before a permit can be issued. Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine and often take six months to two years to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has the right to comment on and otherwise engage in the permitting process, including through intervention in the courts.

      Before a SMCRA permit is issued, a mine operator must submit a bond or other form of financial security to guarantee the performance of reclamation obligations. The Abandoned Mine Land Fund, which

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is part of SMCRA, requires a fee on all coal produced in the U.S. The proceeds are used to rehabilitate lands mined and left unreclaimed prior to August 3, 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund. The fee, which expired on September 30, 2004 and was subsequently extended to June 30, 2005, is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. It is expected the fee will be renewed, although its purpose and the amount per ton are still to be determined as part of the United States government’s budget process.

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

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

Clean Air Act

      The Clean Air Act and the corresponding state laws that regulate the emissions of materials into the air, affect U.S. coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxide, mercury and other compounds emitted by coal-based electricity generating plants.

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

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

      In December 2003, EPA proposed the Clean Air Interstate Rule, which is designed to help bring the eastern half of the United States into compliance with the National Ambient Air Quality Standards for fine particulates and ozone. The rule became final in March 2005 and will require further reduction of

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sulfur dioxide and nitrogen oxide emissions from electricity generating plants in 28 states. The rules will reduce sulfur dioxide and nitrogen oxide emissions by approximately 70% from current levels by 2015.

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

      The Justice Department, on behalf of the EPA, has filed a number of lawsuits since November 1999, alleging that 12 electricity generators violated the new source review provisions of the Clean Air Act Amendments at power plants in the midwestern and southern United States. Six electricity generators have announced settlements with the Justice Department requiring the installation of additional control equipment on selected generating units, and at least one generator has received a favorable court decision. If the remaining electricity generators are found to be in violation, they could be subject to civil penalties and be required to install the required control equipment or cease operations. Our customers are among the named electricity generators and if found not to be in compliance, our customers could be required to install additional control equipment at the affected plants or they could decide to close some or all of those plants. If our customers decide to install additional pollution control equipment at the affected plants, we have the ability to supply coal from various regions to meet any new coal requirements.

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

      The Clean Air Act set a national goal of the prevention of any future, and the remedying of any existing, impairment of visibility in 156 national parks and wilderness areas across the U.S. Under regulations issued by the EPA in 1999, states are required to consider setting a goal of restoring natural visibility conditions in Class I areas in their states by 2064 and to explain their reasons to the extent they determine not to adopt this goal. The state plans must require the application of “Best Available Retrofit Technology” (“BART”) after 2010 on certain electric generating stations reasonably anticipated to cause or contribute to regional haze which impairs visibility in these areas. The extent and nature of these BART requirements have been the subject of litigation, with EPA expected to issue new regulations in the Spring of 2005. Five western states have elected an option offered by EPA of regulating visibility-impairing emissions through a regional rather than a source-by-source approach. However, this option is currently the subject of litigation, with a court decision expected over the next several months. EPA’s regional haze regulations, once finalized, could cause our customers to install equipment to control sulfur dioxide and nitrogen oxide emissions. The requirement to install control equipment could affect the amount of coal supplied to those customers if they decide to switch to other sources of fuel to lower emission of sulfur dioxide and nitrogen oxide.

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

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

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

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

Clean Water Act

      The Clean Water Act of 1972 affects U.S. coal mining operations by establishing in-stream water quality standards and treatment standards for waste water discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, reporting requirements and performance standards are requirements of NPDES permits that govern the discharge of pollutants into water.

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

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

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

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

Resource Conservation and Recovery Act

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

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

CERCLA (Superfund)

      The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” — commonly known as Superfund) affects U.S. coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault. Under the EPA’s Toxic Release Inventory process, companies are required annually to report listed toxic materials that exceed defined quantities. We report chemicals used in water treatment and ash received for disposal from power generation customers.

Regulatory Matters — Australia

      The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control and noise planning issues such as approvals to expand existing mines or to develop new mines, and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory rehabilitation.

      Mining and exploration in Australia is generally carried on under leases or licenses granted by state governments. Mining leases are typically for an initial term of up to 21 years (but which may be renewed) and contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.

Native Title and Cultural Heritage

      Since 1992, the Australian courts have recognized that native title to lands, as recognized under the laws and customs of the Aboriginal inhabitants of Australia, may have survived the process of European settlement. These developments are supported by the Federal Native Title Act (NTA) which recognizes and protects native title, and under which a national register of native title claims has been established.

      Native title rights do not extend to minerals however, native title rights can be affected by the mining process unless those rights have previously been extinguished. Native title rights can be extinguished either by a valid act of Government (as set out in the NTA) or by the loss of connection between the land and the group of Aboriginal peoples concerned.

      The NTA provides that where native title rights still exist and the mining project will affect those native title rights, it will be necessary to consult with the relevant Aboriginal group and to come to an agreement on issues such as the preservation of sacred or important sites, the employment of members of the group by the mine operator, and the payment of compensation for the effect on native title of the

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mining project. In the absence of agreement with the relevant Aboriginal group, there is an arbitration provision in the NTA.

      There is also federal and state legislation to prevent damage to Aboriginal cultural heritage and archeological sites.

      The NTA and laws protecting Aboriginal cultural heritage and archeological sites have had no impact on our current operations.

Environmental

      The federal system requires an approval to be obtained for any activity which will have a significant impact on a matter of national environmental significance. Matters of national environmental significance include listed endangered species, nuclear actions, World Heritage areas, National Heritage areas and migratory species. An application for such an approval may require public consultation and may be approved, refused or granted subject to conditions. Otherwise, responsibility for environmental regulation in Australia is primarily vested in the states.

      Each state and territory in Australia has its own environmental and planning regime for the development of mines. In addition, each state and territory also has a specific act dealing with mining in particular, regulating the granting of mining licenses and leases. The mining legislation in each state and territory operates concurrently with environmental and planning legislation. The mining legislation governs mining licenses and leases, including the restoration of land, following the completion of mining activities. Apart from the grant of rights to mine itself (which are covered by the mining statutes), all licensing, permitting, consent and approval requirements are contained in the various state and territory environmental and planning statutes.

      The particular provisions of the various state and territory environmental and planning statutes vary depending upon the jurisdiction. Despite variation in details, each state and territory has a system involving at least two major phases. First, obtaining the developmental application and, if that is granted, obtaining the detailed operational pollution control licenses (which authorize emissions up to a maximum level); and second, obtaining pollution control approvals (which authorize the installation of pollution control equipment and devices). In the first regulatory phase, an application to a regulatory authority is filled. The relevant authority will either grant a conditional consent, an unconditional consent, or deny the application based on the details of the application and on any submissions or objections lodged by members of the public. If the developmental application is granted, the detailed pollution control license may then be issued and such license may regulate emissions to the atmosphere; emissions in waters; noise impacts, including impacts from blasting; dust impacts; the generation, handling, storage and transportation of waste; and requirements for the rehabilitation and restoration of land.

      Each state and territory in Australia also has either a specific statute or certain sections in other environmental and planning statutes relating to the contamination of land and vesting powers in the various regulatory authorities in respect of the remediation of contaminated land. Those statutes are based on varying policies — the primary difference between the statutes is that in certain states and territories, liability for remediation is placed upon the occupier of the land, regardless of the culpability of that occupier for the contamination. In other states and territories, primary liability for remediation is placed on the original polluter, whether or not the polluter still occupies the land. If the original polluter cannot itself carry out the remediation, then a number of the statutes contain provisions which enable recovery of the costs of remediation from the polluter as a debt.

      Many of the environmental planning statutes across the states and territories contain “third party” appeal rights in relation, particularly, to the first regulatory phase. This means that any party has a right to take proceedings for a threatened or actual breach of the statute, without first having to establish that any particular interest of that person (other than as a member of the public) stands to be affected by the threatened or actual breach.

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      Accordingly, in most states and territories throughout Australia, mining activities involve a number of regulatory phases. Following exploratory investigations pursuant to a mining lease, the activity proposed to be carried out must be the subject of an application for the activity or development. This phase of the regulatory process, as noted above, usually involves the preparation of extensive documents to constitute the application, addressing all of the environmental impacts of the proposed activity. It also generally involves extensive notification and consultation with other relevant statutory authorities and members of the public. Once a decision is made to allow a mine to be developed by the grant of a development consent, permit or other approval, then a formal mining lease can be obtained under the mining statute. In addition, operational licenses and approvals can then be applied for and obtained in relation to pollution control devices and emissions to the atmosphere, to waters and for noise. The obtaining of licenses and approvals, during the operational phase, generally does not involve any extensive notification or consultation with members of the public, as most of these issues are anticipated to be resolved in the first regulatory phase.

Occupational Health And Safety

      The combined effect of various state and federal statutes requires an employer to ensure that persons employed in a mine are safe from injury by providing a safe working environment and systems of work; safety machinery; equipment, plant and substances; and appropriate information, instruction, training and supervision.

      In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation that deals specifically with the coal mining industry. Mining employers, owners, directors and managers, persons in control of work places, mine managers, supervisors and employees are all subject to these duties.

      It is mandatory for an employer to have insurance coverage in respect of the compensation of injured workers; similar schemes are in effect throughout Australia which are of a no fault nature and which provide for benefits up to a prescribed level. The specific benefits vary from jurisdiction to jurisdiction, but generally include the payment of weekly compensation to an incapacitated employee, together with payment of medical, hospital and related expenses. The injured employee has a right to sue his or her employer for further damages if a case of negligence can be established.

Global Climate Change

      The United States, Australia and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which addresses emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place in the U.S., these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. According to the Department of Energy’s Energy Information Administration, “Emissions of Greenhouse Gases in the United States 2003,” coal accounts for 31% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. In March 2001, President Bush reiterated his opposition to the Kyoto Protocol and further stated that he did not believe that the government should impose mandatory carbon dioxide emission reductions on power plants. In February 2002, President Bush announced a new approach to climate change, confirming the Administration’s opposition to the Kyoto Protocol and proposing voluntary actions to reduce the greenhouse gas intensity of the United States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The President’s climate change initiative calls for a reduction in greenhouse gas intensity of 18% over the next 10 years which is approximately equivalent to the reduction that has occurred over each of the past two decades. Ratification and

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implementation of the Kyoto Protocol by the United States or other actions to limit carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by electric generators.

Additional Information

      We file annual, quarterly and current reports, and our amendments to those reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings without charge through our website, at www.peabodyenergy.com, or the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

      You may also request copies of our filings, at no cost, by telephone at (314) 342-3400 or by mail at: Peabody Energy Corporation, 701 Market Street, Suite 900, St. Louis, Missouri 63101, attention: Investor Relations.

Item 2. Properties.

Coal Reserves

      We had an estimated 9.3 billion tons of proven and probable coal reserves as of December 31, 2004. An estimated 9.1 billion tons of our proven and probable coal reserves are in the United States and 0.2 billion tons are in Australia. Forty-one percent of our reserves, or 3.8 billion tons, are compliance coal and 59% are non-compliance coal. We own approximately 43% of these reserves and lease property containing the remaining 57%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.

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

			Proven and Probable
			Reserves as of
			December 31, 2004(1)
			Owned		Leased		Total
Operating Regions		Locations	Tons		Tons		Tons
			(Tons in millions)
Powder River Basin		Wyoming and Montana		68		3,081		3,149
Southwest		Arizona and New Mexico		625		391		1,016
Colorado		Colorado		43		237		280
Appalachia		West Virginia, Ohio		250		401		651
Midwest		Illinois, Indiana and Kentucky		3,038		927		3,965
Australia		Queensland		—		218		218
	Total Proven and Probable Coal Reserves			4,024		5,255		9,279

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

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

      Proven (Measured) Reserves — Reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so close and the geographic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

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      Probable (Indicated) Reserves — Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measure) reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

      Our estimates of proven and probable coal reserves are established within these guidelines. Proven reserves require the coal to lie within one-quarter mile of a valid point of measure or point of observation, such as exploratory drill holes or previously mined areas. Estimates of probable reserves may lie more than one-quarter mile, but less than three-quarters of a mile, from a point of thickness measurement. Estimates within the proven category have the highest degree of assurance, while estimates within the probable category have only a moderate degree of geologic assurance. Further exploration is necessary to place probable reserves into the proven reserve category. Our active properties generally have a much higher degree of reliability because of increased drilling density. Active surface reserves generally have points of observation as close as 330 feet to 660 feet.

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

      Our reserve estimates are predicated on information obtained from our ongoing drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole database from which the depth, thickness and, where core drilling is used, the quality of the coal are determined. The density of the drill pattern determines whether the reserves will be classified as proven or probable. The reserve estimates are then input into our computerized land management system, which overlays the geological data with data on ownership or control of the mineral and surface interests to determine the extent of our reserves in a given area. The land management system contains reserve information, including the quantity and quality (where available) of reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserve and land holdings. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors.

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

      We periodically engage independent mining and geological consultants to review estimates of our coal reserves. The most recent of these reviews, which was completed in April 2003, included a review of the procedures used by us to prepare our internal estimates, verification of the accuracy of selected property reserve estimates and retabulation of reserve groups according to standard classifications of reliability. This study confirmed that we controlled approximately 9.1 billion tons of proven and probable reserves as of December 31, 2002. After adjusting for acquisitions, divestitures, production and estimate refinements (through additional drilling and exploration) through December 31, 2004, proven and probable reserves totaled 9.3 billion tons.

      With respect to the accuracy of our reserve estimates, our experience is that recovered reserves are within plus or minus 10% of our proven and probable estimates, on average, and our probable estimates are generally within the same statistical degree of accuracy when the necessary drilling is completed to

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move reserves from the probable to the proven classification. On a regional basis, the expected degree of variance from reserve estimate to tons produced is lower in the Powder River Basin, Southwest, and Illinois Basin due to the continuity of the coal seams as confirmed by the mining history. Appalachia, however, has a higher degree of risk due to the mountainous nature of the topography. Our recovered reserves in Appalachia are less predictable and may vary by an additional one to two percent above the threshold discussed above.

      We have numerous federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2004, we leased 11,922 acres of federal land in Colorado, 11,254 acres in Montana and 36,964 acres in Wyoming, for a total of 60,140 nationwide.

      Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 65,000 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments.

      Private coal leases normally have terms of between 10 and 20 years and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments.

      The terms of our private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or these leases may be renewed periodically. With a portfolio of approximately 9.3 billion tons, we believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our significant reserve holdings is one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.

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

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      The following chart provides a summary, by mining complex, of production for the years ended December 31, 2004 and 2003 and 2002, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities. The chart below breaks down our assigned proven and probable reserves into the mining complexes located in a particular geographic region, and does not indicate the legal entity that owns or controls the reserves.

PRODUCTION AND ASSIGNED RESERVES(1)

(Tons in millions)

											Sulfur Content(2)								As of December 31, 2004
			Production
											<1.2 lbs.		>1.2 to 2.5 lbs.		>2.5 lbs.		As		Assigned
Geographic			Year Ended		Year Ended		Year Ended				Sulfur Dioxide		Sulfur Dioxide		Sulfur Dioxide		Received		Proven and
Region/ Mining			Dec. 31,		Dec. 31,		Dec. 31,		Type of		per		per		per		Btu per		Probable
Complex			2004		2003		2002		Coal		Million Btu		Million Btu		Million Btu		Pound(3)		Reserves		Owned		Leased		Surface		Underground
Appalachia:
	Federal			4.9		4.1		5.0		Steam		—		—		28		13,300		28		2		26		—		28
	Big Mountain			1.9		1.5		1.0		Steam		2		22		1		12,800		25		—		25		—		25
	Harris			3.0		3.0		3.2		Steam/Met.		6		4		—		13,600		10		—		10		—		10
	Rocklick			2.0		2.5		3.4		Steam/Met.		7		12		—		13,200		19		—		19		6		13
	Rivers Edge			2.6		2.4		2.4		Steam/Met.		6		2		1		13,500		9		—		9		—		9
		Total		14.4		13.5		15.0				21		40		30				91		2		89		6		85
Midwest:
	Camps/ Highland			3.2		1.7		3.0		Steam		—		—		128		11,300		128		31		97		—		128
	Midwest Operating Unit			—		—		1.4		Steam		—		—		8		11,100		8		8		—		1		7
	Patriot			4.1		4.2		2.7		Steam		—		—		36		10,900		36		—		36		5		31
	Air Quality			1.8		1.9		1.8		Steam		—		28		29		10,600		57		3		54		—		57
	Riola/ Vermilion Grove			2.3		1.8		1.9		Steam		—		—		23		10,500		23		—		23		—		23
	Miller Creek			0.9		0.8		0.8		Steam		—		1		2		11,600		3		—		3		3		—
	Francisco Surface			2.1		2.5		2.4		Steam		—		—		10		10,500		10		2		8		10		—
	Francisco Underground			0.9		—		—				—		—		15		10,700		15		2		13		—		15
	Farmersburg			4.2		4.3		4.1		Steam		—		—		19		10,600		19		10		9		19		—
	Somerville Central			3.2		3.3		3.1		Steam		—		—		11		10,300		11		7		4		11		—
	Somerville			4.1		4.0		3.9		Steam		—		—		13		10,000		13		6		7		13		—
	Viking			1.5		1.4		1.3		Steam		—		2		10		10,700		12		—		12		12		—
	Cottage Grove			2.7		2.5		2.0		Steam		—		—		10		10,400		10		6		4		10		—
	Willow Lake			3.4		2.8		2.4		Steam		—		—		43		11,000		43		35		8		—		43
	Columbia			—		—		0.4		Steam		—		—		—		N/A		—		—		—		—		—
	Dodge Hill			1.2		—		—		Steam		—		—		14		11,700		14		6		8		—		14
		Total		35.6		31.2		31.2				—		31		371				402		116		286		84		318
Powder River Basin:
	Big Sky			—		2.6		2.8		Steam		—		11		1		8,800		12		—		12		12		—
	North Antelope/ Rochelle			82.5		80.1		74.8		Steam		1,299		—		32		8,800		1,331		—		1,331		1,331		—
	Caballo			26.5		22.8		26.0		Steam		713		32		—		8,700		745		—		745		745		—
	Rawhide			6.9		3.6		3.5		Steam		209		67		8		8,600		284		—		284		284		—
		Total		115.9		109.1		107.1				2,221		110		41				2,372		—		2,372		2,372		—
Southwest
	Black Mesa			4.8		4.4		4.6		Steam		17		1		—		10,900		18		—		18		18		—
	Kayenta			8.2		7.8		8.2		Steam		203		80		2		11,000		285		—		285		285		—
	Lee Ranch			5.8		6.9		6.4		Steam		21		132		12		10,000		165		89		76		165		—
	Twentymile			6.4		—		—		Steam		64		—		13		10,700		77		2		75		—		77
	Seneca			1.5		1.5		1.8		Steam		8		—		—		10,200		8		—		8		8		—
		Total		26.7		20.6		21.0				313		213		27				553		91		462		476		77
Australia
	North Goonyella			1.5		—		—		Met		51		—		—		10,830		51		—		51		—		51
	Eaglefield			0.2		—		—		Met		6		—		—		10,300		6		—		6		6		—
	Burton			3.2		—		—		Steam/Met		18		—		—		9,880		18		—		18		18		—
	Wilkie Creek			1.4		1.3		0.4		Steam		22		—		—		8,710		22		—		22		22		—
		Total		6.3		1.3		0.4				97		—		—				97		—		97		46		51
Total				198.9		175.7		174.7				2,652		394		469				3,515		209		3,306		2,984		531

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      The following chart provides a summary of the amount of our proven and probable coal reserves in each U.S. state and Australia, the predominant type of coal mined in the applicable location, our property interest in the reserves and other characteristics of the facilities. The chart below breaks down our proven and probable reserves into geographic regions, and does not indicate the legal entity that owns or controls the reserves.

ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES

As of December 31, 2004

(Tons in millions)

														Sulfur Content(2)
														<1.2 lbs.		>1.2 to 2.5 lbs.		>2.5 lbs.		As
		Total Tons				Proven and								Sulfur Dioxide		Sulfur Dioxide		Sulfur Dioxide		Received		Reserve Control				Mining Method
Coal Seam						Probable						Type of		per		per		per		Btu per
Location		Assigned		Unassigned		Reserves		Proven		Probable		Coal		Million Btu		Million Btu		Million Btu		pound(3)		Owned		Leased		Surface		Underground
Northern Appalachia:
	Ohio		—		40		40		28		12		Steam		—		—		40		11,100		30		10		—		40
	West Virginia		28		220		248		88		160		Steam		—		117		131		12,700		166		82		—		248
	Northern Appalachia		28		260		288		116		172				—		117		171				196		92		—		288
Central Appalachia:
	West Virginia		63		300		363		242		121		Steam/Met.		145		134		84		13,200		54		309		16		347
	Central Appalachia		63		300		363		242		121				145		134		84				54		309		16		347
Midwest:
	Illinois		77		2,325		2,402		1,130		1,272		Steam		5		65		2,332		10,300		2,206		196		74		2,328
	Indiana		140		342		482		344		138		Steam		—		39		443		10,500		310		172		209		273
	Kentucky		185		896		1,081		645		436		Steam		—		1		1,080		10,900		522		559		140		941
	Midwest		402		3,563		3,965		2,119		1,846				5		105		3,855				3,038		927		423		3,542
Powder River Basin:
	Montana		12		151		163		159		4		Steam		15		127		21		8,600		67		96		163		—
	Wyoming		2,360		626		2,986		2,906		80		Steam		2,772		102		112		8,700		1		2,985		2,986		—
	Powder River Basin		2,372		777		3,149		3,065		84				2,787		229		133				68		3,081		3,149		—
Southwest:
	Arizona		303		—		303		303		—		Steam		220		81		2		11,000		—		303		303		—
	Colorado		85		195		280		223		57		Steam		163		—		117		10,700		43		237		9		271
	New Mexico		165		548		713		452		261		Steam		260		367		86		8,700		625		88		696		17
	Southwest		553		743		1,296		978		318				643		448		205				668		628		1,008		288
Australia
	Queensland		97		121		218		132		86		Steam/Met.		218		—		0		10,130		—		218		167		51
Total Proven and Probable			3,515		5,764		9,279		6,652		2,627				3,798		1,033		4,448				4,024		5,255		4,763		4,516

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(1)	Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2004. Unassigned reserves represent coal at suspended locations and coal that has not been committed. These reserves would require new mine development, mining equipment or plant facilities before operations could begin on the property.
(2)	Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal.
(3)	As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The following table reflects the average moisture content used in the determination of as-received Btu by region:

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

Resource Development

      We hold approximately 9.3 billion tons of proven and probable coal reserves and interest in approximately 400,000 acres of surface property. Our Resource Development group constantly reviews these reserves for opportunities to generate revenues through the sale of non-strategic coal reserves and surface land. In addition, we generate revenue through royalties from coal reserves and oil and gas rights leased to third parties, coalbed methane production and farm income from surface land under third party contracts.

Item 3.      Legal Proceedings.

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

Navajo Nation

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

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

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

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

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

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

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

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

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

Navajo and Mohave Generating Stations — Legal Fees and Costs

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

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

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

West Virginia Flooding Litigation

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

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

Citizens Power

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

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

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

Environmental

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

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

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

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

Oklahoma Lead Litigation

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

33

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

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

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

Item 4. Submission of Matters to a Vote of Security Holders.

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

Executive Officers of the Company

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

Name	Age		Position
Irl F. Engelhardt		58	Chairman, Chief Executive Officer and Director
Gregory H. Boyce		50	President and Chief Operating Officer
Sharon D. Fiehler		48	Executive Vice President — Human Resources and Administration
Richard A. Navarre		44	Executive Vice President and Chief Financial Officer
Fredrick D. Palmer		60	Senior Vice President — Government Relations
Roger B. Walcott, Jr.		48	Executive Vice President — Corporate Development
Richard M. Whiting		50	Executive Vice President — Sales, Marketing and Trading
Jeffery L. Klinger		57	Vice President — General Counsel and Secretary

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

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

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

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

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

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

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

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

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

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

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

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

		High		Low
2003
	First Quarter	$	14.80	$	12.26
	Second Quarter		17.56		13.36
	Third Quarter		16.82		14.31
	Fourth Quarter		21.50		15.68
2004
	First Quarter	$	25.30	$	18.21
	Second Quarter		28.01		20.88
	Third Quarter		30.22		25.37
	Fourth Quarter		43.40		27.01

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Dividend Policy

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

Stock Split

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

Item 6. Selected Financial Data.

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

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

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

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

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

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

37

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

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

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

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

												Nine Months
			Year Ended			Year Ended			Year Ended			Ended			Year Ended
			December 31,			December 31,			December 31,			December 31,			March 31,
			2004			2003			2002			2001			2001
			(Dollars in thousands, except share and per share data)
Results of Operations Data
Revenues
	Sales		$	3,545,027		$	2,729,323		$	2,630,371		$	1,869,321		$	2,534,964
	Other revenues			86,555			85,973			89,267			57,029			94,487
		Total revenues		3,631,582			2,815,296			2,719,638			1,926,350			2,629,451
Costs and expenses
	Operating costs and expenses			2,969,209			2,335,800			2,225,344			1,588,596			2,123,526
	Depreciation, depletion and amortization			270,159			234,336			232,413			171,020			240,968
	Asset retirement obligation expense			42,387			31,156			—			—			—
	Selling and administrative expenses			143,025			108,525			101,416			73,553			99,267
	Gain on sale of Australian operations			—			—			—			—			(171,735	)
	Other operating income:
		Net gain on disposal of assets		(23,829	)		(32,772	)		(15,763	)		(22,160	)		(5,737	)
		(Income) loss from equity affiliates		(16,067	)		(6,535	)		2,540			(190	)		1,323
Operating profit				246,698			144,786			173,688			115,531			341,839
	Interest expense			96,793			98,540			102,458			88,686			197,686
	Early debt extinguishment costs			1,751			53,513			—			38,628			11,025
	Interest income			(4,917	)		(4,086	)		(7,574	)		(2,155	)		(8,741	)
Income (loss) before income taxes and minority interests				153,071			(3,181	)		78,804			(9,628	)		141,869
	Income tax provision (benefit)			(26,437	)		(47,708	)		(40,007	)		(7,193	)		40,210
	Minority interests			1,282			3,035			13,292			7,248			7,524
Income (loss) from continuing operations				178,226			41,492			105,519			(9,683	)		94,135
	Income (loss) from discontinued operations			(2,839	)		—			—			—			12,925
Income (loss) before accounting changes				175,387			41,492			105,519			(9,683	)		107,060
	Cumulative effect of accounting changes			—			(10,144	)		—			—			—
Net income (loss)			$	175,387		$	31,348		$	105,519		$	(9,683	)	$	107,060

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											Nine Months
		Year Ended			Year Ended			Year Ended			Ended			Year Ended
		December 31,			December 31,			December 31,			December 31,			March 31,
		2004			2003			2002			2001			2001
		(Dollars in thousands, except share and per share data)
Basic earnings (loss) per share from continuing operations(1)		$	1.43		$	0.39		$	1.01		$	(0.10	)
Diluted earnings (loss) per share from continuing operations(1)		$	1.40		$	0.38		$	0.98		$	(0.10	)
Basic and diluted earnings per Class A/B share from continuing operations(1)														$	1.36
Weighted average shares used in calculating basic earnings (loss) per share(1)			124,366,372			106,819,042			104,331,470			97,492,888			55,049,252
Weighted average shares used in calculating diluted earnings (loss) per share(1)			127,406,316			109,671,256			107,643,520			97,492,888			55,049,252
Dividends declared per share		$	0.26		$	0.23		$	0.20		$	0.10			—
Other Data
Tons sold (in millions)			227.2			203.2			197.9			146.5			192.4
Net cash provided by (used in):
	Operating activities	$	283,760		$	188,861		$	234,804		$	99,492		$	111,980
	Investing activities		(705,030	)		(192,280	)		(144,078	)		(172,989	)		388,462
	Financing activities		693,404			48,598			(58,398	)		49,396			(503,337	)
Adjusted EBITDA(2)			559,244			410,278			406,101			286,551			582,807
Capital expenditures			266,597			156,443			208,562			194,246			151,358
Balance Sheet Data (at period end)
	Total assets	$	6,178,592		$	5,280,265		$	5,125,949		$	5,150,902		$	5,209,487
	Total debt		1,424,965			1,196,539			1,029,211			1,031,067			1,405,621
	Total stockholders’ equity		1,724,592			1,132,057			1,081,138			1,035,472			631,238

(1)

All per share and share amounts reflect the two-for-one stock split effected on March 30, 2005 for shareholders of record on March 16, 2005.

(2)

Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

      Adjusted EBITDA is calculated as follows, in thousands (unaudited):

										Nine Months
	Year Ended			Year Ended			Year Ended			Ended			Year Ended
	December 31,			December 31,			December 31,			December 31,			March 31,
	2004			2003			2002			2001			2001
Income (loss) from continuing operations	$	178,226		$	41,492		$	105,519		$	(9,683	)	$	94,135
Income tax provision (benefit)		(26,437	)		(47,708	)		(40,007	)		(7,193	)		40,210
Depreciation, depletion and amortization		270,159			234,336			232,413			171,020			240,968
Asset retirement obligation expense		42,387			31,156			—			—			—
Interest expense		96,793			98,540			102,458			88,686			197,686
Early debt extinguishment costs		1,751			53,513			—			38,628			11,025
Interest income		(4,917	)		(4,086	)		(7,574	)		(2,155	)		(8,741	)
Minority interests		1,282			3,035			13,292			7,248			7,524
Adjusted EBITDA	$	559,244		$	410,278		$	406,101		$	286,551		$	582,807

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

Overview

      We are the largest private sector coal company in the world, with majority interests in 32 active coal operations located throughout all major U.S. coal producing regions and internationally in Australia. In 2004, we sold 227.2 million tons of coal that accounted for an estimated 20% of all U.S. coal sales, and were more than 85% greater than the sales of our closest competitor. The Energy Information Administration estimates that 1.1 billion tons of coal were consumed in the United States in 2004 and expects domestic consumption of coal by electricity generators to grow at a rate of 1.6% per year through 2025. Coal-fueled generation is used in most cases to meet baseload electricity requirements, and coal use generally grows at the pace of electricity growth. In 2004, coal’s share of electricity generation was approximately 52%, which was more than all other fuels used to generate electricity combined.

      Our primary customers are U.S. utilities, which accounted for 90% of our sales in 2004. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2004, approximately 90% of our sales were under long-term contracts. As of December 31, 2004, we had priced more than 95% of our expected 2005 production. As discussed more fully in “Risks Relating to Our Company,” our results of operations in the near term can be negatively impacted by poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations, and by the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections.

      We conduct business through four principal operating segments: Eastern U.S. Mining, Western U.S. Mining, Australian Mining, and Trading and Brokerage. Our Eastern U.S. Mining operations consist of our Appalachia and Midwest operations, and our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations. The principal business of the Western U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities. The principal business of the Eastern U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities, as well as the mining of some metallurgical coal, sold to steel and coke producers.

      Geologically, Eastern operations mine bituminous and Western operations mine bituminous and subbituminous coal deposits. Our Western U.S. Mining operations are characterized by predominantly surface extraction processes, lower sulfur content and Btu of coal, and higher customer transportation costs (due to longer shipping distances). Our Eastern U.S. Mining operations are characterized by predominantly underground extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances).

      Our Australian Mining operations consist of our Wilkie Creek Mine, two additional mines acquired in April 2004, Burton and North Goonyella, and our recently opened Eaglefield Mine, which is a surface operation adjacent to, and fulfilling contract tonnages in conjunction with, the North Goonyella underground mine. Australian Mining operations are characterized by both surface and underground extraction processes, mining low-sulfur, high Btu coal sold to an international customer base. Primarily metallurgical coal is produced from our Australian mines. Metallurgical coal is approximately 4% of our total sales volume and approximately 3% of U.S. sales volume. In December 2004, we purchased a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine produces approximately 7 million tons of steam coal annually for export to the United States and Europe. Each of our mining operations is described in Item 1 of this report.

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      In addition to our mining operations, which comprised 87% of revenues in 2004, we also generate revenues from brokering and trading coal (12% of revenues), and by creating value from our vast natural resource position by selling non-core land holdings and mineral interests to generate additional cash flows.

      We are developing coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. These projects involve mine-mouth generating plants using our surface lands and coal reserves. Three projects are currently being evaluated — the 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky, the 1,500 megawatt Prairie State Energy Campus in Washington County, Illinois and the 300 megawatt Mustang Energy Project near Grants, N.M. During 2004, one of our subsidiaries and Fluor Daniel Illinois, Inc. signed a letter of intent for engineering, design and construction of Prairie State’s power-related facilities. In January 2005, we achieved a major milestone in the development of the Prairie State Energy Campus when the state of Illinois issued an air permit for the electric generating station and coal mine campus. In January 2005, a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire 47% of the project. In February 2005, certain parties filed an appeal with the Environmental Appeals Board in Washington, D.C. challenging the air permit issued by the Illinois Environmental Protection Agency. The appeal must be resolved before construction of the project can begin. In October 2004, our Mustang Energy Project was awarded a $19.7 million Clean Coal Power Initiative Grant from the Department of Energy to demonstrate technology to achieve ultra low emissions. The plants are expected to be operational following a four-year construction phase, which would begin when the company has completed all necessary permitting, selected partners, secured financing and sold the majority of the output of the plant. These plants will not be operational until at least 2010.

Results of Operations

Adjusted EBITDA

      The discussion of our results of operations below includes references to, and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under generally accepted accounting principles, in Note 26 to our consolidated financial statements.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

Summary

      Our 2004 revenues of $3.63 billion was an increase of 29.0% over prior year, led by improved pricing and an industry-record sales volume of 227.2 million tons. Mines acquired in April 2004 contributed $335.0 million of sales and 11.0 million tons to our current year results.

      Segment Adjusted EBITDA for the full year totaled $773.9 million, a 28.1% increase over $604.0 million in the prior year. Segment Adjusted EBITDA was higher in the current year due to increased sales volumes and price.

      Net income in 2004 was $175.4 million, or $1.38 per share, an increase of 459.5% over 2003 net income of $31.3 million, or $0.29 per share. The increase in net income was primarily due to improved operating results and acquisitions in 2004, and the impact in 2003 of $53.5 million in pretax early debt extinguishment charges and a $10.1 million after tax charge for the cumulative effect of accounting changes.

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Revenues

						Increase (Decrease)
		Year Ended		Year Ended		to Revenues
		December 31,		December 31,
		2004		2003		$		%
		(dollars in thousands)
Sales		$	3,545,027	$	2,729,323	$	815,704		29.9	%
Other revenues			86,555		85,973		582		0.7	%
	Total revenues	$	3,631,582	$	2,815,296	$	816,286		29.0	%

      Revenues increased by 29.0%, or $816.3 million, over the prior year. The acquisition of three mines in April 2004 contributed $335.0 million of total revenue and 11.0 million tons during the year. Excluding revenues from current year acquisitions, U.S. Mining revenues increased $375.4 million, and revenues from our brokerage operations increased $110.9 million on higher pricing and volume worldwide. Our average sales price per ton increased 14.6% during 2004 due to increased overall demand, which has driven pricing higher, most notably in Appalachia, and a change in sales mix. The sales mix has benefited from the increase in sales from the Australian segment, where per ton prices are higher than in domestic markets. In addition to geographic mix changes, our 2004 revenues included a greater proportion of higher priced metallurgical coal sales (our highest value product). Pricing of metallurgical coal has been responding to increased international demand for the product. We sell metallurgical coal from our Eastern U.S. and Australian Mining operations. Other revenues were relatively unchanged from prior year.

      In our Eastern U.S. Mining operations, revenues increased $302.8 million, or 25.3%, as a result of higher pricing and volumes from strong steam and metallurgical coal demand. Production increases at most eastern mines more than offset lower than expected production at certain of our mines and contract sources as a result of geologic difficulties, congestion-related shipping delays and hurricane-related production disruptions and delays. Appalachian revenues led the Eastern U.S. increase, benefiting the most from price increases while also increasing production and sales volumes. Revenues in Appalachia increased $188.1 million, or 37.0%, while in the Midwest, revenues increased by $114.7 million, or 16.6%. Revenues in our Western U.S. Mining operations increased $171.6 million, or 14.0% on both increased volumes and prices. However, the primary driver of increased revenues in the West was a 12.6 million ton increase in sales volume. Growth in volumes were primarily in the Powder River Basin operations, where revenues were up $58.6 million, or 7.5%, and from the addition of the Twentymile Mine in April which added $99.0 million to sales. Powder River Basin production and sales volumes were up as a result of stronger demand for the mines’ low-sulfur product, which overcame difficulties with rail service, downtime at the North Antelope Rochelle Mine to upgrade the loading facility and poor weather, which impaired production early in the year. Revenues in our Australian Mining operations increased $241.5 million compared to 2003 due primarily to the acquisition of two operating mines during 2004 and benefiting from higher overall pricing for our products there.

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Segment Adjusted EBITDA

      Our total segment Adjusted EBITDA of $773.9 million for the full year was $169.9 million higher than 2003 segment Adjusted EBITDA of $604.0 million, and was composed of the following:

						Increase (Decrease) to
						Segment Adjusted
		Year Ended		Year Ended		EBITDA
		December 31,		December 31,
		2004		2003		$			%
		(Dollars in thousands)
Western U.S. Mining		$	402,131	$	357,021	$	45,110			12.6	%
Eastern U.S. Mining			280,357		198,964		81,393			40.9	%
Australian Mining			50,372		2,225		48,147			2163.9	%
Trading and Brokerage			41,039		45,828		(4,789	)		(10.4	)%
	Total Segment Adjusted EBITDA	$	773,899	$	604,038	$	169,861			28.1	%

      Western U.S. Mining operations Adjusted EBITDA increased $45.1 million during 2004, margin per ton increased $0.07, or 2.5%, while sales volume increased 12.6 million tons. The April 2004 acquisition of the Twentymile Mine contributed to $31.2 million of Adjusted EBITDA increase and sales volume, adding 6.2 million tons of the volume increase in 2004. An increase of $20.0 million in Adjusted EBITDA in the Powder River Basin, due primarily to increases in sales volume, contributed most of the remaining improvement in the West. Our Powder River Basin operations continued to benefit from strong demand, leading to record shipping levels which overcame the effects of a planned outage earlier in the year to increase throughput at our North Antelope Rochelle Mine, rail service problems throughout the year and the shutdown of our Big Sky Mine at the end of 2003. Results in the Southwest approximated prior year levels, as pricing improvements generally offset higher costs for fuel and explosives.

      Adjusted EBITDA from our Eastern U.S. Mining operations increased $81.4 million, or 40.9%, compared to prior year due to an increase in margin per ton of $1.11, or 25.8%, and an increase in volume of 5.4 million tons, or 11.7%. Improved pricing led to increased margins in our Eastern operations, despite higher processing costs incurred to upgrade from steam to metallurgical quality, the cost of substitute coal purchases to enable production to be sold in higher-value metallurgical coal markets, hurricane-related transportation and production interruption and increased fuel and steel costs. Appalachia operations drove the improvement in the East with a $101.5 million increase in Adjusted EBITDA. The Appalachia region benefited from strong demand driven pricing and volume and increased higher-priced metallurgical coal sales. Our operations in Appalachia also benefited during the current year from $21.0 million in insurance recoveries and a $9.6 million increase in earnings from our equity interest in a joint venture, more than offsetting higher costs due to equipment and geologic difficulties at a mine in Kentucky. Adjusted EBITDA in the Midwest was $20.1 million less than prior year as increased production and sales, as well as higher overall sales prices, did not overcome poor geologic conditions at certain mines, higher equipment repair costs and higher fuel and steel costs.

      Our Australian Mining operations Adjusted EBITDA increased $48.1 million in the current year. Our acquisition of two mines in April 2004 added 4.8 million tons and increased overall sales volume to 6.1 million tons. Most of the increase in sales tonnage was in higher margin metallurgical coal sales, driving a margin per ton increase of $6.55, or nearly 400%. The current year acquisitions contributed $43.1 million of Adjusted EBITDA in 2004.

      Trading and Brokerage Adjusted EBITDA decreased $4.8 million from the prior year primarily due to higher brokerage results in the prior year. Adjusted EBITDA from trading activities increased over prior year due to improved pricing on our long position.

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Reconciliation of Segment Adjusted EBITDA to Income (Loss) Before Income Taxes and Minority Interests

							Increase (Decrease)
	Year Ended			Year Ended			to Income
	December 31,			December 31,
	2004			2003			$			%
	(Dollars in thousands)
Total Segment Adjusted EBITDA	$	773,899		$	604,038		$	169,861			28.1	%
Corporate and Other Adjusted EBITDA		(214,655	)		(193,760	)		(20,895	)		(10.8	)%
Depreciation, depletion and amortization		(270,159	)		(234,336	)		(35,823	)		(15.3	)%
Asset retirement obligation expense		(42,387	)		(31,156	)		(11,231	)		(36.0	)%
Early debt extinguishment costs		(1,751	)		(53,513	)		51,762			96.7	%
Interest expense		(96,793	)		(98,540	)		1,747			1.8	%
Interest income		4,917			4,086			831			20.3	%
Income (loss) before income taxes and minority interests	$	153,071		$	(3,181	)	$	156,252			n/a

      Total segment Adjusted EBITDA of $773.9 million for the current year is compared with $604.0 million from the prior year in the discussion above. Corporate and Other Adjusted EBITDA results include selling and administrative expenses, net gains on asset disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development, resource management and our Venezuelan mining operations. The increase in Corporate and Other Adjusted EBITDA (net expense) in 2004 compared to 2003 was primarily due to:

•  net gains on asset sales were $8.8 million higher in the prior year. The prior year includes gains of $18.8 million on the sale of land, coal reserves and oil and gas rights, $6.4 million of other asset disposals, and $7.6 million from the sale of 1.15 million units of Penn Virginia Resource Partners LP (“Penn Virginia”), while the current year includes gains of only $8.0 million from other asset disposals and a $15.8 million gain from the sale of a total of 0.775 million units of Penn Virginia in two separate transactions;

•  increased costs in 2004 for generation development ($5.3 million) related to the further development of the Prairie State and Thoroughbred Energy campuses;

•  higher selling and administrative expenses of $34.5 million, primarily associated with higher long-term incentive costs ($17.8 million), pensions, an increase in outside services costs (including costs related to compliance with the Sarbanes-Oxley Act) and the impact of current year acquisitions; and

•  a $2.9 million increase in our accrual for future environmental obligations.

      These increased costs compared to prior year were partially offset by:

•  lower costs ($29.0 million) in 2004 associated with past mining obligations, primarily lower retiree health care costs from the passage of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 and lower closed and suspended mine spending;

•  contributions ($1.2 million) to Adjusted EBITDA from the December 2004 acquisition of a 25.5% interest in the Paso Diablo Mine in Venezuela.

      Depreciation, depletion and amortization increased $35.8 million during 2004 due to higher volume and acquisitions. Asset retirement obligation expense increased $11.2 million during the year due to increased or accelerated reclamation work at certain closed mine sites and the acquisition of additional mining operations during the year.

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      Debt extinguishment costs were $51.8 million higher in the prior year due to the significant prepayment premiums associated with the March 2003 refinancing, discussed in Note 13 to our consolidated financial statements.

Net Income

								Increase (Decrease)
		Year Ended			Year Ended			to Income
		December 31,			December 31,
		2004			2003			$			%
		(Dollars in thousands)
Income (loss) before income taxes and minority interests		$	153,071		$	(3,181	)	$	156,252			n/a
	Income tax benefit		26,437			47,708			(21,271	)		(44.6	)%
	Minority interests		(1,282	)		(3,035	)		1,753			57.8	%
Income from continuing operations			178,226			41,492			136,734			329.5	%
	Loss from discontinued operations		(2,839	)		—			(2,839	)		n/a
Income before accounting changes			175,387			41,492			133,895			322.7	%
	Cumulative effect of accounting changes		—			(10,144	)		10,144			n/a
Net income		$	175,387		$	31,348		$	144,039			459.5	%

      The increase of $144.0 million in net income from 2003 to 2004 was due to the increase in income (loss) before income taxes and minority interests ($156.3 million) discussed above and the impacts of the following:

•  a $21.3 million lower tax benefit in 2004. The tax benefit recorded in 2004 differs from the benefit in 2003 primarily as a result of significantly higher pre-tax income, partially offset by the higher permanent benefit of percentage depletion. The 2004 tax benefit also included a net $25.9 million reduction in the valuation allowance on those net operating loss carry-forwards (“NOL’s”) and alternative minimum tax credits. We evaluated and assessed the expected near-term utilization of NOL’s, book and taxable income trends, available tax strategies and the overall deferred tax position to determine the amount and timing of valuation allowance adjustments;

•  a $2.8 million loss, net of tax, from discontinued operations in the current year due to costs to resolve a contract indemnification claim related to our former Citizens Power subsidiary;

•  lower minority interests during 2004 due to the acquisition in April 2003 of the remaining 18.3% of Black Beauty Coal Company; and

•  a charge in 2003 for the cumulative effect of accounting changes, net of income taxes, of $10.1 million, relating to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations,” the change in method of amortization of actuarial gains and losses related to net periodic postretirement benefit costs and the effect of the recession of EITF No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” as discussed in Note 6 to the consolidated financial statements.

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

Summary

      In 2003, our revenues rose to $2.82 billion, a 3.5% increase over the prior year, led by industry-record sales volume of 203.2 million tons. Our sales volume in the second-half of 2003 was 8.6% stronger than the first half as generators completed upgrades to emission control equipment and increased coal consumption to meet growing industrial demand.

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      Our segment Adjusted EBITDA totaled $604.0 million for the full year, compared with $616.3 million in the prior year. Excluding $37.1 million in contract settlements from Western U.S. Mining’s 2002 results, segment Adjusted EBITDA improved $24.8 million. The improvement was due to higher Western U.S. Mining and Trading and Brokerage results, which more than offset a decrease in Eastern U.S. Mining Adjusted EBITDA results.

      Net income in 2003 totaled $31.3 million, or $0.29 per share, compared with $105.5 million, or $0.98 per share in 2002. The decrease in net income was due to higher asset retirement obligation costs resulting from the adoption of SFAS No. 143, combined with $53.5 million in early debt extinguishment charges and a $10.1 million charge for the cumulative effect of accounting changes, both recorded in the first half of 2003.

Revenues

						Increase (Decrease)
		Year Ended		Year Ended		to Revenues
		December 31,		December 31,
		2003		2002		$			%
		(Dollars in thousands)
Sales		$	2,729,323	$	2,630,371	$	98,952			3.8	%
Other revenues			85,973		89,267		(3,294	)		(3.7	)%
	Total revenues	$	2,815,296	$	2,719,638	$	95,658			3.5	%

      Overall, our revenues increased 3.5% over the prior year. Sales increased 3.8% due to a 5.2% sales volume improvement in 2003. Volume from our brokerage operations increased substantially in 2003 due to improved domestic and export demand, and the inclusion of a full year of sales from the Australian mining operations (Wilkie Creek) acquired in August 2002 also contributed to the volume increase. In the West, revenues were essentially flat compared with the prior year, as record volumes due to strong second-half demand in the Powder River Basin were offset by lower volumes in the Southwest as a result of customer outages due to major power plant repairs in the first half of the year. In the East, revenues declined 5.4% as slightly higher volumes in the Midwest to meet higher demand were more than offset by lower production in Appalachia due to poor weather in both the first and second quarters, and lower production at the Harris Mine and certain contract mines due to equipment and geologic difficulties. Midwest production overcame ramp-up issues at the new Highland Mine and the Vermilion Grove portal of the Riola Mine. Overall, our average sales price decreased 1.4%, due to $27.7 million in sales recorded in 2002 as a result of a favorable arbitration ruling that resulted in a retroactive price adjustment to our Navajo station coal supply agreement, combined with a change in sales mix, as higher priced tons in the Appalachia and Midwest regions represented a lower percentage of our overall sales in 2003. On a regional basis, excluding the effect of the arbitration ruling in the prior year, in 2003 we realized comparable pricing in Appalachia, and improved pricing in the Southwest and Powder River Basin. Midwest prices decreased slightly from 2002 levels.

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Segment Adjusted EBITDA

      Our total segment Adjusted EBITDA was $604.0 million for the year ended December 31, 2003, compared with $616.3 million for the full year 2002, broken down as follows:

						Increase (Decrease)
						Segment Adjusted
		Year Ended		Year Ended		EBITDA
		December 31,		December 31,
		2003		2002		$			%
		(Dollars in thousands)
Western U.S. Mining		$	357,021	$	356,392	$	629			0.2	%
Eastern U.S. Mining			198,964		219,940		(20,976	)		(9.5	)%
Australian Mining			2,225		3,007		(782	)		(26.0	)%
Trading and Brokerage			45,828		36,984		8,844			23.9	%
	Total Segment Adjusted EBITDA	$	604,038	$	616,323	$	(12,285	)		(2.0	)%

      Adjusted EBITDA from our Western U.S. Mining operations increased $0.6 million in 2003. Excluding $37.1 million from 2002 results related to a favorable arbitration ruling and a mediated settlement, Western U.S. Mining Adjusted EBITDA improved $37.7 million, and our margin per ton improved $0.27, or 11%. The improvement was driven by our Powder River Basin operations, which realized improved pricing and record volume from strong demand for its products, combined with lower maintenance and repair costs, that overcame higher fuel and explosives costs. Adjusted EBITDA from our Eastern operations decreased $21.0 million (margin per ton decreased $0.27, or 6%) as a result of a $32.9 million decrease in contribution from our Appalachia operations, primarily due to lower production and higher costs at the Harris Mine, as a result of geologic difficulties, and equipment-related operating difficulties at certain contract mines in 2003. This decrease was partially offset by a $12.0 million improvement in our Midwest operations’ results. The Midwest operations benefited from higher overall volume and improved pricing at our Black Beauty operations, which overcame higher fuel and explosives costs and ramp-up issues at the new Vermilion Grove portal of the Riola Mine.

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

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Reconciliation of Segment Adjusted EBITDA to Income (Loss) Before Income Taxes and Minority Interests

							Increase (Decrease)
	Year Ended			Year Ended			to Income
	December 31,			December 31,
	2003			2002			$			%
	(Dollars in thousands)
Total Segment Adjusted EBITDA	$	604,038		$	616,323		$	(12,285	)		(2.0	)%
Corporate and Other Adjusted EBITDA		(193,760	)		(210,222	)		16,462			7.8	%
Depreciation, depletion and amortization		(234,336	)		(232,413	)		(1,923	)		(0.8	)%
Asset retirement obligation expense		(31,156	)		—			(31,156	)		n/a
Early debt extinguishment costs		(53,513	)		—			(53,513	)		n/a
Interest expense		(98,540	)		(102,458	)		3,918			3.8	%
Interest income		4,086			7,574			(3,488	)		(46.1	)%
Income (loss) before income taxes and minority interests	$	(3,181	)	$	78,804		$	(81,985	)		n/a

      Our total segment Adjusted EBITDA was $604.0 million for the full year, compared with $616.3 million in the prior year (discussed above). Corporate and Other Adjusted EBITDA results include selling and administrative expenses, net gains on asset disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development and resource management. In 2003, these results were impacted by:

•  higher net gains on property disposals of $9.4 million;

•  a $7.6 million gain in 2003 on the sale of 1.15 million units of Penn Virginia;

•  higher selling and administrative expenses of $7.1 million associated with salaried pensions, incentive compensation, litigation, additional healthcare cost controls and Sarbanes-Oxley compliance; and

•  lower costs ($7.3 million) associated with past mining obligations, as the prior year included a $17.2 million charge related to an adverse U.S. Supreme Court decision which assigned us responsibility for the health care premiums of certain beneficiaries previously withdrawn by the Social Security Administration, while the current year included higher retiree healthcare costs of $8.9 million.

      Income (loss) before income taxes and minority interests decreased $82.0 million from 2002, due to early debt extinguishment costs of $53.5 million incurred in 2003 pursuant to our refinancing (see Note 13 to our consolidated financial statements) and asset retirement obligation expense of $31.2 million recognized in 2003 in accordance with SFAS No. 143. Expense in 2002 related to reclamation activities was $11.0 million and was included in “operating costs and expenses” in the statement of operations. The adoption of SFAS No. 143 is discussed in Note 6 to our consolidated financial statements. Interest expense in 2003 decreased $3.9 million, due to $8.9 million in savings realized from our 2003 refinancing, partially offset by $5.0 million higher costs related to surety bonds and letters of credit used to secure our obligations for reclamation, workers’ compensation and lease commitments. Prior year interest income included $4.6 million in interest income received related to excise tax refunds.

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Net Income

								Increase (Decrease)
		Year Ended			Year Ended			to Income
		December 31,			December 31,
		2003			2002			$			%
		(Dollars in thousands)
Income (loss) before income taxes and minority interests		$	(3,181	)	$	78,804		$	(81,985	)		n/a
	Income tax benefit		47,708			40,007			7,701			19.2	%
	Minority interests		(3,035	)		(13,292	)		10,257			77.2	%
Income before accounting changes			41,492			105,519			(64,027	)		(60.7	)%
	Cumulative effect of accounting changes		(10,144	)		—			(10,144	)		n/a
Net income		$	31,348		$	105,519		$	(74,171	)		(70.3	)%

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

•  a higher tax benefit of $7.7 million in 2003. The tax benefit recorded in 2003 differs from the tax expense in 2002 primarily as a result of the magnitude of the percentage depletion deduction (which is a permanent difference) relative to pre-tax income, and a $10.0 million adjustment to our tax reserves;

•  lower minority interests expense in 2003 due to the purchase of the remaining 25% of Arclar Coal Company in September 2002 and the acquisition in April 2003 of the remaining 18.3% of Black Beauty Coal Company; and

•  a charge in 2003 relating to the cumulative effect of accounting changes, net of income taxes, of $10.1 million. This amount represents the aggregate amount of the recognition of accounting changes pursuant to the adoption of SFAS No. 143, the change in method of amortization of actuarial gains and losses related to net periodic postretirement benefit costs and the effect of the rescission of EITF No. 98-10, as discussed in Note 6 to the consolidated financial statements.

Outlook

      Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as there continues to be growth in the U.S., Chinese, Pacific Rim and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. Published indices also show improved year-over-year coal prices in most U.S. and global coal markets, and world-wide coal supply/demand fundamentals remain tight due to market demand and transportation and production infrastructure limitations in most countries. Metallurgical coal is generally selling at a significant premium to steam coal. We expect our recently acquired Australian operations, which produce primarily metallurgical coal, to further enable us to capitalize on the strong global coal markets.

      In the United States, we expect coal demand to remain strong in 2005, assuming continued economic strength, normal weather, and available transportation for coal. Strong demand for coal and coal-based electricity generation is being driven by the strengthening economy, low customer stockpiles, production difficulties for some producers, capacity constraints of nuclear generation and high prices of natural gas and oil. The high price of natural gas is leading coal-fueled generating plants to operate at increasing levels. We expect that high costs and unpredictable supplies of oil and natural gas are likely to remain for the foreseeable future. Current average inventories at U.S. generators are estimated to be below five-year averages and coal-fueled electricity generation is expected to increase to record levels. Generation from nuclear power is currently constrained by capacity.

      We expect the Powder River Basin to remain the largest and fastest-growing region in the United States for coal production due to its abundant coal reserves, low sulfur content and low mining costs. Year-to-year fluctuations in demand will occur based on weather and the strength of the economy. A

49

number of customers plan test burns and increased use of blending to reduce the supply/demand imbalance of Central Appalachian coals. Strong demand is also expected for coals from Colorado, the Midwest and Northern Appalachia.

      We are targeting 2005 production of 210 million to 220 million tons and total sales volume of 240 million to 250 million tons, including 12 to 14 million tons of metallurgical coal. Over 95% of our total production in 2005 has been priced (including 90% of our metallurgical coal production).

      Management expects strong market conditions and operating performance to overcome external cost pressures and adverse rail and port performance. We are experiencing increases in operating costs related to fuel, explosives, steel and healthcare, and have taken measures to mitigate the increases in these costs. In addition, historically low interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. We may also encounter poor geologic conditions, lower third party contract miner or brokerage source performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating difficulties, our operating margins would be negatively impacted.

Critical Accounting Policies

      Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

Employee-Related Liabilities

      Our subsidiaries have significant long-term liabilities for our employees’ postretirement benefit costs, workers’ compensation obligations and defined benefit pension plans. Detailed information related to these liabilities is included in the notes to our consolidated financial statements. Liabilities for postretirement benefit costs and workers’ compensation obligations are not funded. Our pension obligations are funded in accordance with the provisions of federal law. Expense for the year ended December 31, 2004 for these liabilities totaled $146.0 million, while payments were $194.2 million, including a $50.0 million voluntary pre-funding of one pension plan.

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

      We make assumptions related to future trends for medical care costs in the estimates of retiree health care and work-related injury and illness obligations. In addition, we make assumptions related to future compensation increases and rates of return on plan assets in the estimates of pension obligations.

      If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. Our most significant employee liability is postretirement health care, and assumed discount rates and health care cost trend rates have a significant effect on the expense and liability amounts reported for health care plans. Below we have provided two separate sensitivity analyses to demonstrate the significance of these assumptions in relation to reported amounts.

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      Health care cost trend rate (dollars in thousands):

	One Percentage-		One Percentage-
	Point Increase		Point Decrease
Effect on total service and interest cost components(1)	$	7,960	$	(5,462	)
Effect on total postretirement benefit obligation(1)	$	138,793	$	(116,488	)

      Discount rate (dollars in thousands):

	One Half			One Half
	Percentage-Point			Percentage-Point
	Increase			Decrease
Effect on total service and interest cost components(1)	$	987		$	(1,150	)
Effect on total postretirement benefit obligation(1)	$	(65,051	)	$	71,496

(1)  In addition to the effect on total service and interest cost components of expense, changes in trend and discount rates would also increase or decrease the actuarial gain or loss amortization expense component. The gain or loss amortization would approximate the increase or decrease in the obligation divided by 8.43 years at December 31, 2004.

Asset Retirement Obligations

      Our method for accounting for reclamation activities changed on January 1, 2003 as a result of the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” Our asset retirement obligations primarily consist of spending estimates related to surface land reclamation and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mining permit.

      The asset retirement obligation is determined by mine and we use various estimates and assumptions including, among other items, estimates of disturbed acreage as determined from engineering data, estimates of future costs to reclaim the disturbed acreage, the timing of these cash flows, and a credit-adjusted risk-free rate. As changes in estimates occur (such as mine plan revisions, changes in estimated costs, or changes in timing of the reclamation activities), the revisions to the obligation and asset are recognized at the appropriate credit-adjusted risk-free rate. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Asset retirement obligation expense for the year ended December 31, 2004 was $42.4 million, and payments totaled $45.8 million.

Trading Activities

      We engage in the buying and selling of coal in over-the-counter markets. Our coal trading contracts are accounted for on a fair value basis under SFAS No. 133. To establish fair values for our trading contracts, we use bid/ask price quotations obtained from multiple, independent third party brokers to value coal and emission allowance positions. Prices from these sources are then averaged to obtain trading position values. We could experience difficulty in valuing our market positions if the number of third party brokers should decrease or market liquidity is reduced.

      Ninety-nine percent of the contracts in our trading portfolio as of December 31, 2004 were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials, and one percent of our contracts were valued based on similar market transactions. As of December 31, 2004, one hundred percent of the estimated future value of our trading portfolio was scheduled to be realized by the end of 2005.

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     Income Taxes

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

      We establish reserves for tax contingencies when, despite the belief that our tax return positions are fully supported, certain positions are likely to be challenged and may not be fully sustained. The tax contingency reserves are analyzed on a quarterly basis and adjusted based upon changes in facts and circumstances, such as the progress of federal and state audits, case law and emerging legislation. Our effective tax rate includes the impact of tax contingency reserves and changes to the reserves, including related interest, as considered appropriate by management. We establish the reserves based upon management’s assessment of exposure associated with permanent tax differences (i.e. tax depletion expense, etc.) and certain tax sharing agreements. We are subject to federal audits for several open years due to our previous inclusion in multiple consolidated groups and the various parties involved in finalizing those years.

Revenue Recognition

      In general, we recognize revenues when they are realizable and earned. We generated 98% of our revenue in 2004 from the sale of coal to our customers. Revenue from coal sales is realized and earned when risk of loss passes to the customer. Coal sales are made to our customers under the terms of supply agreements, most of which are long-term (greater than one year). Under the typical terms of these agreements, risk of loss transfers to the customers at the mine or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source(s) that delivers coal to its destination.

      With respect to other revenues, other operating income, or gains on asset sales recognized in situations unrelated to the shipment of coal, we carefully review the facts and circumstances of each transaction and apply the relevant accounting literature as appropriate, and do not recognize revenue until the following criteria are met: persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller’s price to the buyer is fixed or determinable; and collectibility is reasonably assured.

Liquidity and Capital Resources

      Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities, sales of non-core assets and debt and equity offerings related to significant transactions. Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs, costs related to past mining obligations and planned acquisitions and development activities. Our ability to pay dividends, service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above, in excess of the primary uses. We typically fund all of our capital expenditure requirements with cash generated from operations, and during 2004 and 2003 have had no borrowings outstanding under our $900.0 million Revolving Credit Facility, which we use primarily for standby letters of credit. This provides us with available borrowing capacity ($554.1 million as of December 31, 2004) to use to fund strategic acquisitions or meet other financing needs.

      Operating activities provided $283.8 million of cash in 2004, an increase of $94.9 million compared with prior year. A $136.7 million increase in net income from continuing operations was the primary contributor to the improvement. Partially offsetting this increase was higher pension plan funding of

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$44.6 million. During the second quarter of 2004, we electively funded $50.0 million to one pension plan, the remaining $12.1 million of current year pension funding was toward minimum funding obligations for our pension plans. By contrast, contributions were $17.5 million in the prior year, $9.9 million of which was voluntary.

      Net cash used in investing activities was $705.0 million in 2004, $512.8 million more than prior year. Investment spending in 2004 includes $421.3 million for the acquisition of the Twentymile Mine in Colorado and two mines in Australia. In the prior year, we spent $90.0 million to acquire the remaining 18.3% of Black Beauty Coal Company. Capital spending of $266.6 million in the current year was $110.2 million more than prior year expenditures of $156.4 million. Current year spending included a large loading facility upgrade in our Powder River Basin operations, $114.7 million of initial payments related to the successful acquisition of a total of 621 million tons of Powder River Basin coal reserves, and equipment purchases in the Midwest and at Australian mines acquired during 2004. In December 2004, we acquired a 25.5% interest in Carbones del Guasare, which owns and manages the Paso Diablo mine in Venezuela, for a net purchase price of $32.5 million. Proceeds from property and equipment disposals were $30.2 million lower than prior year primarily due to the sale of oil and gas rights, land and coal reserves and surplus surface land in Appalachia in 2003, with no comparable transactions in 2004.

      Financing activities provided $693.4 million in 2004 compared with $48.6 million in the prior year, an increase of $644.8 million. The current year included net proceeds from our March 2004 debt and equity offerings of $627.8 million. We issued 17.65 million common shares at $22.50 per share, raising $383.1 million after deducting underwriting discounts, commissions and other expenses, and $250 million from our issuance of 5.875% Senior Notes due in 2016. During the fourth quarter of 2004, we completed a repricing of our Senior Secured Credit Facility, consisting of an amended $450 million Term Loan and a $900 million Revolving Credit Facility. As a result of the repricing, the previous term loan was extinguished and a new loan with nearly identical terms, but a lower interest rate, was issued. The previous Term Loan had been repriced during the first quarter of 2004 concurrent with a $300 million increase in capacity of the revolving loan. Additional payments on long-term debt in 2004 were $36.3 million. During the first half of 2003, we refinanced our debt utilizing proceeds from long-term debt of $1.1 billion to, among other things, repay line of credit borrowings of $121.6 million and long-term debt of $831.0 million and to pay $23.7 million in debt issuance costs in connection with the new debt issued. The prior year included other debt repayments of $37.4 million. Securitized interest in accounts receivable increased $110.0 million in 2004 compared to a decrease of $46.4 million in the prior year. Financing cash flows in the current and prior year periods included dividends of $32.6 million and $24.1 million, respectively. A detailed discussion of our debt instruments and refinancing activity is included in Note 13 to our consolidated financial statements. Dividends are subject to limitations imposed by our 6.875% Senior Notes, 5.875% Senior Notes and Senior Secured Credit Facility covenants.

      As of December 31, 2004 and 2003, our total indebtedness consisted of the following (dollars in thousands):

		December 31,
		2004		2003
Term Loan under Senior Secured Credit Facility		$	448,750	$	446,625
6.875% Senior Notes due 2013			650,000		650,000
5.875% Senior Notes due 2016			239,525		—
Fair value of interest rate swaps — 6.875% Senior Notes			5,189		4,239
5.0% Subordinated Notes			73,621		79,412
Other			7,880		16,263
	Total	$	1,424,965	$	1,196,539

      We filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission in October 2003, which was declared effective in March 2004, allowing us to offer and sell from time to time

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unsecured debt securities consisting of notes, debentures, and other debt securities; common stock; preferred stock; warrants; and/or units totaling a maximum of $1.25 billion. The 2004 debt and equity offerings noted above were made under this universal shelf registration statement, which remains in effect. The shelf registration statement has a remaining capacity of $602.9 million. Related proceeds could be used for general corporate purposes including repayment of other debt, capital expenditures, possible acquisitions and any other purposes that may be stated in any prospectus supplement.

      As of December 31, 2004, there were no outstanding borrowings under our Revolving Credit Facility. We had letters of credit outstanding under the facility of $345.9 million, leaving $554.1 million available for borrowing. We were in compliance with all of the covenants of the Senior Secured Credit Facility, the 6.875% Senior Notes, the 5.875% Senior Notes, and the 5.0% Subordinated Notes as of December 31, 2004.

      In May 2003, we entered into and designated four interest rate swaps with notional amounts totaling $100.0 million as a fair value hedge of our 6.875% Senior Notes. Under the swaps, we pay a floating rate that resets each March 15 and September 15, based upon the six-month LIBOR rate, for a period of ten years ending March 15, 2013 and receive a fixed rate of 6.875%. The average applicable floating rate of the four swaps was 5.14% as of December 31, 2004. At current LIBOR levels, we would realize annualized savings of approximately $1.7 million over the term of the swaps.

      In September 2003, we entered into two $400.0 million interest rate swaps. One $400.0 million notional amount floating-to-fixed interest rate swap, expiring March 15, 2010, was designated as a hedge of changes in expected cash flows on the term loan under the Senior Secured Credit Facility. Under this swap we pay a fixed rate of 6.764% and receive a floating rate of LIBOR plus 2.5% (4.99% at December 31, 2004) that resets each March 15, June 15, September 15 and December 15 based upon the three-month LIBOR rate. Another $400.0 million notional amount fixed-to-floating interest rate swap, expiring March 15, 2013, was designated as a hedge of the changes in the fair value of the 6.875% Senior Notes due 2013. Under this swap, we pay a floating rate of LIBOR plus 1.97% (4.46% at December 31, 2004) that resets each March 15, June 15, September 15 and December 15 based upon the three-month LIBOR rate and receive a fixed rate of 6.875%. The swaps will lower our overall borrowing costs on $400.0 million of debt principal by 0.64% over the term of the floating-to-fixed swap. This results in annual interest savings of $2.6 million over the term of the fixed-to-floating swap.

      The following is a summary of specified types of commercial commitments available to us as of December 31, 2004 (dollars in thousands):

	Expiration Per Year
	Total Amounts		Within
	Committed		1 Year		2-3 Years		4-5 Years		Over 5 Years
Lines of credit and/or standby letters of credit	$	900,000		—		—		—	$	900,000

      In October 2004, our board of directors approved a 20% increase in the regular quarterly dividend on common stock, to $0.075 per share.

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Contractual Obligations

      The following is a summary of our significant contractual obligations as of December 31, 2004 (dollars in thousands):

		Payments Due by Year
		Within						After
		1 Year		2-3 Years		4-5 Years		5 Years
Long-term debt obligations (principal and interest)		$	95,126	$	243,516	$	460,966	$	1,234,582
Capital lease obligations			892		790		38		—
Operating leases obligations			92,817		138,097		69,960		49,417
Unconditional purchase obligations(1)			141,822		5,677		—		—
Coal reserve lease and royalty obligations			79,035		274,562		207,656		52,996
Other long-term liabilities(2)			172,582		344,892		355,376		908,744
	Total contractual cash obligations	$	582,274	$	1,007,534	$	1,093,996	$	2,245,739

(1)	We have purchase agreements with approved vendors for most types of operating expenses. However, our specific open purchase orders (which have not been recognized as a liability) under these purchase agreements, combined with any other open purchase orders, are not material. The commitments in the table above relate to significant capital purchases.
(2)	Represents long-term liabilities relating to our postretirement benefit plans, work-related injuries and illnesses, defined benefit pension plans and mine reclamation and end of mine closure costs.

      We had $147.5 million of purchase obligations related to future capital expenditures at December 31, 2004. Commitments for coal reserve-related expenditures, including Federal Coal Leases, are included in “Coal reserve lease and royalty obligations” in the table above. The contractual commitments detailed in the table above do not include expenditures related to the Federal Coal Lease bid that was won in February 2005 and the related tons are not included in our reserves.

      Total capital expenditures for 2005 are expected to range from $450 million to $500 million. Approximately 50% of projected 2005 capital expenditures relates to the Federal Coal Leases and longwall equipment at the Twentymile Mine and longwall replacement components in Australia, and the remainder is expected be used to purchase or develop reserves, replace or add equipment, fund cost reduction initiatives and upgrade equipment and facilities at the operations we recently acquired. We anticipate funding these capital expenditures primarily through operating cash flow. In addition, cash requirements to fund employee related and reclamation liabilities included above are expected to be funded from operating cash flow, along with obligations related to long-term debt, capital and operating leases and coal reserves. We believe the risk of generating lower than anticipated operating cash flow in 2005 is reduced by our high level of sales commitments (over 95% of 2005 planned production), improved pricing and ongoing efforts to improve our operating cost structure.

Off-Balance Sheet Arrangements

      In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds and our accounts receivable securitization. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

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      We use a combination of surety bonds, corporate guarantees (i.e. self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement benefits and coal lease obligations as follows as of December 31, 2004 (dollars in millions):

					Workers’		Retiree
	Reclamation		Lease		Compensation		Healthcare
	Obligations		Obligations		Obligations		Obligations		Other(1)		Total
Self Bonding	$	653.3	$	—	$	—	$	—	$	—	$	653.3
Surety Bonds		294.5		134.3		91.7		—		27.6		548.1
Letters of Credit		0.4		25.1		72.9		120.1		130.7		349.2
	$	948.2	$	159.4	$	164.6	$	120.1	$	158.3	$	1,550.6

(1)  Includes financial guarantees primarily related to joint venture debt, the Pension Benefit Guarantee Corporation and collateral for surety companies.

      We have guaranteed $9.2 million of debt of an affiliate in which we have a 49% equity investment, as described in Note 22 to our consolidated financial statements. Our remaining guarantees and indemnifications are discussed in Note 22 to our consolidated financial statements.

      In March 2000, we established an accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been contributed to the Seller are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (“Conduit”). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We used proceeds from the sale of our accounts receivable in lieu of drawing down on our revolving credit facility or to repay long-term debt, effectively reducing our overall borrowing costs. On September 16, 2004, we and our wholly-owned, bankruptcy-remote subsidiary closed on an expansion of the accounts receivable securitization facility. Under the terms of the amended agreement, the total facility capacity was increased from $140 million to $225 million and the receivables of additional wholly-owned subsidiaries of ours are now eligible to participate in the facility. The maturity of the facility was also extended to September 2009. All other terms and conditions remain substantially unchanged. The funding cost of the securitization program was $1.7 million and $2.3 million for the year ended December 31, 2004 and 2003, respectively. Under the provisions of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” the securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from our consolidated balance sheet. The amount of undivided interests in accounts receivable sold to the Conduit were $200.0 million and $90.0 million as of December 31, 2004 and 2003, respectively. A detailed description of our $225.0 million accounts receivable securitization is included in Note 4 to our consolidated financial statements.

Accounting Pronouncements Not Yet Implemented

      On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004), Share-Based Payment, or “SFAS No. 123(R),” which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends FASB Statement No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. Pro forma disclosure is no longer an alternative.

      SFAS No. 123(R) must be adopted no later than July 1, 2005 (for calendar year companies), and we expect to adopt the standard on that date, using one of the two methods permitted by SFAS No. 123(R), described below:

•  A “modified prospective” method in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments

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	granted after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date.
•	A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

      As permitted by SFAS No. 123, we currently account for share-based payments to employees using APB Opinion No. 25’s intrinsic value method and, as such, generally recognize no compensation cost for employee stock options. Accordingly, the adoption of SFAS No. 123(R)’s fair value method will have an impact on our results of operations, although it will have no impact on our overall financial position. Had we adopted SFAS No. 123(R) in prior periods, the impact of that standard would have approximated the impact of SFAS No. 123 as described in the disclosure of pro forma net income and earnings per share in Note 1 to our consolidated financial statements. The precise impact of the adoption of SFAS No. 123(R) on us in 2005 and beyond cannot be predicted at this time because it will depend on levels of equity-based compensation granted in the future. However, because we make our annual equity-based compensation grants in January, prior to the issuance of our financial statements, an estimate of the impact of the adoption of SFAS No. 123(R) on 2005 net income can be made. Based on stock option grants made in January 2005, considering option grants outstanding in 2005 made prior to 2005, and assuming no additional stock option grants in 2005 beyond January 2005, we anticipate (assuming the modified prospective method is used) recognizing expense for stock options for the period from July 1, 2005 to December 31, 2005 of $2.3 million, net of taxes. It should be noted that annual equity-based compensation grants in years prior to 2005 consisted of a higher number of stock options than the grant made in 2005. For the January 2005 grant, we delivered comparable equity-based compensation value by granting a combination of stock options and restricted stock. Prior to January 2005, we had not previously granted restricted stock as part of our annual compensation strategy. Expense related to restricted stock (which vests over five years, and assuming no grants beyond January 2005) is anticipated to be approximately $0.8 million, net of taxes, in 2005.

Risks Relating to Our Company

If a substantial portion of our long-term coal supply agreements terminate, our revenues and operating profits could suffer if we were unable to find alternate buyers willing to purchase our coal on comparable terms to those in our contracts.

      A substantial portion of our sales is made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. For the year ended December 31, 2004, 90% of our sales volume was sold under long-term coal supply agreements. At December 31, 2004, our coal supply agreements had remaining terms ranging from one to 17 years and an average volume-weighted remaining term of approximately 3.4 years.

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

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could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts. Moreover, some of these agreements permit the customer to terminate the contract if transportation costs, which our customers typically bear, increase substantially. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.

      The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Market prices for coal decreased in most regions in 2002. In 2003, pricing improved for eastern coal regions and moved slightly higher for western coal regions, and in 2004 pricing was substantially higher for the eastern coal regions and slightly higher for western coal regions. As a result, we cannot predict the future strength of the coal market and cannot assure you that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, two of our largest coal supply agreements are the subject of ongoing litigation and arbitration.

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

      For the year ended December 31, 2004, we derived 25% of our total coal revenues from sales to our five largest customers. At December 31, 2004, we had 45 coal supply agreements with these customers expiring at various times from 2005 to 2011. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be successful and those customers may not continue to purchase coal from us under long-term coal supply agreements. If a number of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.

      Peabody Western has a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to the operation of the Mohave plant beyond 2005 or the temporary or permanent shutdown of the plant. In a July 2003 filing with the California Public Utilities Commission, the operator affirmed that the Mohave plant was not forecast to return to service as a coal-fueled resource until mid-2009 at the earliest if the plant is shutdown at December 31, 2005. Southern California Edison has subsequently reaffirmed this forecast to the Commission. On December 2, 2004, the California Public Utilities Commission issued an opinion authorizing Southern California Edison to make necessary expenditures at the Mohave plant to preserve the “Mohave-open” option while Southern California Edison continues to seek resolution of the water and coal issues. The opinion stated that its goal was to return the Mohave plant to service with as short of a shut-down period as possible. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline from Peabody Western’s Black Mesa Mine to the Mohave plant. As a part of the alternate dispute resolution referenced in the Navajo Nation litigation, Peabody Western has been negotiating with the owners of the Mohave Generating Station and the Navajo Generating Station, and the two tribes to resolve the complex issues surrounding the groundwater dispute and other disputes involving the two generating stations. Resolution of these issues is critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. If these issues are not resolved in a timely manner, the operation of the Mohave plant will cease or be suspended on December 31, 2005. Absent a satisfactory alternate dispute resolution, it is unlikely that the coal supply agreement for the Mohave plant will be renewed in time to avoid a shutdown of the mine in 2006. The Mohave plant is the sole customer of the Black Mesa Mine,

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which sold 4.7 million tons in 2004. In 2004, the mine generated $25.2 million of Adjusted EBITDA, which represents 4.5% of our total of $559.2 million.

Our financial performance could be adversely affected by our substantial debt.

      Our financial performance could be affected by our substantial indebtedness. As of December 31, 2004, our total indebtedness was approximately $1,425.0 million, and we had $554.1 million of available borrowing capacity under our revolving credit facility. We may also incur additional indebtedness in the future.

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

•  making it more difficult for us to pay interest and satisfy our debt obligations;

•  increasing our vulnerability to general adverse economic and industry conditions;

•  requiring the dedication of a substantial portion of our cash flow from operations to the payment of principal of, and interest on, our indebtedness, thereby reducing the availability of the cash flow to fund working capital, capital expenditures or other general corporate uses;

•  limiting our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements;

•  limiting our flexibility in planning for, or reacting to, changes in our business and in the coal industry; and

•  placing us at a competitive disadvantage compared to less leveraged competitors.

      In addition, our indebtedness subjects us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us. Furthermore, substantially all of our assets secure our indebtedness under our credit facility.

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

If transportation for our coal becomes unavailable or uneconomic for our customers, our ability to sell coal could suffer.

      Transportation costs represent a significant portion of the total cost of coal and, as a result, the cost of transportation is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy or could make some of our operations less competitive than other sources of coal. Certain coal supply agreements, which account for less than 5% of our tons sold, permit the customer to terminate the contract if the cost of transportation increases by an amount ranging from 10% to 20% in any given 12-month period.

      Coal producers depend upon rail, barge, trucking, overland conveyor, pipeline and ocean-going vessels to deliver coal to markets. While our coal customers typically arrange and pay for transportation of coal from the mine or port to the point of use, disruption of these transportation services because of weather-related problems, strikes, lock-outs, transportation delays or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations. For

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example, the high volume of coal shipped from all Powder River Basin mines could create temporary congestion on the rail systems servicing that region.

      Continued increases in coal demand, combined with many customers’ inventories that are lower than historical averages, created periodic regional rail and port congestion in 2004. To the extent rail or port congestion constrains our operations’ ability to successfully ship coal to our customers, our operating results will be reduced.

Risks inherent to mining could increase the cost of operating our business.

      Our mining operations are subject to conditions beyond our control that can delay coal deliveries or increase the cost of mining at particular mines for varying lengths of time. These conditions include weather and natural disasters, unexpected maintenance problems, key equipment failures, variations in coal seam thickness, variations in the amount of rock and soil overlying the coal deposit, variations in rock and other natural materials and variations in geologic conditions.

Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations could increase those costs or limit our ability to produce coal.

      Federal, state and local authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production. The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or judicial interpretations of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations.

      In addition, the United States and over 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations, which took effect in February 2005. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. According to the Department of Energy’s Energy Information Administration Emissions of Greenhouse Gases in the United States 2003, coal accounts for 31% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. Further developments in connection with regulations or other limits on carbon dioxide emissions could have a material adverse effect on our financial condition or results of operations.

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Our expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions prove to be incorrect.

      We provide postretirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation under Statement of Financial Accounting Standards No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” which we estimate had a present value of $1,020.8 million as of December 31, 2004, $81.3 million of which was a current liability. We have estimated these unfunded obligations based on assumptions described in the notes to our consolidated financial statements. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher. Moreover, regulatory changes could increase our obligations to provide these or additional benefits.

      We are party to an agreement with the Pension Benefit Guaranty Corporation, or the PBGC, and TXU Europe Limited, an affiliate of our former parent corporation, under which we are required to make specified contributions to two of our defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If we or the PBGC give notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if we fail to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guarantee in place from TXU Europe Limited in favor of the PBGC before it draws on our letter of credit. On November 19, 2002 TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the United States). As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

      In addition, certain of our subsidiaries participate in two defined benefit multi-employer pension funds that were established as a result of collective bargaining with the United Mine Workers of America (UMWA) pursuant to the National Bituminous Coal Wage Agreement as periodically negotiated. The UMWA 1950 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked prior to January 1, 1976. This is a closed group of beneficiaries with no new entrants. The UMWA 1974 Pension Plan provides pension and disability pension benefits to qualifying represented employees retiring from a participating employer where the employee last worked after December 31, 1975.

      Contributions to these funds could increase as a result of future collective bargaining with the United Mine Workers of America, a shrinking contribution base as a result of the insolvency of other coal companies who currently contribute to these funds, lower than expected returns on pension fund assets, higher medical and drug costs or other funding deficiencies.

      The United Mine Workers of America Combined Fund was created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of our retired former employees who last worked prior to 1976, as well as orphaned beneficiaries of out of business companies who were receiving benefits as orphans prior to the 1992 law; no new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Another fund, the 1992 Benefit Plan also created by the same federal law in 1992 provides benefits to qualifying retired former employees of companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business, but the overall exposure for new beneficiaries into this fund is limited to retirees covered under their employer’s plan who retired prior to October 1, 1994. Another fund, the 1993 Benefit Fund was established through collective bargaining and provides retiree medical benefits to qualifying retired former employees who retired after September 30, 1994 of certain signatory companies who have gone out of business and have defaulted in providing their former employees with retiree medical benefits. Beneficiaries continue to be added to this fund as employers go out of business.

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      Based upon the enactment of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, we assumed future cash savings which allowed us to reduce our projected post-retirement benefit obligations and related expense. Failure to achieve these assumed future savings under all benefit plans could adversely affect our financial condition, results of operations and cash flow.

Our future success depends upon our ability to continue acquiring and developing coal reserves that are economically recoverable.

      Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserves through acquisitions of government and other leases and producing properties and continuing to use our existing properties. The federal government also leases natural gas and coalbed methane reserves in the West, including in the Powder River Basin. Some of these natural gas and coalbed methane reserves are located on, or adjacent to, some of our Powder River Basin reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2004, we leased a total of 60,140 acres from the federal government and added an additional 17,598 through February 2005. The limit could restrict our ability to lease additional federal lands. For additional discussion of our federal leases see Item 2. Properties of this Annual Report on Form 10-K.

      Our planned mine development projects and acquisition activities may not result in significant additional reserves and we may not have continuing success developing additional mines. Most of our mining operations are conducted on properties owned or leased by us. Because title to most of our leased properties and mineral rights are not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we must receive various governmental permits. We cannot predict whether we will continue to receive the permits necessary for us to operate profitably in the future. We may not be able to negotiate new leases from the government or from private parties or obtain mining contracts for properties containing additional reserves or maintain our leasehold interest in properties on which mining operations are not commenced during the term of the lease. From time to time, we have experienced litigation with lessors of our coal properties and with royalty holders.

A decrease in the production of our metallurgical coal (or other high-margin products) or a decrease in the price of metallurgical coal (or other high-margin products) could decrease our anticipated profitability.

      We more than doubled our sales of metallurgical coal in 2004, primarily as a result of the acquisition of coal operations in Australia in April 2004. Our current annual capacity for metallurgical coal production is approximately 12 to 14 million tons. Prices for metallurgical coal in late 2004 and early 2005 have reached historically high levels. We have committed 90% of our projected 2005 metallurgical coal production at significantly higher prices than in the past. As a result, our projected margins from these sales have increased significantly, and will represent a larger percentage of our overall revenues and profits in 2005. To the extent we experience either production or transportation difficulties that impair our ability to ship metallurgical coal to our customers at anticipated levels, our profitability will be reduced in 2005.

      After 2005, we have metallurgical coal production that has not yet been priced. As a result, a decrease in metallurgical coal prices could decrease our profitability beyond 2005.

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An inability of contract miner or brokerage sources to fulfill the delivery terms of their contracts with us could reduce our profitability.

      In conducting our trading, brokerage and mining operations, we utilize third party sources of coal production, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon the reliability (including financial viability) and price of the third-party supply, our obligation to supply coal to customers in the event that adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market, and other factors.

If the coal industry experiences overcapacity in the future, our profitability could be impaired.

      During the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in added production capacity throughout the industry, all of which led to increased competition and lower coal prices. Similarly, continued increases in future coal prices could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices in the future.

We could be negatively affected if we fail to maintain satisfactory labor relations.

      As of December 31, 2004, we and our subsidiaries had approximately 7,900 employees. As of December 31, 2004, approximately 40% of our hourly employees were represented by unions and they generated 21% of our 2004 coal production. Relations with our employees, and where applicable, organized labor, are important to our success.

United States

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

Australia

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

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      Because of the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our competitors who operate without union labor may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. The 10-month United Mine Workers of America strike in 1993 had a material adverse effect on us.

Our operations could be adversely affected if we fail to appropriately secure our obligations.

      U.S. federal and state laws and Australian laws require us to secure certain of our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. The primary method for us to meet those obligations is to post a corporate guarantee (i.e. self bond) or to provide a third party surety bond. As of December 31, 2004, we had $653.3 million of self bonds in place for our reclamation obligations. As of December 31, 2004, we also had outstanding surety bonds with third parties for post-mining reclamation totaling $294.5 million. We had an additional $91.7 million of surety bonds in place for workers’ compensation obligations and $134.3 million of surety bonds securing coal leases. All other bonding, including performance and infrastructure bonds, totaled $27.6 million. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us to secure new surety bonds or renew bonds without the posting of partial collateral. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds or to provide a suitable alternatives would have a material adverse effect on us. That failure could result from a variety of factors including the following:

•  lack of availability, higher expense or unfavorable market terms of new surety bonds;

•  restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indenture or new credit facility; and

•  the exercise by third-party surety bond issuers of their right to refuse to renew the surety.

      Our ability to self bond reduces our costs of providing financial assurances. To the extent we are unable to maintain our current level of self bonding, due to legislative or regulatory changes or changes in our financial condition, our costs would increase.

Our ability to operate our company effectively could be impaired if we lose key personnel or fail to attract qualified personnel.

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

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations.

      Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition and results of operations. Our business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of our control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations. As a result, there could be delays or losses in transportation and deliveries of coal to

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our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

      Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties. These new power plant owners or other customers may have credit ratings that are below investment grade. If deterioration of the creditworthiness of our customers occurs, our $225.0 million accounts receivable securitization program and our business could be adversely affected.

Our certificate of incorporation and by-laws include provisions that may discourage a takeover attempt.

      Provisions contained in our certificate of incorporation and by-laws and Delaware law could make it more difficult for a third party to acquire us, even if doing so might be beneficial to our stockholders. Provisions of our by-laws and certificate of incorporation impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. For example, a change of control of our company may be delayed or deterred as a result of the stockholders’ rights plan adopted by our board of directors. These provisions could limit the price that certain investors might be willing to pay in the future for shares of our common stock and may have the effect of delaying or preventing a change in control.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

      The potential for changes in the market value of our coal trading, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading portfolio is evaluated using a value at risk analysis (described below). Value at risk analysis is not used to evaluate our non-trading interest rate and currency portfolios. A description of each market risk category is set forth below. We attempt to manage market risks through diversification, controlling position sizes, and executing hedging strategies. Due to lack of quoted market prices and the long term, illiquid nature of the positions, we have not quantified market risk related to our non-trading, long-term coal supply agreement portfolio.

Coal Trading Activities and Related Commodity Price Risk

      We engage in over-the-counter and direct trading of coal. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure, in value at risk terms, that we may assume at any point in time.

      We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, options, and swaps, at market value in our consolidated financial statements. Our trading portfolio included forwards and swaps at December 31, 2004 and included forwards, futures and options at December 31, 2003. Our policy for accounting for coal trading activities is described in Note 1 to our consolidated financial statements.

      We perform a value at risk analysis on our coal trading portfolio, which includes over-the-counter and brokerage trading of coal. The use of value at risk allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. Value at risk represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon (liquidation

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period) within a specified confidence level. Our value at risk model is based on the industry standard variance/co-variance approach. This captures our exposure related to both option and forward positions. Our value at risk model assumes a 15-day holding period and a 95% one-tailed confidence interval. This means that there is a one in 20 statistical chance that the portfolio would lose more than the value at risk estimates during the liquidation period.

      The use of value at risk allows management to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. Due to the subjectivity in the choice of the liquidation period, reliance on historical data to calibrate the models and the inherent limitations in the value at risk methodology, we perform regular stress and scenario analysis to estimate the impacts of market changes on the value of the portfolio. The results of these analyses are used to supplement the value at risk methodology and identify additional market-related risks.

      We use historical data to estimate our value at risk and to better reflect current asset and liability volatilities. Given our reliance on historical data, value at risk is effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. An inherent limitation of value at risk is that past changes in market risk factors may not produce accurate predictions of future market risk. Value at risk should be evaluated in light of this limitation.

      During the year ended December 31, 2004, the actual low, high, and average values at risk for our coal trading portfolio were $0.5 million, $6.1 million, and $2.9 million, respectively. During the year ended December 31, 2003, the actual low, high, and average values at risk for our coal trading portfolio were $0.4 million, $3.2 million, and $1.4 million, respectively. As of December 31, 2004, one hundred percent of the value of our trading portfolio was scheduled to be realized by the end of 2005.

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

Credit Risk

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

Foreign Currency Risk

      We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2005 involves hedging approximately 70% of our anticipated, non-capital Australian dollar-denominated expenditures. As of December 31, 2004, we had in place forward contracts designated as cash flows hedges with notional amounts outstanding totaling $515.0 million of which $285.0 million, $170.0 million and $60.0 million will expire in 2005, 2006 and 2007, respectively. The accounting for these derivatives is discussed in Note 2 to our consolidated financial statements. Our current expectation for 2005 non-capital, Australian dollar-denominated cash expenditures is approximately $600 million. A change in the Australian dollar/ U.S. dollar exchange rate of US$0.01

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(ignoring the effects of hedging) would result in an increase or decrease in our “Operating costs and expenses” of $6.0 million per year.

Interest Rate Risk

      Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed rate debt as a percent of net debt through the use of various hedging instruments, which are discussed in detail in Note 13 to our consolidated financial statements. As of December 31, 2004, after taking into consideration the effects of interest rate swaps, we had $872.9 million of fixed-rate borrowings and $552.1 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $5.5 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one-percentage point increase in interest rates would result in a $60.7 million decrease in the estimated fair value of these borrowings.

Other Non-trading Activities

      We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 90% of our sales volume under long-term coal supply agreements during 2004 and 2003. As of December 31, 2004, we had sales commitments for over 95% of our 2005 production, leaving 5 to 10 million tons unpriced. Also as of December 31, 2005, we had 65 to 75 million tons and 130 to 140 million tons of expected production available for sale or repricing at market prices for 2006 and 2007, respectively. We have an annual metallurgical coal production capacity of 12 to 14 million tons, all of which is priced for 2005 and none of which is priced beyond March 2006.

      Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage this risk, we use a combination of forward contracts with our suppliers and financial derivative contracts, primarily swap contracts with financial institutions. In addition, we utilize derivative contracts to hedge our commodity price exposure. As of December 31, 2004, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel. Notional amounts outstanding under these contracts, scheduled to expire through 2007, were 76.7 million gallons of heating oil and 28.7 million gallons of crude oil. Overall, we have fixed prices for approximately 90% of our anticipated diesel fuel requirements in 2005.

      We expect to consume approximately 95 million gallons of fuel per year. Based on this usage, a change in fuel prices of one cent per gallon (ignoring the effects of hedging) would result in an increase or decrease in our “Operating costs and expenses” of approximately $1 million per year.

Item 8. Financial Statements and Supplementary Data.

      See Part IV, Item 15 of this report for information required by this Item, which is incorporated by reference from our December 31, 2004 Annual Report to Stockholders.

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

      None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

      As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures

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were effective in timely alerting them to material information relating to our company and its consolidated subsidiaries required to be included in our periodic SEC filings.

Changes in Internal Control Over Financial Reporting

      There were no changes in our internal control over financial reporting identified in connection with the evaluation required by paragraph (d) of Exchange Act Rules 13a-15 or 15d-15 that was conducted during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

      Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control framework and processes were designed to provide reasonable assurance to management and the Board of Directors regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

      Management recognizes its responsibility for establishing a strong ethical culture so that our affairs are conducted according to the highest standards of personal and corporate conduct.

      Our internal control over financial reporting includes those policies and procedures that:

•  pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

•  provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of management and our Directors; and

•  provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the consolidated financial statements.

      Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect misstatements. Further, because of changing conditions, effectiveness of internal control over financial reporting may vary over time.

      Management assessed the effectiveness of our internal control over financial reporting and concluded that, as of December 31, 2004, such internal control is effective. Management’s assessment of internal control over financial reporting excludes the Australian operations acquired during 2004, as allowed by current SEC regulations related to internal controls involving recently acquired entities. These operations constituted $309.3 million and $251.0 million of total and net assets, respectively; and $235.9 million and $31.2 million of revenues and operating profit, respectively; and such amounts are included in our consolidated financial statements as of and for the year ended December 31, 2004. Management did not assess the effectiveness of internal control over financial reporting at these operations because we continue to integrate these operations into our control environment, thus making it impractical to complete an assessment as of December 31, 2004.

      In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control — Integrated Framework.

      Our Independent Registered Public Accounting Firm, Ernst & Young LLP, with direct access to our Board of Directors through its Audit Committee, have audited the consolidated financial statements we prepared. Their report on the consolidated financial statements is incorporated by reference from our December 31, 2004 Annual Report to Stockholders as referenced in Part II, Item 8. Financial Statements

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and Supplementary Data. Ernst & Young LLP has audited management’s assessment of our internal control over financial reporting, as stated in their report included herein.

Management’s Process to Assess the Effectiveness of Internal Control Over Financial Reporting

      Management’s conclusion on the effectiveness of internal control over financial reporting is based on a thorough and comprehensive evaluation and analysis of the five elements of COSO (shown in italics below), and is based on, but not limited to, the following:

•  Documentation of entity-wide controls establishing the culture and “tone-at-the-top” of the organization, in support of our Control Environment, Risk Assessment Process, Information and Communication policies and the ongoing Monitoring of these control processes and systems.

•  An evaluation of Control Activities by work process. Key controls and compensating controls were documented and tested by each of our work processes, including controls over all relevant financial statement assertions related to all significant accounts and disclosures. Internal control deficiencies were identified and prioritized, and appropriate remediation action plans were defined, implemented and retested.

•  A centralized review and analysis of all internal control deficiencies across the enterprise to determine whether such deficiencies, either separately or in the aggregate, represented a significant deficiency or material weakness.

•  An evaluation of any changes in work processes, systems, organization or policy that could materially impact internal control over financial reporting.

•  Certifications regarding financial results and internal control conclusions from managers and work process owners.

      In addition, we maintain an internal auditing program that independently assesses the effectiveness of internal control over financial reporting, including testing of the five COSO elements.

/s/ IRL F. ENGELHARDT	/s/ RICHARD A. NAVARRE
Irl F. Engelhardt	Richard A. Navarre
Chairman and Chief Executive Officer	Executive Vice President and Chief Financial Officer

March 7, 2005

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Peabody Energy Corporation

      We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Peabody Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Peabody Energy Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

      A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

      Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

      As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls over the Australian operations acquired in 2004, which are included in the December 31, 2004, consolidated financial statements of Peabody Energy Corporation and constituted $309.3 million and $251.0 million of total and net assets, respectively, as of December 31, 2004, and $235.9 million and $31.2 million of revenues and operating profit, respectively, for the year then ended. Our audit of internal control over financial reporting of Peabody Energy Corporation also did not include an evaluation of the internal control over financial reporting of the Company’s Australian operations acquired in 2004.

      In our opinion, management’s assessment that Peabody Energy Corporation maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Peabody Energy Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

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

/s/ Ernst & Young LLP

St. Louis, Missouri

March 7, 2005

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Item 9B. Other Information.

      The Board of Directors amended Section 1.6 of the Company’s Amended and Restated By-Laws on March 15, 2005 to confirm the voting requirement for the election of directors as a plurality vote. The amendment became effective on the same day. Because this Annual Report on Form 10-K is being filed within four business days from March 15, the amendment is being disclosed hereunder rather than under Item 5.03 of Form 8-K. The amended By-Laws are attached hereto as Exhibit 3.2 pursuant to Item 601(b)(3) of Regulation S-K.

PART III

Item 10. Directors and Executive Officers of the Registrant.

      The information required by Item 401 of Regulation S-K is included under the caption “Election of Directors” in our 2005 Proxy Statement and in Part I Item 4 of this report under the caption “Executive Officers of the Company.” Such information is incorporated herein by reference. The information required by Item 405 of Regulation S-K is included under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in our 2005 Proxy Statement and is incorporated herein by reference.

Item 11. Executive Compensation.

      The information required by Item 402 of Regulation S-K is included under the caption “Executive Compensation” in our 2005 Proxy Statement and is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management.

      The information required by Item 403 of Regulation S-K is included under the caption “Ownership of Company Securities” in our 2005 Proxy Statement and is incorporated herein by reference.

Equity Compensation Plan Information

      As required by Item 201(d) of Regulation S-K, the following table provides information regarding our equity compensation plans as of December 31, 2004:

					Number of Securities
	(a)				Remaining Available for
	Number of Securities				Future Issuance Under
	to be Issued upon		Weighted-Average		Equity Compensation
	Exercise of		Exercise Price of		Plans (Excluding
	Outstanding Options,		Outstanding Options,		Securities Reflected in
Plan Category	Warrants and Rights		Warrants and Rights		Column (a))
Equity compensation plans approved by security holders		7,234,168	$	11.80		8,051,438
Equity compensation plans not approved by security holders		—		—		—
Total		7,234,168	$	11.80		8,051,438

Item 13. Certain Relationships and Related Transactions.

      The information required by Item 404 of Regulation S-K is included under the caption “Related Party Transactions” in our 2005 Proxy Statement and is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services.

      The information required by Item 9(e) of Schedule 14A is included under the caption “Principal Accountant Fees and Services” in our 2005 Proxy Statement and is incorporated herein by reference.

72

PART IV

Item 15. Exhibits, Financial Statement Schedules.

      (a) Financial Statements

      (1) The following consolidated financial statements (included in Exhibit 13) of Peabody Energy Corporation, as released in pages 49 to 91 of our December 31, 2004 Annual Report to Stockholders, are incorporated by reference:

	Exhibit 13
	Page(s)
Report of Independent Registered Public Accounting Firm		1
Consolidated Statements of Operations — Years Ended December 31, 2004, 2003 and 2002		2
Consolidated Balance Sheets — December 31, 2004 and December 31, 2003		3
Consolidated Statements of Cash Flows — Years Ended December 31, 2004, 2003 and 2002		4
Statements of Changes in Stockholders’ Equity — Years Ended December 31, 2004, 2003 and 2002		5
Notes to Consolidated Financial Statements		6
Summary Quarterly Financial Information (unaudited)		48
Segment Information		49

           (2) Financial Statement Schedule.

      The following financial statement schedule of Peabody Energy Corporation, and the report thereon of the independent registered public accounting firm, are at the pages indicated:

	Page
Report of Independent Registered Public Accounting Firm on Financial Statement Schedule		F-1
Valuation and Qualifying Accounts		F-2

      All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted

           (3) Exhibits.

           See Exhibit Index hereto.

73

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Peabody Energy Corporation

/s/ IRL F. ENGELHARDT

Irl F. Engelhardt

Chairman and Chief Executive Officer

Date: March 16, 2005

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.

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

74

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

75

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Stockholders

Peabody Energy Corporation

      We have audited the consolidated financial statements of Peabody Energy Corporation as of December 31, 2004 and 2003, and for the three years in the period ended December 31, 2004, and have issued our report thereon dated March 7, 2005. Our audits also included the financial statement schedule listed in Item 15(a). This schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion based on our audits. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

/s/ ERNST & YOUNG LLP

St. Louis, Missouri

March 7, 2005

F-1

PEABODY ENERGY CORPORATION

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

			Balance at		Charged to									Balance
			Beginning		Costs and									at End
Description			of Period		Expenses			Deductions(1)			Other(2)			of Period
YEAR ENDED DECEMBER 31, 2004
	Reserves deducted from asset accounts:
		Advance royalty recoupment reserve	$	14,465	$	—		$	(101	)	$	3,860		$	18,224
		Reserve for materials and supplies		7,563		796			(4,742	)		802			4,419
		Allowance for doubtful accounts		1,361		—			—			—			1,361
YEAR ENDED DECEMBER 31, 2003
	Reserves deducted from asset accounts:
		Advance royalty recoupment reserve	$	13,585	$	(181	)	$	—		$	1,061		$	14,465
		Reserve for materials and supplies		9,065		—			(992	)		(510	)		7,563
		Allowance for doubtful accounts		1,331		30			—			—			1,361
YEAR ENDED DECEMBER 31, 2002
	Reserves deducted from asset accounts:
		Advance royalty recoupment reserve	$	12,836	$	154		$	—		$	595		$	13,585
		Reserve for materials and supplies		9,893		—			(912	)		84			9,065
		Allowance for doubtful accounts		1,496		(165	)		—			—			1,331

(1)	Reserves utilized, unless otherwise indicated.
(2)	Balances transferred (to) from other accounts or reserves recorded as part of a property or business acquisition.

F-2

EXHIBIT INDEX

      The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.

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

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

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

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

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

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

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

†  Filed herewith.

EX-3.2

                                                                     EXHIBIT 3.2


                              AMENDED AND RESTATED
                                     BY-LAWS
                                       OF
                           PEABODY ENERGY CORPORATION


                                   ARTICLE I

                             MEETING OF STOCKHOLDERS

         Section 1.1. Place of Meeting. Meetings of the stockholders of the
Corporation shall be held at such place either within or without the State of
Delaware as the Board of Directors may determine.

         Section 1.2. Annual Meetings. (A) Annual meetings of stockholders shall
be held, at a date, time and place fixed by the Board of Directors and stated in
the notice of meeting, to elect a Board of Directors and to transact such other
business as may properly come before the meeting.

         (B) Nominations of persons for election to the Board of Directors of
the Corporation and the proposal of business to be considered by the
stockholders may be made at an annual meeting of stockholders (1) pursuant to
the Corporation's notice of meeting delivered pursuant to Article 1, Section 4
of these By-Laws, (2) by or at the direction of the Chairman of the Board or (3)
by any stockholder of the Corporation who is entitled to vote at the meeting,
who complied with the notice procedures set forth in subparagraphs (B) and (C)
of this Section 2 and who was a stockholder of record at the time such notice is
delivered to the Secretary of the Corporation.

         (C) For nominations or other business to be properly brought before an
annual meeting by a stockholder pursuant to clause (3) of paragraph (B) of these
By-Laws, the stockholder must have given timely notice thereof in writing to the
Secretary of the Corporation, and, in the case of business other than
nominations, such other business must be a proper matter for stockholder action.
To be timely, a stockholder's notice shall be delivered to the Secretary at the
principal executive offices of the Corporation not less than ninety (90) days
nor more than one hundred and twenty (120) days prior to the first anniversary
of the preceding year's annual meeting; provided, however, that in the event
that the date of the annual meeting is advanced by more than twenty (20) days,
or delayed by more than seventy (70) days, from such anniversary date, notice by
the stockholder to be timely must be so delivered not earlier than one hundred
and twenty (120) days prior to such annual meeting and not later than the close
of business on the later of the ninetieth (90th) day prior to such annual
meeting or the tenth (10th) day following the day on which public announcement
of the date of such meeting is first made. Such stockholder's notice shall set
forth (1) as to each person whom the stockholder proposes to nominate for
election or re-election as a director all information relating to such person
that is required to be disclosed in solicitations of proxies for election of
directors, or is otherwise required, in each case pursuant to Regulation 14A
under the Securities Exchange Act of 1934, as amended (the "Exchange Act"),
including such person's written consent to being named in the proxy statement as
a nominee and to serving as a director if elected; (2) as to any other business
that the



stockholder proposes to bring before the meeting, a brief description of the
business desired to be brought before the meeting, the reasons for conducting
such business at the meeting and any material interest in such business of such
stockholder and the beneficial owner, if any, on whose behalf the proposal is
made; and (3) as to the stockholder giving the notice and the beneficial owner,
if any, on whose behalf the nomination or proposal is made (a) the name and
address of such stockholder, as they appear on the Corporation's books, and of
such beneficial owner and (b) the class and number of shares of the Corporation
which are owned beneficially and of record by such stockholder and such
beneficial owner.

         (D) Notwithstanding anything in the second sentence of paragraph (C) of
these By-Laws to the contrary, in the event that the number of directors to be
elected to the Board of Directors of the Corporation is increased and there is
no public announcement naming all of the nominees for director or specifying the
size of the increased Board of Directors made by the Corporation at least eighty
days prior to the first anniversary of the preceding year's annual meeting, a
stockholder's notice required by this By-Law shall also be considered timely,
but only with respect to nominees for any new positions created by such
increase, if it shall be delivered to the Secretary at the principal executive
offices of the Corporation not later than the close of business on the tenth
(10th) day following the day on which such public announcement is first made by
the Corporation.

         Section 1.3. Special Meetings. (A) Except as otherwise required by law,
special meetings of the stockholders may be called pursuant to the provisions of
the Third Amended and Restated Certificate of Incorporation of the Corporation,
filed with the Delaware Secretary of State on May 21, 2001 (the "Charter").

         (B) Only such business shall be conducted at a special meeting of
stockholders as shall have been brought before the meeting pursuant to the
Corporation's notice of meeting pursuant to Article I, Section 4 of these By-
Laws. Nominations of persons for election to the Board of Directors may be made
at a special meeting of stockholders at which directors are to be elected
pursuant to the Corporation's notice of meeting (1) by or at the direction of
the Board of Directors or (2) by any stockholder of the Corporation who is
entitled to vote at the meeting, who complies with the notice procedures set
forth in these By-Laws and who is a stockholder of record at the time such
notice is delivered to the Secretary of the Corporation. Nominations by
stockholders of persons for election to the Board of Directors may be made at
such a special meeting of stockholders if the stockholder's notice as required
by paragraph (C) of Section 2 shall be delivered to the Secretary at the
principal executive offices of the Corporation not earlier than the ninetieth
day prior to such special meeting and not later than the close of business on
the later of the seventieth day prior to such special meeting or the tenth day
following the day on which public announcement is first made of the date of the
special meeting and of the nominees proposed by the Board of Directors to be
elected at such meeting.

         Section 1.4. Notice. Except as otherwise provided by law, at least ten
(10) and not more than sixty (60) days before each meeting of stockholders,
written notice of the time, date and place of the meeting, and, in the case of a
special meeting, the purpose or purposes for which the meeting is called, shall
be given to each stockholder.

                                      -2-


         Section 1.5. Quorum. At any meeting of stockholders, the holders of
record, present in person or by proxy, of a majority of the Corporation's issued
and outstanding capital stock shall constitute a quorum for the transaction of
business, except as otherwise provided by law. In the absence of a quorum, any
officer entitled to preside at or to act as secretary of the meeting shall have
power to adjourn the meeting from time to time until a quorum is present.

         Section 1.6. Voting. Except as otherwise provided by law or by the
Charter, (a) all matters submitted to a meeting of stockholders, other than the
election of directors, shall be decided by vote of the holders of record of a
majority of the shares of the Corporation's issued and outstanding capital stock
present in person or represented by proxy at the meeting and entitled to vote on
the matter, and (b) directors shall be elected by a plurality of the votes of
the shares of the Corporation's issued and outstanding capital stock present in
person or represented by proxy at the meeting and entitled to vote on the
election of directors.

         Section 1.7. General. (A) Only persons who are nominated in accordance
with the procedures set forth in these By-Laws shall be eligible to serve as
directors and only such business shall be conducted at a meeting of stockholders
as shall have been brought before the meeting in accordance with the procedures
set forth in these By-Laws. Except as otherwise provided by law, the Certificate
of Incorporation or these By-Laws, the Chairman of the meeting shall have the
power and duty to determine whether a nomination or any business proposed to be
brought before the meeting was made in accordance with the procedures set forth
in this By-Law and, if any proposed nomination or business is not in compliance
with these By-Laws, to declare that such defective nomination shall be
disregarded or that such proposed business shall not be transacted.

         (B) For purposes of these By-Laws, "public announcement" shall mean
disclosure in a press release reported by the Dow Jones News Service, Associated
Press or comparable national news service or disclosure in a document publicly
filed by the Corporation with the Securities and Exchange Commission pursuant to
Section 13, 14 or 15(d) of the Exchange Act.

         (C) For purposes of this By-Law, no adjournment nor notice of
adjournment of any meeting shall be deemed to constitute a new notice of such
meeting for purposes of this Article, and in order for any notification required
to be delivered by a stockholder pursuant to this Article to be timely, such
notification must be delivered within the periods set forth above with respect
to the originally scheduled meeting. Subject to applicable law, the Board of
Directors may elect to postpone any previously scheduled meeting of
stockholders.

         (D) Notwithstanding the foregoing provisions of this Article, a
stockholder shall also comply with all applicable requirements of the Exchange
Act and the rules and regulations thereunder with respect to the matters set
forth in these By-Laws. Nothing in these By-Laws shall be deemed to affect any
rights of stockholders to request inclusion of proposals in the Corporation's
proxy statement pursuant to Rule 14a-8 under the Exchange Act.



                                      -3-


                                   ARTICLE II

                                    DIRECTORS

         Section 2.1. Number, Election and Removal of Directors. The number of
Directors that shall constitute the Board of Directors shall be not less than
three nor more than 15. Within the limits specified in the Charter, the number
of Directors shall be determined by the Board of Directors or by the
stockholders. The Directors shall be elected by the stockholders at their annual
meeting in the manner set forth in the Charter. Vacancies and newly created
directorships resulting from any increase in the number of Directors may be
filled pursuant to the terms of the Charter. Directors may be removed only for
cause, and only by the affirmative vote of at least 75 percent in voting power
of all shares of the Corporation entitled to vote generally in the election of
directors, voting as a single class.

         Section 2.2. Meetings. Regular meetings of the Board of Directors shall
be held at such times and places as may from time to time be fixed by the Board
of Directors or as may be specified in a notice of meeting. Special meetings of
the Board of Directors may be held at any time upon the call of the Chairman or
President and shall be called by the President or Secretary if directed by a
majority of the Directors. Telegraphic or written notice of each special meeting
of the Board of Directors shall be sent to each Director not less than two days
before such meeting. A meeting of the Board of Directors may be held without
notice immediately after the annual meeting of the stockholders. Notice need not
be given of regular meetings of the Board of Directors.

         Section 2.3. Quorum. One-third of the entire Board of Directors shall
constitute a quorum for the transaction of business. If a quorum is not present
at any meeting of the Board of Directors, the Directors present may adjourn the
meeting from time to time, without notice other than announcement at the
meeting, until such a quorum is present. Except as otherwise provided by law,
the Certificate of Incorporation of the Corporation, these By-Laws or any
contract or agreement to which the Corporation is a party, the act of a majority
of the Directors present at any meeting at which there is a quorum shall be the
act of the Board of Directors.

         Section 2.4. Committees of Directors. The Board of Directors may, by
resolution adopted by a majority of the entire Board, designate one or more
committees, including without limitation an Executive Committee, to have and
exercise such power and authority as the Board of Directors shall specify. In
the absence or disqualification of a member of a committee, the member or
members thereof present at any meeting and not disqualified from voting, whether
or not he or they constitute a quorum, may unanimously appoint another Director
to act at the meeting in place of any such absent or disqualified member.

                                  ARTICLE III

                                    OFFICERS

         Section 3.1. General. The officers of the Corporation shall consist of
a Chairman of the Board of Directors, a Chief Executive Officer, a President,
one or more Vice



                                      -4-


Presidents, a Secretary, a Treasurer and such other additional officers with
such titles (including, without limitation, a Chief Operating Officer and a
Chief Financial Officer) as the Board of Directors shall from time to time
determine, all of whom shall be elected by and shall serve at the pleasure of
the Board of Directors. Subject to applicable law, an officer may hold more than
one office, if so elected by the Board of Directors. Such officers shall have
the usual powers and shall perform all the usual duties incident to their
respective offices. Such officers shall also have such powers and duties as from
time to time may be conferred by the Board of Directors. All officers shall be
subject to the supervision and direction of the Board of Directors. The Chairman
of the Board shall be chosen from among the directors. The Board of Directors
may from time to time elect, or the Chief Executive Officer or President may
appoint, such other officers (including one or more Assistant Vice Presidents,
Assistant Secretaries, Assistant Treasurers, and Assistant Controllers) and such
agents, as may be necessary or desirable for the conduct of the business of the
Corporation. Such other officers and agents shall have such duties and shall
hold their offices for such terms as may be prescribed by the Board of Directors
or by the Chief Executive Officer or President, as the case may be. The officers
of the Corporation need not be stockholders of the Corporation nor, except in
the case of the Chairman of the Board, need such officers be directors of the
Corporation.

         Section 3.2. Election and Term of Office. The officers of the
Corporation shall be elected annually by the Board of Directors at the regular
meeting of the Board of Directors held after the annual meeting of stockholders.
If the election of officers shall not be held at such meeting, such election
shall be held as soon thereafter as convenient. Each officer shall hold office
until his successor shall have been duly elected and shall have qualified or
until his death or until he shall resign, but any officer may be removed from
office at any time as provided in Section 3.3.

         Section 3.3. Removal. Any officer elected, or agent appointed, by the
Board of Directors may be removed by the affirmative vote of a majority of the
entire Board of Directors whenever, in their judgment, the best interests of the
Corporation would be served thereby. Any officer or agent appointed by the Chief
Executive Officer or the President may be removed by the Chief Executive Officer
or the President, as the case may be, whenever, in such officer's judgment, the
best interests of the Corporation would be served thereby. Such removal shall be
without prejudice to the contractual rights, if any, of the person so removed;
provided that no elected officer shall have any contractual rights against the
Corporation for compensation beyond the date of the election of his successor,
his death, his resignation or his removal, whichever event shall first occur,
except as otherwise provided in an employment contract or under an employee
deferred compensation plan.

         Section 3.4. Vacancies. A newly created elected office and a vacancy in
any elected office because of death, resignation, or removal may be filled by
the Board of Directors for the unexpired portion of the term at any meeting of
the Board of Directors. Any vacancy in an office appointed by the Chief
Executive Officer or the President because of death, resignation, or removal may
be filled by the Chief Executive Officer or the President.



                                      -5-


                                   ARTICLE IV

                                 INDEMNIFICATION

         To the fullest extent permitted by the Delaware General Corporation
Law, the Corporation shall indemnify any current or former Director or officer
of the Corporation and may, at the discretion of the Board of Directors,
indemnify any current or former employee or agent of the Corporation against all
expenses, judgments, fines and amounts paid in settlement actually and
reasonably incurred by him in connection with any threatened, pending or
completed action, suit or proceeding brought by or in the right of the
Corporation or otherwise, to which he was or is a party or is threatened to be
made a party by reason of his current or former position with the Corporation or
by reason of the fact that he is or was serving, at the request of the
Corporation, as a director, officer, partner, trustee, employee or agent of
another corporation, partnership, joint venture, trust or other enterprise.

                                   ARTICLE V

                               GENERAL PROVISIONS

         Section 5.1. Notices. Whenever any statute, the Certificate of
Incorporation or these By-Laws require notice to be given to any Director or
stockholder, such notice may be given in writing by mail, addressed to such
Director or stockholder at his address as it appears on the records of the
Corporation, with postage thereon prepaid. Such notice shall be deemed to have
been given when it is deposited in the United States mail. Notice to Directors
may also be given by telegram.

         Section 5.2. Fiscal Year. The fiscal year of the Corporation shall be
fixed by the Board of Directors.



                                      -6-

EX-4.9

                                                                     EXHIBIT 4.9

                          FIFTH SUPPLEMENTAL INDENTURE

      FIFTH SUPPLEMENTAL INDENTURE (this "Supplemental Indenture"), dated as of
October 18, 2004, by and among the entities listed on Schedule 1 attached hereto
(the "Guaranteeing Subsidiaries"), each being a subsidiary of Peabody Energy
Corporation (or its permitted successor), a Delaware corporation (the
"Company"), the Company, the other Subsidiary Guarantors (as defined in the
Indenture referred to herein) and US Bank National Association, as Trustee under
the Indenture referred to below (the "Trustee").

                                   WITNESSETH

      WHEREAS, the Company has heretofore executed and delivered to the Trustee
an Indenture (the "Indenture"), dated as of March 21, 2003 providing for the
issuance of an unlimited amount of 6-7/8% Notes due 2013 (the "Notes"), as
supplemented by a First Supplemental Indenture, dated as of May 7, 2003; Second
Supplemental Indenture, dated as of September 30, 2003; and Third Supplemental
Indenture, dated as of February 24, 2004; and Fourth Supplemental Indenture,
dated April 22, 2004;

      WHEREAS, the Indenture provides that under certain circumstances the
Guaranteeing Subsidiaries shall execute and deliver to the Trustee a
supplemental indenture pursuant to which the Guaranteeing Subsidiaries shall
unconditionally guarantee all of the Company's Obligations under the Notes on
the terms and conditions set forth herein (the "Subsidiary Guarantee"); and

      WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is
authorized to execute and deliver this Supplemental Indenture.

      NOW THEREFORE, in consideration of the foregoing and for other good and
valuable consideration, the receipt of which is hereby acknowledged, the
Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the
equal and ratable benefit of the Holders of the Notes as follows:

      1.    CAPITALIZED TERMS. Capitalized terms used herein without definition
shall have the meanings assigned to them in the Indenture.

      2.    AGREEMENT TO GUARANTEE. The Guaranteeing Subsidiaries hereby agree
as follows:

            (a)   Along with all Subsidiary Guarantors named in the Indenture,
                  to jointly and severally Guarantee to each Holder of a Note
                  authenticated and delivered by the Trustee and to the Trustee
                  and its successors and assigns, irrespective of the validity
                  and enforceability of the Indenture, the Notes or the
                  obligations of the Company hereunder or thereunder, that:


                  (i)   the principal of and interest on the Notes will be
                        promptly paid in full when due, whether at maturity, by
                        acceleration, redemption or otherwise, and interest on
                        the overdue principal of and interest on the Notes, if
                        any, if lawful, and all other obligations of the Company
                        to the Holders or the Trustee hereunder or thereunder
                        will be promptly paid in full or performed, all in
                        accordance with the terms hereof and thereof; and

                  (ii)  in case of any extension of time of payment or renewal
                        of any Notes or any of such other obligations, that same
                        will be promptly paid in full when due or performed in
                        accordance with the terms of the extension or renewal,
                        whether at stated maturity, by acceleration or
                        otherwise.

                  Failing payment when due of any amount so guaranteed or any
                  performance so guaranteed for whatever reason, the Subsidiary
                  Guarantors shall be jointly and severally obligated to pay the
                  same immediately. Each Subsidiary Guarantor agrees that this
                  is a guarantee of payment and not a guarantee of collection.

            (b)   The obligations hereunder shall be joint and several and
                  unconditional, irrespective of the validity or enforceability
                  of the Notes or the obligations of the Company under the
                  Indenture, the absence of any action to enforce the same, any
                  waiver or consent by any Holder of the Notes with respect to
                  any provisions hereof or thereof, the recovery of any judgment
                  against the Company, any action to enforce the same or any
                  other circumstance which might otherwise constitute a legal or
                  equitable discharge or defense of a Subsidiary Guarantor.

            (c)   The following is hereby waived: diligence, presentment, demand
                  of payment, filing of claims with a court in the event of
                  insolvency or bankruptcy of the Company, any right to require
                  a proceeding first against the Company, protest, notice and
                  all demands whatsoever.

            (d)   This Subsidiary Guarantee shall not be discharged except by
                  complete performance of the obligations contained in the Notes
                  and the Indenture.

            (e)   If any Holder or the Trustee is required by any court or
                  otherwise to return to the Company, the Subsidiary Guarantors,
                  or any custodian, Trustee, liquidator or other similar
                  official acting in relation to either the Company or the
                  Subsidiary Guarantors, any amount paid by either to the
                  Trustee or such Holder, this Subsidiary Guarantee, to the
                  extent theretofore discharged, shall be reinstated in full
                  force and effect.

                                       2


            (f)   The Guaranteeing Subsidiaries shall not be entitled to any
                  right of subrogation in relation to the Holders in respect of
                  any obligations guaranteed hereby until payment in full of all
                  obligations guaranteed hereby.

            (g)   As between the Subsidiary Guarantors, on the one hand, and the
                  Holders and the Trustee, on the other hand, (x) the maturity
                  of the obligations guaranteed hereby may be accelerated as
                  provided in Article 6 of the Indenture for the purposes of
                  this Subsidiary Guarantee, notwithstanding any stay,
                  injunction or other prohibition preventing such acceleration
                  in respect of the obligations guaranteed hereby, and (y) in
                  the event of any declaration of acceleration of such
                  obligations as provided in Article 6 of the Indenture, such
                  obligations (whether or not due and payable) shall forthwith
                  become due and payable by the Subsidiary Guarantors for the
                  purpose of this Subsidiary Guarantee.

            (h)   The Subsidiary Guarantors shall have the right to seek
                  contribution from any non-paying Subsidiary Guarantor so long
                  as the exercise of such right does not impair the rights of
                  the Holders under the Subsidiary Guarantee.

            (i)   Pursuant to Section 10.04 of the Indenture, after giving
                  effect to any maximum amount and any other contingent and
                  fixed liabilities that are relevant under any applicable
                  Bankruptcy or fraudulent conveyance laws, and after giving
                  effect to any collections from, rights to receive contribution
                  from or payments made by or on behalf of any other Subsidiary
                  Guarantor in respect of the obligations of such other
                  Subsidiary Guarantor under Article 10 of the Indenture shall
                  result in the obligations of such Subsidiary Guarantor under
                  Subsidiary Guarantee not constituting a fraudulent transfer or
                  conveyance.

      3.    EXECUTION AND DELIVERY. Each of the Guaranteeing Subsidiaries agrees
that the Subsidiary Guarantees shall remain in full force and effect
notwithstanding any failure to endorse on each Note a notation of such
Subsidiary Guarantee.

      4.    GUARANTEEING SUBSIDIARY MAY CONSOLIDATE, ETC. ON CERTAIN TERMS.

            (a)   The Guaranteeing Subsidiaries may not consolidate with or
                  merge with or into (whether or not such Senior Subordinated
                  Note Guarantor is the surviving Person) another corporation,
                  Person or entity whether or not affiliated with such
                  Subsidiary Guarantor unless:

                  (i)   subject to Section 10.04 of the Indenture, the Person
                        formed by or surviving any such consolidation or merger
                        (if other than a Subsidiary Guarantor or the Company)

                                       3


                        unconditionally assumes all the obligations of such
                        Subsidiary Guarantor, pursuant to a supplemental
                        Indenture in form and substance reasonably satisfactory
                        to the Trustee, under the Notes, the Indenture and the
                        Subsidiary Guarantee on the terms set forth herein or
                        therein; and

                  (ii)  immediately after giving effect to such transaction, no
                        Default or Event of Default exists.

            (b)   In case of any such consolidation, merger, sale or conveyance
                  and upon the assumption by the successor corporation, by
                  supplemental Indenture, executed and delivered to the Trustee
                  and satisfactory in form to the Trustee, of the Subsidiary
                  Guarantee endorsed upon the Notes and the due and punctual
                  performance of all of the covenants and conditions of the
                  Indenture to be performed by the Subsidiary Guarantor, such
                  successor corporation shall succeed to and be substituted for
                  the Subsidiary Guarantor with the same effect as if it had
                  been named herein as a Subsidiary Guarantor. Such successor
                  corporation thereupon may cause to be signed any or all of the
                  Subsidiary Guarantees to be endorsed upon all of the Notes
                  issuable hereunder which theretofore shall not have been
                  signed by the Company and delivered to the Trustee. All the
                  Subsidiary Guarantees so issued shall in all respects have the
                  same legal rank and benefit under the Indenture as the
                  Subsidiary Guarantees theretofore and thereafter issued in
                  accordance with the terms of the Indenture as though all of
                  such Subsidiary Guarantees had been issued at the date of the
                  execution hereof.

            (c)   Except as set forth in Articles 4 and 5 of the Indenture, and
                  notwithstanding clauses (a) and (b) above, nothing contained
                  in the Indenture or in any of the Notes shall prevent any
                  consolidation or merger of a Subsidiary Guarantor with or into
                  the Company or another Subsidiary Guarantor, or shall prevent
                  any sale or conveyance of the property of a Subsidiary
                  Guarantor as an entirety or substantially as an entirety to
                  the Company or another Subsidiary Guarantor.

      5.    RELEASES.

            (a)   In the event of a sale or other disposition of all of the
                  assets of any Subsidiary Guarantor, by way of merger,
                  consolidation or otherwise, or a sale or other disposition of
                  all to the capital stock of any Subsidiary Guarantor, then
                  such Subsidiary Guarantor (in the event of a sale or other
                  disposition, by way of merger, consolidation or otherwise, of
                  all of the capital stock of such Subsidiary

                                       4


                  Guarantor) or the corporation acquiring the property (in the
                  event of a sale or other disposition of all or substantially
                  all of the assets of such Subsidiary Guarantor) will be
                  released and relieved of any obligations under its Subsidiary
                  Guarantee; provided that the Net Proceeds of such sale or
                  other disposition are applied in accordance with the
                  applicable provisions of the Indenture, including without
                  limitation Section 4.10 of the Indenture. Upon delivery by the
                  Company to the Trustee of an Officer's Certificate and an
                  Opinion of Counsel to the effect that such sale or other
                  disposition was made by the Company in accordance with the
                  provisions of the Indenture, including without limitation
                  Section 4.10 of the Indenture, the Trustee shall execute any
                  documents reasonably required in order to evidence the release
                  of any Subsidiary Guarantor from its obligations under its
                  Subsidiary Guarantee.

            (b)   Any Subsidiary Guarantor not released from its obligations
                  under its Subsidiary Guarantee shall remain liable for the
                  full amount of principal of and interest on the Notes and for
                  the other obligations of any Subsidiary Guarantor under the
                  Indenture as provided in Article 10 of the Indenture.

      6.    NO RECOURSE AGAINST OTHERS. No past, present or future director,
officer, employee, incorporator, stockholder or agent of the Guaranteeing
Subsidiaries, as such, shall have any liability for any obligations of the
Company or any of the Guaranteeing Subsidiaries under the Notes, any Subsidiary
Guarantees, the Indenture or this Supplemental Indenture or for any claim based
on, in respect of, or by reason of, such obligations or their creation. Each
Holder of the Notes by accepting a Note waives and releases all such liability.
The waiver and release are part of the consideration for issuance of the Notes.
Such waiver may not be effective to waive liabilities under the federal
securities laws and it is the view of the Commission that such a waiver is
against public policy.

      7.    NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL
GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

      8.    COUNTERPARTS. The parties may sign any number of copies of this
Supplemental Indenture. Each signed copy shall be an original, but all of them
together represent the same agreement.

      9.    EFFECT OF HEADINGS. The Section headings herein are for convenience
only and shall not affect the construction hereof.

      10.   THE TRUSTEE. The Trustee shall not be responsible in any manner
whatsoever for or in respect of the validity or sufficiency of this Supplemental
Indenture or for or in respect of the recitals contained herein, all of which
recitals are made solely by the Guaranteeing Subsidiaries and the Company.

                                       5


      IN WITNESS WHEREOF, the parties hereto have caused this Supplemental
Indenture to be executed by their respective officers thereunto duly authorized,
as of the date first written above.

PEABODY ENERGY CORPORATION                 US BANK NATIONAL ASSOCIATION
("COMPANY")                                ("TRUSTEE")

By: /s/ WALTER L. HAWKINS, JR.             By: /s/ PHILIP G. KANE, JR.
   ------------------------------------        ---------------------------------
Name: Walter L. Hawkins, Jr.               Name: Philip G. Kane, Jr.

Title: Vice President and Treasurer        Title: Vice President

EXISTING SUBSIDIARY GUARANTORS:

                                       AFFINITY MINING COMPANY
                                       ARCLAR COMPANY, LLC
                                       ARID OPERATIONS INC.
                                       BEAVER DAM COAL COMPANY
                                       BIG RIDGE, INC.
                                       BIG SKY COAL COMPANY
                                       BLACK BEAUTY COAL COMPANY
                                       BLACK BEAUTY EQUIPMENT COMPANY
                                       BLACK BEAUTY HOLDING COMPANY, LLC
                                       BLACK BEAUTY MINING, INC.
                                       BLACK BEAUTY RESOURCES, INC.
                                       BLACK BEAUTY UNDERGROUND, INC.
                                       BLACK HILLS MINING COMPANY, LLC
                                       BLACK STALLION COAL COMPANY, LLC
                                       BLACK WALNUT COAL COMPANY
                                       BLUEGRASS COAL COMPANY
                                       BTU EMPIRE CORPORATION
                                       BTU VENEZUELA, LLC
                                       BTU WORLDWIDE, INC.
                                       CABALLO COAL COMPANY
                                       CHARLES COAL COMPANY
                                       CLEATON COAL COMPANY
                                       COAL PROPERTIES CORP.
                                       COLONY BAY COAL COMPANY
                                       COLORADO YAMPA COAL COMPANY
                                       COOK MOUNTAIN COAL COMPANY
                                       COTTONWOOD LAND COMPANY
                                       CYPRUS CREEK LAND COMPANY
                                       CYPRUS CREEK LAND RESOURCES, LLC
                                       EACC CAMPS, INC.
                                       EAGLE COAL COMPANY
                                       EASTERN ASSOCIATED COAL CORP.
                                       EASTERN ROYALTY CORP.
                                       EMPIRE MARINE, LLC
                                       FALCON COAL COMPANY
                                       GALLO FINANCE COMPANY
                                       GIBCO MOTOR EXPRESS, LLC
                                       GOLD FIELDS CHILE, S.A.
                                       GOLD FIELDS MINING CORPORATION
                                       GOLD FIELDS OPERATING CO. - ORTIZ

                                       6


                                       GRAND EAGLE MINING, INC.
                                       HAYDEN GULCH TERMINAL, INC.
                                       HIGHLAND MINING COMPANY
                                       HIGHWALL MINING SERVICES COMPANY
                                       HILLSIDE MINING COMPANY
                                       INDEPENDENCE MATERIAL HANDLING
                                          COMPANY
                                       INDIAN HILL COMPANY
                                       INTERIOR HOLDINGS CORP.
                                       JAMES RIVER COAL TERMINAL COMPANY
                                       JARRELL'S BRANCH COAL COMPANY
                                       JUNIPER COAL COMPANY
                                       KANAWHA RIVER VENTURES I, LLC
                                       KAYENTA MOBILE HOME PARK, INC.
                                       LOGAN FORK COAL COMPANY
                                       MARTINKA COAL COMPANY
                                       MIDCO SUPPLY AND EQUIPMENT
                                          CORPORATION
                                       MIDWEST COAL ACQUISITION CORP.
                                       MOUNTAIN VIEW COAL COMPANY
                                       MUSTANG ENERGY COMPANY, L.L.C.
                                       NORTH PAGE COAL CORP.
                                       OHIO COUNTY COAL COMPANY
                                       PATRIOT COAL COMPANY, L.P.
                                       PDC PARTNERSHIP HOLDINGS, INC.
                                       PEABODY AMERICA, INC.
                                       PEABODY ARCHVEYOR, L.L.C.
                                       PEABODY COAL COMPANY
                                       PEABODY COALSALES COMPANY
                                       PEABODY COALTRADE, INC.
                                       PEABODY DEVELOPMENT COMPANY,LLC
                                       PEABODY DEVELOPMENT LAND HOLDINGS, LLC
                                       PEABODY ENERGY GENERATION HOLDING COMPANY
                                       PEABODY ENERGY INVESTMENTS, INC.
                                       PEABODY ENERGY SOLUTIONS, INC.
                                       PEABODY HOLDING COMPANY, INC.
                                       PEABODY NATURAL GAS, LLC
                                       PEABODY NATURAL RESOURCES COMPANY
                                       PEABODY POWERTREE INVESTMENTS, LLC
                                       PEABODY RECREATIONAL LANDS, L.L.C.
                                       PEABODY SOUTHWESTERN COAL COMPANY
                                       PEABODY TERMINALS, INC.
                                       PEABODY VENEZUELA COAL CORP.
                                       PEABODY-WATERSIDE DEVELOPMENT, L.L.C.
                                       PEABODY WESTERN COAL COMPANY
                                       PEC EQUIPMENT COMPANY, LLC
                                       PINE RIDGE COAL COMPANY
                                       POINT PLEASANT DOCK COMPANY, LLC
                                       POND CREEK LAND RESOURCES, LLC
                                       POND RIVER LAND COMPANY
                                       PORCUPINE PRODUCTION, LLC
                                       PORCUPINE TRANSPORTATION, LLC
                                       POWDER RIVER COAL COMPANY
                                       PRAIRIE STATE GENERATING COMPANY, LLC
                                       RIO ESCONDIDO COAL CORP.
                                       RIVERS EDGE MINING, INC.
                                       RIVERVIEW TERMINAL COMPANY
                                       SENECA COAL COMPANY

                                       7


                                       SENTRY MINING COMPANY
                                       SHOSHONE COAL CORPORATION
                                       SNOWBERRY LAND COMPANY
                                       STAR LAKE ENERGY COMPANY, L.L.C.
                                       STERLING SMOKELESS COAL COMPANY
                                       SUGAR CAMP PROPERTIES
                                       THOROUGHBRED, L.L.C.
                                       THOROUGHBRED GENERATING COMPANY, LLC
                                       THOROUGHBRED MINING COMPANY, L.L.C.
                                       TWENTYMILE COAL COMPANY
                                       WILLIAMSVILLE COAL COMPANY, LLC
                                       YANKEETOWN DOCK CORPORATION

                                       By: /s/ WALTER L. HAWKINS, JR.
                                          -------------------------------------
                                          Name: Walter L. Hawkins, Jr.
                                          Title:  Vice President

                                       8


NEW GUARANTEEING SUBSIDIARIES:

                                       APPALACHIA MINE SERVICES, LLC

                                       By: /s/ WALTER L. HAWKINS, JR.
                                           ------------------------------------
                                       Name: Walter L. Hawkins, Jr.
                                       Title: Vice President & Treasurer

                                       COAL RESERVES HOLDING LIMITED
                                       LIABILITY COMPANY NO. 1.

                                       By: /s/ WALTER L. HAWKINS, JR.
                                          -------------------------------------
                                       Name: Walter L. Hawkins, Jr.
                                       Title: Vice President & Treasurer

                                       COAL RESERVES HOLDING LIMITED
                                       LIABILITY COMPANY NO. 2.

                                       By: /s/ WALTER L. HAWKINS, JR.
                                          ---------------------------------
                                       Name: Walter L. Hawkins, Jr.
                                       Title: Vice President & Treasurer

                                       COALSALES, LLC

                                       By: /s/ WALTER L. HAWKINS, JR.
                                          ---------------------------------
                                       Name: Walter L. Hawkins, Jr.
                                       Title: Vice President & Treasurer

                                       PEABODY COALTRADE INTERNATIONAL, LLC

                                       By: /s/ WALTER L. HAWKINS, JR.
                                          ---------------------------------
                                       Name: Walter L. Hawkins, Jr.
                                       Title: Vice President & Treasurer

                                       9


                                   SCHEDULE 1

                          NEW GUARANTEEING SUBSIDIARIES

APPALACHIA MINE SERVICES, LLC, a Delaware Limited Liability Company
COAL RESERVES HOLDING LIMITED LIABILITY COMPANY NO. 1, a Delaware Limited
Liability Company
COAL RESERVES HOLDING LIMITED LIABILITY COMPANY NO. 2, a Delaware Limited
Liability Company
COALSALES, LLC, a Delaware Limited Liability Company
PEABODY COALTRADE INTERNATIONAL, LLC, a Delaware Limited Liability Company

                                       10

EX-4.13

                                                                    EXHIBIT 4.13

                          THIRD SUPPLEMENTAL INDENTURE

                  Third Supplemental Indenture (this "SUPPLEMENTAL INDENTURE"),
dated as of October 18, 2004, among the entities listed on Schedule 1 attached
hereto ("GUARANTEEING SUBSIDIARIES"), each being a subsidiary of Peabody Energy
Corporation (or its permitted successor), a Delaware corporation (the
"COMPANY"), the Company, the other Subsidiary Guarantors (as defined in the
Indenture referred to herein) and U.S. Bank National Association, as Trustee
under the Indenture referred to below (the "TRUSTEE").

                               W I T N E S S E T H

                  WHEREAS, the Company has heretofore executed and delivered to
the Trustee the First Supplemental Indenture dated as of March 23, 2004 to the
Indenture dated as of March 19, 2004, (the "BASE INDENTURE," and, together with
the First Supplemental Indenture, the "INDENTURE") providing for the issuance of
an unlimited amount of 5-7/8% Senior Notes due 2016 (the "NOTES"); as
supplemented by the Second Supplemental Indenture, dated as of April 22, 2004;

                  WHEREAS, the Indenture provides that under certain
circumstances the Guaranteeing Subsidiaries shall execute and deliver to the
Trustee a supplemental Indenture pursuant to which the Guaranteeing Subsidiaries
shall unconditionally guarantee all of the Company's Obligations under the Notes
and the Indenture on the terms and conditions set forth herein (the "SUBSIDIARY
GUARANTEE"); and

                  WHEREAS, pursuant to Section 9.01 of the Base Indenture, the
Trustee is authorized to execute and deliver this Supplemental Indenture.

                  NOW THEREFORE, in consideration of the foregoing and for other
good and valuable consideration, the receipt of which is hereby acknowledged,
the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for
the equal and ratable benefit of the Holders of the Notes as follows:

                  1.    CAPITALIZED TERMS. Capitalized terms used herein without
definition shall have the meanings assigned to them in the Indenture.

                  2.    AGREEMENT TO GUARANTEE. The Guaranteeing Subsidiaries
hereby agrees as follows:

                  (a)   Along with all Subsidiary Guarantors named in the
                        Indenture, to jointly and severally Guarantee to each
                        Holder of a Note authenticated and delivered by the
                        Trustee and to the Trustee and its successors and
                        assigns, irrespective of the validity and enforceability
                        of the Indenture, the Notes or the obligations of the
                        Company hereunder or thereunder, that:




                        (i)   the principal of and interest on the Notes will be
                              promptly paid in full when due, whether at
                              maturity, by acceleration, redemption or
                              otherwise, and interest on the overdue principal
                              of and interest on the Notes, if any, if lawful,
                              and all other obligations of the Company to the
                              Holders or the Trustee hereunder or thereunder
                              will be promptly paid in full or performed, all in
                              accordance with the terms hereof and thereof; and

                        (ii)  in case of any extension of time of payment or
                              renewal of any Notes or any of such other
                              obligations, that same will be promptly paid in
                              full when due or performed in accordance with the
                              terms of the extension or renewal, whether at
                              stated maturity, by acceleration or otherwise.
                              Failing payment when due of any amount so
                              guaranteed or any performance so guaranteed for
                              whatever reason, the Subsidiary Guarantors shall
                              be jointly and severally obligated to pay the same
                              immediately.

                  (b)   The obligations hereunder shall be unconditional,
                        irrespective of the validity, regularity or
                        enforceability of the Notes or the Indenture, the
                        absence of any action to enforce the same, any waiver or
                        consent by any Holder of the Notes with respect to any
                        provisions hereof or thereof, the recovery of any
                        judgment against the Company, any action to enforce the
                        same or any other circumstance which might otherwise
                        constitute a legal or equitable discharge or defense of
                        a Subsidiary Guarantor.

                  (c)   The following is hereby waived: diligence presentment,
                        demand of payment, filing of claims with a court in the
                        event of insolvency or bankruptcy of the Company, any
                        right to require a proceeding first against the Company,
                        protest, notice and all demands whatsoever.

                  (d)   This Subsidiary Guarantee shall not be discharged except
                        by complete performance of the obligations contained in
                        the Notes and the Indenture.

                  (e)   If any Holder or the Trustee is required by any court or
                        otherwise to return to the Company, the Subsidiary
                        Guarantors, or any custodian, Trustee, liquidator or
                        other similar official acting in relation to either the
                        Company or the Subsidiary Guarantors, any amount paid by
                        either to the Trustee or such Holder, this Subsidiary
                        Guarantee, to the extent theretofore discharged, shall
                        be reinstated in full force and effect.

                  (f)   The Guaranteeing Subsidiaries shall not be entitled to
                        any right of subrogation in relation to the Holders in
                        respect of any obligations

                                       2


                        guaranteed hereby until payment in full of all
                        obligations guaranteed hereby.

                  (g)   As between the Subsidiary Guarantors, on the one hand,
                        and the Holders and the Trustee, on the other hand, (x)
                        the maturity of the obligations guaranteed hereby may be
                        accelerated as provided in Article 6 of the First
                        Supplemental Indenture for the purposes of this
                        Subsidiary Guarantee, notwithstanding any stay,
                        injunction or other prohibition preventing such
                        acceleration in respect of the obligations guaranteed
                        hereby, and (y) in the event of any declaration of
                        acceleration of such obligations as provided in Article
                        6 of the First Supplemental Indenture, such obligations
                        (whether or not due and payable) shall forthwith become
                        due and payable by the Subsidiary Guarantors for the
                        purpose of this Subsidiary Guarantee.

                  (h)   The Subsidiary Guarantors shall have the right to seek
                        contribution from any non-paying Subsidiary Guarantor so
                        long as the exercise of such right does not impair the
                        rights of the Holders under the Subsidiary Guarantee.

                  (i)   Pursuant to Section 9.04 of the First Supplemental
                        Indenture, after giving effect to any maximum amount and
                        any other contingent and fixed liabilities that are
                        relevant under any applicable Bankruptcy or fraudulent
                        conveyance laws, and after giving effect to any
                        collections from, rights to receive contribution from or
                        payments made by or on behalf of any other Subsidiary
                        Guarantor in respect of the obligations of such other
                        Subsidiary Guarantor under Article 9 of the First
                        Supplemental Indenture shall result in the obligations
                        of such Subsidiary Guarantor under its Subsidiary
                        Guarantee not constituting a fraudulent transfer or
                        conveyance.

                  3.    EXECUTION AND DELIVERY. Each of the Guaranteeing
Subsidiaries agrees that the Subsidiary Guarantees shall remain in full force
and effect notwithstanding any failure to endorse on each Note a notation of
such Subsidiary Guarantee.

                  4.    GUARANTEEING SUBSIDIARY MAY CONSOLIDATE, ETC. ON CERTAIN
 TERMS.

                  (a)   The Guaranteeing Subsidiaries may not consolidate with
                        or merge with or into (whether or not such Subsidiary
                        Guarantor is the surviving Person) another corporation,
                        Person or entity whether or not affiliated with such
                        Subsidiary Guarantor unless:

                        (i)   subject to Section 9.04 of the First Supplemental
                              Indenture, the Person formed by or surviving any
                              such consolidation or merger (if other than a
                              Subsidiary Guarantor or the Company)
                              unconditionally assumes all the obligations of
                              such Subsidiary

                                       3


                              Guarantor, pursuant to a supplemental Indenture in
                              form and substance reasonably satisfactory to the
                              Trustee, under the Notes, the Indenture and the
                              Subsidiary Guarantee on the terms set forth herein
                              or therein; and

                        (ii)  immediately after giving effect to such
                              transaction, no Default or Event of Default
                              exists.

                  (b)   In case of any such consolidation, merger, sale or
                        conveyance and upon the assumption by the successor
                        corporation, by supplemental Indenture, executed and
                        delivered to the Trustee and satisfactory in form to the
                        Trustee, of the Subsidiary Guarantee endorsed upon the
                        Notes and the due and punctual performance of all of the
                        covenants and conditions of the Indenture to be
                        performed by the Subsidiary Guarantor, such successor
                        corporation shall succeed to and be substituted for the
                        Subsidiary Guarantor with the same effect as if it had
                        been named herein as a Subsidiary Guarantor. Such
                        successor corporation thereupon may cause to be signed
                        any or all of the Subsidiary Guarantees to be endorsed
                        upon all of the Notes issuable hereunder which
                        theretofore shall not have been signed by the Company
                        and delivered to the Trustee. All the Subsidiary
                        Guarantees so issued shall in all respects have the same
                        legal rank and benefit under the Indenture as the
                        Subsidiary Guarantees theretofore and thereafter issued
                        in accordance with the terms of the Indenture as though
                        all of such Subsidiary Guarantees had been issued at the
                        date of the execution hereof.

                  (c)   Except as set forth in Articles 4 and 5 of the First
                        Supplemental Indenture, and notwithstanding clauses (a)
                        and (b) above, nothing contained in the Indenture or in
                        any of the Notes shall prevent any consolidation or
                        merger of a Subsidiary Guarantor with or into the
                        Company or another Subsidiary Guarantor, or shall
                        prevent any sale or conveyance of the property of a
                        Subsidiary Guarantor as an entirety or substantially as
                        an entirety to the Company or another Subsidiary
                        Guarantor.

                  5.    RELEASES.

                  (a)   In the event of a sale or other disposition of all of
                        the assets of any Subsidiary Guarantor, by way of
                        merger, consolidation or otherwise, or a sale or other
                        disposition of all to the capital stock of any
                        Subsidiary Guarantor, then such Subsidiary Guarantor (in
                        the event of a sale or other disposition, by way of
                        merger, consolidation or otherwise, of all of the
                        capital stock of such Subsidiary Guarantor) or the
                        corporation acquiring the property (in the event of a
                        sale or other disposition of all or substantially all of
                        the assets of such Subsidiary Guarantor) will be

                                       4


                        released and relieved of any obligations under its
                        Subsidiary Guarantee; provided that the Net Proceeds of
                        such sale or other disposition are applied in accordance
                        with the applicable provisions of the Indenture,
                        including without limitation Section 4.10 of the
                        Indenture. Upon delivery by the Company to the Trustee
                        of an Officer's Certificate and an Opinion of Counsel to
                        the effect that such sale or other disposition was made
                        by the Company in accordance with the provisions of the
                        Indenture, including without limitation Section 4.10 of
                        the First Supplemental Indenture, the Trustee shall
                        execute any documents reasonably required in order to
                        evidence the release of any Subsidiary Guarantor from
                        its obligations under its Subsidiary Guarantee.

                  (b)   Any Subsidiary Guarantor not released from its
                        obligations under its Subsidiary Guarantee shall remain
                        liable for the full amount of principal of and interest
                        on the Notes and for the other obligations of any
                        Subsidiary Guarantor under the Indenture as provided in
                        Article 9 of the First Supplemental Indenture.

                  6.    NO RECOURSE AGAINST OTHERS. No past, present or future
director, officer, employee, incorporator, stockholder or agent of the
Guaranteeing Subsidiaries, as such, shall have any liability for any obligations
of the Company or any Guaranteeing Subsidiaries under the Notes, any Subsidiary
Guarantees, the Indenture or this Supplemental Indenture or for any claim based
on, in respect of, or by reason of, such obligations or their creation. Each
Holder of the Notes by accepting a Note waives and releases all such liability.
The waiver and release are part of the consideration for issuance of the Notes.
Such waiver may not be effective to waive liabilities under the federal
securities laws and it is the view of the Commission that such a waiver is
against public policy.

                  7.    NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK
SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

                  8.    COUNTERPARTS. The parties may sign any number of copies
of this Supplemental Indenture. Each signed copy shall be an original, but all
of them together represent the same agreement.

                  9.    EFFECT OF HEADINGS. The Section headings herein are for
convenience only and shall not affect the construction hereof.

                  10.   THE TRUSTEE. The Trustee shall not be responsible in any
manner whatsoever for or in respect of the validity or sufficiency of this
Supplemental Indenture or for or in respect of the recitals contained herein,
all of which recitals are made solely by the Guaranteeing Subsidiaries and the
Company.

                                       5


                  IN WITNESS WHEREOF, the parties hereto have caused this
Supplemental Indenture to be duly executed and attested, all as of the date
first above written.

PEABODY ENERGY CORPORATION                 US BANK NATIONAL ASSOCIATION
("COMPANY")                                ("TRUSTEE")

By: /s/ WALTER L. HAWKINS, JR.             By: /s/ PHILIP G. KANE, JR.
    ---------------------------------          ---------------------------------
Name: Walter L. Hawkins, Jr.               Name: Philip G. Kane, Jr.

Title: Vice President and Treasurer        Title: Vice President

EXISTING SUBSIDIARY GUARANTORS:

                                           AFFINITY MINING COMPANY
                                           ARCLAR COMPANY, LLC
                                           ARID OPERATIONS INC.
                                           BEAVER DAM COAL COMPANY
                                           BIG RIDGE, INC.
                                           BIG SKY COAL COMPANY
                                           BLACK BEAUTY COAL COMPANY
                                           BLACK BEAUTY EQUIPMENT COMPANY
                                           BLACK BEAUTY HOLDING COMPANY, LLC
                                           BLACK BEAUTY MINING, INC.
                                           BLACK BEAUTY RESOURCES, INC.
                                           BLACK BEAUTY UNDERGROUND, INC.
                                           BLACK HILLS MINING COMPANY, LLC
                                           BLACK STALLION COAL COMPANY, LLC
                                           BLACK WALNUT COAL COMPANY
                                           BLUEGRASS COAL COMPANY
                                           BTU EMPIRE CORPORATION
                                           BTU VENEZUELA, LLC
                                           BTU WORLDWIDE, INC.
                                           CABALLO COAL COMPANY
                                           CHARLES COAL COMPANY
                                           CLEATON COAL COMPANY
                                           COAL PROPERTIES CORP.
                                           COLONY BAY COAL COMPANY
                                           COLORADO YAMPA COAL COMPANY
                                           COOK MOUNTAIN COAL COMPANY
                                           COTTONWOOD LAND COMPANY
                                           CYPRUS CREEK LAND COMPANY
                                           CYPRUS CREEK LAND RESOURCES, LLC
                                           EACC CAMPS, INC.
                                           EAGLE COAL COMPANY
                                           EASTERN ASSOCIATED COAL CORP.

                                       6


                                           EASTERN ROYALTY CORP.
                                           EMPIRE MARINE, LLC
                                           FALCON COAL COMPANY
                                           GALLO FINANCE COMPANY
                                           GIBCO MOTOR EXPRESS, LLC
                                           GOLD FIELDS CHILE, S.A.
                                           GOLD FIELDS MINING CORPORATION
                                           GOLD FIELDS OPERATING CO. - ORTIZ
                                           GRAND EAGLE MINING, INC.
                                           HAYDEN GULCH TERMINAL, INC.
                                           HIGHLAND MINING COMPANY
                                           HIGHWALL MINING SERVICES COMPANY
                                           HILLSIDE MINING COMPANY
                                           INDEPENDENCE MATERIAL HANDLING
                                              COMPANY
                                           INDIAN HILL COMPANY
                                           INTERIOR HOLDINGS CORP.
                                           JAMES RIVER COAL TERMINAL COMPANY
                                           JARRELL'S BRANCH COAL COMPANY
                                           JUNIPER COAL COMPANY
                                           KANAWHA RIVER VENTURES I, LLC
                                           KAYENTA MOBILE HOME PARK, INC.
                                           LOGAN FORK COAL COMPANY
                                           MARTINKA COAL COMPANY
                                           MIDCO SUPPLY AND EQUIPMENT
                                              CORPORATION
                                           MIDWEST COAL ACQUISITION CORP.
                                           MOUNTAIN VIEW COAL COMPANY
                                           MUSTANG ENERGY COMPANY, L.L.C.
                                           NORTH PAGE COAL CORP.
                                           OHIO COUNTY COAL COMPANY
                                           PATRIOT COAL COMPANY, L.P.
                                           PDC PARTNERSHIP HOLDINGS, INC.
                                           PEABODY AMERICA, INC.
                                           PEABODY ARCHVEYOR, L.L.C.
                                           PEABODY COAL COMPANY
                                           PEABODY COALSALES COMPANY
                                           PEABODY COALTRADE, INC.
                                           PEABODY DEVELOPMENT COMPANY,LLC
                                           PEABODY DEVELOPMENT LAND HOLDINGS,
                                           LLC
                                           PEABODY ENERGY GENERATION HOLDING
                                           COMPANY
                                           PEABODY ENERGY INVESTMENTS, INC.
                                           PEABODY ENERGY SOLUTIONS, INC

                                       7


                                           PEABODY HOLDING COMPANY, INC.
                                           PEABODY NATURAL GAS, LLC
                                           PEABODY NATURAL RESOURCES COMPANY
                                           PEABODY POWERTREE INVESTMENTS, LLC
                                           PEABODY RECREATIONAL LANDS, L.L.C.
                                           PEABODY SOUTHWESTERN COAL COMPANY
                                           PEABODY TERMINALS, INC.
                                           PEABODY VENEZUELA COAL CORP.
                                           PEABODY-WATERSIDE DEVELOPMENT, L.L.C.
                                           PEABODY WESTERN COAL COMPANY
                                           PEC EQUIPMENT COMPANY, LLC
                                           PINE RIDGE COAL COMPANY
                                           POINT PLEASANT DOCK COMPANY, LLC
                                           POND CREEK LAND RESOURCES, LLC
                                           POND RIVER LAND COMPANY
                                           PORCUPINE PRODUCTION, LLC
                                           PORCUPINE TRANSPORTATION, LLC
                                           POWDER RIVER COAL COMPANY
                                           PRAIRIE STATE GENERATING COMPANY, LLC
                                           RIO ESCONDIDO COAL CORP.
                                           RIVERS EDGE MINING, INC.
                                           RIVERVIEW TERMINAL COMPANY
                                           SENECA COAL COMPANY
                                           SENTRY MINING COMPANY
                                           SHOSHONE COAL CORPORATION
                                           SNOWBERRY LAND COMPANY
                                           STAR LAKE ENERGY COMPANY, L.L.C.
                                           STERLING SMOKELESS COAL COMPANY
                                           SUGAR CAMP PROPERTIES
                                           THOROUGHBRED, L.L.C.
                                           THOROUGHBRED GENERATING COMPANY, LLC
                                           THOROUGHBRED MINING COMPANY, L.L.C.
                                           TWENTYMILE COAL COMPANY
                                           WILLIAMSVILLE COAL COMPANY, LLC
                                           YANKEETOWN DOCK CORPORATION

                                           By: /s/ WALTER L. HAWKINS, JR.
                                               --------------------------------

                                               Name: Walter L. Hawkins, Jr.

                                               Title: Vice President

                                       8


NEW GUARANTEEING SUBSIDIARIES:

                                           APPALACHIA MINE SERVICES, LLC

                                           By: /s/ WALTER L. HAWKINS, JR.
                                               ---------------------------------
                                           Name: Walter L. Hawkins, Jr.
                                           Title: Vice President & Treasurer

                                           COAL RESERVES HOLDING LIMITED
                                           LIABILITY COMPANY NO. 1.

                                           By: /s/ WALTER L. HAWKINS, JR.
                                               ---------------------------------
                                           Name: Walter L. Hawkins, Jr.
                                           Title: Vice President & Treasurer

                                           COAL RESERVES HOLDING LIMITED
                                           LIABILITY COMPANY NO. 2.

                                           By: /s/ WALTER L. HAWKINS, JR.
                                               ---------------------------------
                                           Name: Walter L. Hawkins, Jr.
                                           Title: Vice President & Treasurer

                                           COALSALES, LLC

                                           By: /s/ WALTER L. HAWKINS, JR.
                                               ---------------------------------
                                           Name: Walter L. Hawkins, Jr.
                                           Title: Vice President & Treasurer

                                           PEABODY COALTRADE INTERNATIONAL, LLC

                                           By: /s/ WALTER L. HAWKINS, JR.
                                              ----------------------------------
                                           Name: Walter L. Hawkins, Jr.
                                           Title: Vice President & Treasurer

                                       9


                                   SCHEDULE 1

                          NEW GUARANTEEING SUBSIDIARIES

APPALACHIA MINE SERVICES, LLC, a Delaware Limited Liability Company
COAL RESERVES HOLDING LIMITED LIABILITY COMPANY NO. 1, a Delaware Limited
Liability Company
COAL RESERVES HOLDING LIMITED LIABILITY COMPANY NO. 2, a Delaware Limited
Liability Company
COALSALES, LLC, a Delaware Limited Liability Company
PEABODY COALTRADE INTERNATIONAL, LLC, a Delaware Limited Liability Company

                                       10

EX-10.4

                                                                    EXHIBIT 10.4

              AMENDMENT NO. 3 TO SECOND AMENDED AND RESTATED CREDIT
                                   AGREEMENT
                          DATED AS OF OCTOBER 27, 2004

        This AMENDMENT NO. 3 TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT
(this "Amendment") is among PEABODY ENERGY CORPORATION, a Delaware corporation
(the "Borrower"), the Lenders (as defined below), FLEET NATIONAL BANK, as
administrative agent (in such capacity, the "Administrative Agent"), and
WACHOVIA BANK, NATIONAL ASSOCIATION, as syndication agent.

                             PRELIMINARY STATEMENTS:

                1. The Borrower, the Lenders and the Administrative Agent have
entered into that certain Second Amended and Restated Credit Agreement, dated as
of March 21, 2003, by and among the Borrower, the several lenders from time to
time parties thereto (the "Lenders"), Wachovia Bank, National Association and
Lehman Commercial Paper Inc., as syndication agents, Banc of America Securities
LLC (formerly known as Fleet Securities, Inc.), Wachovia Capital Markets, LLC
(formerly known as Wachovia Securities, Inc.) and Lehman Brothers Inc., as
arrangers, Morgan Stanley Senior Funding, Inc. and U.S. Bank National
Association, as documentation agents, and the Administrative Agent (as amended
through the date hereof, the "Credit Agreement"; capitalized terms used and not
otherwise defined herein have the meanings assigned to such terms in the Credit
Agreement).

                2. The Borrower has requested that the Lenders amend the Credit
Agreement to, among other things, (i) reduce the Applicable Margin on the Loans
and the Revolving Credit Commitment fee rate and (ii) extend the Revolving Loan
Termination Date.

                3. Subject to the terms and conditions set forth below, and in
consideration of certain agreements of the Borrower and other Credit Parties set
forth herein and in the accompanying Consent of Credit Parties, the
Administrative Agent, the Syndication Agent and the requisite Lenders are
willing to agree to the amendment described below.

        NOW, THEREFORE, in consideration of the premises and for other good and
valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:

                SECTION 1 Amendments to Credit Agreement. Upon the satisfaction
of the applicable conditions precedent set forth in Section 2, the Credit
Agreement is hereby amended as follows:

        (a) The following new definitions are hereby added to subsection 1.1 of
the Credit Agreement:

                "Additional Term Loan": the Loans made by any Lender to the
                Borrower pursuant to subsection 2.1(a)(iii).



                "Additional Term Loan Commitment": the commitment of a Lender
                set forth on Schedule 1 to the Lender Addendum delivered by such
                Lender to make an Additional Term Loan to the Borrower pursuant
                to subsection 2.1(a)(iii).

                "Third Amendment Effective Date": the date on which the
                amendments contained in Section 1 of the Third Amendment became
                effective in accordance with its terms, which for all purposes
                under this Agreement will be deemed to be October 27, 2004.

                "Third Amendment": Amendment No. 3 to this Agreement, dated as
                of October 27, 2004.

        (b) The definition of "Revolving Loan Termination Date" contained in
subsection 1.1 of the Credit Agreement is hereby amended and restated in its
entirety as follows:

                "Revolving Loan Termination Date": March 21, 2010.

        (c) The definition of "Commitment Fee Rate" contained in subsection 1.1
of the Credit Agreement is hereby amended and restated in its entirety as
follows:

                "Commitment Fee Rate": at any time, the rate per annum set forth
                on Schedule I, under the relevant column heading opposite the
                level of the Consolidated Total Obligations to Consolidated
                EBITDA Ratio most recently determined.

        (d) The definition of "Usage Ratio" contained in subsection 1.1 of the
Credit Agreement is hereby deleted in its entirety.

        (e) The definition of "Existing Securitization" contained in subsection
1.1 of the Credit Agreement is hereby amended and restated in its entirety as
follows:

                "Existing Securitization": the accounts receivable
                securitization financing of P&L Receivables Company LLC,
                existing as of the Third Amendment Effective Date in an
                aggregate amount of up to $225,000,000.

        (f) The definition of "Specified Hedge Agreement" contained in
subsection 1.1 of the Credit Agreement is hereby amended to delete the words
"and the Syndication Agents" where they appear therein.

        (g) The definition of "Term Loans" contained in subsection 1.1 of the
Credit Agreement is hereby amended to add the following text at the end thereof:

                ", and after the Third Amendment Effective Date, Additional Term
                Loans made by Lenders to the Borrower pursuant to subsection
                2.1(a)(iii) shall be deemed to be Term Loans for all purposes
                hereunder."



                                       2


        (h) The definition of Term Loan Commitment contained in subsection 1.1
of the Credit Agreement is hereby amended to replace the words "pursuant to
subsection 2.1(a)(i); and "Term Loan Commitments" means such commitments of all
Term Lenders in the aggregate, which shall be $450,000,000" with the following
text:

                "pursuant to subsection 2.1(a)(i) or after the Third Amendment
                Effective Date, Additional Term Loans pursuant to subsection
                2.1(a)(iii); and "Term Loan Commitments" means such commitments
                of all Term Lenders in the aggregate, which as of the Third
                Amendment Effective Date shall be $450,000,000."

        (i) Subsection 2.1(a) of the Credit Agreement is hereby amended to add
the following new subsection (iii):

                "(iii) Additional Term Loans. Each Lender severally agrees to
                make a term loan to the Borrower on the Third Amendment
                Effective Date in an aggregate principal amount equal to such
                Lender's Additional Term Loan Commitment. Amounts borrowed under
                this subsection 2.1(a)(iii) and subsequently repaid may not be
                reborrowed."

        (j) Subsection 2.5(a) of the Credit Agreement is hereby amended to
replace the table therein with the following table:




                                         Scheduled Repayment of
Payment Date                                  Term Loans
- ------------                                  ----------
                                           
  12/31/04                                    $1,250,000
  3/31/05                                     $1,250,000
  6/30/05                                     $1,250,000
  9/30/05                                     $1,250,000
  12/31/05                                    $2,500,000
  3/31/06                                     $2,500,000
  6/30/06                                     $2,500,000
  9/30/06                                     $2,500,000
  12/31/06                                    $3,125,000
  3/31/07                                     $3,125,000
  6/30/07                                     $3,125,000
  9/30/07                                     $3,125,000
  12/31/07                                    $3,750,000
  3/31/08                                     $3,750,000
  6/30/08                                     $3,750,000
  9/30/08                                     $3,750,000
  12/31/08                                    $3,750,000
  3/31/09                                     $3,750,000
  6/30/09                                     $100,000,000
  9/30/09                                     $100,000,000
  12/31/09                                    $100,000,000
  Termination Date                            $100,000,000




                                       3


        (k) Subsection 7.8 of the Credit Agreement is hereby amended to replace
the number "$350,000,000 with the number "$450,000,000".

        (l) Subsection 7.9(l) of the Credit Agreement is hereby amended and
restated in its entirety to read as follows:

                "(l) In addition to investments permitted under subsection
                7.9(o), and, with respect to Credit Parties that are not Blanket
                Grantors under subsection 7.9(j), (i) Investments not to exceed
                $150,000,000 per fiscal year in Restricted and Unrestricted
                Subsidiaries for the purpose of making payments under federal
                coal leases and (ii) other Investments in Unrestricted
                Subsidiaries, Restricted Subsidiaries and Credit Parties which
                are not Blanket Grantors, in an amount not to exceed in the
                aggregate outstanding at any time under this clause (ii) (net of
                dividends and other distributions paid in respect thereof) five
                percent (5%) of the Total Assets of the Borrower and its
                Restricted Subsidiaries (determined immediately prior to the
                time of each such Investment);"

        (m) Subsection 10.1 of the Credit Agreement is hereby amended to (i)
delete the third sentence thereof in its entirety and (ii) delete the words ",
the Syndication Agents" in the last sentence thereof.

        (n) Schedule I to the Credit Agreement is hereby amended and restated in
its entirety as the Schedule I attached hereto as Exhibit A.

                SECTION 2 Conditions to Effectiveness of Amendments. The
effectiveness of the amendments contained in Section 1 of this Amendment is
conditioned upon satisfaction of the following conditions precedent:

        (a) the Administrative Agent shall have received (i) signed written
authorization from the Required Lenders to execute this Amendment and
counterparts of this Amendment signed by the Borrower and counterparts of the
Consent of Credit Parties attached hereto (the "CONSENT") signed by the Credit
Parties and (ii) unless otherwise waived by the Administrative Agent, a fully
executed Assignment and Acceptance from each Lender (including without
limitation from each Nonconsenting Lender);

        (b) each of the representations and warranties in Section 3 below shall
be true and correct in all material respects as of the date on which such
amendment becomes effective;

        (c) the Administrative Agent shall have received payment in immediately
available funds of all reasonable out-of-pocket costs and expenses incurred by
the Administrative Agent (including, without limitation, legal fees) and by
Wachovia Bank, National Association, in each case, for which invoices have been
presented;

        (d) the Administrative Agent shall have received the executed legal
opinion of (x) Simpson, Thacher & Bartlett LLP, counsel to the Borrower and
special New York counsel to the other Credit Parties, (y) Jeffery Klinger, Esq.,
special Missouri counsel to the Borrower and in-house counsel to the other
Credit Parties, in each case, in form and substance reasonably




                                       4


acceptable to the Administrative Agent; and

        (e) the Administrative Agent shall have received such other documents,
instruments and opinions as it shall have reasonably requested.

                SECTION 3 Representations and Warranties. The Borrower
represents and warrants to the Administrative Agent and the Lenders as follows:

        (a) Authority. Each of the Credit Parties has the requisite corporate
power and authority to execute and deliver this Amendment and the Consent, as
applicable, and to perform its obligations hereunder and under the Credit
Documents (as modified hereby). The execution, delivery and performance by the
Borrower and each other Credit Party of this Amendment, the Consent (as
applicable), the Credit Documents (as modified hereby) and the transactions
contemplated hereby and thereby have been duly approved by all necessary
corporate action of such Person and no other corporate proceedings on the part
of such Person are necessary to consummate such transactions.

        (b) No Legal Bar. The execution and delivery of this Amendment and of
the Consent by each Credit Party party thereto, and the performance of the
Credit Agreement and each other Credit Document, as amended hereby, by the
Borrower and each other Credit Party party thereto: (i) will not violate any
Requirement of Law or any Contractual Obligation applicable to or binding, the
Borrower any Restricted Subsidiary or any of their respective properties or
assets and (ii) will not result in the creation or imposition of a Lien on any
of its properties or assets pursuant to any Requirement of Law applicable to it
or any of its Contractual Obligations, except for the Liens arising under the
Credit Documents.

        (c) Enforceability. This Amendment has been duly executed and delivered
by the Borrower. The Consent has been duly executed and delivered by each Credit
Party. This Amendment, the Consent and each Credit Document (as modified hereby)
is the legal, valid and binding obligation of each Credit Party hereto and
thereto, enforceable against such Credit Party in accordance with its terms,
subject to the effects of bankruptcy, insolvency, fraudulent conveyance,
reorganization, moratorium and other similar laws relating to or affecting
creditors' rights generally, general equitable principles (whether considered in
a proceeding in equity or at law) and an implied covenant of good faith and fair
dealing, and is in full force and effect.

        (d) Representations and Warranties. The representations and warranties
contained in each Credit Document (other than any such representations and
warranties that, by their terms, are specifically made as of a date other than
the date hereof) are true and correct in all material respects on and as of the
date hereof as though made on and as of the date hereof.

        (e) No Default. Both immediately before and after giving effect to the
amendments set forth in Section 1 hereof no event has occurred and is continuing
that constitutes a Default or Event of Default.

                SECTION 4 Reference to and Effect on Credit Agreement.

        (a) Upon and after the effectiveness of this Amendment, each reference
in the Credit




                                       5


Agreement to "this Agreement", "hereunder", "hereof" or words of like import
referring to the Credit Agreement, and each reference in the other Credit
Documents to "the Credit Agreement", "thereunder", "thereof" or words of like
import referring to the Credit Agreement, shall mean and be a reference to the
Credit Agreement as modified hereby.

        (b) Except as specifically modified above, the Credit Agreement and the
other Credit Documents are and shall continue to be in full force and effect and
are hereby in all respects ratified and confirmed. Without limiting the
generality of the foregoing, the Security Documents and all of the Collateral
described therein do and shall continue to secure the payment of all Obligations
under and as defined therein, in each case as modified hereby.

        (c) The execution, delivery and effectiveness of this Amendment shall
not, except as expressly provided herein, operate as a waiver of any right,
power or remedy of the Administrative Agent or any Lender under any of the
Credit Documents, nor, except as expressly provided herein, constitute a waiver
or amendment of any provision of any of the Credit Documents.

                SECTION 5 Counterparts. This Amendment may be executed in any
number of counterparts and by different parties hereto in separate counterparts,
each of which when so executed and delivered shall be deemed to be an original
and all of which taken together shall constitute one and the same agreement.
Delivery of an executed counterpart of a signature page to this Amendment by
facsimile shall be effective as delivery of a manually executed counterpart of
this Amendment or such Consent.

                SECTION 6 Severability. Any provision of this Amendment that is
prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction,
be ineffective to the extent of such prohibition or unenforceability without
invalidating the remaining provisions hereof, and any such prohibition or
unenforceability in any jurisdiction shall not invalidate or render
unenforceable such provision in any other jurisdiction.

                SECTION 7 Governing Law. This Amendment shall be governed by,
and construed in accordance with, the laws of the State of New York.

                            (signature page follows)


                                       6



        IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be
executed by their respective officers thereunto duly authorized, as of the date
first written above.


                                       PEABODY ENERGY CORPORATION,
                                       a Delaware corporation


                                       By:
                                          --------------------------------------
                                           Name:
                                           Title:


                                       FLEET NATIONAL BANK,
                                       as Administrative Agent, on behalf of the
                                       Required Lenders


                                       By:
                                          --------------------------------------
                                           Name:
                                           Title:

                                       WACHOVIA BANK, NATIONAL ASSOCIATION,
                                       as Syndication Agent


                                       By:
                                          --------------------------------------
                                           Name:
                                           Title:







                            CONSENT OF CREDIT PARTIES
                          DATED AS OF OCTOBER 27, 2004


                The undersigned, as Guarantors and as Grantors under the
"Guarantee and Collateral Agreement", as Grantors under the "Trademark Security
Agreement" and each "Patent Security Agreement" and as Mortgagors under each
"Mortgage" (as such terms are defined in and under the Credit Agreement referred
to in the foregoing Amendment No. 3), as applicable, each hereby consents and
agrees to the foregoing Amendment No. 3 and hereby confirms and agrees that (i)
each of the Guarantee and Collateral Agreement, the Trademark Security
Agreement, each Patent Security Agreement and each Mortgage is, and shall
continue to be, in full force and effect and is hereby ratified and confirmed in
all respects except that, upon the effectiveness of said Amendment No. 3, each
reference in the Guarantee and Collateral Agreement, the Trademark Security
Agreement, each Patent Security Agreement and each Mortgage to the "Credit
Agreement", "thereunder", "thereof" and words of like import referring to the
Credit Agreement, shall mean and be a reference to the Credit Agreement as
modified by said Amendment No. 3, (ii) the Guarantee and Collateral Agreement
and all of the Collateral described therein does, and shall continue to, secure
the payment of all of the Obligations as defined in the Guarantee and Collateral
Agreement, (iii) the Trademark Security Agreement and all of the Collateral
described therein does, and shall continue to, secure the payment of all of the
Obligations as defined in the Guarantee and Collateral Agreement, (iv) each
Patent Security Agreement and all of the Collateral described therein does, and
shall continue to, secure the payment of all of the Obligations as defined in
the Guarantee and Collateral Agreement and (v) each Mortgage and all of the
Collateral described therein does, and shall continue to, secure the payment of
all of the Obligations as defined in the Guarantee and Collateral Agreement.


                            (signature pages follow)





        IN WITNESS WHEREOF, the parties hereto have caused this Consent of
Credit Parties to be executed by their respective officers thereunto duly
authorized, as of the date first written above.


                         PEABODY ENERGY CORPORATION
                         AFFINITY MINING COMPANY
                         APPALACHIA MINE SERVICES, LLC
                         ARCLAR COMPANY, LLC
                         ARID OPERATIONS INC.
                         BEAVER DAM COAL COMPANY
                         BIG RIDGE, INC.
                         BIG SKY COAL COMPANY
                         BLACK BEAUTY EQUIPMENT COMPANY
                         BLACK BEAUTY HOLDING COMPANY, LLC
                         BLACK BEAUTY MINING, INC.
                         BLACK BEAUTY RESOURCES, INC.
                         BLACK BEAUTY UNDERGROUND, INC.
                         BLACK WALNUT COAL COMPANY
                         BLUEGRASS COAL COMPANY
                         BTU EMPIRE CORPORATION
                         BTU WORLDWIDE, INC.
                         CABALLO COAL COMPANY
                         CHARLES COAL COMPANY
                         CLEATON COAL COMPANY
                         COAL PROPERTIES CORP.
                         COAL RESERVES HOLDING LIMITED LIABILITY COMPANY NO. 1
                         COAL RESERVES HOLDING LIMITED LIABILITY COMPANY NO. 2
                         COALSALES, LLC
                         COLORADO YAMPA COAL COMPANY
                         COOK MOUNTAIN COAL COMPANY
                         COTTONWOOD LAND COMPANY
                         CYPRUS CREEK LAND COMPANY
                         EACC CAMPS, INC.
                         EAGLE COAL COMPANY
                         EASTERN ASSOCIATED COAL CORP.
                         EASTERN ROYALTY CORP.
                         EMPIRE MARINE, LLC
                         FALCON COAL COMPANY
                         GALLO FINANCE COMPANY
                         GIBCO MOTOR EXPRESS, LLC
                         GOLD FIELDS CHILE, S.A.
                         GOLD FIELDS MINING CORPORATION






                         GOLD FIELDS OPERATING CO. - ORTIZ
                         GRAND EAGLE MINING, INC.
                         HAYDEN GULCH TERMINAL, INC.
                         HIGHLAND MINING COMPANY
                         HIGHWALL MINING SERVICES COMPANY
                         HILLSIDE MINING COMPANY
                         INDEPENDENCE MATERIAL HANDLING COMPANY
                         INDIAN HILL COMPANY
                         INTERIOR HOLDINGS CORP.
                         JAMES RIVER COAL TERMINAL COMPANY
                         JARRELL'S BRANCH COAL COMPANY
                         JUNIPER COAL COMPANY
                         KAYENTA MOBILE HOME PARK, INC.
                         LOGAN FORK COAL COMPANY
                         MARTINKA COAL COMPANY
                         MIDCO SUPPLY AND EQUIPMENT CORPORATION
                         MIDWEST COAL ACQUISITION CORP.
                         MOUNTAIN VIEW COAL COMPANY
                         NORTH PAGE COAL CORP.
                         OHIO COUNTY COAL COMPANY
                         PDC PARTNERSHIP HOLDINGS, INC.
                         PEABODY AMERICA, INC.
                         PEABODY COAL COMPANY
                         PEABODY COALSALES COMPANY
                         PEABODY COALTRADE, INC.
                         PEABODY COALTRADE INTERNATIONAL, LLC
                         PEABODY ENERGY GENERATION HOLDING
                         PEABODY ENERGY INVESTMENTS, INC.
                         PEABODY ENERGY SOLUTIONS, INC.
                         PEABODY HOLDING COMPANY, INC.
                         PEABODY SOUTHWESTERN COAL COMPANY
                         PEABODY TERMINALS, INC.
                         PEABODY VENEZUELA COAL CORP.
                         PEABODY WESTERN COAL COMPANY
                         PINE RIDGE COAL COMPANY
                         POND RIVER LAND COMPANY
                         POWDER RIVER COAL COMPANY
                         RIO ESCONDIDO COAL CORP.
                         RIVERS EDGE MINING, INC.
                         RIVERVIEW TERMINAL COMPANY
                         SENECA COAL COMPANY
                         SENTRY MINING COMPANY
                         SHOSHONE COAL COPRORATION





                         SNOWBERRY LAND COMPANY
                         STERLING SMOKELESS COAL COMPANY
                         SUGAR CAMP PROPERTIES
                         TWENTYMILE COAL COMPANY
                         YANKEETOWN DOCK CORPORATION


                         By:
                             ---------------------------------------------------
                             Name:
                             Title:

                        (signatures continued next page)





                BLACK BEAUTY COAL COMPANY
                     By: Thoroughbred, L.L.C.,
                         a Delaware limited liability company, its Partner

                     By:
                        -------------------------------------------------------
                          Name:
                          Title:


                BLACK HILLS MINING COMPANY, LLC
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member


                     By:
                        -------------------------------------------------------
                          Name:
                          Title:


                BLACK STALLION COAL COMPANY, LLC
                     By: Black Walnut Coal Company,
                         its Sole Member


                     By:
                        -------------------------------------------------------
                          Name:
                          Title:


                BTU VENEZUELA LLC
                     By: Peabody Energy Corporation,
                         a Delaware corporation, its Sole Member

                     By:
                        -------------------------------------------------------
                          Name:
                          Title:


                COLONY BAY COAL COMPANY
                     By: Charles Coal Company,
                         a Delaware corporation, its General Partner

                     By:
                        -------------------------------------------------------
                          Name:
                          Title:

                        (signatures continued next page)





                CYPRUS CREEK LAND RESOURCES, LLC
                     By: Peabody Development Company, LLC
                         By: Peabody Holding Company, Inc.
                              a New York corporation, its Sole Member


                         By:
                            ----------------------------------------------------
                              Name:
                              Title:


                KANAWHA RIVER VENTURES I, LLC
                     By: Snowberry Land Company,
                         its Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                MUSTANG ENERGY COMPANY, L.L.C.
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                PATRIOT COAL COMPANY, L.P.
                     By: Bluegrass Coal Company,
                         a Delaware corporation, its Partner

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:

                     By: Sentry Mining Company,
                         a Delaware corporation, its Partner

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                        (signatures continued next page)






                PEABODY ARCHVEYOR, L.L.C.
                     By: Gold Fields Mining Corporation,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                PEABODY DEVELOPMENT COMPANY, LLC
                     By: Peabody Holding Company, Inc.
                         a New York corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                PEABODY DEVELOPMENT LAND HOLDINGS, LLC
                     By: Peabody Development Company, LLC
                         By: Peabody Holding Company, Inc.
                             a New York corporation, its Sole Member


                         By:
                            ----------------------------------------------------
                              Name:
                              Title:

                     By: Peabody Holding Company, Inc.,
                         a New York corporation, its Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                PEABODY NATURAL GAS, LLC
                     By: Peabody Holding Company, Inc.,
                         a New York corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:



                        (signatures continued next page)





                PEABODY NATURAL RESOURCES COMPANY
                     By: Gold Fields Mining Corporation,
                         a Delaware corporation, its Partner

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:

                     By: Peabody America, Inc.,
                         a Delaware corporation, its Partner

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:



                PEABODY POWERTREE INVESTMENTS, LLC
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                PEABODY RECREATIONAL LANDS, L.L.C.
                     By: Peabody Development Company, LLC
                         By: Peabody Holding Company, Inc.
                              a New York corporation, its Sole Member


                         By:
                            ----------------------------------------------------
                              Name:
                              Title:


                PEABODY-WATERSIDE DEVELOPMENT, L.L.C.
                     By: Peabody Development Company, LLC
                         By: Peabody Holding Company, Inc.
                              a New York corporation, its Sole Member


                         By:
                            ----------------------------------------------------
                              Name:
                              Title:


                        (signatures continued next page)






                PEC EQUIPMENT COMPANY, LLC
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                POINT PLEASANT DOCK COMPANY, LLC
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                POND CREEK LAND RESOURCES, LLC
                     By: Peabody Coal Company,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                PORCUPINE PRODUCTION, LLC
                     By: Peabody Development Company, LLC
                         By: Peabody Holding Company, Inc.
                              a New York corporation, its Sole Member


                         By:
                            ----------------------------------------------------
                              Name:
                              Title:


                PORCUPINE TRANSPORTATION, LLC
                     By: Peabody Development Company, LLC
                         By: Peabody Holding Company, Inc.
                              a New York corporation, its Sole Member


                         By:
                            ----------------------------------------------------
                              Name:
                              Title:

                        (signatures continued next page)





                PRAIRIE STATE GENERATING COMPANY, LLC
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                STAR LAKE ENERGY COMPANY, L.L.C.
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                THOROUGHBRED, L.L.C.
                     By: Peabody Holding Company, Inc.,
                         a New York corporation, its Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                     By: Peabody Development Company, LLC
                         By: Peabody Holding Company, Inc.
                              a New York corporation, its Sole Member

                         By:
                            ----------------------------------------------------
                              Name:
                              Title:


                THOROUGHBRED GENERATING COMPANY, LLC
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                        (signatures continued next page)






                THOROUGHBRED MINING COMPANY, L.L.C.
                     By: BTU Worldwide, Inc.,
                         a Delaware corporation, its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:


                WILLIAMSVILLE COAL COMPANY, LLC
                     By: Midwest Coal Acquisition Corp.,
                         its Sole Member

                     By:
                        --------------------------------------------------------
                          Name:
                          Title:





                                                                       EXHIBIT A


                                                                      Schedule I
                                                             to Credit Agreement

                                  Pricing Grid





             CONSOLIDATED                         REVOLVING CREDIT
                 TOTAL         REVOLVING CREDIT       FACILITY                               TERM LOAN
            OBLIGATIONS TO         FACILITY          APPLICABLE                             APPLICABLE          TERM LOAN
             CONSOLIDATED     APPLICABLE MARGIN     MARGIN - BASE      COMMITMENT FEE     MARGIN - LIBOR    APPLICABLE MARGIN
  LEVEL      EBITDA RATIO        -LIBOR RATE            RATE                RATE               RATE            - BASE RATE
- ---------- ------------------ ------------------- ------------------ ------------------- ------------------ -------------------
                                                                                              
    I          =>3.25x              1.750%             0.750%             0.375%               1.750%            0.750%
    II         =>2.75x              1.250%             0.250%             0.250%               1.250%            0.250%
   III         =>2.25x              1.000%             0.000%             0.250%               1.000%            0.000%
    IV          <2.25x              0.750%             0.000%             0.200%               0.750%            0.000%

EX-10.49

                                                                   EXHIBIT 10.49

                             FIRST AMENDMENT TO THE
                           PEABODY ENERGY CORPORATION
                           DEFERRED COMPENSATION PLAN


        WHEREAS, Peabody Energy Corporation (the "Company") previously
established, and currently maintains, the Peabody Energy Corporation Deferred
Compensation Plan (the "Plan") for the benefit of a select group of management
or highly compensated employees;

        WHEREAS, as a result of new tax legislation, the Company deems it
desirable to no longer allow employees to begin participation in the Plan and to
no longer allow new contributions to be made to the Plan on or after the
effective date of such new tax legislation;

        WHEREAS, pursuant to Section 10.1 of the Plan, the Company, through
action of the Board, has the power to amend the Plan to effectuate the
foregoing;

        NOW, THEREFORE, BE IT RESOLVED that the Plan be, and it hereby is,
amended as follows:

                                       I.

        Article II of the Plan is amended by adding a new Section 2.3 at the end
thereof to read as follows:

                "2.3 NO NEW PARTICIPANT. Notwithstanding anything herein to the
        contrary, the Committee shall not select any additional Employees to
        become Eligible Employees or otherwise allow Employees previously
        selected as Eligible Employees to become Participants in the Plan for
        purposes of deferring compensation on or after the effective date of
        Section 409A of the Code."

                                       II.

        Article III, Section 3.1 of the Plan is amended by adding the following
at the end thereof:

                "Notwithstanding anything herein to the contrary, no additional
        Employee Deferral Election shall be allowed to be filed under the Plan
        for purposes of deferring compensation on or after the effective date of
        Section 409A of the Code."




                                      III.

        In all other respects, the Plan shall remain in full force and effect.


        IN WITNESS WHEREOF, the Company has caused this First Amendment to be
signed by its duly authorized officer this __ day of December 2004.


                                  PEABODY ENERGY CORPORATION


                                  By:
                                     --------------------------
                                        Sharon D. Fiehler
                                        Executive Vice President

EX-13

                                                                      EXHIBIT 13

            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, 2004 and 2003, 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, 2004. 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 as of December 31, 2004 and 2003, and the consolidated results of
its operations and its cash flows for the three years ended December 31, 2004,
in conformity with U.S. generally accepted accounting principles.

      As discussed in Note 6 to the consolidated financial statements, on
January 1, 2003, the Company changed its method of accounting for asset
retirement obligations, non-derivative trading contracts, and actuarial gains
and losses related to net periodic post-retirement benefit costs.

      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, 2004, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission, and our report dated March 7, 2005, expressed an unqualified opinion
thereon.


                                       /s/ Ernst & Young LLP

St. Louis, Missouri
March 7, 2005

                                       1


                           PEABODY ENERGY CORPORATION
                      CONSOLIDATED STATEMENTS OF OPERATIONS



                                                                    Year Ended December 31,
                                                 -------------------------------------------------------
                                                     2004                  2003                 2002
                                                 ------------          ------------         ------------
                                                 (Dollars in thousands, except share and per share data)
                                                                                   
REVENUES
    Sales                                        $  3,545,027          $  2,729,323         $  2,630,371
    Other revenues                                     86,555                85,973               89,267
                                                 ------------          ------------         ------------
       Total revenues                               3,631,582             2,815,296            2,719,638

COSTS AND EXPENSES
    Operating costs and expenses                    2,969,209             2,335,800            2,225,344
    Depreciation, depletion and amortization          270,159               234,336              232,413
    Asset retirement obligation expense                42,387                31,156                    -
    Selling and administrative expenses               143,025               108,525              101,416
    Other operating income:
       Net gain on disposal of assets                 (23,829)              (32,772)             (15,763)
       (Income) loss from equity affiliates           (16,067)               (6,535)               2,540
                                                 ------------          ------------         ------------
OPERATING PROFIT                                      246,698               144,786              173,688
    Interest expense                                   96,793                98,540              102,458
    Early debt extinguishment costs                     1,751                53,513                    -
    Interest income                                    (4,917)               (4,086)              (7,574)
                                                 ------------          ------------         ------------

INCOME (LOSS) BEFORE INCOME TAXES AND                 153,071                (3,181)              78,804
MINORITY INTERESTS
    Income tax benefit                                (26,437)              (47,708)             (40,007)
    Minority interests                                  1,282                 3,035               13,292
                                                 ------------          ------------         ------------
INCOME FROM CONTINUING OPERATIONS                     178,226                41,492              105,519
    Loss from discontinued operations, net of
       income tax benefit of $ 1,893                   (2,839)                    -                    -
                                                 ------------          ------------         ------------
INCOME BEFORE ACCOUNTING CHANGES                      175,387                41,492              105,519
    Cumulative effect of accounting changes,
       net of income tax benefit of $ 6,762                 -               (10,144)                   -
                                                 ------------          ------------         ------------
NET INCOME                                       $    175,387          $     31,348         $    105,519
                                                 ============          ============         ============
BASIC EARNINGS PER SHARE
    Income from continuing operations            $       1.43                $ 0.39         $       1.01
    Loss from discontinued operations                   (0.02)                    -                    -
    Cumulative effect of accounting changes                 -                 (0.10)                   -
                                                 ------------          ------------         ------------
       Net income                                $       1.41                $ 0.29         $       1.01
                                                 ============          ============         ============
WEIGHTED AVERAGE SHARES OUTSTANDING               124,366,372           106,819,042          104,331,470
                                                 ============          ============         ============
DILUTED EARNINGS PER SHARE
    Income from continuing operations            $       1.40          $       0.38         $       0.98
    Loss from discontinued operations                   (0.02)                    -                    -
    Cumulative effect of accounting changes                 -                 (0.09)                   -
                                                 ------------          ------------         ------------
       Net income                                $       1.38          $       0.29         $       0.98
                                                 ============          ============         ============
WEIGHTED AVERAGE SHARES OUTSTANDING               127,406,316           109,671,256          107,643,520
                                                 ============          ============         ============
DIVIDENDS DECLARED PER SHARE                     $       0.26          $       0.23         $       0.20
                                                 ============          ============         ============


          See accompanying notes to consolidated financial statements

                                       2


                           PEABODY ENERGY CORPORATION
                           CONSOLIDATED BALANCE SHEETS



                                                                                            DECEMBER 31,
                                                                                  --------------------------------
                                                                                       2004              2003
                                                                                  --------------     -------------
                                                                                       (Dollars in thousands,
                                                                                  except share and per share data)
                                                                                               
                                      ASSETS
Current assets
    Cash and cash equivalents                                                       $   389,636       $   117,502
    Accounts receivable, less allowance for doubtful
       accounts of $1,361 at December 31, 2004 and 2003                                 193,784           220,891
    Inventories                                                                         323,609           246,493
    Assets from coal trading activities                                                  89,165            58,321
    Deferred income taxes                                                                15,461            15,749
    Other current assets                                                                 42,947            23,784
                                                                                    -----------       -----------
       Total current assets                                                           1,054,602           682,740
Property, plant, equipment and
  mine development
    Land and coal interests                                                           4,512,893         3,951,160
    Buildings and improvements                                                          718,803           642,654
    Machinery and equipment                                                             883,380           716,723
    Less accumulated depreciation,
       depletion and amortization                                                    (1,333,645)       (1,029,551)
                                                                                    -----------       -----------
Property, plant, equipment and
  mine development, net                                                               4,781,431         4,280,986
Investments and other assets                                                            342,559           316,539
                                                                                    -----------       -----------
       Total assets                                                                 $ 6,178,592       $ 5,280,265
                                                                                    ===========       ===========
                       LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
    Current maturities of long-term debt                                            $    18,979       $    23,049
    Liabilities from coal trading activities                                             63,565            36,304
    Accounts payable and accrued expenses                                               691,600           572,615
                                                                                    -----------       -----------
       Total current liabilities                                                        774,144           631,968

Long-term debt, less current maturities                                               1,405,986         1,173,490
Deferred income taxes                                                                   393,266           434,426
Asset retirement obligations                                                            396,022           384,048
Workers' compensation obligations                                                       227,476           209,954
Accrued postretirement benefit costs                                                    939,503           961,811
Other noncurrent liabilities                                                            315,694           350,602
                                                                                    -----------       -----------
       Total liabilities                                                              4,452,091         4,146,299

Minority interests                                                                        1,909             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, 2004 or 2003                                                        -                 -
    Series Common Stock - $0.01 per share par value; 40,000,000
       shares authorized, no shares issued or outstanding
       as of December 31, 2004 or 2003                                                        -                 -
    Common Stock - $0.01 per share par value; 150,000,000 shares authorized,
       129,829,134 shares issued and 129,567,954 shares outstanding as
       of December 31, 2004 and 150,000,000 shares authorized, 109,544,620 shares
       issued and 109,293,508 shares outstanding as of December 31, 2003                  1,298             1,095
    Additional paid-in capital                                                        1,437,319         1,008,461
    Retained earnings                                                                   350,968           208,149
    Unearned restricted stock awards                                                       (459)             (358)
    Employee stock loans                                                                      -               (31)
    Accumulated other comprehensive loss                                                (60,618)          (81,572)
    Treasury shares, at cost: 261,180 shares and 251,112 shares as of
      December 31, 2004 and 2003, respectively                                           (3,916)           (3,687)
                                                                                    -----------       -----------
       Total stockholders' equity                                                     1,724,592         1,132,057
                                                                                    -----------       -----------
         Total liabilities and stockholders' equity                                 $ 6,178,592       $ 5,280,265
                                                                                    ===========       ===========


          See accompanying notes to consolidated financial statements

                                       3


                           PEABODY ENERGY CORPORATION
                      CONSOLIDATED STATEMENTS OF CASH FLOWS



                                                                                             YEAR ENDED DECEMBER 31,
                                                                                    -----------------------------------------
                                                                                       2004            2003            2002
                                                                                    ---------       ----------      ---------
                                                                                              (Dollars in thousands)
                                                                                                           
CASH FLOWS FROM OPERATING ACTIVITIES
Net income                                                                          $ 175,387       $   31,348      $ 105,519
   Loss from discontinued operations                                                    2,839                -              -
   Cumulative effect of accounting changes, net of taxes                                    -           10,144              -
                                                                                    ---------       ----------      ---------
      Income from continuing operations                                               178,226           41,492        105,519
Adjustments to reconcile income from continuing operations
 to net cash provided by operating activities:
   Depreciation, depletion and amortization                                           270,159          234,336        232,413
   Deferred income taxes                                                              (31,925)         (48,259)       (41,323)
   Early debt extinguishment costs                                                      1,751           53,513              -
   Amortization of debt discount and debt issuance costs                                8,330            8,158          9,768
   Net gain on disposal of assets                                                     (23,829)         (32,772)       (15,763)
   (Income) loss from equity affiliates                                               (16,067)          (6,535)         2,540
   Dividends received from equity investments                                          13,614            4,781              -
   Changes in current assets and liabilities, net of acquisitions
      Accounts receivable, net of sale                                                (34,649)         (21,279)        26,573
      Materials and supplies                                                           (8,411)          (5,005)          (682)
      Coal inventory                                                                  (49,370)         (11,800)       (12,191)
      Net assets from coal trading activities                                          (3,583)         (22,771)       (18,072)
      Other current assets                                                             (1,438)          (3,621)         6,589
      Accounts payable and accrued expenses                                            66,576           34,423        (48,928)
   Asset retirement obligations                                                        (6,571)          (9,563)       (12,146)
   Workers' compensation obligations                                                   10,479              156           (522)
   Accrued postretirement benefit costs                                               (32,499)           3,705         (2,567)
   Obligation to industry fund                                                        (11,367)          (4,981)          (492)
   Contributions to pension plans                                                     (62,082)         (17,490)       (14,305)
   Other, net                                                                          16,416           (7,627)        18,393
                                                                                    ---------       ----------      ---------
      Net cash provided by operating activities                                       283,760          188,861        234,804
                                                                                    ---------       ----------      ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant, equipment and mine development                         (266,597)        (156,443)      (208,562)
Additions to advance mining royalties                                                 (16,239)         (14,010)       (14,889)
Acquisitions, net                                                                    (429,061)         (90,000)       (45,537)
Investments in joint ventures                                                         (32,472)          (1,400)          (475)
Proceeds from sale of coal reserves to Penn Virginia Resource Partners, L.P.                -                -         72,500
Proceeds from disposal of assets                                                       39,339           69,573         52,885
                                                                                    ---------       ----------      ---------
      Net cash used in investing activities                                          (705,030)        (192,280)      (144,078)
                                                                                    ---------       ----------      ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Net change in revolving lines of credit                                                     -         (121,584)        14,647
Proceeds from long-term debt                                                          700,013        1,102,735          1,815
Payments of long-term debt                                                           (482,924)        (868,386)       (47,749)
Net proceeds from equity offering                                                     383,125                -              -
Proceeds from stock options exercised                                                  27,266           31,329          2,650
Proceeds from employee stock purchases                                                  2,343            1,737          3,251
Increase (decrease) of securitized interests in accounts receivable                   110,000          (46,400)        (3,600)
Payment of debt issuance costs                                                        (12,875)         (23,700)             -
Distributions to minority interests                                                    (1,007)          (4,186)        (9,800)
Dividends paid                                                                        (32,568)         (24,058)       (20,863)
Other                                                                                      31            1,111          1,251
                                                                                    ---------       ----------      ---------
      Net cash provided by (used in) financing activities                             693,404           48,598        (58,398)
Effect of exchange rate changes on cash and cash equivalents                                -            1,113            260
                                                                                    ---------       ----------      ---------
Net increase in cash and cash equivalents                                             272,134           46,292         32,588
Cash and cash equivalents at beginning of year                                        117,502           71,210         38,622
                                                                                    ---------       ----------      ---------
Cash and cash equivalents at end of year                                            $ 389,636       $  117,502      $  71,210
                                                                                    =========       ==========      =========


          See accompanying notes to consolidated financial statements

                                       4


                           PEABODY ENERGY CORPORATION
           CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY



                                                                                        Unearned                 Accumulated
                                                                          Additional   Restricted     Other     Comprehensive
                                                    Preferred   Common      Paid-in      Stock       Employee      Income
                                                      Stock      Stock      Capital      Awards    Stock Loans     (Loss)
                                                    ---------   ------   ------------  ----------  -----------  -------------
                                                                             (Dollars in thousands)
                                                                                              
December 31, 2001                                     $   -    $ 1,040   $   951,008     $    -     $ (2,391)     $ (30,345)
    Comprehensive income:
       Net income                                         -          -             -          -            -              -
       Foreign currency translation adjustment            -          -             -          -            -             15
       Minimum pension liability adjustment
          (net of $32,703 tax benefit)                    -          -             -          -            -        (47,297)

    Comprehensive income
    Dividends paid                                        -          -             -          -            -              -
    Loan repayments                                       -          -             -          -        1,249              -
    Stock options exercised                               -         10         4,334          -            -              -
    Income tax benefits from stock options                -          -           910          -            -              -
    Stock grants to non-employee directors                -          -            50          -            -              -
    Employee stock purchases                              -          2         3,249          -            -              -
    Shares repurchased and retired                        -         (4)       (1,508)         -            -              -
                                                      -----    -------   -----------     ------     --------      ---------
December 31, 2002                                         -      1,048       958,043          -       (1,142)       (77,627)
    Comprehensive income:
       Net income                                         -          -             -          -            -              -
       Foreign currency translation adjustment            -          -             -          -            -          3,138
       Decrease in fair value of cash flow hedges
          (net of $4,694 tax benefit)                     -          -             -          -            -         (7,041)
       Minimum pension liability adjustment
          (net of $27 tax benefit)                        -          -             -          -            -            (42)

    Comprehensive income
    Dividends paid                                        -          -             -          -            -              -
    Loan repayments                                       -          -             -          -        1,111              -
    Stock options exercised                               -         45        35,290          -            -              -
    Income tax benefits from stock options                -          -        12,925          -            -              -
    Employee stock purchases                              -          2         1,735          -            -              -
    Stock grants to non-employee directors                -          -           100          -            -              -
    Employee stock grants                                 -          -           368       (368)           -              -
    Deferred compensation earned                          -          -             -         10            -              -
    Shares repurchased                                    -          -             -          -            -              -
                                                      -----    -------   -----------     ------     --------      ---------
December 31, 2003                                         -      1,095     1,008,461       (358)         (31)       (81,572)
    Comprehensive income:
       Net income                                         -          -             -          -            -              -
       Increase in fair value of cash flow hedges
          (net of $9,945 tax provision)                   -          -             -          -            -         14,915
       Minimum pension liability adjustment
          (net of $4,026 tax provision)                   -          -             -          -            -          6,039

    Comprehensive income
    Issuance of common stock in connection with
       equity offering, net of expenses                   -        176       382,949          -            -              -
    Dividends paid                                        -          -             -          -            -              -
    Loan repayments                                       -          -             -          -           31              -
    Stock options exercised                               -         27        27,648          -            -              -
    Income tax benefits from stock options                -          -        15,718          -            -              -
    Employee stock purchases                              -          -         2,343          -            -              -
    Employee stock grants                                 -          -           200       (200)           -              -
    Deferred compensation earned                          -          -             -         99            -              -
    Shares repurchased                                    -          -             -          -            -              -
                                                      -----    -------   -----------     ------     --------      ---------
December 31, 2004                                     $   -    $ 1,298   $ 1,437,319     $ (459)    $      -      $ (60,618)
                                                      =====    =======   ===========     ======     ========      =========

                                                                               Total
                                                     Retained   Treasury   Stockholders'
                                                     Earnings     Stock       Equity
                                                     --------   --------   -------------
                                                          (Dollars in thousands)
                                                                  
December 31, 2001                                   $ 116,203      $ (43)   $ 1,035,472
    Comprehensive income:
       Net income                                     105,519          -        105,519
       Foreign currency translation adjustment              -          -             15
       Minimum pension liability adjustment
          (net of $32,703 tax benefit)                      -          -        (47,297)
                                                                            -----------
    Comprehensive income                                                         58,237
    Dividends paid                                    (20,863)         -        (20,863)
    Loan repayments                                         -          -          1,249
    Stock options exercised                                 -          -          4,344
    Income tax benefits from stock options                  -          -            910
    Stock grants to non-employee directors                  -          -             50
    Employee stock purchases                                -          -          3,251
    Shares repurchased and retired                          -          -         (1,512)
                                                    ---------   --------    -----------
December 31, 2002                                     200,859        (43)     1,081,138
    Comprehensive income:
       Net income                                      31,348          -         31,348
       Foreign currency translation adjustment              -          -          3,138
       Decrease in fair value of cash flow hedges
          (net of $4,694 tax benefit)                       -          -         (7,041)
       Minimum pension liability adjustment
          (net of $27 tax benefit)                          -          -            (42)
                                                                            -----------
    Comprehensive income                                                         27,403
    Dividends paid                                    (24,058)         -        (24,058)
    Loan repayments                                         -          -          1,111
    Stock options exercised                                 -          -         35,335
    Income tax benefits from stock options                  -          -         12,925
    Employee stock purchases                                -          -          1,737
    Stock grants to non-employee directors                  -          -            100
    Employee stock grants                                   -          -              -
    Deferred compensation earned                            -          -             10
    Shares repurchased                                      -     (3,644)        (3,644)
                                                    ---------   --------    -----------
December 31, 2003                                     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
       Minimum pension liability adjustment
          (net of $4,026 tax provision)                     -          -          6,039
                                                                            -----------
    Comprehensive income                                                        196,341
    Issuance of common stock in connection with
       equity offering, net of expenses                     -          -        383,125
    Dividends paid                                    (32,568)         -        (32,568)
    Loan repayments                                         -          -             31
    Stock options exercised                                 -          -         27,675
    Income tax benefits from stock options                  -          -         15,718
    Employee stock purchases                                -          -          2,343
    Employee stock grants                                   -          -              -
    Deferred compensation earned                            -          -             99
    Shares repurchased                                      -       (229)          (229)
                                                    ---------   --------    -----------
December 31, 2004                                   $ 350,968   $ (3,916)   $ 1,724,592
                                                    =========   ========    ===========


           See accompanying notes to consolidated financial statements

                                       5


                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

   BASIS OF PRESENTATION

      The consolidated financial statements include the accounts of the Company
and its controlled affiliates. All intercompany transactions, profits, and
balances have been eliminated in consolidation.

      On March 2, 2005, the Company announced a two-for-one stock split on all
shares of its common stock payable to shareholders of record at the close of
business on March 16, 2005. The additional shares will be distributed on March
30, 2005. All share and per share amounts in these consolidated financial
statements and related notes reflect the stock split.

   DESCRIPTION OF BUSINESS

      The Company is engaged in the mining of steam coal for sale primarily to
electric utilities and metallurgical coal to industrial customers. The Company's
mining operations are located in the United States and Australia, and include an
equity interest in mining operations in Venezuela. In addition to the Company's
mining operations, the Company markets, brokers and trades coal. Finally, the
Company is also involved in related energy businesses that include participation
in the development of coal-fueled generating plants, coalbed methane production
and transportation-related services.

   NEW PRONOUNCEMENTS

      On December 16, 2004, the Financial Accounting Standards Board ("FASB")
issued Statement of Financial Accounting Standards ("SFAS") No. 123 (revised
2004), Share-Based Payment, or "SFAS No. 123(R)," which is a revision of SFAS
No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123(R) supersedes
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.

      SFAS No. 123(R) must be adopted no later than July 1, 2005 (for calendar
year companies), and the Company expects to adopt the standard on that date,
using one of the two methods permitted by SFAS No. 123(R), described below:

      -     A "modified prospective" method in which compensation cost is
            recognized beginning with the effective date (a) based on the
            requirements of SFAS No. 123(R) for all share-based payments granted
            after the effective date and (b) based on the requirements of SFAS
            No. 123 for all awards granted to employees prior to the effective
            date of SFAS No. 123(R) that remain unvested on the effective date.

      -     A "modified retrospective" method which includes the requirements of
            the modified prospective method described above, but also permits
            entities to restate based on the amounts previously recognized under
            SFAS No. 123 for purposes of pro forma disclosures either (a) all
            prior periods presented or (b) prior interim periods of the year of
            adoption.

      As permitted by SFAS No. 123, the Company currently accounts for
share-based payments to employees using APB Opinion No. 25's intrinsic value
method and, as such, generally recognizes no compensation cost for employee
stock options. Accordingly, the adoption of SFAS No. 123(R)'s fair value method
will have an impact on our results of operations, although it will have no
impact on our overall financial position. Had we adopted SFAS No. 123(R) in
prior periods, the impact of that standard would have approximated the impact of
SFAS No. 123 as described below in the disclosure of pro forma net income and
earnings per share in Note 1 to our consolidated financial statements. The
precise impact of the adoption of SFAS No. 123(R) on the Company in 2005 and
beyond cannot be predicted at this time because it will depend on levels of
equity-based compensation granted in the future. However, because the Company
makes its annual equity-based compensation grants in January, prior to the
issuance of the Company's financial statements, an estimate of the impact of the
adoption of SFAS No. 123(R) on 2005 net income can be made. Based on stock
option grants made in January 2005, considering option grants outstanding in
2005 made prior to 2005, and assuming no additional stock option grants in 2005
beyond January 2005, the Company anticipates (assuming the modified prospective
method is used) recognizing expense for stock options for the period from July
1, 2005 to December 31, 2005 of $2.3 million, net of taxes. It should be noted
that annual equity-based compensation grants in years prior to 2005 consisted of
a higher number of stock options than the grant made in 2005. For the January
2005 grant, the Company delivered comparable equity-based compensation value by
granting a combination of stock options and restricted stock. Prior to January
2005, the Company had not previously granted restricted stock as part of its
annual compensation strategy. Expense related to restricted stock (which vests
over five years, and assuming no grants beyond January 2005) is anticipated to
be approximately $0.8 million, net of taxes, in 2005.

                                       6


      In May 2004, in response to the federal Medicare Prescription Drug,
Improvement and Modernization Act of 2003 ("Medicare Act"), the FASB finalized
guidance on how employers should account for the Medicare Act in FASB Staff
Position 106-2, "Accounting and Disclosure Requirements Related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003". The FASB guidance
did not impact the Company's accounting for the Medicare Act as initially
applied under FASB Staff Position 106-1, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization Act of
2003," the effects of which are described in Note 17.

      Emerging Issues Task Force ("EITF") Issue 04-02, effective April 30, 2004,
states that mineral rights are tangible assets. Prior to this consensus, the
Company provided a separate line item for leased coal interests and advance
royalties within the consolidated balance sheet as of December 31, 2003. As of
December 31, 2004, leased coal interests and advance royalties are presented in
the same manner as they had been before December 2003, and are included within
property, plant, equipment and mine development within the consolidated balance
sheet. Prior year amounts have been reclassified to conform with the current
year presentation.

   SALES

      The Company's revenue from coal sales is realized and earned when risk of
loss passes to the customer. Coal sales are made to the Company's customers
under the terms of coal supply agreements, most of which are long-term (greater
than one year). Under the typical terms of these coal supply agreements, title
and risk of loss transfers to the customer at the mine or port, where coal is
loaded to the rail, barge, ocean-going vessel, truck or other transportation
source(s) that serves each of the Company's mines. The Company incurs certain
"add-on" taxes and fees on coal sales. Coal sales are reported including taxes
and fees charged by various federal and state governmental bodies.

   OTHER REVENUES

      Other revenues include royalties related to coal lease agreements, sales
agency commissions, farm income, coalbed methane revenues, and net revenues from
coal trading activities accounted for under SFAS No. 133. Royalty income
generally results from the lease or sublease of mineral rights to third parties,
with payments based upon a percentage of the selling price or an amount per ton
of coal produced. Certain agreements require minimum annual lease payments
regardless of the extent to which minerals are produced from the leasehold. The
terms of these agreements generally range from specified periods of five to 15
years, or can be for an unspecified period until all reserves are depleted.

   STOCK COMPENSATION

      The Company applies APB Opinion No. 25 and related interpretations in
accounting for its equity incentive plans. The Company recorded $0.3 million,
$0.4 million and $0.2 million of compensation expense during the years ended
December 31, 2004, 2003 and 2002, respectively, for stock options and restricted
stock granted. The following table reflects pro forma net income and diluted
earnings per share had compensation cost been determined for the Company's
non-qualified and incentive stock options based on the fair value at the grant
dates consistent with the methodology set forth under SFAS No. 123, "Accounting
for Stock-Based Compensation":



                                         YEAR ENDED DECEMBER 31,
                               -------------------------------------------
(Dollars in thousands,
except per share data)             2004            2003            2002
                               -----------     -----------     -----------
                                                      
Net income:
   As reported                 $   175,387     $    31,348     $   105,519
   Pro forma                       168,628          22,617         100,639
Basic earnings per share:
   As reported                 $      1.41     $      0.29     $      1.01
   Pro forma                          1.36            0.21            0.96
Diluted earnings per share:
   As reported                 $      1.38     $      0.29     $      0.98
   Pro forma                          1.32            0.21            0.93


      These pro forma amounts may not be representative of future disclosures
since the estimated fair value of stock options is amortized to expense over the
vesting period, and additional options may be granted in future years.

      Compensation expense for awards with graded vesting provisions is
recognized on a straight-line basis.

                                       7


   DISCONTINUED OPERATIONS

      The Company classifies items within discontinued operations in the
statement of operations when the operations and cash flows of a particular
component (defined as operations and cash flows that can be clearly
distinguished, operationally and for financial reporting purposes, from the rest
of the entity) of the Company have been (or will be) eliminated from the ongoing
operations of the Company as a result of a disposal transaction and the Company
will no longer have any significant continuing involvement in the operations of
that component. Results of operations for the year ended December 31, 2004
include a $2.8 million loss, net of taxes, related to the Company's former
Citizens Power subsidiary (discussed further in Note 24).

   CASH AND CASH EQUIVALENTS

      Cash and cash equivalents are stated at cost, which approximates fair
value. Cash equivalents consist of highly liquid investments with original
maturities of three months or less.

   INVENTORIES

      Materials and supplies and coal inventory are valued at the lower of
average cost or market. Coal inventory costs include labor, supplies, equipment
costs, operating overhead and other related costs.

   ASSETS AND LIABILITIES FROM COAL TRADING ACTIVITIES

      Through October 25, 2002, the Company's coal trading activities were
accounted for using the fair value method required by EITF Issue No. 98-10
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" ("EITF 98-10"). On October 25, 2002, the EITF reached a consensus in
EITF Issue 02-3 "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities" ("EITF 02-3") to rescind EITF 98-10 for all energy
trading contracts entered into after that date. As a result of the rescission,
energy trading contracts entered into after October 25, 2002 were evaluated
under SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities" ("SFAS No. 133"), as amended. Trading contracts entered into after
October 25, 2002 that meet the SFAS No. 133 definition of a derivative were
accounted for at fair value, while contracts that do not qualify as derivatives
were accounted for under the accrual method.

      For contracts entered into prior to October 25, 2002, the rescission of
EITF 98-10 was effective January 1, 2003. Accordingly, the effect of the
rescission on non-derivative energy trading contracts entered into prior to
October 25, 2002 was recorded as a cumulative effect of a change in accounting
principle in the first quarter of 2003, as discussed in Note 6. This accounting
change only affected the timing of the recognition of income or losses on
contracts that do not meet the definition of a derivative, and did not change
the underlying economics or cash flows of those transactions.

      The Company's trading contracts, which include contracts entered into
prior to October 25, 2002 accounted for under EITF 98-10 and contracts entered
into after October 25, 2002 that meet the definition of a derivative under SFAS
No. 133, are reflected at fair value and are included in "Assets and liabilities
from coal trading activities" in the consolidated balance sheets as of December
31, 2004 and 2003.

      Under EITF 02-3, all mark-to-market gains and losses on energy trading
contracts (including derivatives and hedged contracts) are presented on a net
basis in the statement of operations, even if settled physically. The Company's
consolidated statements of operations reflect revenues related to all
mark-to-market trading contracts on a net basis in "Other revenues."

   PROPERTY, PLANT, EQUIPMENT AND MINE DEVELOPMENT

      Property, plant, equipment and mine development are recorded at cost.
Interest costs applicable to major asset additions are capitalized during the
construction period, including $0.2 million, $1.2 million and $2.8 million for
the years ended December 31, 2004, 2003 and 2002, respectively.

      Expenditures which extend the useful lives of existing plant and equipment
are capitalized. Maintenance and repairs are charged to operating costs as
incurred. Costs incurred to develop coal mines or to expand the capacity of
operating mines are capitalized. Costs incurred to maintain current production
capacity at a mine and exploration expenditures are charged to operating costs
as incurred. Costs to acquire computer hardware and the development and/or
purchase of software for internal use are capitalized and depreciated over the
estimated useful lives.

                                       8


      Reserves are recorded at cost, or at fair value in the case of acquired
businesses. As of December 31, 2004 and 2003, the net book value of coal
reserves totaled $3.6 billion and $3.3 billion, respectively. These amounts
include $1.7 billion and $1.6 billion, respectively, attributable to properties
where the Company was not currently engaged in mining operations or leasing to
third parties and, therefore, the coal reserves were not currently being
depleted. Included in the book value of coal reserves are mineral rights, which
include leased coal interests and advance royalties. The net book value of
mineral rights was $2.1 billion and $1.8 billion at December 31, 2004 and 2003,
respectively.

      Depletion of coal reserves is computed using the units-of-production
method utilizing only proven and probable reserves in the depletion base.
Amortization of advance royalties is computed using the units-of-production
method. Mine development costs are principally amortized over the estimated
lives of the mines using the straight-line method.

      Depreciation of plant and equipment (excluding life of mine assets) is
computed using the straight-line method over the estimated useful lives as
follows:



                                                       YEARS
                                                   -------------
                                                
Building and improvements ......................        10 to 29
Machinery and equipment ........................         2 to 30
Leasehold improvements .........................   Life of Lease


      In addition, certain plant and equipment assets associated with mining are
depreciated using the straight-line method over the estimated life of the mine,
which varies from one to 32 years.

   INVESTMENTS IN JOINT VENTURES

      The Company accounts for its investments in less than majority owned
corporate joint ventures under either the equity or cost method. The Company
currently has no investments accounted for under the cost method. The Company
applies the equity method to investments in joint ventures when it has the
ability to exercise significant influence over the operating and financial
policies of the joint venture. Investments accounted for under the equity method
are initially recorded at cost, and any difference between the cost of the
Company's investment and the underlying equity in the net assets of the joint
venture are amortized over the lives of the assets which give rise to the
difference. The Company's pro rata share of earnings from joint ventures and
basis difference amortization is reported in the consolidated statement of
operations in "(Income) loss from equity affiliates." The book value of the
Company's equity method investments as of December 31, 2004 and 2003 was $83.2
million and $60.5 million, respectively, and is reported within "Investments and
other assets" in the consolidated balance sheet.

   GENERATION DEVELOPMENT COSTS

      Development costs related to coal-based electricity generation, including
expenditures for permitting and licensing, are capitalized at cost under the
guidelines in SFAS No. 142, "Goodwill and Other Intangible Assets." Start-up
costs, as defined in Statement of Position No. 98-5, "Reporting on the Costs of
Start-up Activities," are expensed as incurred. Development costs of $16.7
million and $14.8 million were recorded as part of "Investments and other
assets" in the consolidated balance sheets as of December 31, 2004 and 2003,
respectively.

   ASSET RETIREMENT OBLIGATIONS

      SFAS No. 143, which was adopted by the Company (see Note 6) on January 1,
2003, addresses financial accounting and reporting for obligations associated
with the retirement of tangible long-lived assets and the associated asset
retirement costs. The Company's asset retirement obligation ("ARO") liabilities
primarily consist of spending estimates related to reclaiming surface land and
support facilities at both surface and underground mines in accordance with
federal and state reclamation laws as defined by each mining permit.

      The Company estimates its ARO liabilities for final reclamation and mine
closure based upon detailed engineering calculations of the amount and timing of
the future cash spending for a third party to perform the required work.
Spending estimates are escalated for inflation, then discounted at the
credit-adjusted risk-free rate. The Company records an ARO asset associated with
the discounted liability for final reclamation and mine closure. The obligation
and corresponding asset are recognized in the period in which the liability is
incurred. The ARO asset is amortized on the units-of-production method over its
expected life and the ARO liability is accreted to the projected spending date.
As changes in estimates occur (such as mine plan revisions, changes in estimated
costs, or changes in timing of the performance of reclamation activities), the
revisions to the obligation and asset are recognized at the appropriate
credit-adjusted risk-free rate.

                                       9


      The Company also recognizes an obligation for contemporaneous reclamation
liabilities incurred as a result of surface mining. Contemporaneous reclamation
consists primarily of grading, topsoil replacement and revegetation of
backfilled pit areas.

      Prior to the adoption of SFAS 143, the Company recorded a liability for
the estimated costs to reclaim land as the acreage was disturbed during the
mining process. The estimated costs to reclaim support acreage and to perform
other related functions at both surface and underground mines were recorded
ratably over the lives of the mines. As of December 31, 2004, the Company had
$294.5 million in surety bonds outstanding to secure reclamation obligations or
activities. The amount of reclamation self-bonding in certain states in which
the Company qualifies was $653.3 million as of December 31, 2004. Additionally,
the Company had $0.4 million of letters of credit in support of reclamation
obligations or activities as of December 31, 2004.

   ENVIRONMENTAL LIABILITIES

      Included in "Other noncurrent liabilities" are accruals for other
environmental matters that are recorded in operating expenses when it is
probable that a liability has been incurred and the amount of the liability can
be reasonably estimated. Accrued liabilities are exclusive of claims against
third parties and are not discounted. In general, costs related to environmental
remediation are charged to expense.

   INCOME TAXES

      Income taxes are accounted for using a balance sheet approach in
accordance with SFAS No. 109, "Accounting for Income Taxes" ("SFAS 109"). The
Company accounts for deferred income taxes by applying statutory tax rates in
effect at the date of the balance sheet to differences between the book and tax
basis of assets and liabilities. A valuation allowance is established if it is
"more likely than not" that the related tax benefits will not be realized. In
determining the appropriate valuation allowance, the Company considers projected
realization of tax benefits, book and taxable income trends, available tax
strategies and the overall deferred tax position.

   POSTRETIREMENT HEALTH CARE AND LIFE INSURANCE BENEFITS

      The Company accounts for postretirement benefits other than pensions in
accordance with SFAS No. 106 "Employers' Accounting for Postretirement Benefits
Other Than Pensions" ("SFAS 106") which requires the cost to provide the
benefits to be accrued over the employees' period of active service. These costs
are determined on an actuarial basis.

   MULTI-EMPLOYER BENEFIT PLANS

      The Company has an obligation to contribute to two plans established by
the Coal Industry Retiree Health Benefits Act of 1992 - the "Combined Fund" and
the "1992 Plan". The Combined Fund obligations are accounted for in accordance
with Emerging Issues Task Force No. 92-13, "Accounting for Estimated Payments in
Connection with the Coal Industry Retiree Health Benefit Act of 1992," as
determined on an actuarial basis. The 1992 Plan qualifies as a multi-employer
plan under SFAS 106 and expense is recognized as contributions are made.

      A third fund, the 1993 Benefit Fund (the "1993 Plan"), 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 the Company's liability is
limited to its contractual commitment of $0.50 per hour worked. The 1993 Plan
qualifies as a multi-employer plan under SFAS 106 and expense is recognized as
contributions are made.

   PENSION PLANS

      The Company sponsors non-contributory defined benefit pension plans which
are accounted for in accordance with SFAS No. 87 "Employers' Accounting for
Pensions" ("SFAS 87") which requires the cost to provide the benefits to be
accrued over the employees' period of active service. These costs are determined
on an actuarial basis.

      The Company also participates in two multi-employer pension plans, the
United Mine Workers of America 1950 Pension Plan (the "1950 Plan") and the
United Mine Workers of America 1974 Pension Plan (the "1974 Plan"). These plans
qualify as multi-employer plans under SFAS 87 and expense is recognized as
contributions are made.

                                       10


   POSTEMPLOYMENT BENEFITS

      The Company provides postemployment benefits to qualifying employees,
former employees and dependents and accounts for these items on the accrual
basis in accordance with SFAS No. 112 "Employers' Accounting for Postemployment
Benefits" ("SFAS 112"). Postemployment benefits include workers' compensation
occupational disease which is accounted for on the actuarial basis over the
employees' period of active service, workers' compensation traumatic injury
claims which are accounted for based on estimated loss rates applied to payroll
and claim reserves determined by independent actuaries and claims
administrators, disability income benefits which are accrued when a claim occurs
and continuation of medical benefits which are recognized when the obligation
occurs.

   DERIVATIVES

      SFAS No. 133 (as amended) requires the recognition of all derivatives as
assets or liabilities within the consolidated balance sheets at fair value.
Gains or losses on derivative financial instruments designated as fair value
hedges are recognized immediately in the consolidated statement of operations,
along with the offsetting gain or loss related to the underlying hedged item.

      Gains or losses on derivative financial instruments designated as cash
flow hedges are recorded as a separate component of stockholders' equity until
settlement (or until hedge ineffectiveness is determined), whereby gains or
losses are reclassified to the consolidated statements of operations in
conjunction with the recognition of the underlying hedged item. Hedge
ineffectiveness had no effect on results of operations for the years ended
December 31, 2004, 2003 or 2002.

   USE OF ESTIMATES IN THE PREPARATION OF THE CONSOLIDATED FINANCIAL STATEMENTS

      The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.

      In particular, the Company has significant long-term liabilities relating
to retiree health care, work-related injuries and illnesses and defined pension
plans. Each of these liabilities is actuarially determined and the Company uses
various actuarial assumptions, including the discount rate and future cost
trends, to estimate the costs and obligations for these items. In addition, the
Company has significant asset retirement obligations that involve estimations of
costs to remediate mining lands and the timing of cash outlays for such costs.
If these assumptions do not materialize as expected, actual cash expenditures
and costs incurred could differ materially from current estimates. Moreover,
regulatory changes could increase the obligation to satisfy these or additional
obligations.

      Finally, in evaluating the valuation allowance related to the Company's
deferred tax assets, the Company takes into account various factors, including
the expected level of future taxable income and available tax planning
strategies. If actual results differ from the assumptions made in the evaluation
of our valuation allowance, we may record a change in valuation allowance
through income tax expense in the period such determination is made.

   IMPAIRMENT OF LONG-LIVED ASSETS

      The Company records impairment losses on long-lived assets used in
operations when events and circumstances indicate that the assets might be
impaired and the undiscounted cash flows estimated to be generated by those
assets under various assumptions are less than the carrying amounts of those
assets. Impairment losses are measured by comparing the estimated fair value of
the impaired asset to its carrying amount. There were no impairment losses
recorded during the periods covered by the consolidated financial statements.

   FOREIGN CURRENCY TRANSLATION

      For the Company's foreign subsidiaries whose functional currency is the
local currency, all assets and liabilities are translated at current exchange
rates. Consolidated statements of operations accounts are translated at an
average rate for each period. Resulting translation adjustments are reported as
a component of comprehensive income. The Company had foreign subsidiaries whose
functional currency was the local currency during the years ended December 31,
2003 and 2002.

                                       11


      For the Company's foreign subsidiaries where the functional currency is
the U.S. dollar, monetary assets and liabilities are translated at year-end
exchange rates while non-monetary items are translated at historical rates.
Income and expense accounts are translated at the average rates in effect during
the year, except for those expenses related to balance sheet amounts that are
remeasured at historical exchange rates. The Company has foreign subsidiaries
whose functional currency is the U.S. dollar during the years ended December 31,
2004 and 2003. Gains and losses from foreign currency remeasurement are included
in the consolidated statements of operations. Gains and losses from foreign
currency remeasurement did not have a material impact on the Company's
consolidated financial position or results of operations for the years ended
December 31, 2004 or 2003.

   RECLASSIFICATIONS

      Certain amounts in prior periods have been reclassified to conform with
the report classifications of the year ended December 31, 2004, with no effect
on previously reported net income or stockholders' equity.

(2)   RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

      The Company is exposed to various types of risk in the normal course of
business, including fluctuations in commodity prices, interest rates and foreign
currency exchange rates. These risks are actively monitored to ensure compliance
with the risk management policies of the Company. In most cases, commodity price
risk (excluding coal trading activities) related to the sale of coal is
mitigated through the use of long-term, fixed-price contracts rather than
financial instruments, while commodity price risk related to materials used in
production is managed through the use of fixed price contracts and derivatives.

      Interest rate and foreign currency exchange risk are managed through the
use of forward contracts, swaps and options. The Company's usage of interest
rate swaps is discussed in Note 13.

TRADING ACTIVITIES

      The Company performs a value at risk analysis of its trading portfolio,
which includes over-the-counter and brokerage trading of coal. The use of value
at risk allows management to quantify, in dollars, on a daily basis, the price
risk inherent in its trading portfolio. The Company's value at risk model is
based on the industry standard variance/co-variance approach. This captures
exposure related to both option and forward positions.

      During the year ended December 31, 2004, the low, high, and average values
at risk for the Company's coal trading portfolio were $0.5 million, $6.1
million, and $2.9 million, respectively. Further discussion of the Company's
coal trading assets and liabilities is included in Note 3.

      The Company also monitors other types of risk associated with its coal
trading activities, including credit, market liquidity and counterparty
nonperformance.

COMMODITY PRICE RISK

      In addition to the derivatives related to our trading activities, the
Company enters contracts to manage its exposure to price volatility of certain
fuels. As of December 31, 2004, the Company had derivative contracts designated
as cash flow hedges with notional amounts outstanding totaling 105.4 million
gallons, with maturities extending through 2007. The consolidated balance sheet
as of December 31, 2004 reflects unrealized gains on the cash flow hedges of
$5.8 million, which is recorded net of a $2.3 million tax provision, in other
comprehensive income (see Note 20).

CREDIT RISK

      The Company's concentration of credit risk is substantially with energy
producers and marketers and electric utilities, although it also has exposure to
international steel producers. The Company's 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 the Company engages in
a transaction with a counterparty that does not meet its credit standards, the
Company may protect its position by requiring the counterparty to provide
appropriate credit enhancement.

      When appropriate the Company has taken steps to reduce the Company's
credit exposure to customers or counterparties whose credit has deteriorated and
who may pose a higher risk, as determined by the Company's credit management
function, of failure to perform under their contractual obligations. These steps
include obtaining letters of credit or cash collateral, requiring prepayments
for shipments

                                       12


or the creation of customer trust accounts held for the Company's benefit to
fund the payment for coal under existing coal supply agreements.

      To reduce the Company's credit exposure related to its trading and
brokerage activities, the Company seeks to enter into netting agreements with
counterparties that permit the Company 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

      The Company utilizes currency forwards and options to hedge currency risk
associated with anticipated Australian dollar expenditures. As of December 31,
2004, the Company had forward contracts designated as cash flow hedges with
notional amounts outstanding totaling $515.0 million, with maturities extending
through 2007. The consolidated balance sheet as of December 31, 2004 reflects
unrealized gains on the cash flow hedges of $18.2 million, which is recorded net
of a $7.3 million tax provision, in other comprehensive income (see Note 20).

EMPLOYEES

      As of December 31, 2004, the Company and its subsidiaries had
approximately 7,900 employees. As of December 31, 2004, approximately 40% of the
hourly employees were affiliated with organized labor unions and generated 21%
of the Company's 2004 coal production. Relations with our employees and, where
applicable, organized labor are important to the Company's success.

      UNITED STATES

      The United Mine Workers of America represented approximately 30% of the
hourly employees and generated 16% of the Company's domestic production during
the year ended December 31, 2004. An additional 6% of the hourly employees are
represented by labor unions other than the United Mine Workers of America. These
employees generated 2% of the Company's production during the year ended
December 31, 2004. Hourly workers at mines in Arizona and one of our mines in
Colorado are represented by the United Mine Workers of America under the Western
Surface Agreement, which was ratified in 2000 and is effective through September
1, 2005. Union labor east of the Mississippi River is primarily represented by
the United Mine Workers of America, and the majority of union mines are subject
to the National Bituminous Coal Wage Agreement. The current five-year labor
agreement was ratified in December 2001 and is effective through December 31,
2006.

      AUSTRALIA

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

                                       13


(3)   ASSETS AND LIABILITIES FROM COAL TRADING ACTIVITIES

      The Company's coal trading portfolio included forward and swap contracts
as of December 31, 2004 and included forward, futures, and options contracts as
of December 31, 2003. The fair value of coal trading derivatives as of December
31, 2004 and 2003 is set forth below:



                                  DECEMBER 31, 2004          DECEMBER 31, 2003
                               -----------------------    ----------------------
                                ASSETS     LIABILITIES     ASSETS    LIABILITIES
                               --------    -----------    --------   -----------
(Dollars in thousands)
                                                         
Forward contracts              $ 89,042      $ 60,914     $ 57,980     $ 34,380
Other                               123         2,651          341        1,924
                               --------      --------     --------     --------
   Total                       $ 89,165      $ 63,565     $ 58,321     $ 36,304
                               ========      ========     ========     ========


      Ninety-nine percent of the contracts in the Company's trading portfolio as
of December 31, 2004 were valued utilizing prices from over-the-counter market
sources, adjusted for coal quality and traded transportation differentials, and
one percent of the Company's contracts were valued based on similar market
transactions. As of December 31, 2004, one hundred percent of the estimated
future value of the Company's trading portfolio was scheduled to be realized by
the end of 2005.

      At December 31, 2004, 79% of the Company's credit exposure related to coal
trading activities was with investment grade counterparties.

      The Company's coal trading operations traded 33.4 million tons, 40.0
million tons, and 66.9 million tons for the years ended December 31, 2004, 2003
and 2002, respectively.

(4)   ACCOUNTS RECEIVABLE SECURITIZATION

      The Company has established an accounts receivable securitization program
through its wholly-owned, bankruptcy-remote subsidiary ("Seller"). Under the
program, the Company contributes undivided interests in a pool of eligible trade
receivables to the Seller, which then sells, 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. The
Company utilizes proceeds from the sale of its accounts receivable as an
alternative to other forms of debt, effectively reducing its overall borrowing
costs. The funding cost of the securitization program was $1.7 million, $2.3
million and $3.3 million for the years ended December 31, 2004, 2003 and 2002,
respectively. The securitization program is currently scheduled to expire in
September 2009.

      The securitization transactions have been recorded as sales, with those
accounts receivable sold to the Conduit removed from the consolidated balance
sheets. The amount of undivided interests in accounts receivable sold to the
Conduit was $200.0 million and $90.0 million as of December 31, 2004 and 2003,
respectively.

      The Seller is a separate legal entity whose assets are available first and
foremost to satisfy the claims of its creditors. Eligible receivables, as
defined in the securitization agreement, consist of trade receivables from most
of the Company's domestic subsidiaries, and are reduced for certain items such
as past due balances and concentration limits. Of the eligible pool of
receivables contributed to the Seller, undivided interests in only a portion of
the pool are sold to the Conduit. The Company (the Seller) continues to own
$58.1 million of receivables as of December 31, 2004 that represents collateral
supporting the securitization program. The Seller's interest in these
receivables is subordinate to the Conduit's interest in the event of default
under the securitization agreement.

      If the Company defaulted under the securitization agreement or if its pool
of eligible trade receivables decreased significantly, the Company could be
prohibited from selling any additional receivables in the future under the
agreement.

(5)   BUSINESS COMBINATIONS


                                       14


   RAG COAL INTERNATIONAL AG

      On April 15, 2004, the Company purchased, through two separate agreements,
all of the equity interests in three coal operations from RAG Coal International
AG. The combined purchase price, including related costs and fees, of $442.2
million was funded from the Company's equity and debt offerings as discussed in
Notes 13 and 18. The purchases included two mines in Queensland, Australia that
collectively produce 7 to 8 million tons per year of metallurgical coal and the
Twentymile Mine in Colorado, which produces 7 to 8 million tons per year of
steam coal. The two Australian mines increased the Company's metallurgical coal
capacity to 12 to 14 million tons per year and the Company believes they are
well positioned to access the metallurgical coal markets in the Pacific Rim. The
Twentymile Mine has been perennially one of the largest and most productive
underground mines in the United States. The results of operations of the two
mines in Queensland, Australia are included in the Company's Australian Mining
Operations segment and the results of operations of the Twentymile Mine are
included in the Company's Western U.S. Mining segment from the April 15, 2004
purchase date. The acquisition was accounted for as a purchase.

      The preliminary purchase accounting allocations related to the acquisition
have been recorded in the accompanying consolidated financial statements as of,
and for periods subsequent to, April 15, 2004. The final valuation of the net
assets acquired is expected to be finalized once third-party appraisals are
completed. Given the size and complexity of the acquisition, the fair valuation
of certain assets is still preliminary. Additionally, adjustment to the
estimated liabilities assumed in connection with the acquisition may still be
required.

      The following table summarizes the preliminary estimated fair values of
the assets acquired and the liabilities assumed at the date of acquisition
(dollars in thousands):

                                                                  
Accounts receivable                                                  $  46,639
Materials and supplies                                                   6,038
Coal inventory                                                          11,543
Other current assets                                                     6,234
Property, plant, equipment and mine development                        466,753
Accounts payable and accrued expenses                                  (49,057)
Other noncurrent assets and liabilities, net                           (66,885)
                                                                     ---------
Total purchase price, net of cash received of $20,914                $ 421,265
                                                                     =========



                                       15


      In connection with the acquisition of the assets of the Australian mines
and the Twentymile Mine, the Company acquired contract based intangibles
consisting solely of coal supply agreement obligations (customer contracts) that
were unfavorable to the Company based upon current market prices for similar
coal as of April 15, 2004. As required by SFAS No. 141, "Business Combinations",
these below market obligations were fair valued as part of the purchase price
allocation and recorded as liabilities. The liabilities were amortized as the
coal was shipped as follows (dollars in thousands):



                           Opening Balance     Amortization through    Net Book Value at
Contractual Obligation    at April 15, 2004     December 31, 2004      December 31, 2004
- ----------------------    -----------------    --------------------    -----------------
                                                              
US                            $ 29,848              $  (9,472)              $ 20,376
Foreign                         11,974                (10,840)                 1,134
                              --------              ---------               --------
  Total                       $ 41,822              $ (20,312)              $ 21,510
                              ========              =========               ========


Estimated amortization (to income) for the next five years is as follows
(dollars in thousands):



Year ended December 31,
- -----------------------
                         
2005                        $  9,693
2006                           5,775
2007                           4,919
2008                             718
2009                             405
                            --------
    Total                   $ 21,510
                            ========


                                       16


      The following unaudited pro forma financial information presents the
combined results of operations of the Company and the operations acquired from
RAG Coal International AG, on a pro forma basis, as though the companies had
been combined as of the beginning of each period presented. The pro forma
financial information does not necessarily reflect the results of operations
that would have occurred had the Company and the operations acquired from RAG
Coal International AG constituted a single entity during those periods (dollars
in thousands, except per share data):



                                           Year Ended December 31,
                                           ------------------------
                                             2004*          2003
                                           ----------    ----------
                                                   
Revenues:
    As reported                            $3,631,582    $2,815,296
    Pro forma                               3,756,944     3,206,002

Income before accounting changes
    As reported                            $  175,387    $   41,492
    Pro forma                                 172,119        88,252

Net Income
    As reported                            $  175,387    $   31,348
    Pro forma                                 172,119        78,108

Basic earnings per share - net income:
    As reported                            $     1.41    $     0.29
    Pro forma                                    1.34          0.63

Diluted earnings per share - net income:
    As reported                            $     1.38    $     0.29
    Pro forma                                    1.31          0.61


*     During the first quarter of 2004, prior to the Company's acquisition, the
      Australian underground mine acquired by the Company in April 2004
      experienced a roof collapse on a portion of the active mine face,
      resulting in the temporary suspension of mining activities. Due to the
      inability to ship during a portion of this downtime, costs to return the
      mine to operations and shipping limits imposed as the result of unrelated
      restrictions of capacity at a third party loading facility, the pro forma
      Australian operation experienced a net loss in the quarter immediately
      prior to acquisition.

   DODGE HILL HOLDING JV, LLC

      On December 29, 2004, the Company purchased the remaining 55% interest in
Dodge Hill Holding JV, LLC for $7.0 million of assumed debt that was repaid
immediately upon closing, $2.8 million of cash and contingent earn-out payments
based on annual and cumulative EBIT (as defined in the purchase agreement)
through 2007. Dodge Hill Holding JV, LLC operates an underground operation
located in Kentucky which mined 1.2 million tons in 2004. The acquisition was
accounted for as a purchase.

   CARBONES DEL GUASARE

      On December 2, 2004, the Company completed the acquisition of a 25.5%
equity interest in Carbones del Guasare, S.A., from RAG Coal International AG
for a net purchase price of $32.5 million. Carbones del Guasare, a joint venture
that includes Anglo American plc and a Venezuelan governmental partner, operates
the Paso Diablo surface mine in northwestern Venezuela, which produces
approximately 7 million tons per year of steam coal for electricity generators
and steel producers primarily in North America and Europe. The Company accounted
for the purchase under the equity method of accounting.

   BLACK BEAUTY COAL COMPANY

      On April 7, 2003, the Company purchased the remaining 18.3% of Black
Beauty Coal Company and affiliated entities not owned by it for $90.0 million
and contingent consideration. Based on the achievement of certain operating
profit goals set forth in the purchase agreement, the Company paid additional
consideration of $5.0 million in 2004. As a result of the acquisition, the
Company now owns 100% of Black Beauty Coal Company. The acquisition was
accounted for as a purchase.

   ARCLAR COMPANY, LLC

      On September 16, 2002, the Company purchased a 25% interest in Arclar
Company, LLC ("Arclar"), for $14.9 million. The Company's Black Beauty Coal
Company subsidiary owns the remaining 75% of Arclar. Arclar owns the Willow Lake
and Cottage Grove mines in Southern Illinois and more than 50 million tons of
coal reserves. With the Arclar purchase, the Company also acquired controlling
interest of an entity that resulted in the consolidation of $12.5 million of
long-term debt and related assets. The acquisition was accounted for as a
purchase.

   ALLIED QUEENSLAND COALFIELDS PARTY LIMITED

      On August 22, 2002, the Company purchased Allied Queensland Coalfields
Party Limited ("AQC") and its controlled affiliates from Mirant Corporation for
$21.2 million. As a result of the acquisition, the Company now owns the 1.4
million ton per year Wilkie Creek Coal Mine and coal reserves in Queensland,
Australia. The results of AQC's operations are included in the Company's
Australian Mining Operations segment. The acquisition was accounted for as a
purchase.

                                       17


   BEAVER DAM COAL COMPANY

      On June 26, 2002, the Company purchased Beaver Dam Coal Company, located
in Western Kentucky, for $17.7 million. Through the acquisition, the Company
obtained ownership of more than 100 million tons of coal reserves and 22,000
surface acres. The acquisition was accounted for as a purchase.

      The results of operations for each of these entities are included in the
Company's consolidated results of operations from the effective date of each
acquisition. Except for the RAG Coal International AG acquisitions, had the
acquired entities' (discussed above) results of operations been included in the
Company's results of operations since January 1, 2002, there would have been no
material effect on the Company's consolidated statement of operations, financial
condition or cash flows.

(6)   CUMULATIVE EFFECT OF ACCOUNTING CHANGES

      On January 1, 2003, the Company adopted SFAS No. 143, which addresses
accounting and reporting for obligations associated with the retirement of
tangible long-lived assets and the associated asset retirement costs.

      Pursuant to the January 1, 2003 adoption of SFAS No. 143, the Company:

      -     Recognized a credit to income during the first quarter of 2003 of
            $9.1 million, net of taxes, for the cumulative effect of the
            accounting change;

      -     Increased total liabilities by $0.5 million to record the asset
            retirement obligations;

      -     Increased property, plant and equipment by $12.1 million to add
            incremental asset retirement costs to the carrying amount of the
            Company's mine properties and investments and other assets by $6.5
            million to reflect the incremental amount of reclamation obligations
            recoverable from third parties; and

      -     Increased accumulated depreciation, depletion and amortization by
            $2.9 million for the amount of expense that would have been
            recognized in prior periods.

      Adopting SFAS No. 143 had no impact on the Company's reported cash flows.
The Company's reclamation liabilities are unfunded.

      On October 25, 2002, the EITF rescinded EITF Issue No. 98-10 "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities." As a
result of the rescission, trading contracts entered into prior to October 25,
2002 that did not meet the definition of a derivative under SFAS No. 133 were no
longer accounted for on a fair value basis, effective January 1, 2003. In the
first quarter of 2003, the Company recorded a cumulative effect charge in the
statement of operations of $20.2 million, net of income taxes, to reverse the
unrealized gains and losses on non-derivative energy trading contracts recorded
prior to December 31, 2002.

      Effective January 1, 2003, the Company changed its method of amortizing
actuarial gains and losses related to net periodic postretirement benefit costs.
The Company previously amortized actuarial gains and losses using a 5% corridor
with an amortization period of three years. Under the new method, the corridor
has been eliminated and all actuarial gains and losses are now amortized over
the average remaining service period of active plan participants, which was
estimated at 9.26 years. The Company considers this method preferable in that
the elimination of the corridor allows a closer approximation of the fair value
of the liability for postretirement benefit costs, and the amortization of
actuarial gains and losses over the average remaining service period provides a
better matching of the cost of the associated liability over the working life of
the active plan participants. As a result of this change, the Company recognized
a $0.9 million cumulative effect gain in the first quarter of 2003.

                                       18


      The effect of the accounting changes noted above for the year ended
December 31, 2003 was to increase income before accounting changes by $20.4
million, or $0.19 per diluted share, net of income taxes. The cumulative effect
charge of $10.1 million (net of income tax benefit of $6.8 million) to apply
retroactively the new methods described above was included in results of
operations for the year ended December 31, 2003. Below are pro forma net income
and earnings per share results for the Company assuming the new methods had been
retroactively applied (dollars in thousands, except per share data):



                                                                        YEAR ENDED
                                                                       DECEMBER 31,
                                                                -------------------------
                                                                   2003           2002
                                                                -----------   -----------
                                                                        
Net income:
    As reported ....................................            $    31,348   $   105,519
    Pro forma ......................................                 41,492        87,007
Basic earnings per share:
    As reported ....................................            $      0.29   $      1.01
    Pro forma ......................................                   0.39          0.83
Diluted earnings per share:
    As reported ....................................            $      0.29   $      0.98
    Pro forma ......................................                   0.38          0.81


(7)   SHELF REGISTRATION STATEMENT

      The Company filed a shelf registration statement on Form S-3 with the
Securities and Exchange Commission on October 22, 2003, which was declared
effective in March 2004. The universal shelf registration statement remains
effective, with remaining capacity of $602.9 million.

(8)   EARNINGS PER SHARE

      A reconciliation of weighted average shares outstanding follows:



                                                    YEAR ENDED          YEAR ENDED          YEAR ENDED
                                                DECEMBER 31, 2004   DECEMBER 31, 2003   DECEMBER 31, 2002
                                                -----------------   -----------------   -----------------
                                                                               
Weighted average shares outstanding - basic        124,366,372         106,819,042         104,331,470
Dilutive impact of stock options                     3,039,944           2,852,214           3,312,050
                                                   -----------         -----------         -----------
Weighted average shares outstanding - diluted      127,406,316         109,671,256         107,643,520
                                                   ===========         ===========         ===========


      For the years ended December 31, 2004, 2003 and 2002, respectively,
options for two thousand, 0.2 million and 2.4 million shares were excluded from
the diluted earnings per share calculations for the Company's common stock
because they were anti-dilutive. In addition, the Company granted 0.2 million
options to purchase common stock and 0.2 million shares of restricted stock in
January 2005.

(9)   INVENTORIES

      Inventories consisted of the following (dollars in thousands):



                                                                       DECEMBER 31,
                                                         --------------------------------
                                                            2004                  2003
                                                         -----------          -----------
                                                                        
Materials and supplies                                   $    57,467          $    44,421
Raw coal                                                      17,590               15,815
Advance stripping                                            197,225              151,725
Saleable coal                                                 51,327               34,532
                                                         -----------          -----------
  Total                                                  $   323,609          $   246,493
                                                         ===========          ===========


      Materials and supplies and coal inventory are valued at the lower of
average cost or market. Raw coal represents coal stockpiles that may be sold in
current condition or may be further processed prior to shipment to a customer.
Advance stripping consists of the costs to remove overburden above an unmined
coal seam as part of the surface mining process. These costs include labor,
supplies, equipment costs and operating overhead, and are charged to operations
as coal from the seam is sold.

                                       19


(10) LEASES

      The Company leases equipment and facilities under various noncancelable
lease agreements. Certain lease agreements require the maintenance of specified
ratios and contain restrictive covenants which limit indebtedness, subsidiary
dividends, investments, asset sales and other Company actions. Rental expense
under operating leases was $108.1 million, $106.8 million and $116.3 million for
the years ended December 31, 2004, 2003 and 2002, respectively. The net book
value of property, plant, equipment and mine development assets under capital
leases was $1.4 million and $2.8 million as of December 31, 2004 and 2003,
respectively.

      The Company also leases coal reserves under agreements that require
royalties to be paid as the coal is mined. Certain agreements also require
minimum annual royalties to be paid regardless of the amount of coal mined
during the year. Total royalty expense was $233.9 million, $183.5 million and
$181.1 million for the years ended December 31, 2004, 2003 and 2002,
respectively.

      A substantial amount of the coal mined by the Company is produced from
mineral reserves leased from the owner. One of the major lessors is the U.S.
government, from which the Company leases substantially all of the coal it mines
in Wyoming and Colorado under terms set by Congress and administered by the U.S.
Bureau of Land Management. The terms of these leases are generally for an
initial term of ten years but may be extended by diligent development and mining
of the reserve until all economically recoverable reserves are depleted. The
Company has met the diligent development requirements for substantially all of
these federal leases either directly through production or by including the
lease as a part of a logical mining unit with other leases upon which
development has occurred. Annual production on these federal leases must total
at least 1% of the original amount of coal in the entire logical mining unit.
Royalties are payable monthly at a rate of 12.5% of the gross realization from
the sale of the coal mined using surface mining methods and at a rate of 8.0% of
the gross realization for coal produced using underground mining methods.

      The Company also leases the coal production at its Arizona mines from The
Navajo Nation and the Hopi Tribe under leases that are administered by the U.S.
Department of the Interior. These leases expire once mining activities cease.
The royalty rates are also generally based upon a percentage of the gross
realization from the sale of coal. These rates are subject to redetermination
every ten years under the terms of the leases. The remainder of the leased coal
is generally leased from state governments, land holding companies and various
individuals. The duration of these leases varies greatly. Typically, the lease
terms are automatically extended as long as active mining continues. Royalty
payments are generally based upon a specified rate per ton or a percentage of
the gross realization from the sale of the coal.

      On December 19, 2002, the Company entered into a transaction with Penn
Virginia Resource Partners, L.P. ("PVR") whereby the Company sold 120 million
tons of coal reserves in exchange for $72.5 million in cash and 2.76 million
units, or 15 percent, of the PVR master limited partnership. The Company's
subsidiaries leased back the coal and pay royalties as the coal is mined. No
gain or loss was recorded at the inception of this transaction.

     In 2004 and 2003, the Company sold 0.775 million and 1.15 million,
respectively, of the PVR units received in the December 2002 transaction. The
sales were accounted for under SFAS No. 66, "Sales of Real Estate", and gains of
$15.8 million and $7.6 million were recognized in the years ended December 31,
2004 and 2003, respectively. The remaining deferred gain from the sales of the
reserves and units of $22.4 million is intended to provide for the Company's
potential exposure to loss resulting from its continuing involvement in the
properties and will be amortized over the minimum term of the leases, and the
difference of $3.9 million between the fair value of the units received and the
carrying value of the coal reserves sold will be amortized as the leased coal is
mined. The Company accounts for its investment in PVR under the equity method of
accounting, under the provisions of Statement of Position No. 78-9, "Accounting
for Investments in Real Estate Ventures." As of December 31, 2004, the Company
owns approximately 5% of PVR. Based upon PVR's closing price on the New York
Stock Exchange, the market value of the Company's investment was $43.7 million
at December 31, 2004.

      As of December 31, 2004, the Company's lease obligations were secured by
outstanding surety bonds and letters of credit totaling $159.4 million. As of
December 31, 2004, the covenants under certain lease agreements of the Company's
consolidated subsidiaries required a minimum consolidated tangible net worth (as
defined in the agreement) of not less than $500.0 million.

                                       20


      Future minimum lease and royalty payments as of December 31, 2004, are as
follows:



                                                      CAPITAL       OPERATING       COAL
YEAR ENDED DECEMBER 31                                LEASES          LEASES      RESERVES
- ----------------------                              -----------     ---------    ---------
                                                            (Dollars in thousands)
                                                                        
2005                                                $       892      $ 92,817    $  79,035
2006                                                        476        78,781      138,817
2007                                                        314        59,316      135,745
2008                                                         38        45,041      132,882
2009                                                          -        24,919       74,774
2010 and thereafter                                           -        49,417       52,996
                                                    -----------     ---------    ---------
Total minimum lease payments                        $     1,720     $ 350,291    $ 614,249
                                                                    =========    =========
Less interest                                                85
                                                    -----------
Present value of minimum capital lease payments     $     1,635
                                                    ===========


(11)  ACCOUNTS PAYABLE AND ACCRUED EXPENSES

      Accounts payable and accrued expenses consisted of the following:



                                                                     DECEMBER 31,
                                                             ------------------------------
                                                                2004                2003
                                                             ---------          -----------
                                                                  (Dollars in thousands)
                                                                          
Trade accounts payable                                       $ 267,998          $   191,601
Accrued taxes other than income                                 99,061               85,202
Accrued payroll and related benefits                            76,256               54,414
Accrued health care                                             83,844               77,167
Accrued interest                                                21,305               18,585
Workers' compensation obligations                               41,436               43,604
Accrued royalties                                               23,516               19,880
Accrued lease payments                                           7,927                8,153
Other accrued expenses                                          70,257               74,009
                                                             ---------          -----------
 Total accounts payable and accrued expenses                 $ 691,600          $   572,615
                                                             =========          ===========


(12)  INCOME TAXES

      Income (loss) before income taxes, minority interests and discontinued
operations consisted of the following:



                                                              YEAR ENDED DECEMBER 31,
                                                       ------------------------------------
                                                          2004        2003          2002
                                                       ---------    --------      ---------
                                                             (Dollars in thousands)
                                                                         
U.S.                                                   $ 118,076    $  1,734      $  75,684
Non U.S.                                                  34,995      (4,915)         3,120
                                                       ---------    --------      ---------
  Total                                                $ 153,071    $ (3,181)     $  78,804
                                                       =========    ========      =========


                                       21


      Total income tax benefit consisted of the following:



                                                                 YEAR ENDED DECEMBER 31,
                                                          ----------------------------------
                                                            2004         2003         2002
                                                          --------     --------     --------
                                                                (Dollars in thousands)
                                                                           
Current:
   U.S. federal                                           $    655     $      -     $      -
   Non U.S                                                   4,533          251        1,066
   State                                                       300          300          250
                                                          --------     --------     --------
   Total current                                             5,488          551        1,316
                                                          --------     --------     --------
Deferred:
   U.S. federal                                            (33,275)     (46,231)     (37,847)
   Non U.S                                                    (328)           -           12
   State                                                     1,678       (2,028)      (3,488)
                                                          --------     --------     --------
   Total deferred                                          (31,925)     (48,259)     (41,323)
                                                          --------     --------     --------
   Total benefit                                          $(26,437)    $(47,708)    $(40,007)
                                                          ========     ========     ========


      The income tax rate differed from the U.S. federal statutory rate as
follows:



                                                                       YEAR ENDED DECEMBER 31,
                                                      ---------------------------------------------------
                                                          2004               2003                2002
                                                      ------------        ----------         ------------
                                                                      (Dollars in thousands)
                                                                                    
Federal statutory rate                                $     53,575        $   (1,113)        $     27,581
Depletion                                                  (43,488)          (34,436)             (38,136)
Foreign earnings and disposition gains                      (8,043)             (965)                 (14)
State income taxes, net of U.S. federal tax benefit          1,872            (1,834)              (3,325)
Changes in valuation allowance                             (25,863)             (230)             (26,865)
Changes in tax reserves                                          -           (10,000)                   -
Other, net                                                  (4,490)              870                  752
                                                      ------------        ----------         ------------
    Total                                             $    (26,437)       $  (47,708)        $    (40,007)
                                                      ============        ==========         ============


                                       22


      The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and liabilities consisted of the following:



                                                                       DECEMBER 31,
                                                          ------------------------------------
                                                               2004                   2003
                                                          -------------           ------------
                                                                  (Dollars in thousands)
                                                                            
Deferred tax assets:
    Accrued reclamation and mine closing liabilities      $      46,776           $     43,955
    Accrued long-term workers' compensation liabilities         100,157                 98,951
    Postretirement benefit obligations                          391,410                416,639
    Intangible tax asset and purchased contract rights           45,001                 59,566
    Tax credits and loss carryforwards                          377,183                324,199
    Obligation to industry fund                                  13,365                 18,032
    Additional minimum pension liability                         48,188                 52,566
    Others                                                       82,844                 91,760
                                                          -------------           ------------
    Total gross deferred tax assets                           1,104,924              1,105,668
                                                          -------------           ------------
Deferred tax liabilities:
    Property, plant, equipment and mine development, leased
      coal interests and advance royalties, principally due
      to differences in depreciation,depletion and asset
      writedowns                                             1,271,758              1,292,311
    Inventory                                                    64,973                 56,653
    Others                                                        2,465                  5,985
                                                          -------------           ------------
    Total gross deferred tax liabilities                      1,339,196              1,354,949
                                                          -------------           ------------
    Valuation allowance                                        (143,533)              (169,396)
                                                          -------------           ------------
    Net deferred tax liability                            $    (377,805)          $   (418,677)
                                                          =============           ============
Deferred taxes consisted of the following:
Current deferred income taxes                             $      15,461           $     15,749
Noncurrent deferred income taxes                               (393,266)              (434,426)
                                                          -------------           ------------
Net deferred tax liability                                $    (377,805)          $   (418,677)
                                                          =============           ============


      The Company's deferred tax assets include alternative minimum tax ("AMT")
credits of $54.0 million and net operating loss ("NOL") carryforwards of $322.7
million as of December 31, 2004. The AMT credits have no expiration date and the
NOL carryforwards begin to expire in the year 2019. Utilization of the majority
of these AMT credits and NOL carryforwards is subject to various limitations
because of previous changes in ownership (as defined in the Internal Revenue
Code) of the Company and ultimate realization could be negatively impacted by
market conditions and other variables not known or anticipated at this time. The
AMT credits and NOL carryforwards are offset by a valuation allowance of $143.5
million. The valuation allowance was reduced by $25.9 million, $0.2 million and
$26.9 million for the years ended December 31, 2004, 2003 and 2002,
respectively. The Company evaluated and assessed the expected near-term
utilization of NOL's, book and taxable income trends, available tax strategies
and the overall deferred tax position to determine the amount and timing of
valuation allowance adjustments.

      The Company establishes reserves for tax contingencies when, despite the
belief that the Company's 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. The Company's effective tax rate
includes the impact of tax contingency reserves and changes to the reserves,
including related interest, as considered appropriate by management. The Company
establishes 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. The Company is subject to federal audits for
several open years due to its previous inclusion in multiple consolidated groups
and the various parties involved in finalizing those years. The tax contingency
reserve was decreased for the year ended December 31, 2003 by $10.0 million
reflecting the reduction in exposure due to the completion of a federal audit
for the tax years ended April 30, 1999, 2000 and 2001.

                                       23


      The total amount of undistributed earnings of foreign subsidiaries for
income tax purposes was approximately $28.2 million and $2.2 million at December
31, 2004 and 2003, respectively. On October 22, 2004, the American Jobs Creation
Act of 2004 (the "Act") was signed into law. The Act creates a temporary
incentive for U.S. multinationals to repatriate accumulated income earned
outside the U.S. at an effective tax rate of 5.25%. FASB Staff Position FAS
109-2, "Accounting and Disclosure Guidance for the Foreign Earnings Repatriation
Provision within the American Jobs Creation Act of 2004" allows companies
additional time to evaluate the effect of the law regarding whether
unrepatriated foreign earnings continue to qualify for APB Opinion No. 23's
exception for recognizing deferred tax liabilities as retained by SFAS 109.
Through December 31, 2004, the Company has not provided deferred taxes on
foreign earnings because such earnings were intended to be indefinitely
reinvested outside the U.S. Whether the Company will ultimately take advantage
of this provision depends on a number of factors, including reviewing future
Congressional guidance, before a decision can be made. Until that time, the
Company maintains its current intention to indefinitely reinvest accumulated
earnings of its foreign subsidiaries. Should the Company repatriate these
earnings, a one-time tax charge to the Company's consolidated results of
operations of up to $2 million could occur.

      The Company made U.S. Federal tax payments totaling $1.4 million for the
year ended December 31, 2004. The Company made no U.S. Federal tax payments for
the years ended December 31, 2003 or December 31, 2002. The Company paid state
and local income taxes totaling $0.3 million, $0.4 million, and $0.2 million for
the years ended December 31, 2004, 2003 and 2002, respectively. The Company made
non-U.S. tax payments totaling $6.3 million and $3.2 million for the years ended
December 31, 2004 and 2003, respectively. There were no non-U.S. tax payments in
the year ended December 31, 2002.

(13)  LONG-TERM DEBT

      The Company's total indebtedness (in thousands) consisted of the following
at:



                                                                     DECEMBER 31,
                                                           --------------------------------
                                                               2004                2003
                                                           -------------      -------------
                                                                        
Term Loan under Senior Secured Credit Facility             $     448,750      $     446,625
6.875% Senior Notes due 2013                                     650,000            650,000
5.875% Senior Notes due 2016                                     239,525                  -
Fair value of interest rate swaps -- 6.875% Senior Notes           5,189              4,239
5.0% Subordinated Note                                            73,621             79,412
Other                                                              7,880             16,263
                                                           -------------      -------------
   Total                                                   $   1,424,965      $   1,196,539
                                                           =============      =============


      During March 2003, the Company entered into a series of transactions to
refinance a substantial portion of its outstanding indebtedness. The refinancing
expanded the Company's revolving line of credit capacity and lowered its overall
borrowing costs. In connection with the refinancing, the Company incurred total
early debt extinguishment costs of $53.5 million.

      The following table shows the sources and uses (in thousands) of cash
related to the refinancing transactions:

                                                                     
Sources:
  Revolving Credit Facility                                             $         -
  Term Loan under Senior Secured Credit Facility                            450,000
  6.875% Senior Notes due 2013                                              650,000
                                                                        -----------
     Total                                                              $ 1,100,000
                                                                        ===========
Uses:
  Repayment of 9.625% Senior Subordinated Notes                         $   392,219
  Repayment of 8.875% Senior Notes                                          317,098
  Repayment of Black Beauty indebtedness                                    203,215
  Fees and prepayment premiums paid in connection with refinancing           63,697
  Acquisition of 18.3% interest in Black Beauty Coal Company                 90,000
  Cash                                                                       33,771
                                                                        -----------
     Total                                                              $ 1,100,000
                                                                        ===========



                                       24


SENIOR SECURED CREDIT FACILITY

      On March 21, 2003, the Company entered into a Senior Secured Credit
Facility (the "Facility") that consisted of a $600.0 million revolving credit
facility and a $450.0 million term loan. The revolving credit facility, which
was scheduled to expire in March 2008, bore interest at LIBOR plus 2.0% and
provided for maximum borrowings and/or letters of credit of $600.0 million. The
term loan bore interest at LIBOR plus 2.5%.

      On March 8, 2004, the Company entered into an amendment to refinance the
Facility, which expanded the maximum borrowings under the revolving credit
facility from $600.0 million to $900.0 million and reduced the interest rate
payable on the existing term loan under the Facility from LIBOR plus 2.5% to
LIBOR plus 1.75%.

      On October 27, 2004, the Company refinanced the Facility, which reduced
the applicable margin on the loans and the revolving credit agreement fee rate
and extended the revolving loan termination date to March 2010. The refinancing
also reduced the interest rate payable on the existing term loan under the
Facility from LIBOR plus 1.75% to LIBOR plus 1.25%. The applicable rate was
3.74% as of December 31, 2004. The Company had letters of credit outstanding
under the revolving credit facility of $345.9 million at December 31, 2004,
leaving $554.1 million available for borrowing.

      Total principal of $48.8 million will be paid in quarterly installments
through March 31, 2009. The remaining principal of $400.0 million is due in
quarterly installments of $100.0 million to be paid from June 30, 2009 through
March 21, 2010. The Facility is secured by the capital stock and certain assets
of the Company's "restricted subsidiaries" (as defined in the Facility). These
restricted subsidiaries are also guarantors of the Facility. Under the Facility,
the Company must comply with certain financial covenants on a quarterly basis.
These covenants include a minimum EBITDA (as defined in the Facility) interest
coverage ratio, a maximum "total obligations" (as defined in the Facility) to
EBITDA ratio and a maximum senior secured debt to EBITDA ratio. The Company was
in compliance with these covenants as of December 31, 2004.

6.875% SENIOR NOTES DUE MARCH 2013

      On March 21, 2003, the Company issued $650.0 million in senior notes,
which bear interest at 6.875% and are due in March 2013. The notes were
initially sold in accordance with Securities and Exchange Commission Rule 144A,
and the Company filed a registration statement in June 2003 with the Securities
and Exchange Commission that enabled the holders of the notes to exchange them
for publicly registered notes with substantially the same terms. The notes,
which are unsecured, are guaranteed by the Company's "restricted subsidiaries"
as defined in the note indenture. The note indenture contains covenants which,
among other things, limit the Company's ability to incur additional indebtedness
and issue preferred stock, pay dividends or make other distributions, make other
restricted payments and investments, create liens, sell assets and merge or
consolidate with other entities. The notes are redeemable prior to March 15,
2008 at a redemption price equal to 100% of the principal amount plus a
make-whole premium (as defined in the indenture) and on or after March 15, 2008
at fixed redemption prices as set forth in the indenture.

5.875% SENIOR NOTES DUE MARCH 2016

      On March 23, 2004, the Company completed an offering of $250.0 million of
5.875% Senior Notes due 2016. The notes are senior unsecured obligations of the
Company and rank equally with all of the Company's other senior unsecured
indebtedness. Interest payments are scheduled to occur on April 15 and October
15 of each year, and commenced on April 15, 2004. The notes are guaranteed by
the Company's "restricted subsidiaries" as defined in the note indenture. The
note indenture contains covenants which, among other things, limit the Company's
ability to incur additional indebtedness and issue preferred stock, pay
dividends or make other distributions, make other restricted payments and
investments, create liens, sell assets and merge or consolidate with other
entities. The notes are redeemable prior to April 15, 2009 at a redemption price
equal to 100% of the principal amount plus a make-whole premium (as defined in
the indenture) and on or after April 15, 2009 at fixed redemption prices as set
forth in the indenture. Net proceeds from the offering, after deducting
underwriting discounts and expenses, were $244.7 million.

INTEREST RATE SWAPS

      In May 2003, the Company entered into and designated four interest rate
swaps with combined notional amounts totaling $100.0 million as a fair value
hedge of the Company's 6.875% Senior Notes. Under the swaps, the Company pays a
floating rate that resets each March 15 and September 15, based upon the
six-month LIBOR rate, for a period of ten years ending March 15, 2013 and
receives a fixed rate of 6.875%. The average applicable floating rate for the
four swaps was 5.14% as of December 31, 2004.

                                       25


      In September 2003, the Company entered into two $400.0 million interest
rate swaps. One $400.0 million notional amount floating-to-fixed interest rate
swap, expiring March 15, 2010, was designated as a hedge of changes in expected
cash flows on the term loan under the Senior Secured Credit Facility. The term
loan was refinanced in October 2004, and the swap was re-designated as a hedge
of the refinanced term loan. Under this swap, the Company pays a fixed rate of
6.764% and receives a floating rate of LIBOR plus 2.5% (4.99% at December 31,
2004) that resets each March 15, June 15, September 15 and December 15 based
upon the three-month LIBOR rate. Another $400.0 million notional amount
fixed-to-floating interest rate swap, expiring March 15, 2013, was designated as
a hedge of the changes in the fair value of the 6.875% Senior Notes due 2013.
Under this swap, the Company pays a floating rate of LIBOR plus 1.97% (4.46% at
December 31, 2004) that resets each March 15, June 15, September 15 and December
15 based upon the three-month LIBOR rate and receives a fixed rate of 6.875%.
The swaps will lower the Company's overall borrowing costs on $400.0 million of
debt principal by 0.64% over the term of the floating-to-fixed swap.

      Because the critical terms of the swaps and the respective debt
instruments they hedge coincide, there was no hedge ineffectiveness recognized
in the statement of operations during the year ended December 31, 2004. As of
December 31, 2004 and 2003, respectively, the balance sheet reflected a net
unrealized gain on the fair value hedges discussed above of $5.2 million and
$4.2 million, which is reflected as an adjustment to the carrying value of the
Senior Notes (see table above). Related to the cash flow hedge, the balance
sheet at December 31, 2004 and 2003, respectively, reflected an unrealized loss
of $10.9 million and $14.3 million, which is recognized net of a $4.4 million
and $5.7 million tax benefit, in other comprehensive loss (see Note 20).

5.0% SUBORDINATED NOTE

      The 5.0% Subordinated Note is recorded net of discount at an effective
annual interest rate of 12.0%. Interest and principal are payable each March 1
and scheduled principal payments of $10.0 million per year are due from 2005
through 2006 with $60.0 million due March 1, 2007. The 5.0% Subordinated Note is
expressly subordinated in right of payment to all prior indebtedness (as
defined), including borrowings under the Senior Secured Credit Facility, the
6.875% Senior Notes due March 2013 and the 5.875% Senior Notes due March 2016.

OTHER

      Other long-term debt, which consists principally of notes payable, is due
in installments through 2008. The weighted average effective interest rate of
this debt was 3.51% as of December 31, 2004.

      The aggregate amounts of long-term debt maturities subsequent to December
31, 2004 are as follows (dollars in thousands):



YEAR OF MATURITY
- ----------------
                                          
2005                                         $    18,979
2006                                              24,110
2007                                              67,940
2008                                              15,472
2009                                             303,750
2010 and thereafter                              994,714
                                             -----------
    Total                                    $ 1,424,965
                                             ===========


      Interest paid on long-term debt was $87.4 million, $89.0 million and $93.0
million for the years ended December 31, 2004, 2003 and 2002, respectively. No
interest was paid on the revolving credit facility in 2004. Interest paid was
$0.1 million and $2.5 million for the years ended December 31, 2003 and 2002,
respectively.

EARLY DEBT EXTINGUISHMENT COSTS

      In connection with the refinancing of the Senior Secured Credit Facility
on October 27, 2004, the Company incurred a non-cash charge of $2.4 million to
write-off unamortized debt issuance costs related to the term loan.

      In connection with the July 2004 repurchase of $10.5 million of 5.875%
Senior Notes due 2016, the Company realized a gain on early debt extinguishment
of $0.6 million, comprised of the following:

      -     The excess of carrying value of the notes over the cash cost to
            retire the notes of $0.8 million; offset by

      -     Non-cash charges to write-off debt issuance costs associated with
            the debt extinguished of $0.2 million.

                                       26


      The overall effect of the transactions noted above for the year ended
December 31, 2004, was a charge for early debt extinguishment costs of $1.8
million.

      In connection with the refinancing that occurred in March 2003, the
Company incurred early debt extinguishment costs during the year ended December
31, 2003 of $53.5 million, comprised of the following:

      -     The excess of prepayment premiums over the carrying value of the
            debt retired of $41.8 million;

      -     Non-cash charges to write-off debt issuance costs associated with
            the debt extinguished of $17.5 million; and

      -     A $5.8 million gain related to the termination and monetization of
            interest rate swaps associated with the debt extinguished.

(14)  ASSET RETIREMENT OBLIGATIONS

      SFAS No. 143 addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the associated
asset retirement costs. The Company's asset retirement obligation ("ARO")
liabilities primarily consist of spending estimates related to reclaiming
surface land and support facilities at both surface and underground mines in
accordance with federal and state reclamation laws as defined by each mine
permit. The obligation and corresponding asset are recognized in the period in
which the liability is incurred.

      The Company estimates its ARO liabilities for final reclamation and mine
closure based upon detailed engineering calculations of the amount and timing of
the future cash spending for a third party to perform the required work.
Spending estimates are escalated for inflation, then discounted at the
credit-adjusted risk-free rate (6.42% at January 1, 2004.) The Company records
an ARO asset associated with the liability. The ARO asset is amortized on the
units of production method over its expected life and the ARO liability is
accreted to the projected spending date. Changes in estimates could occur due to
mine plan revisions, changes in estimated costs, and changes in timing of the
performance of reclamation activities.

      The Company also recognizes an obligation for contemporaneous reclamation
liabilities incurred as a result of surface mining.

      A reconciliation of the Company's liability for asset retirement
obligations for the year ended December 31, 2004, is as follows (dollars in
thousands):

                                                          
Balance at December 31, 2003                                 $ 384,048
  Liabilities incurred                                          22,985
  Liabilities settled                                          (45,765)
  Accretion expense                                             30,635
  Revisions to estimate                                          4,119
                                                             ---------
Balance at December 31, 2004                                 $ 396,022
                                                             =========



      Total asset retirement obligations as of December 31, 2004, of $396.0
million consisted of $303.7 million related to locations with active mining
operations and $92.3 million related to locations that are closed or inactive.

(15)  WORKERS' COMPENSATION OBLIGATIONS

      Certain subsidiaries of the Company are subject to the Federal Coal Mine
Health and Safety Act of 1969, and the related workers' compensation laws in the
states in which they operate. These laws require the subsidiaries to pay
benefits for occupational disease resulting from coal workers' pneumoconiosis
("occupational disease"). Changes to the federal regulations became effective in
August 2001. The revised regulations are expected to result in higher costs and
have been incorporated into the provision for occupational disease as determined
by independent actuaries. Provisions for occupational disease costs are based on
determinations by independent actuaries or claims administrators.

      The Company provides income replacement and medical treatment for work
related traumatic injury claims as required by applicable state law. Provisions
for estimated claims incurred are recorded based on estimated loss rates applied
to payroll and claim reserves determined by independent actuaries or claims
administrators.

      Certain subsidiaries of the Company are required to contribute to state
workers' compensation funds for second injury and other costs incurred by the
state fund based on a payroll-based assessment by the applicable state.
Provisions are recorded based on the payroll based assessment criteria.

                                       27


      As of December 31, 2004, the Company had $164.6 million in surety bonds
and letters of credit outstanding to secure workers' compensation obligations.

      Workers' compensation provision consists of the following components:



                                              YEAR ENDED DECEMBER 31,
                                     ---------------------------------------
(DOLLARS IN THOUSANDS)                 2004            2003           2002
                                     --------        --------       --------
                                                           
Occupational disease:
  Service cost                       $  4,346        $  3,807       $  2,942
  Interest cost                        11,568          11,760         12,049
  Net amortization                        742             339            466
                                     --------        --------       --------
Total occupational disease             16,656          15,906         15,457
  Traumatic injury claims              27,141          19,691         25,722
  State assessment taxes               15,365          15,016         14,204
                                     --------        --------       --------
Total provision                      $ 59,162        $ 50,613       $ 55,383
                                     ========        ========       ========


      Workers' compensation obligations consist of amounts accrued for loss
sensitive insurance premiums, uninsured claims, and related taxes and
assessments under black lung and traumatic injury workers compensation programs.

      The workers' compensation obligations consisted of the following:



                                                    DECEMBER 31,
                                            ---------------------------
(DOLLARS IN THOUSANDS)                         2004              2003
                                            ---------         ---------
                                                        
Occupational disease costs                  $ 186,647         $ 177,500
Traumatic injury claims                        81,713            75,482
State assessment taxes                            552               576
                                            ---------         ---------
  Total obligations                           268,912           253,558
Less current portion                          (41,436)          (43,604)
                                            ---------         ---------
  Noncurrent obligations                    $ 227,476         $ 209,954
                                            =========         =========


The reconciliation of changes in the benefit obligation of the occupational
disease liability is as follows:



                                                 DECEMBER 31,
                                            ----------------------
(DOLLARS IN THOUSANDS)                        2004          2003
                                            ---------    ---------
                                                   
Beginning of year obligation                $ 191,993    $ 181,597
Less insured claims                                 -       (5,359)
                                            ---------    ---------
   Net obligation                             191,993      176,238
Service cost                                    4,346        3,807
Interest cost                                  11,568       11,760
Actuarial (gain) loss                            (601)       5,556
Insured claim liability reversion                   -        5,200
Acquisitions                                    2,514            -
Benefit and administrative payments           (10,474)     (10,568)
                                            ---------    ---------
   Net obligation at end of year              199,346      191,993
Unamortized loss and prior service cost       (12,699)     (14,493)
                                            ---------    ---------
Accrued cost                                $ 186,647    $ 177,500
                                            =========    =========


                                       28


      The liability for occupational disease claims represents the
actuarially-determined present value of known claims and an estimate of future
claims that will be awarded to current and former employees. The projections for
the year ended December 31, 2004 were based on a 6.4% per annum discount rate
and a 3.5% estimate for the annual rate of inflation. The projections for the
year ended December 31, 2003 were based on a 7.0% per annum discount rate and a
3.5% estimate for the annual rate of inflation. Traumatic injury workers'
compensation obligations are estimated from both case reserves and actuarial
determinations of historical trends, discounted at 6.4% and 7.0% for the years
ended December 31, 2004 and 2003, respectively. The liability for occupational
disease claims was based on a discount rate of 6.1% and 6.4% at December 31,
2004 and 2003, respectively.

  FEDERAL BLACK LUNG EXCISE TAX REFUND CLAIMS

      In addition to the obligations discussed above, certain subsidiaries of
the Company are required to pay black lung excise taxes to the Federal Black
Lung Trust Fund (the "Trust Fund"). The Trust Fund pays occupational disease
benefits to entitled former miners who worked prior to July 1, 1973. Excise
taxes are based on the selling price of coal, up to a maximum per-ton amount.

      The Company recorded expense reductions of $6.8 million for the year ended
December 31, 2002 related to excise tax refund claims filed with the Internal
Revenue Service. These refund claims, covering the period from 1991-1999, were
based on federal court actions that determined that excise taxes paid on export
sales of coal are unconstitutional.

      During the years ended December 31, 2004 and 2003, the Company recorded
interest income of $0.2 million and $0.9 million, respectively, related to
excise tax refunds. During the year ended December 31, 2002, the Company
received $26.8 million of excise tax refunds and recorded related interest
income of $4.6 million. The Company had a receivable for excise tax refunds of
$19.4 million and $24.4 million as of December 31, 2004 and 2003, respectively.

(16) PENSION AND SAVINGS PLANS

      One of the Company's subsidiaries, Peabody Holding Company, sponsors a
defined benefit pension plan covering substantially all salaried U.S. employees
and eligible hourly employees at certain Peabody Holding Company subsidiaries
(the "Peabody Plan"). A Peabody Holding Company subsidiary also has a defined
benefit pension plan covering eligible employees who are represented by the
United Mine Workers of America under the Western Surface Agreement of 2000 (the
"Western Plan"). Twentymile Coal Company ("Twentymile"), a subsidiary of the
Company, sponsors two defined benefit pension plans, one which covers
substantially all Twentymile hourly employees (the "Twentymile Hourly Plan") and
one which covers substantially all Twentymile salaried employees (the
"Twentymile Salaried Plan"). Peabody Holding Company and the Company's Gold
Fields Mining Corporation ("Gold Fields") subsidiary sponsor separate unfunded
supplemental retirement plans to provide senior management with benefits in
excess of limits under the federal tax law and increased benefits to reflect a
service adjustment factor.

      Annual contributions to the plans are made as determined by consulting
actuaries based upon the Employee Retirement Income Security Act of 1974 minimum
funding standard. In May 1998, the Company entered into an agreement with the
Pension Benefit Guaranty Corporation which requires the Company to maintain
certain minimum funding requirements. Assets of the plans are primarily invested
in various marketable securities, including U.S. government bonds, corporate
obligations and listed stocks.

     Net periodic pension costs included the following components:



                                                         YEAR ENDED DECEMBER 31,
                                               -------------------------------------------
                                                 2004             2003              2002
                                               --------         --------          --------
                                                          (Dollars in thousands)
                                                                         
Service cost for benefits earned               $ 12,275         $ 10,184          $  9,592
Interest cost on projected benefit obligation    43,658           41,794            39,919
Expected return on plan assets                  (49,813)         (44,462)          (45,512)
Other amortizations and deferrals                22,366           13,179               831
                                               --------         --------          --------
Net periodic pension costs                     $ 28,486         $ 20,695          $  4,830
                                               ========         ========          ========


      The Company amortizes actuarial gains and losses using a 5% corridor with
a five-year amortization period.

                                       29


      During the period ended March 31, 1999, the Company made an amendment to
phase out the Peabody Plan beginning January 1, 2000. Effective January 1, 2001,
certain employees no longer accrue future service under the plan while other
employees accrue reduced service under the plan based on their age and years of
service as of December 31, 2000. For plan benefit calculation purposes, employee
earnings are also frozen as of December 31, 2000. The Company has adopted an
enhanced savings plan contribution structure in lieu of benefits formerly
accrued under the defined benefit pension plan.

      The following summarizes the change in benefit obligation, change in plan
assets and funded status of the Company's plans:



                                                                                   DECEMBER 31,
                                                                              ----------------------
                                                                                 2004        2003
                                                                              ----------  ----------
                                                                              (Dollars in thousands)
                                                                                    
Change in benefit obligation:
Benefit obligation at beginning of period                                     $ 681,300   $ 601,926
Service cost                                                                     12,275      10,184
Interest cost                                                                    43,658      41,794
Acquisitions                                                                     27,328           -
Benefits paid                                                                   (35,095)    (33,214)
Actuarial loss                                                                   29,817      60,610
                                                                              ---------   ---------
Benefit obligation at end of period                                             759,283     681,300
                                                                              ---------   ---------
Change in plan assets:
Fair value of plan assets at beginning of period                                527,914     456,622
Actual return on plan assets                                                     68,819      87,016
Acquisitions                                                                     18,680           -
Employer contributions                                                           62,082      17,490
Benefits paid                                                                   (35,095)    (33,214)
                                                                              ---------   ---------
Fair value of plan assets at end of period                                      642,400     527,914
                                                                              ---------   ---------
Funded status                                                                  (116,883)   (153,386)
Unrecognized actuarial loss                                                     140,175     151,432
Unrecognized prior service cost                                                   2,201       2,457
                                                                              ---------   ---------
Accrued pension asset                                                         $  25,493   $     503
                                                                              =========   =========
Amounts recognized in the consolidated balance sheets:
Accrued benefit liability                                                     $ (99,905)  $(135,635)
Intangible asset                                                                  4,067       4,742
Additional minimum pension liability, included in other comprehensive income    121,331     131,396
                                                                              ---------   ---------
Net amount recognized                                                         $  25,493   $     503
                                                                              =========   =========


      The accumulated benefit obligation for all pension plans was $740.9
million and $663.5 million as of December 31, 2004 and 2003, respectively. The
projected benefit obligation and the accumulated benefit obligation exceeded
plan assets for all plans as of December 31, 2004 and 2003. The following
presents information applicable to pension plans with accumulated benefit
obligations in excess of plan assets:



                                                                                  DECEMBER 31,
                                                                             ----------------------
                                                                               2004          2003
                                                                             --------      --------
                                                                             (Dollars in thousands)
                                                                                     
Projected benefit obligation                                                 $759,283      $681,300
Accumulated benefit obligation                                                740,931       663,549
Fair value of plan assets                                                     642,400       527,914


                                       30


      The provisions of SFAS No. 87 require the recognition of an additional
minimum liability and related intangible asset to the extent that accumulated
benefits exceed plan assets. As of December 31, 2004 and 2003, the Company has
recorded $121.3 million and $131.4 million, respectively, to reflect the
Company's minimum liability. The current portion of the Company's pension
liability as reflected within "Accounts payable and accrued expenses" at
December 31, 2004 and 2003 was $5.8 million and $14.1 million, respectively. The
noncurrent portion of the Company's pension liability as reflected within "Other
noncurrent liabilities" at December 31, 2004 and 2003 was $90.0 million and
$116.8 million, respectively.

      The weighted-average assumptions used to determine the benefit obligations
as of the end of each year were as follows:



                                                   YEAR ENDED DECEMBER 31,
                                            ------------------------------------
                                                   2004               2003
                                            -----------------  -----------------
                                                         
Discount rate                                           6.10%              6.40%
Rate of compensation increase                           3.50%              3.75%
Measurement date                            December 31, 2004  December 31, 2003


      The weighted-average assumptions used to determine net periodic benefit
cost were as follows:



                                                YEAR ENDED DECEMBER 31,
                                          ------------------------------------
                                                2004                2003
                                          -----------------  -----------------
                                                       
Discount rate                                         6.40%              7.00%
Expected long-term return on plan assets              8.75%              8.75%
Rate of compensation increase                         3.75%              3.75%
Measurement date                          December 31, 2003  December 31, 2002


      The expected rate of return on plan assets is determined by taking into
consideration expected long-term returns associated with each major asset class
(net of inflation) based on long-term historic ranges, inflation assumptions,
and the expected net value from active management of the assets based on actual
results.

PLAN ASSETS

      Assets of the Peabody Plan, the Western Plan, the Twentymile Hourly Plan
and the Twentymile Salaried Plan are commingled in the Peabody Holding Company
Master Trust (the "Master Trust") and are invested in accordance with investment
guidelines that have been established by the Company's Retirement Committee (the
"Retirement Committee") after consultation with outside investment advisors and
actuaries.

      As of the year ended December 31, 2004, Master Trust assets totaled $642.4
million and were invested in the following major asset categories:



                        BALANCE AS OF        PERCENTAGE
                         DECEMBER 31,   ALLOCATION OF TOTAL
                            2004               ASSETS          TARGET ALLOCATION
                        -------------   -------------------    -----------------
                                       (Dollars in thousands)
                                                      
Equity securities         $339,287              52.8%                50.0%
Fixed income               250,749              39.0%                40.0%
Real estate                 49,647               7.8%                10.0%
Cash fund                    2,717               0.4%                 0.0%
                          --------            ------               ------
Total                     $642,400            100.00%              100.00%
                          ========            ======               ======


                                       31


      As of the year ended December 31, 2003, Master Trust assets totaled $527.9
million and were invested in the following major asset categories:



                     BALANCE AS OF       PERCENTAGE
                      DECEMBER 31,   ALLOCATION OF TOTAL
                         2003              ASSETS           TARGET ALLOCATION
                     -------------  ----------------------  -----------------
                                    (Dollars in thousands)
                                                   
Equity securities      $279,145             52.9%                 50.0%
Fixed income            199,627             37.8%                 40.0%
Real estate              45,254              8.6%                 10.0%
Cash fund                 3,888              0.7%                  0.0%
                       --------            -----                 -----
Total                  $527,914            100.0%                100.0%
                       ========            =====                 =====


      The asset allocation targets have been set with the expectation that the
plan's assets will fund the plan's expected liabilities with an appropriate
level of risk. To determine the appropriate target asset allocations, the
Retirement Committee considers the demographics of the plan participants, the
funding status of the plan, the business and financial profile of the Company
and other associated risk preferences. These allocation targets are reviewed by
the Retirement Committee on a regular basis and revised as necessary.
Periodically assets are rebalanced among major asset categories to maintain the
allocations within a range of plus or minus 5% of the target allocation.

      Plan assets are either under active management by third-party investment
advisors or in index funds, all selected and monitored by the Retirement
Committee. The Retirement Committee has established specific investment
guidelines for each major asset class including performance benchmarks,
allowable and prohibited investment types and concentration limits. In general,
the plan investment guidelines do not permit leveraging the Master Trust's
assets. Equity investment guidelines do not permit entering into put or call
options (except as deemed appropriate to manage currency risk), and futures
contracts are permitted only to the extent necessary to equitize cash holdings.

CONTRIBUTIONS

      The Company expects to contribute $4.6 million to its funded pension plans
and make $1.2 million in expected benefit payments attributable to its unfunded
pension plans during 2005.

ESTIMATED FUTURE BENEFITS PAYMENTS

      The following benefit payments (net of retiree contributions), which
reflect expected future service, as appropriate, are expected to be paid by the
Company:



                                                             PENSION BENEFITS
                                                          ----------------------
                                                          (Dollars in thousands)
                                                       
2005                                                         $     37,922
2006                                                               39,320
2007                                                               40,958
2008                                                               43,024
2009                                                               44,947
Years 2010-2014                                                   270,546


MULTI-EMPLOYER PENSION PLANS

      Certain subsidiaries participate in multi-employer pension plans (the 1950
Plan and the 1974 Plan), which provide defined benefits to substantially all
hourly coal production workers represented by the United Mine Workers of America
other than those covered by the Western Plan. Benefits under the United Mine
Workers of America plans are computed based on service with the subsidiaries or
other signatory employers. There were no contributions to the multi-employer
pension plans during the years ended December 31, 2004, 2003 or 2002.

                                       32


DEFINED CONTRIBUTION PLANS

      The Company sponsors employee retirement accounts under seven 401(k) plans
for eligible salaried U.S. employees. The Company matches voluntary
contributions to each plan up to specified levels. A performance contribution
feature allows for contributions based upon meeting specified Company
performance targets. The expense for these plans was $10.2 million, $9.4 million
and $8.1 million for the years ended December 31, 2004, 2003 and 2002,
respectively.

(17) POSTRETIREMENT HEALTH CARE AND LIFE INSURANCE BENEFITS

      The Company currently provides health care and life insurance benefits to
qualifying salaried and hourly retirees and their dependents from defined
benefit plans established by the Company. Employees of Gold Fields are only
eligible for life insurance benefits as provided by the Company. Plan coverage
for the health and life insurance benefits is provided to future hourly retirees
in accordance with the applicable labor agreement. The Company accounts for
postretirement benefits using the accrual method.

      Net periodic postretirement benefits costs included the following
components:



                                                                    YEAR ENDED DECEMBER 31,
                                                                -------------------------------
                                                                  2004       2003       2002
                                                                ---------  ---------  ---------
                                                                    (DOLLARS IN THOUSANDS)
                                                                             
Service cost for benefits earned                                $  4,430   $  4,670   $  4,219
Interest cost on accumulated postretirement benefit obligation    63,635     77,984     76,691
Amortization of prior service cost                               (13,230)   (15,787)   (14,698)
Amortization of actuarial losses                                   3,575     16,802      8,180
                                                                --------   --------   --------
Net periodic postretirement benefit costs                       $ 58,410   $ 83,669   $ 74,392
                                                                ========   ========   ========


      The following table sets forth the plans' combined funded status
reconciled with the amounts shown in the consolidated balance sheets:



                                                             DECEMBER 31,
                                                      --------------------------
                                                          2004          2003
                                                      ------------  ------------
                                                        (DOLLARS IN THOUSANDS)
                                                              
Change in benefit obligation:
Benefit obligation at beginning of period             $ 1,023,453   $ 1,253,187
Service cost                                                4,430         4,670
Interest cost                                              63,635        77,984
Participant contributions                                   1,360         1,231
Plan amendments                                             4,492       (10,561)
Plan amendments due to Medicare Reform Act                      -       (19,130)
Acquisitions                                               10,191             -
Benefits paid                                             (83,451)      (80,795)
Actuarial gain due to Medicare Reform Act                       -      (162,369)
Actuarial (gain) loss                                     210,075       (40,764)
                                                      -----------   -----------
Benefit obligation at end of period                     1,234,185     1,023,453
                                                      -----------   -----------
Change in plan assets:
Fair value of plan assets at beginning of period                -             -
Employer contributions                                     82,091        79,564
Participant contributions                                   1,360         1,231
Benefits paid                                             (83,451)      (80,795)
                                                      -----------   -----------
Fair value of plan assets at end of period                      -             -
                                                      -----------   -----------
Funded status                                          (1,234,185)   (1,023,453)
Unrecognized actuarial loss                               236,634        30,134
Unrecognized prior service cost                           (23,270)      (40,992)
                                                      -----------   -----------
Accrued postretirement benefit obligation              (1,020,821)   (1,034,311)
Less current portion                                       81,318        72,500
                                                      -----------   -----------
Noncurrent obligation                                 $  (939,503)  $  (961,811)
                                                      ===========   ===========


      The weighted-average assumptions used to determine the benefit obligations
as of the end of each year were as follows:

                                       33




                                                           YEAR ENDED DECEMBER 31,
                                                     ------------------------------------
                                                            2004                2003
                                                     -----------------  -----------------
                                                                  
Discount rate                                                    6.10%              6.40%
Rate of compensation increase                                    3.50%              3.75%
Measurement date                                     December 31, 2004  December 31, 2003


      The weighted-average assumptions used to determine net periodic benefit
cost were as follows:



                                                            YEAR ENDED DECEMBER 31,
                                                     ------------------------------------
                                                           2004                2003
                                                     -----------------  -----------------
                                                                  
Discount rate                                                    6.40%              7.00%
Expected long-term return on plan assets                           N/A                N/A
Rate of compensation increase                                    3.75%              3.75%
Measurement date                                     December 31, 2003  December 31, 2002


      The following presents information about the assumed health care cost
trend rate:



                                                                  YEAR ENDED DECEMBER 31,
                                                                  -----------------------
                                                                     2004        2003
                                                                  --------  -------------
                                                                      
Health care cost trend rate assumed for next year                    8.00%          7.00%
Rate to which the cost trend is assumed to decline (the ultimate
trend rate)                                                          4.75%          4.75%
Year that the rate reaches the ultimate trend rate                   2010           2009


      Assumed health care cost trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage-point change in the
assumed health care cost trend would have the following effects:



                                                      ONE-PERCENTAGE-  ONE-PERCENTAGE-
                                                      POINT INCREASE    POINT DECREASE
                                                      ---------------  ---------------
                                                           (DOLLARS IN THOUSANDS)
                                                                 
Effect on total service and interest cost components      $   7,960      $  (5,462)
Effect on total postretirement benefit obligation         $ 138,793      $(116,488)


PLAN ASSETS

      The Company's postretirement benefit plans are unfunded.

CASH FLOWS

      The Company expects to pay $85.7 million in benefits attributable to its
postretirement benefit plans during 2005.

                                       34


   ESTIMATED FUTURE BENEFITS PAYMENTS

      The following benefit payments (net of retiree contributions), which
reflect expected future service, as appropriate, are expected to be paid by the
Company:



                 (DOLLARS IN THOUSANDS)
                 ----------------------
              
2005               $      85,650
2006                      75,044
2007                      78,731
2008                      82,364
2009                      84,231
Years 2010-2014          460,893


   MEDICARE AND OTHER PLAN CHANGES

      On December 8, 2003 the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (the "Act") was signed into law. The Company elected
not to defer the effects of the Act as discussed in FASB Staff Position 106-1,
"Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003." Additionally, the Company did
not elect the Federal Subsidy provisions of the Act; rather the Company
coordinated benefits with available Medicare coverage considered the primary
payer, whether or not the beneficiary enrolled and paid the required premiums.

      The Company recognized a reduction in the benefit obligation on two
distinct components. For plans that required amendment to incorporate the Act,
the Company recognized a liability reduction of $19.1 million. This reduction
was treated as a negative plan amendment and is being amortized to income over
six years beginning December 15, 2003. For plans that did not require amendment,
the Company recognized a liability reduction of $162.4 million. The reduction
was treated as a change in the estimated cost to provide benefits to Medicare
eligible beneficiaries constituting a component of the cumulative actuarial gain
or loss subject to amortization in accordance with the Company's amortization
method.

      In July 2001, the Company adopted changes to the prescription drug
program. Effective January 1, 2002, an incentive mail order and comprehensive
utilization management program was added to the prescription drug program. The
effect of the change on the retiree health care liability was $38.4 million. The
Company began recognizing the effect of the plan amendment over three years
beginning July 1, 2001. Net periodic postretirement benefit costs were reduced
by $6.4 million for December 31, 2004, and $12.8 million for each of the years
ended December 31, 2003 and 2002, for this change.

      In January 1999, the Company adopted reductions to the salaried employee
medical coverage levels for employees retiring before January 1, 2003, which was
changed to January 1, 2005, in 2002. For employees retiring on or after January
1, 2005, the current medical plan is replaced with a medical premium
reimbursement plan. This plan change did not apply to Powder River or Lee Ranch
salaried employees. The change in the retiree health care plan resulted in a
$22.4 million reduction to the salaried retiree health care liability. The
Company began recognizing the effect of the plan amendment over nine years
beginning January 1, 1999. The effect was $2.5 million for each of the years
ended December 31, 2004, 2003 and 2002.

      ACCOUNTING CHANGE

      Effective January 1, 2003, the Company changed its accounting method of
amortizing actuarial gains and losses. Previously the Company employed a 5%
corridor, 3-year amortization of actuarial gains and losses. Effective January
1, 2003, the Company changed to a 0% corridor, average remaining service period
of active employees (8.43 years and 9.26 years at January 1, 2004 and 2003,
respectively), which was deemed preferable. The Company recorded the cumulative
effect of the change in accounting as a credit to income of $0.9 million (net of
tax expense of $0.6 million), as discussed in Note 6.

                                       35


  MULTI-EMPLOYER BENEFIT PLANS

      Retirees formerly employed by certain subsidiaries and their predecessors,
who were members of the United Mine Workers of America, last worked before
January 1, 1976 and were receiving health benefits on July 20, 1992, receive
health benefits provided by the Combined Fund, a fund created by the Coal
Industry Retiree Health Benefit Act of 1992 (the "Coal Act"). The Coal Act
requires former employers (including certain subsidiaries of the Company) and
their affiliates to contribute to the Combined Fund according to a formula. In
addition, certain Federal Abandoned Mine Lands funds will be transferred to fund
certain benefits.

      The Company has recorded an actuarially determined liability representing
the amounts anticipated to be due to the Combined Fund. The noncurrent portion
related to this obligation as reflected within "Other noncurrent liabilities" in
the consolidated balance sheets as of December 31, 2004 and 2003, was $33.4
million and $44.8 million, respectively. The current portion related to this
obligation reflected in "Accounts payable and accrued expenses" in the
consolidated balance sheets as of December 31, 2004 and 2003, was $6.4 million
and $6.7 million, respectively.

      Expense of $4.9 million was recognized for the year ended December 31,
2004. Expense consisted of interest discount of $3.8 million and amortization of
actuarial loss of $1.1 million. Expense of $1.2 million was recognized for the
year ended December 31, 2003. Expense consisted of interest discount of $3.4
million and amortization of actuarial gain of $2.2 million. Expense of $16.7
million was recognized for the year ended December 31, 2002, which included a
charge of $17.2 million related to an adverse U.S. Supreme Court ruling
regarding health care beneficiaries previously assigned to the Company by the
Social Security Administration. The ruling overturned a U.S. Court of Appeals
decision in June 2001 that the Social Security Administration had improperly
assigned the beneficiaries to the Company.

      The Company made contributions of $16.6 million, $16.2 million and $7.2
million to the Combined Fund for the years ended December 31, 2004, 2003 and
2002, respectively.

      The Coal Act also established a multi-employer benefit plan ("1992 Plan")
which will provide medical and death benefits to persons who are not eligible
for the Combined Fund, who retired prior to October 1, 1994 and whose employer
and any affiliates are no longer in business. A prior labor agreement
established the 1993 United Mine Workers of America Benefit Trust ("1993 Plan")
to provide health benefits for retired miners not covered by the Coal Act. The
1992 Plan and the 1993 Plan qualify under SFAS No. 106 as multi-employer benefit
plans, which allows the Company to recognize expense as contributions are made.
The expense related to these funds was $4.4 million, $5.3 million and $4.1
million for the years ended December 31, 2004, 2003 and 2002, respectively.

      Pursuant to the provisions of the Coal Act and the 1992 Plan, the Company
is required to provide security in an amount equal to three times the annual
cost of providing health care benefits for all individuals receiving benefits
from the 1992 Plan who are attributable to the Company, plus all individuals
receiving benefits from an individual employer plan maintained by the Company
who are entitled to receive such benefits. In accordance with the Coal Act and
the 1992 Plan, the Company has outstanding letters of credit as of December 31,
2004 of $120.1 million to secure the Company's obligation.

(18) STOCKHOLDERS' EQUITY

COMMON STOCK

      The Company has 150.0 million authorized shares of $0.01 par value common
stock. Holders of common stock are entitled to one vote per share on all matters
to be voted upon by the stockholders. The holders of common stock do not have
cumulative voting rights in the election of directors. Holders of common stock
are entitled to ratably receive dividends if, as and when dividends are declared
from time to time by the Board of Directors. Upon liquidation, dissolution or
winding up, any business combination or a sale or disposition of all or
substantially all of the assets, the holders of common stock are entitled to
receive ratably the assets available for distribution to the stockholders after
payment of liabilities and accrued but unpaid dividends and liquidation
preferences on any outstanding preferred stock or series common stock. The
common stock has no preemptive or conversion rights and is not subject to
further calls or assessment by the Company. There are no redemption or sinking
fund provisions applicable to the common stock.

                                       36


PREFERRED STOCK AND SERIES COMMON STOCK

      In addition to the common stock, the Board of Directors is authorized to
issue up to 10.0 million shares of preferred stock and up to 40.0 million shares
of series common stock. The Board of Directors is authorized to determine the
terms and rights of each series, including the number of authorized shares,
whether dividends (if any) will be cumulative or non-cumulative and the dividend
rate of the series, redemption or sinking fund provisions, conversion terms,
prices and rates, and amounts payable on shares of the series in the event of
any voluntary or involuntary liquidation, dissolution or winding up of the
affairs of the Company. The Board of Directors may also determine restrictions
on the issuance of shares of the same series or of any other class or series,
and the voting rights (if any) of the holders of the series. There were no
outstanding shares of preferred stock or series common stock as of December 31,
2004.

PREFERRED SHARE PURCHASE RIGHTS PLAN

      In July 2002, the Board of Directors of the Company adopted a preferred
share purchase rights plan (the "Rights Plan"). In connection with the Rights
Plan, the Board of Directors of the Company declared a dividend of one preferred
share purchase right (a "Right") for each outstanding share of common stock, par
value $0.01 per share, of the Company. The Rights Plan expires in August 2012.

      The Rights have certain anti-takeover effects. The Rights will cause
substantial dilution to a person or group that attempts to acquire the Company
on terms not approved by the Company's Board of Directors, except pursuant to
any offer conditioned on a substantial number of Rights being acquired. The
Rights should not interfere with any merger or other business combination
approved by the Board of Directors since the Rights may be redeemed by the
Company at a redemption price of $0.001 per Right prior to the time that a
person or group has acquired beneficial ownership of 15% or more of the common
stock of the Company. In addition, the Board of Directors is authorized to
reduce the 15% threshold to not less than 10%.

TREASURY STOCK

      During the years ended December 31, 2004 and 2003, the Company received
10,068 and 216,702 shares, respectively, of common stock as consideration for
employees' exercise of stock options. The value of the common stock tendered by
employees to exercise stock options was based upon the closing price on the
dates of the respective transactions. The common stock tenders were in
accordance with the provisions of the 1998 Stock Purchase and Option Plan, which
was previously approved by the Company's Board of Directors.

EQUITY OFFERING

      On March 23, 2004, the Company completed an offering of 17,650,000 shares
of the Company's common stock, priced at $22.50 per share. Net proceeds from the
offering, after deducting underwriting discounts and commissions and other
expenses, were $383.1 million, and were primarily used, as discussed in Note 5,
to fund the acquisition of three coal operations from RAG Coal International AG.

                                       37


      The following table summarizes common share activity from December 31,
2001 to December 31, 2004:



                                                                    SHARES
                                                                  OUTSTANDING
                                                                  ------------
                                                               
DECEMBER 31, 2001                                                 104,020,492
  Stock options exercised                                             582,406
  Employee stock purchases                                            314,462
  Stock grants to non-employee directors                                3,816
  Shares repurchased and retired                                     (120,620)
                                                                  -----------
DECEMBER 31, 2002                                                 104,800,556
  Stock options exercised                                           4,527,540
  Employee stock purchases                                            152,134
  Stock grants to non-employee directors                                9,980
  Stock grant to executive                                             20,000
  Shares repurchased                                                 (216,702)
                                                                  -----------
DECEMBER 31, 2003                                                 109,293,508
  Stock options exercised                                           2,476,934
  Employee stock purchases                                            148,824
  Stock grants to non-employee directors                                8,756
  Equity offering                                                  17,650,000
  Shares repurchased                                                  (10,068)
                                                                  -----------
DECEMBER 31, 2004                                                 129,567,954
                                                                  ===========


SECONDARY OFFERINGS

      On March 23, 2004, concurrent with the primary equity offering described
above, Lehman Brothers Merchant Banking Partners II L.P. and affiliates
("Merchant Banking Fund"), the Company's largest stockholder as of that date,
sold 20,534,338 shares of the Company's common stock. The Company did not
receive any proceeds from the sale of shares by Merchant Banking Fund. This
offering completed Merchant Banking Fund's planned exit strategy and eliminated
the remaining portion of their beneficial ownership of the Company.

      On August 4, 2003, Merchant Banking Fund sold 10,800,000 shares of common
stock. Merchant Banking Fund received all net proceeds. The Company did not sell
any shares through the offering. Merchant Banking Fund's beneficial ownership of
the Company declined from 29% to 19%.

      On May 7, 2003, certain shareholders of the Company, including Merchant
Banking Fund, sold 11,500,000 shares of common stock, including sales under an
over-allotment option of 1,500,000 shares. The selling shareholders received all
net proceeds. The Company did not sell any shares through the offering. Merchant
Banking Fund sold, in the aggregate, 11,235,650 shares in the offering, and
their beneficial ownership of the Company declined from 41% to 29%.

(19) EQUITY COMPENSATION PLANS

  LONG-TERM EQUITY INCENTIVE PLANS

      Effective May 6, 2004, shareholders approved and the Company adopted the
"2004 Long-Term Equity Incentive Plan," making 7.0 million shares of the
Company's common stock available for grant. The Board of Directors may provide
such grants in the form of stock appreciation rights, restricted stock,
performance awards, incentive stock options, nonqualified stock options and
stock units. The Company made no awards under this plan for the year ended
December 31, 2004.

      In connection with the initial public offering, the Company adopted the
"Long-Term Equity Incentive Plan," making 5.0 million shares of the Company's
common stock available for grant. The Board of Directors may provide such grants
in the form of stock appreciation rights, restricted stock, performance awards,
incentive stock options, nonqualified stock options and stock units. The Company
granted 2.0 million and 1.4 million non-qualified options to purchase common
stock during the years ended December 31, 2003 and 2002, respectively. These
options generally vest over three years and expire 10 years after date of grant.
The Company made no awards under this plan for the year ended December 31, 2004.

                                       38


      Performance units granted by the Company vest over, and are payable in
cash subject to the achievement of performance goals at the conclusion of, the
three year measurement period. Three performance unit grants were outstanding
during 2004. The payout related to the 2002 and 2003 grants is based on the
Company's stock price performance compared to both an industry peer group and an
S&P Index. The payout related to the 2004 grant (which will vest at the end of
2006) is based 50% on stock price performance compared to both an industry peer
group and an S&P Index and 50% on a return on capital target. During the years
ended December 31, 2004, 2003 and 2002, the Company granted 0.2 million
performance units in each period. As a result of the Company's performance under
the terms of these grants, the Company recognized compensation expense of $21.1
million, $3.3 million and $2.1 million in 2004, 2003 and 2002, respectively.

   STOCK PURCHASE AND OPTION PLAN

      Effective May 19, 1998, the Company adopted the "1998 Stock Purchase and
Option Plan for Key Employees of P&L Coal Holdings Corporation," making 11.2
million shares of the Company's common stock available for grant. The Board of
Directors provided such grants in the form of stock, non-qualified options and
incentive stock options. The Company granted 1.1 million non-qualified options
to purchase common stock during the year ended December 31, 2004. These options
vest over three years and expire 10 years after date of grant.

   NON-EMPLOYEE DIRECTOR EQUITY INCENTIVE PLAN

      During the nine months ended December 31, 2001, the Company also adopted
the Equity Incentive Plan for Non-Employee Directors. Under that plan, members
of the Company's Board of Directors who are not employees of the Company or one
of its affiliates will be eligible to receive grants of restricted stock and
stock options. Restricted stock will be granted to a director upon election or
appointment to the Board of Directors, and will vest upon the third anniversary
of the date of grant. Options to purchase stock will be granted to eligible
directors each year at the annual meeting of the Board of Directors, and will
vest ratably over three years. All options granted under the plan will expire
after 10 years from the date of the grant, subject to earlier termination in
connection with a director's termination of service.

      The Company recognized compensation cost related to grants of common stock
to management and non-employee directors of $0.1 million during each of the
years ended December 31, 2004, 2003, and 2002.

      A summary of outstanding option activity is as follows:



                            YEAR                                 YEAR                                YEAR
                            ENDED           WEIGHTED             ENDED           WEIGHTED            ENDED            WEIGHTED
                          DECEMBER           AVERAGE           DECEMBER          AVERAGE           DECEMBER           AVERAGE
                             31,            EXERCISE              31,            EXERCISE             31,             EXERCISE
                            2004             PRICE               2003             PRICE              2002              PRICE
                         -----------      ------------        -----------      ------------      ------------       ------------
                                                                                                  
Beginning balance         8,773,686       $      10.44        11,547,658       $       8.51        11,356,686       $       7.85
  Granted                 1,078,742              21.26         1,964,574              15.44         1,372,468              13.42
  Exercised              (2,476,934)             11.10        (4,527,540)              7.73          (582,406)              7.15
  Forfeited                (141,326)             12.06          (211,006)              9.66          (599,090)              8.57
                         ----------                           ----------                           ----------
Outstanding               7,234,168       $      11.80         8,773,686       $      10.44        11,547,658       $       8.51
                         ==========                           ==========                           ==========
Exercisable               2,063,478       $      11.85         3,326,128       $      10.49         5,798,392       $       7.59
                         ==========                           ==========                           ==========


                                       39


      A summary of options outstanding and exercisable as of December 31, 2004
is as follows:



                             OPTIONS OUTSTANDING                 OPTIONS EXERCISABLE
                           ----------------------------------------------------------
                                         WEIGHTED
                                          AVERAGE     WEIGHTED               WEIGHTED
                                         REMAINING     AVERAGE                AVERAGE
                                        CONTRACTUAL   EXERCISE               EXERCISE
RANGE OF EXERCISE PRICES    NUMBER         LIFE        PRICE      NUMBER      PRICE
- ------------------------   ---------    -----------   --------   ---------   --------
                                                              
          $ 7.15           3,738,136        4.0        $ 7.15      903,878    $ 7.15
$11.70 to $13.65             626,900        7.0         13.40      222,448     13.42
$13.66 to $15.60           1,349,108        7.5         14.43      516,056     14.16
$15.61 to $17.55             266,282        8.7         16.92      220,428     17.13
$17.56 to $19.50             202,000        8.8         19.50      200,668     19.50
$19.51 to $21.45             977,024        8.9         20.98            -         -
$21.46 to $30.50              74,718        9.4         24.54            -         -
                           ---------                             ---------
                           7,234,168                             2,063,478
                           =========                             =========


      The weighted average fair values of the Company's stock options and the
assumptions used in applying the Black-Scholes option pricing model (for grants
during the years ended December 31, 2004, 2003 and 2002) were as follows:



                                            DECEMBER 31,
                             ------------------------------------------
                                2004           2003           2002
                             ------------   ------------   ------------
                                                  
Weighted average fair value  $    8.92       $    6.75      $    6.59
Risk-free interest rate            3.9%            3.6%           4.6%
Expected option life         5.9 years       6.6 years      7.0 years
Expected volatility                 40%             42%            49%
Dividend yield                     1.0%            1.4%           1.4%


   EMPLOYEE STOCK PURCHASE PLAN

      During 2001, the Company adopted an employee stock purchase plan. Total
shares of common stock available for purchase under the plan were 3.0 million.
Eligible full-time and part-time employees are able to contribute up to 15% of
their base compensation into this plan, subject to a limit of $25,000 per year.
Employees are able to purchase Company common stock at a 15% discount to the
lower of the fair market value of the Company's common stock on the initial and
ending dates of each offering period. Shares purchased under the plan were 0.1
million, 0.2 million and 0.3 million for the years ended December 31, 2004, 2003
and 2002, respectively.

                                       40


(20) COMPREHENSIVE INCOME (LOSS)

      The after-tax components of accumulated other comprehensive income (loss)
are as follows:



                                                                                                                   TOTAL
                                                                                        MINIMUM                 ACCUMULATED
                                                                    FOREIGN CURRENCY    PENSION                    OTHER
                                                                       TRANSLATION     LIABILITY    CASH FLOW  COMPREHENSIVE
(DOLLARS IN THOUSANDS)                                                 ADJUSTMENT      ADJUSTMENT    HEDGES        LOSS
                                                                    ----------------   ----------   ---------  -------------
                                                                                                   
December 31, 2001                                                      $      -        $ (30,345)    $     -     $ (30,345)
Current period change                                                        15          (47,297)          -       (47,282)
                                                                       --------        ---------     -------     ---------
December 31, 2002                                                            15          (77,642)          -       (77,627)
Net decrease in value of cash flow hedges                                     -                -      (3,694)       (3,694)
Reclassification from other comprehensive income to earnings                  -                -      (3,347)       (3,347)
Current period change                                                     3,138              (42)          -         3,096
                                                                       --------        ---------     -------     ---------
December 31, 2003                                                         3,153          (77,684)     (7,041)      (81,572)
Net increase in value of cash flow hedges                                     -                -      22,584        22,584
Reclassification from other comprehensive income to earnings                  -                -      (7,669)       (7,669)
Current period change                                                         -            6,039           -         6,039
                                                                       --------        ---------     -------     ---------
December 31, 2004                                                      $  3,153        $ (71,645)    $ 7,874     $ (60,618)
                                                                       ========        =========     =======     =========


(21) RELATED PARTY TRANSACTIONS

      Lehman Brothers Inc. ("Lehman Brothers") is an affiliate of Lehman
Brothers Merchant Banking Partners II L.P. ("Merchant Banking Fund"). Prior to
the March 2004 secondary offering described above, Merchant Banking Fund was the
Company's largest shareholder.

      Lehman Brothers served as lead underwriter in connection with the
Company's sale of limited partner interests in PVR in December 2004, March 2004
and December 2003, as discussed in Note 10 above. Lehman Brothers received
customary fees, plus reimbursement of certain expenses, for those services.

      In March 2004, Morgan Stanley and Lehman Brothers served as joint managers
in connection with the secondary equity offering discussed in Note 18 above.
Lehman Brothers received from third parties customary underwriting discounts and
commissions from the offering. The Company paid no fees to Lehman Brothers
related to the secondary equity offerings. Merchant Banking Fund, the Company's
largest stockholder as of that date, sold 20,534,338 shares in the offering,
completing the Merchant Banking Fund's planned exit strategy to reduce its
equity ownership in the Company to zero.

      Lehman Commercial Paper Inc. was a participant in the Company's Senior
Secured Credit Facility, which was amended in October 2004. Lehman Commercial
Paper Inc. received $0.02 million of the $2.3 million credit facility amendment
fee.

      As discussed in Note 13 above, in March 2003, the Company refinanced a
substantial portion of its indebtedness by entering into a new Senior Secured
Credit Facility and issuing new Senior Notes. Based upon a competitive bidding
process conducted by members of management and reviewed by members of the
Company's Board of Directors not affiliated with Lehman Brothers, the Company
appointed Wachovia Securities, Inc., Fleet Securities, Inc. and Lehman Brothers
as lead arrangers for the Senior Secured Credit Facility, and Lehman Brothers
and Morgan Stanley as joint book running managers for the Senior Notes. Lehman
Brothers received total fees of $7.4 million for their services in connection
with the refinancing; such fees were consistent with the fees paid to other
parties to the transaction for their respective services.

      As discussed in Note 13 above, in May 2003, the Company entered into four
$25.0 million fixed-to-floating interest rate swaps as a hedge of the changes in
fair value of the 6.875% Senior Notes due 2013. Lehman Brothers was chosen as
one of the swap counterparties as part of a competitive bidding process among
eight financial institutions.

                                       41


      In May 2003 and August 2003, Lehman Brothers served as the lead
underwriter in connection with the secondary offerings discussed in Note 18
above, and fees for their services were paid by the selling shareholders and not
by the Company. The Company paid incidental expenses customarily incurred by a
registering company in connection with the secondary offerings. Lehman Brothers
served as the lead underwriter in connection with a secondary public offering of
Company common stock, which was completed in April 2002. Merchant Banking Fund
also sold shares of Company common stock in that offering. The Company paid
expenses customarily incurred by a registering company in connection with the
secondary offering. Merchant Banking Fund sold, in the aggregate, 16,310,000
shares in the offering.

(22) GUARANTEES AND FINANCIAL INSTRUMENTS WITH OFF-BALANCE-SHEET RISK

      In the normal course of business, the Company is a party to guarantees and
financial instruments with off-balance-sheet risk, such as bank letters of
credit, performance or surety bonds and other guarantees and indemnities, which
are not reflected in the accompanying consolidated balance sheets. Such
financial instruments are valued based on the amount of exposure under the
instrument and the likelihood of performance being required. In the Company's
past experience, virtually no claims have been made against these financial
instruments. Management does not expect any material losses to result from these
guarantees or off-balance-sheet instruments.

   LETTERS OF CREDIT AND BONDING

      The Company has letters of credit, surety bonds and corporate guarantees
(such as self bonds) in support of the Company's reclamation, lease, workers'
compensation, retiree healthcare and other obligations as follows as of December
31, 2004:



                                                       Workers'       Retiree
                     Reclamation        Lease        Compensation    Healthcare
                     Obligations     Obligations     Obligations     Obligations        Other            Total
                     ------------    ------------    ------------    ------------    ------------    -------------
                                                         (dollars in thousands)
                                                                                   
Self Bonding         $    653,254    $          -    $          -    $          -    $          -    $    653,254
Surety Bonds              294,505         134,301          91,744               -          27,558         548,108
Letters of Credit             358          25,140          72,869         120,089         130,743         349,199
                     ------------    ------------    ------------    ------------    ------------    ------------

                     $    948,117    $    159,441    $    164,613    $    120,089    $    158,301    $  1,550,561
                     ============    ============    ============    ============    ============    ============


      Other includes the letters of credit obligations described below and an
additional $78.5 million in letters of credit and surety bonds related to
collateral for surety companies, road maintenance, performance guarantees and
other operations.

      The Company owns a 30.0% interest in a partnership that leases a coal
export terminal from the Peninsula Ports Authority of Virginia under a 30-year
lease that permits the partnership to purchase the terminal at the end of the
lease term for a nominal amount. The partners have severally (but not jointly)
agreed to make payments under various agreements which in the aggregate provide
the partnership with sufficient funds to pay rents and to cover the principal
and interest payments on the floating-rate industrial revenue bonds issued by
the Peninsula Ports Authority, and which are supported by letters of credit from
a commercial bank. The Company's maximum reimbursement obligation to the
commercial bank is in turn supported by a letter of credit totaling $42.8
million.

      The Company is party to an agreement with the Pension Benefit Guarantee
Corporation, or the PBGC, and TXU Europe Limited, an affiliate of the Company's
former parent corporation, under which the Company is required to make special
contributions to two of the Company's defined benefit pension plans and to
maintain a $37.0 million letter of credit in favor of the PBGC. If the Company
or the PBGC gives notice of an intent to terminate one or more of the covered
pension plans in which liabilities are not fully funded, or if the Company fails
to maintain the letter of credit, the PBGC may draw down on the letter of credit
and use the proceeds to satisfy liabilities under the Employee Retirement Income
Security Act of 1974, as amended. The PBGC, however, is required to first apply
amounts received from a $110.0 million guarantee in place from TXU Europe
Limited in favor of the PBGC before it draws on the Company's letter of credit.
On November 19, 2002 TXU Europe Limited was placed under the administration
process in the United Kingdom (a process similar to bankruptcy proceedings in
the United States). As a result of these proceedings, TXU Europe Limited may be
liquidated or otherwise reorganized in such a way as to relieve it of its
obligations under its guarantee.

                                       42


   OTHER GUARANTEES

      The Company owns a 49.0% interest in a joint venture that operates an
underground mine and preparation plant facility in West Virginia. The partners
have severally agreed to guarantee the debt of the joint venture, which consists
of an $18.8 million loan facility. Monthly principal payments on the loan
facility of approximately $0.3 million are due through September 2010. Interest
payments on the loan facility are due monthly and accrue at prime, or 5.25% as
of December 31, 2004. The total amount of the joint venture's debt guaranteed by
the Company was $9.2 million as of December 31, 2004.

      The Company has guaranteed the performance of Asset Management Group
("AMG") under a coal purchase contract with a third party, which has terms
extending through December 31, 2006. Default occurs upon AMG's non-delivery of
specified monthly tonnage. In the event of a default, the Company assumes AMG's
position for the remaining term of the purchase contract. The guarantee arose
from an agreement by which AMG mines under a royalty-based contract with the
Company. As of December 31, 2004, the maximum potential future payments under
this guarantee are approximately $16.0 million, based on current spot coal
prices. As a matter of recourse in the event of a default, the Company has
access to a minimal amount of cash held in escrow and the ability to trigger an
assignment of the AMG assets to the Company. Based on these recourse options and
the remote probability of non-performance by AMG due to their proven operating
history, the Company has valued the liability associated with the guarantee at
zero.

      As part of an arrangement through which the Company obtained an exclusive
sales representation agreement with a coal mining company (the "Counterparty")
that operates surface mining operations in Illinois, the Company issued a
financial guarantee in May 2004 on behalf of the Counterparty. This guarantee
facilitated the Counterparty's efforts to obtain reclamation bonding for the
surface mine that will produce the coal to be purchased under the sales
representation agreement. The total amount guaranteed by the Company was $1.1
million, and the fair value of the guarantee recognized as a liability was less
than $0.1 million as of December 31, 2004. The Company's obligation under the
guarantee is scheduled to expire by June 2007.

      The Company is the lessee under numerous equipment and property leases, as
described in Note 10. It is common in such commercial lease transactions for the
Company, as the lessee, to agree to indemnify the lessor for the value of the
property or equipment leased, should the property be damaged or lost during the
course of the Company's operations. The Company expects that losses with respect
to leased property would be covered by insurance (subject to deductibles).

      The Company and certain of its subsidiaries have guaranteed other
subsidiaries' performance under their various lease obligations. Aside from
indemnification of the lessor for the value of the property leased, the
Company's maximum potential obligations under its leases are equal to the
respective future minimum lease payments as presented in Note 10 and the Company
assumes that no amounts could be recovered from third parties.

      The Company has provided financial guarantees under certain long-term debt
agreements entered into by its subsidiaries, and substantially all of the
Company's subsidiaries provide financial guarantees under long-term debt
agreements entered into by the Company. Descriptions of the Company's (and its
subsidiaries') debt are included in Note 13, and supplemental
guarantor/non-guarantor financial information is provided in Note 27. The
maximum amounts payable under the Company's debt agreements are presented in
Note 13 and assume that no amounts could be recovered from third parties.

      In connection with the sale of Citizens Power, the Company has indemnified
the buyer from certain losses resulting from specified power contracts and
guarantees. The indemnity is described in detail in Note 24. A discussion of the
Company's accounts receivable securitization is included in Note 4 to the
consolidated financial statements.

(23) FAIR VALUE OF FINANCIAL INSTRUMENTS

      SFAS No. 107, "Disclosures About Fair Value of Financial Instruments,"
defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced or liquidation sale.

      The following methods and assumptions were used by the Company in
estimating its fair value disclosures for financial instruments as of December
31, 2004 and 2003:

      -     Cash and cash equivalents, accounts receivable and accounts payable
            and accrued expenses have carrying values which approximate fair
            value due to the short maturity or the financial nature of these
            instruments.

      -     The fair value of the Company's coal trading assets and liabilities
            was determined as described in Note 3.

                                       43


      -     Long-term debt fair value estimates are based on estimated borrowing
            rates to discount the cash flows to their present value. The 5.0%
            Subordinated Note carrying amount is net of unamortized note
            discount.

      -     The fair values of interest rate swap contracts, currency forward
            contracts and fuel hedge contracts were provided by the respective
            contract counterparties, and were based on benchmark transactions
            entered into on terms substantially similar to those entered into by
            the Company and the contract counterparties. Based on these
            estimates as of December 31, 2004, the Company would have paid $5.7
            million upon liquidation of its interest rate swaps and would have
            received $18.2 million and $5.8 million, respectively, upon
            liquidation of its currency forwards and fuel hedges.

      -     Other noncurrent liabilities include a deferred purchase obligation
            related to the prior purchase of a mine facility. The fair value
            estimate is based on the same assumption as long-term debt.

      The carrying amounts and estimated fair values of the Company's debt and
deferred purchase obligation are summarized as follows:



                                   DECEMBER 31, 2004         DECEMBER 31, 2003
                                ------------------------  ------------------------
                                  CARRYING    ESTIMATED    CARRYING     ESTIMATED
(DOLLARS IN THOUSANDS)             AMOUNT     FAIR VALUE    AMOUNT     FAIR VALUE
- ----------------------------    -----------  -----------  -----------  -----------
                                                           
Long-term debt                  $ 1,424,965  $ 1,447,235  $ 1,196,539  $ 1,248,388
Deferred purchase obligation          6,717        6,807       11,632       11,906


      See Note 2 for a discussion of the Company's derivative financial
instruments.

(24) COMMITMENTS AND CONTINGENCIES

   ENVIRONMENTAL

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

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

      The Company's policy is to accrue environmental cleanup-related costs of a
noncapital nature when those costs are believed to be probable and can be
reasonably estimated. The quantification of environmental exposures requires an
assessment of many factors, including changing laws and regulations,
advancements in environmental technologies, the quality of information available
related to specific sites, the assessment stage of each site investigation,
preliminary findings and the length of time involved in remediation or
settlement. For certain sites, the Company also assesses the financial
capability of other potentially responsible parties and, where allegations are
based on tentative findings, the reasonableness of the Company's apportionment.
The Company has not anticipated any recoveries from insurance carriers or other
potentially responsible third parties in the estimation of liabilities recorded
on its consolidated balance sheets. Undiscounted liabilities for environmental
cleanup-related costs totaled $40.5 million as of December 31, 2004 and $38.9
million at December 31, 2003, $15.1 million and $6.9 million of which was a
current liability, respectively. These amounts represent those costs that the
Company believes are probable and reasonably estimable. Significant uncertainty
exists as to whether claims will be pursued against Gold Fields in all cases,
and where they are pursued, the amount of the eventual costs and liabilities,
which could be greater or less than this provision. The Company anticipates that
all significant remaining environmental remediation costs discussed above will
be paid by the end of 2009.

      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.

                                       44


   NAVAJO NATION

On June 18, 1999, the Navajo Nation served the Company's subsidiaries, Peabody
Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company
("Peabody Western"), with a complaint that had been filed in the U.S. District
Court for the District of Columbia. The Navajo Nation has alleged 16 claims,
including Civil Racketeer Influenced and Corrupt Organizations Act, or RICO,
violations and fraud and tortious interference with contractual relationships.
The complaint alleges that the defendants jointly participated in unlawful
activity to obtain favorable coal lease amendments. Plaintiff also alleges that
defendants interfered with the fiduciary relationship between the United States
and the Navajo Nation. The plaintiff is seeking various remedies including
actual damages of at least $600 million, which could be trebled under the RICO
counts, punitive damages of at least $1 billion, a determination that Peabody
Western's two coal leases for the Kayenta and Black Mesa mines have terminated
due to Peabody Western's breach of these leases and a reformation of the two
coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court
allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted
seven claims including fraud and is seeking various remedies including
unspecified actual damages, punitive damages and reformation of its coal lease.

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

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

      The outcome of litigation is subject to numerous uncertainties. Based on
the Company's evaluation of the issues and their potential impact, the amount of
any potential loss cannot be estimated. However, the Company believes this
matter will be resolved without a material adverse effect on the Company's
financial condition, results of operations or cash flows.

   SOUTHERN CALIFORNIA EDISON COMPANY -- MOHAVE GENERATING STATION

      In response to a demand for arbitration by one of the Company's
subsidiaries, Peabody Western, Southern California Edison Company and the other
owners of the Mohave Generating Station filed a lawsuit on June 20, 1996 in the
Superior Court of Maricopa County, Arizona. The lawsuit sought a declaratory
judgment that mine decommissioning costs and retiree health care costs are not
recoverable by Peabody Western under the terms of a coal supply agreement dated
May 26, 1976.

      By order filed July 2, 2001, the court granted Peabody Western's motion
for summary judgment on liability with respect to retiree healthcare costs.
Southern California Edison filed a motion for reconsideration, which was denied
by the court on October 16, 2001. Peabody Western reached a mediated settlement
with the owners of the Mohave Generating Station, which resulted in the
recognition of $15.1 million in pre-tax earnings during the year ended December
31, 2002. The settlement provided for customer reimbursement of mine
decommissioning and certain other post-mining expenditures.

   SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT -- NAVAJO
GENERATING STATION

      In May 1997, Salt River Project Agricultural Improvement and Power
District, or "Salt River", acting for all owners of the Navajo Generating
Station, exercised their contractual option to review certain cumulative cost
changes during a five-year period from 1992 to 1996. In July 1999, Salt River
notified Peabody Western that it believed the owners were entitled to a price
decrease of $1.92 per ton as a result of the review. Salt River also claimed
entitlement to a retroactive price adjustment to January 1997 and that an
overbilling of $50.5 million had occurred during the same five-year period. In
October 1999, Peabody Western notified Salt River that it believed it was
entitled to a $2.00 per ton price increase as a result of the review. The
parties were unable to settle the dispute and Peabody Western filed a demand for
arbitration in September 2000.

      On July 20, 2002, Peabody Western received a favorable decision from the
arbitrators. The decision increased the price of coal by approximately $0.50 per
ton from 1997 through 2001 and thereafter. As a result of the decision, the
Company received pre-tax earnings of approximately $22 million during the year
ended December 31, 2002.

                                       45


   SALT RIVER PROJECT AGRICULTURAL IMPROVEMENT AND POWER DISTRICT -- MINE
CLOSING AND RETIREE HEALTH CARE

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

      Peabody Western filed a motion to compel arbitration of these claims,
which was granted in part by the trial court. Specifically, the trial court
ruled that the mine decommissioning costs were subject to arbitration but that
the retiree health care costs were not subject to arbitration. This ruling was
subsequently upheld on appeal. As a result, Peabody Western, Salt River Project
and the other owners of the Navajo Generating Station will arbitrate the mine
decommissioning costs issue and will litigate the retiree health care costs
issue. The Company has recorded a receivable for mine decommissioning costs of
$68.6 million and $63.6 million included in Investments and Other Assets at
December 31, 2004 and 2003, respectively.

      The outcome of litigation is subject to numerous uncertainties. Based on
the Company's evaluation of the issues and their potential impact, the amount of
any potential loss cannot be estimated. However, the Company believes this
matter will be resolved without a material adverse effect on the Company's
financial condition, results of operations or cash flows.

   CALIFORNIA PUBLIC UTILITIES COMMISSION PROCEEDINGS REGARDING THE FUTURE OF
THE MOHAVE GENERATING STATION

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

   WEST VIRGINIA FLOODING LITIGATION

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

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

                                       46


   CITIZENS POWER

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

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

      In 1997, a Citizens Power subsidiary, now called Edison Mission Marketing
& Trading ("EMMT"), entered into a power purchase agreement with CL Power Sales
Eight LLC ("CL8") to sell power in connection with a restructured power supply
agreement that runs through 2016. In 1999, the Citizens Power subsidiary entered
into a power purchase agreement with NRG Power Marketing Inc. ("NRG Power
Marketing") for the same term, for resale to CL8. NRG Power Marketing
subsequently filed a Chapter 11 bankruptcy petition and on August 6, 2003, NRG
Power Marketing obtained bankruptcy court approval to reject the power purchase
agreement. The NRG Power Marketing power purchase agreement was one of the
contracts covered by the indemnity. EMMT reached an agreement with NRG Power
Marketing to settle the claims for the benefit of the members of CL8, because
CL8 had a contractual right to the claim. On May 27, 2004, CL8 entered into a
settlement agreement with EMMT which terminated the EMMT power purchase
agreement. CL8 also entered into new restructured agreements with the lenders
and other parties. On the same date, the Company entered into a settlement
agreement with Edison Mission Energy and EMMT in which the Company paid $3
million to settle claims related to the NRG Power Marketing power purchase
agreement and EMMT's termination of its power purchase agreement. The Company
incurred total costs in 2004 related to the NRG Power Marketing power purchase
agreement (and related settlement) of $2.8 million, net of a tax benefit of $1.9
million. These amounts are classified within discontinued operations in the
statement of operations.

      The Company believes that it does not have any further exposure under the
NRG or EMMT power purchase agreements related to CL8. The Company also believes
that it does not currently have any exposure under any other contracts currently
covered by the indemnity.

   OKLAHOMA LEAD LITIGATION

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

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

                                       47


      The outcome of litigation is subject to numerous uncertainties. Based on
the Company's evaluation of the issues and their potential impact, the amount of
any potential loss cannot be estimated. However, the Company believes this
matter will be resolved without a material adverse effect on the Company's
financial condition, results of operations or cash flows.

  OTHER

      In addition, the Company at times becomes a 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 will not have a material effect on the financial
position, results of operations or liquidity of the Company.

      Accounts receivable in the consolidated balance sheet as of December 31,
2004 includes $18.1 million of receivables billed between 2001 and 2004 that
have been disputed by two customers who have withheld payment. The Company
believes these billings were made properly under the coal supply agreement with
each customer. The Company is in arbitration and litigation with these customers
to resolve this issue and believes the receivables to be fully collectible under
the terms of each agreement.

      At December 31, 2004, purchase commitments for capital expenditures were
approximately $147.5 million. Commitments for expenditures to be made under
coal leases are reflected in Note 10.

(25) SUMMARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

      A summary of the unaudited quarterly results of operations for the years
ended December 31, 2004 and 2003, is presented below. Peabody Energy common
stock is listed on the New York Stock Exchange under the symbol "BTU."



                                                                              Year Ended December 31, 2004
                                                              ----------------------------------------------------------------
                                                                  First             Second           Third          Fourth
(Dollars in thousands except per share and stock price data)     Quarter            Quarter         Quarter         Quarter
- ------------------------------------------------------------  -------------      -------------   --------------  -------------
                                                                                                     
Revenues                                                      $     772,293      $     916,771   $      918,989  $   1,023,529
Operating profit                                                     36,935             48,886           73,902         86,975
Income before accounting changes                                     22,580             41,481           43,437         67,889
Net income                                                           22,580             41,481           43,437         67,889
Basic earnings per share before accounting changes            $        0.20      $        0.32   $         0.34  $        0.53
Diluted earnings per share before accounting changes          $        0.20      $        0.32   $         0.33  $        0.51
Weighted average shares used in calculating basic
   earnings per share                                           111,576,252        127,927,900      128,557,174    129,303,852
Weighted average shares used in calculating diluted
   earnings per share                                           114,309,698        130,876,522      131,558,064    132,451,806
Stock price -- high and low prices                            $25.30-$18.21      $28.01-$20.88   $ 30.22-$25.37  $43.40-$27.01
Dividends per share                                           $      0.0625      $      0.0625   $       0.0625  $       0.075


      Operating profit for the first quarter and fourth quarter of 2004 included
the $9.9 million and $5.9 million, respectively, gain on the sale of PVR common
units as discussed in Note 10. Operating profit for the third quarter and fourth
quarter of 2004 included $9.5 million and $11.5 million, respectively, in
business interruption insurance recoveries. Operating profit for the second
quarter and fourth quarter of 2004 included charges related to long-term
compensation plans of $6.6 million and $10.5 million, respectively. Income
before accounting changes for the second quarter and the fourth quarter of 2004
included a reduction in the valuation allowance on NOL carryforwards of $10.0
million and $18.0 million, respectively. Income before accounting changes for
the fourth quarter of 2004 included the loss on disposal of discontinued
operations, net of taxes, of $2.8 million. The results of operations from the
RAG Coal International AG acquisitions were included in the Company's
consolidated results of operations from the effective date of the acquisitions,
April 15, 2004.

                                       48




                                                                                  Year Ended December 31, 2003
                                                                ---------------------------------------------------------------
                                                                    First            Second           Third          Fourth
(Dollars in thousands except per share and stock price data)       Quarter          Quarter          Quarter        Quarter
- ------------------------------------------------------------    -------------    -------------    -------------   -------------
                                                                                                      
Revenues                                                        $     680,226    $     691,412    $     699,925   $     743,733
Operating profit                                                       34,531           30,292           35,589          44,374
Income (loss) before accounting changes                                  (937)          (1,304)          21,518          22,215
Net income (loss)                                                     (11,081)          (1,304)          21,518          22,215
Basic earnings (loss) per share before accounting
 changes                                                        $       (0.01)   $       (0.01)   $        0.20   $        0.20
Diluted earnings (loss) per share before accounting
 changes                                                        $       (0.01)   $       (0.01)   $        0.19   $        0.20
Weighted average shares used in calculating basic
 earnings per share                                               104,828,082      105,503,998      108,005,318     108,881,194
Weighted average shares used in calculating diluted
 earnings per share                                               104,828,082      105,503,998      110,451,758     111,370,376
Stock price -- high and low prices                              $14.80-$12.26    $17.56-$13.36    $16.82-$14.31   $21.50-$15.68
Dividends per share                                             $        0.05    $        0.05    $      0.0625   $      0.0625


      Income (loss) before accounting changes for the first quarter and second
quarter of 2003 included $21.2 million and $32.3 million, respectively, of early
debt extinguishment costs (see Note 13) partially offset by gains on property
sales of $7.7 million and $11.7 million during the first and second quarters,
respectively. Net income for the first quarter of 2003 included the cumulative
effect of accounting changes, net of taxes, of $10.1 million as discussed in
Note 6. Net income (loss) before accounting changes for the second quarter of
2003 included a $10.0 million adjustment to the Company's tax reserves.
Operating profit for the fourth quarter of 2003 included the $7.6 million gain
on the sale of PVR common units as discussed in Note 10.

      The quarterly revenues reported for the years ended December 31, 2004 and
2003 differ from the amounts previously reported in the 2004 and 2003 Form
10-Q's. The differences between the amounts presented above and the amounts in
the Form 10-Q's result from the reclassification of income from equity
affiliates from "Other revenues" to "Income (loss) from equity affiliates" and
the reclassification of the gain on the sale of PVR common units from "Other
revenues" to "Net gain on disposal of assets." The quarterly basic and diluted
earnings per share and weighted average shares, the low and high stock price,
and the dividends per share differ from the previously reported amounts in the
Form 10-Q's. The amounts above reflect a two-for-one stock split as described in
Note 28.

(26)  SEGMENT INFORMATION

      The Company reports its operations primarily through the following
reportable operating segments: "Western U.S. Mining," "Eastern U.S. Mining,"
"Australian Mining" and "Trading and Brokerage." The principal business of the
Western U.S. Mining, Eastern U.S. Mining and Australian Mining segments is
mining, preparation and sale of steam coal, sold primarily to electric
utilities, and metallurgical coal, sold to steel and coke producers. Western
U.S. Mining operations are characterized by predominantly surface mining
extraction processes, lower sulfur content and Btu of coal, and longer shipping
distances from the mine to the customer. Conversely, Eastern U.S. Mining
operations are characterized by predominantly underground mining extraction
processes, higher sulfur content and Btu of coal, and shorter shipping distances
from the mine to the customer. Geologically, Western operations mine primarily
subbituminous and Eastern operations mine bituminous coal deposits. Australian
Mining operations are characterized by both surface and underground extraction
processes, mining low sulfur, high Btu coal sold to an international customer
base. The Trading and Brokerage segment's principal business is the marketing,
brokerage and trading of coal. "Corporate and Other" includes selling and
administrative expenses, net gains on property disposals, costs associated with
past mining obligations and revenues and expenses related to the Company's other
commercial activities such as coalbed methane, generation development and
resource management.

      For the year ended December 31, 2004, 90% of the Company's sales were to
U.S. electricity generators, 3% were to the U.S. industrial sector, and 7% were
to customers outside the United States.

                                       49


      Operating segment results for the year ended December 31, 2004 were as
follows:



                              WESTERN       EASTERN     AUSTRALIAN    TRADING AND    CORPORATE
(DOLLARS IN THOUSANDS)      U.S. MINING   U.S. MINING     MINING       BROKERAGE     AND OTHER     CONSOLIDATED
- ----------------------      -----------   -----------   -----------   -----------   -----------    ------------
                                                                                 
Revenues                    $ 1,393,617   $ 1,501,352   $   270,926   $   462,820   $     2,867    $ 3,631,582
Adjusted EBITDA(1)              402,131       280,357        50,372        41,039      (214,655)       559,244
Total assets                  2,487,510     1,311,890       343,155       118,800     1,917,237      6,178,592
Capital expenditures            167,194        66,418        19,665            23        13,297        266,597
Income from
 equity affiliates                   21        12,334             -             -         3,712         16,067


      Operating segment results for the year ended December 31, 2003 were as
follows:



                               WESTERN       EASTERN     AUSTRALIAN    TRADING AND    CORPORATE
(DOLLARS IN THOUSANDS)       U.S. MINING   U.S. MINING     MINING       BROKERAGE     AND OTHER     CONSOLIDATED
- ----------------------       -----------   -----------   -----------   -----------   -----------    ------------
                                                                                  
Revenues                     $ 1,221,991   $ 1,198,531   $    29,435   $   351,929   $    13,410    $ 2,815,296
Adjusted EBITDA(1)               357,021       198,964         2,225        45,828      (193,760)       410,278
Total assets                   2,147,831     1,322,656        34,180       119,161     1,656,437      5,280,265
Capital expenditures              31,667       111,815         1,393         1,943         9,625        156,443
Income from
 equity affiliates                    36         1,985             -             -         4,514          6,535


      Operating segment results for the year ended December 31, 2002 were as
follows:



                               WESTERN       EASTERN     AUSTRALIAN    TRADING AND    CORPORATE
(DOLLARS IN THOUSANDS)       U.S. MINING   U.S. MINING     MINING       BROKERAGE     AND OTHER     CONSOLIDATED
- ----------------------       -----------   -----------   -----------   -----------   -----------    ------------
                                                                                  
Revenues                     $ 1,219,337   $ 1,266,412   $     9,933   $   206,387   $    17,569    $ 2,719,638
Adjusted EBITDA(1)               356,392       219,940         3,007        36,984      (210,222)       406,101
Capital expenditures              63,753       128,494           189         3,413        12,713        208,562
Loss from
 equity affiliates                  (367)       (2,173)            -             -             -         (2,540)


      Reconciliation of adjusted EBITDA to consolidated income (loss) before
income taxes follows:



                                        YEAR ENDED        YEAR ENDED         YEAR ENDED
(DOLLARS IN THOUSANDS)              DECEMBER 31, 2004  DECEMBER 31, 2003  DECEMBER 31, 2002
- ----------------------              -----------------  -----------------  -----------------
                                                                 
Total adjusted EBITDA(1)                $ 559,244          $ 410,278          $ 406,101
Depreciation, depletion
  and amortization                        270,159            234,336            232,413
Asset retirement
  obligation expense                       42,387             31,156                  -
Interest expense                           96,793             98,540            102,458
Early debt extinguishment costs             1,751             53,513                  -
Interest income                            (4,917)            (4,086)            (7,574)
Minority interests                          1,282              3,035             13,292
                                        ---------          ---------          ---------
Income (loss) before income taxes       $ 151,789          $  (6,216)         $  65,512
                                        =========          =========          =========


- ----------
(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.

                                       50


================================================================================

(27)  SUPPLEMENTAL GUARANTOR/NON-GUARANTOR FINANCIAL INFORMATION

      In accordance with the indentures governing the 6.875% Senior Notes due
2013 and the 5.875% Senior Notes due 2016, certain wholly-owned U.S.
subsidiaries of the Company have fully and unconditionally guaranteed the 6.875%
Senior Notes and the 5.875% Senior Notes, on a joint and several basis. Separate
financial statements and other disclosures concerning the Guarantor Subsidiaries
are not presented because management believes that such information is not
material to the holders of the 6.875% Senior Notes and the 5.875% Senior Notes.
The following condensed historical financial statement information is provided
for the Guarantor/Non-Guarantor Subsidiaries.

                           PEABODY ENERGY CORPORATION
          SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



                                                                            YEAR ENDED DECEMBER 31, 2004
                                                    --------------------------------------------------------------------------------
                                                      PARENT          GUARANTOR      NON-GUARANTOR
                                                     COMPANY         SUBSIDIARIES    SUBSIDIARIES      ELIMINATIONS     CONSOLIDATED
                                                    -----------      ------------    -------------     ------------     ------------
                                                                               (Dollars in Thousands)
                                                                                                         
Total revenues                                      $         -      $ 3,151,658      $   546,606      $   (66,682)     $ 3,631,582

Costs and expenses:
  Operating costs and expenses                           (5,230)       2,560,871          480,250          (66,682)       2,969,209
  Depreciation, depletion and amortization                    -          257,411           12,748                -          270,159
  Asset retirement obligation expense                         -           41,081            1,306                -           42,387
  Selling and administrative expenses                     1,460          136,035            5,530                -          143,025
  Other operating income:
   Net gain on disposal of assets                             -          (23,386)            (443)               -          (23,829)
   Income from equity affiliates                              -          (16,067)               -                -          (16,067)
  Interest expense                                      143,790           60,421           11,838         (119,256)          96,793
  Early debt extinguishment costs                         1,751                -                -                -            1,751
  Interest income                                       (51,977)         (51,888)         (20,308)         119,256           (4,917)
                                                    -----------      -----------      -----------      -----------      -----------
Income (loss) before income taxes
 and minority interests                                 (89,794)         187,180           55,685                -          153,071
  Income tax provision (benefit)                        (57,251)          21,441            9,373                -          (26,437)
  Minority interests                                          -            1,282                -                -            1,282
                                                    -----------      -----------      -----------      -----------      -----------
Income (loss) from continuing operations                (32,543)         164,457           46,312                -          178,226
  Loss from discontinued operations, net of taxes             -           (2,839)               -                -           (2,839)
                                                    -----------      -----------      -----------      -----------      -----------
Net income (loss)                                   $   (32,543)     $   161,618      $    46,312      $         -      $   175,387
                                                    ===========      ===========      ===========      ===========      ===========


                                       51


                           PEABODY ENERGY CORPORATION
          SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



                                                                              YEAR ENDED DECEMBER 31, 2003
                                                    --------------------------------------------------------------------------------
                                                       PARENT         GUARANTOR      NON-GUARANTOR
                                                      COMPANY        SUBSIDIARIES     SUBSIDIARIES     ELIMINATIONS     CONSOLIDATED
                                                    -----------      ------------    -------------     ------------     ------------
                                                                              (Dollars in Thousands)
                                                                                                         
Total revenues                                      $         -      $ 2,695,827      $   181,494      $   (62,025)     $ 2,815,296

Costs and expenses:
  Operating costs and expenses                               99        2,230,569          167,157          (62,025)       2,335,800
  Depreciation, depletion and amortization                    -          229,529            4,807                -          234,336
  Asset retirement obligation expense                         -           30,905              251                -           31,156
  Selling and administrative expenses                       886          105,365            2,274                -          108,525
  Other operating income:
   Net gain on disposal of assets                             -          (32,587)            (185)               -          (32,772)
   Income from equity affiliates                              -           (6,535)               -                -           (6,535)
  Interest expense                                      138,422          118,386            3,493         (161,761)          98,540
  Early debt extinguishment costs                        46,164            7,349                -                -           53,513
  Interest income                                       (81,897)         (69,159)         (14,791)         161,761           (4,086)
                                                    -----------      -----------      -----------      -----------      -----------
Income (loss) before income taxes
 and minority interests                                (103,674)          82,005           18,488                -           (3,181)
  Income tax provision (benefit)                        (52,015)          (2,377)           6,684                -          (47,708)
  Minority interests                                          -            3,035                -                -            3,035
                                                    -----------      -----------      -----------      -----------      -----------
Income (loss) from continuing operations                (51,659)          81,347           11,804                -           41,492
  Cumulative effect of accounting changes,
   net of taxes                                           6,762          (16,349)            (557)               -          (10,144)
                                                    -----------      -----------      -----------      -----------      -----------
Net income (loss)                                   $   (44,897)     $    64,998      $    11,247      $         -      $    31,348
                                                    ===========      ===========      ===========      ===========      ===========


                           PEABODY ENERGY CORPORATION
          SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS



                                                                             YEAR ENDED DECEMBER 31, 2002
                                                    --------------------------------------------------------------------------------
                                                       PARENT         GUARANTOR      NON-GUARANTOR
                                                      COMPANY        SUBSIDIARIES     SUBSIDIARIES     ELIMINATIONS     CONSOLIDATED
                                                    -----------      ------------    -------------     ------------     ------------
                                                                                (Dollars in Thousands)
                                                                                                         
Total revenues                                      $         -      $ 2,633,861      $   146,548      $   (60,771)     $ 2,719,638

Costs and expenses:
  Operating costs and expenses                                -        2,162,410          123,705          (60,771)       2,225,344
  Depreciation, depletion and amortization                    -          229,756            2,657                -          232,413
  Selling and administrative expenses                       443           98,715            2,258                -          101,416
  Other operating income:
   Net gain on disposal of assets                             -          (15,692)             (71)               -          (15,763)
   Loss from equity affiliates                                -            2,540                -                -            2,540
  Interest expense                                      137,821          111,059            3,700         (150,122)         102,458
  Interest income                                       (68,601)         (74,034)         (15,061)         150,122           (7,574)
                                                    -----------      -----------      -----------      -----------      -----------
Income (loss) before income taxes
 and minority interests                                 (69,663)         119,107           29,360                -           78,804
  Income tax provision (benefit)                         37,687          (64,513)         (13,181)               -          (40,007)
  Minority interests                                          -           13,292                -                -           13,292
                                                    -----------      -----------      -----------      -----------      -----------
Net income (loss)                                   $  (107,350)     $   170,328      $    42,541      $         -      $   105,519
                                                    ===========      ===========      ===========      ===========      ===========


                                       52


                           PEABODY ENERGY CORPORATION
               SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS



                                                                                  DECEMBER 31, 2004
                                                    -------------------------------------------------------------------------------
                                                      PARENT          GUARANTOR      NON-GUARANTOR
                                                     COMPANY        SUBSIDIARIES     SUBSIDIARIES     ELIMINATIONS     CONSOLIDATED
                                                    -----------     ------------     ------------     ------------     ------------
                                                                                (Dollars in Thousands)
                                                                                                        
ASSETS
Current assets
  Cash and cash equivalents                         $   373,066     $     3,562      $    13,008      $         -      $   389,636
  Accounts receivable                                     1,611          86,748          105,425                -          193,784
  Inventories                                                 -         290,863           32,746                -          323,609
  Assets from coal trading activities                         -          89,165                -                -           89,165
  Deferred income taxes                                       -          15,050              411                -           15,461
  Other current assets                                   19,737          15,971            7,239                -           42,947
                                                    -----------     -----------      -----------      -----------      -----------
    Total current assets                                394,414         501,359          158,829                -        1,054,602
Property, plant, equipment and mine development
  Land and coal interests                                     -       4,371,153          141,740                -        4,512,893
  Building and improvements                                   -         662,317           56,486                -          718,803
  Machinery and equipment                                     -         767,325          116,055                -          883,380
  Less accumulated depreciation,
   depletion and amortization                                 -      (1,289,947)         (43,698)               -       (1,333,645)
                                                    -----------     -----------      -----------      -----------      -----------
Property, plant, equipment and mine
 development, net                                             -       4,510,848          270,583                -        4,781,431
Investments and other assets                          4,808,202          34,410            3,577       (4,503,630)         342,559
                                                    -----------     -----------      -----------      -----------      -----------
    Total assets                                    $ 5,202,616     $ 5,046,617      $   432,989      $(4,503,630)     $ 6,178,592
                                                    ===========     ===========      ===========      ===========      ===========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
  Current maturities of long-term debt              $     5,000     $    12,971      $     1,008      $         -      $    18,979
  Payables and notes payable to affiliates, net       2,022,037      (2,217,311)         195,274                -                -
  Liabilities from coal trading activities                    -          63,565                -                -           63,565
  Accounts payable and accrued expenses                  20,120         599,253           72,227                -          691,600
                                                    -----------     -----------      -----------      -----------      -----------
    Total current liabilities                         2,047,157      (1,541,522)         268,509                -          774,144
Long-term debt, less current maturities               1,338,465          65,228            2,293                -        1,405,986
Deferred income taxes                                     5,250         386,351            1,665                -          393,266
Other noncurrent liabilities                             18,658       1,852,684            7,353                -        1,878,695
                                                    -----------     -----------      -----------      -----------      -----------
    Total liabilities                                 3,409,530         762,741          279,820                -        4,452,091
Minority interests                                            -           1,909                -                -            1,909
Stockholders' equity                                  1,793,086       4,281,967          153,169       (4,503,630)       1,724,592
                                                    -----------     -----------      -----------      -----------      -----------
    Total liabilities and stockholders'
     equity                                         $ 5,202,616     $ 5,046,617      $   432,989      $(4,503,630)     $ 6,178,592
                                                    ===========     ===========      ===========      ===========      ===========


                                       53


                           PEABODY ENERGY CORPORATION
               SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS



                                                                                 DECEMBER 31, 2003
                                                       -----------------------------------------------------------------------
                                                         PARENT        GUARANTOR    NON-GUARANTOR
                                                        COMPANY       SUBSIDIARIES   SUBSIDIARIES   ELIMINATIONS   CONSOLIDATED
                                                       -----------    ------------  -------------   ------------   ------------
                                                                               (Dollars in Thousands)
                                                                                                    
ASSETS
Current assets
  Cash and cash equivalents                            $   114,575    $     1,392    $     1,535    $         -    $   117,502
  Accounts receivable                                        1,022        190,517         29,352              -        220,891
  Inventories                                                    -        244,372          2,121              -        246,493
  Assets from coal trading activities                            -         58,321              -              -         58,321
  Deferred income taxes                                          -         15,050            699              -         15,749
  Other current assets                                       2,793         14,977          6,014              -         23,784
                                                       -----------    -----------    -----------    -----------    -----------
    Total current assets                                   118,390        524,629         39,721              -        682,740
Property, plant, equipment and mine development
  Land and coal interests                                        -      3,923,998         27,162              -      3,951,160
  Building and improvements                                      -        628,665         13,989              -        642,654
  Machinery and equipment                                        -        695,934         20,789              -        716,723
  Less accumulated depreciation,
    depletion and amortization                                   -     (1,008,817)       (20,734)             -     (1,029,551)
                                                       -----------    -----------    -----------    -----------    -----------
Property, plant, equipment and mine development, net             -      4,239,780         41,206              -      4,280,986
Investments and other assets                             3,583,860        180,058          1,145     (3,448,524)       316,539
                                                       -----------    -----------    -----------    -----------    -----------
    Total assets                                       $ 3,702,250    $ 4,944,467    $    82,072    $(3,448,524)   $ 5,280,265
                                                       ===========    ===========    ===========    ===========    ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
  Current maturities of long-term debt                 $     4,500    $    16,707    $     1,842    $         -    $    23,049
  Payables and notes payable to affiliates, net          1,360,978     (1,373,499)        12,521              -              -
  Liabilities from coal trading activities                       -         35,851            453              -         36,304
  Accounts payable and accrued expenses                     16,690        535,914         20,011              -        572,615
                                                       -----------    -----------    -----------    -----------    -----------
    Total current liabilities                            1,382,168       (785,027)        34,827              -        631,968
Long-term debt, less current maturities                  1,096,364         74,014          3,112              -      1,173,490
Deferred income taxes                                       (4,694)       432,159          6,961              -        434,426
Other noncurrent liabilities                                21,824      1,880,889          3,702              -      1,906,415
                                                       -----------    -----------    -----------    -----------    -----------
    Total liabilities                                    2,495,662      1,602,035         48,602              -      4,146,299
Minority interests                                               -          1,909              -              -          1,909
Stockholders' equity                                     1,206,588      3,340,523         33,470     (3,448,524)     1,132,057
                                                       -----------    -----------    -----------    -----------    -----------
    Total liabilities and stockholders' equity         $ 3,702,250    $ 4,944,467    $    82,072    $(3,448,524)   $ 5,280,265
                                                       ===========    ===========    ===========    ===========    ===========


                                       54

                           PEABODY ENERGY CORPORATION
          SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



                                                                         YEAR ENDED DECEMBER 31, 2004
                                                             ------------------------------------------------------
                                                               PARENT       GUARANTOR    NON-GUARANTOR
                                                              COMPANY     SUBSIDIARIES   SUBSIDIARIES    CONSOLIDATED
                                                             ---------    ------------   -------------   ------------
                                                                              (Dollars in Thousands)
                                                                                             
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by (used in) operating activities          $ (81,656)     $ 301,542      $  63,874      $ 283,760
                                                             ---------      ---------      ---------      ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant, equipment and
    mine development                                                 -       (244,164)       (22,433)      (266,597)
Additions to advance mining royalties                                -        (15,989)          (250)       (16,239)
Acquisitions, net                                                    -       (193,736)      (235,325)      (429,061)
Investments in joint ventures                                        -        (32,472)             -        (32,472)
Proceeds from disposal of assets                                     -         38,408            931         39,339
                                                             ---------      ---------      ---------      ---------
Net cash used in investing activities                                -       (447,953)      (257,077)      (705,030)
                                                             ---------      ---------      ---------      ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt                                   700,000             13              -        700,013
Payments of long-term debt                                    (458,350)       (22,921)        (1,653)      (482,924)
Net proceeds from equity offering                              383,125              -              -        383,125
Proceeds from stock options exercised                           27,266              -              -         27,266
Proceeds from employee stock purchases                           2,343              -              -          2,343
Increase of securitized interests in accounts receivable             -              -        110,000        110,000
Payment of debt issuance costs                                 (12,875)             -              -        (12,875)
Distributions to minority interests                                  -         (1,007)             -         (1,007)
Dividends paid                                                 (32,568)             -              -        (32,568)
Transactions with affiliates, net                             (268,825)       172,501         96,324              -
Other                                                               31              -              -             31
                                                             ---------      ---------      ---------      ---------
Net cash provided by financing activities                      340,147        148,586        204,671        693,404
                                                             ---------      ---------      ---------      ---------
Net increase in cash and cash equivalents                      258,491          2,175         11,468        272,134
Cash and cash equivalents at beginning of year                 114,575          1,392          1,535        117,502
                                                             ---------      ---------      ---------      ---------
Cash and cash equivalents at end of year                     $ 373,066      $   3,567      $  13,003      $ 389,636
                                                             =========      =========      =========      =========


                                       55


                           PEABODY ENERGY CORPORATION
          SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



                                                                                    YEAR ENDED DECEMBER 31, 2003
                                                                 --------------------------------------------------------------
                                                                   PARENT          GUARANTOR      NON-GUARANTOR
                                                                  COMPANY         SUBSIDIARIES    SUBSIDIARIES      CONSOLIDATED
                                                                 -----------      ------------    -------------     ------------
                                                                                     (Dollars in Thousands)
                                                                                                        
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by (used in) operating activities              $   (41,869)     $   208,729      $    22,001      $   188,861
                                                                 -----------      -----------      -----------      -----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant, equipment and
   mine development                                                        -         (150,975)          (5,468)        (156,443)
Additions to advance mining royalties                                      -          (14,010)               -          (14,010)
Acquisitions, net                                                          -          (90,000)               -          (90,000)
Investments in joint ventures                                              -           (1,400)               -           (1,400)
Proceeds from disposal of assets                                           -           68,765              808           69,573
                                                                 -----------      -----------      -----------      -----------
Net cash used in investing activities                                      -         (187,620)          (4,660)        (192,280)
                                                                 -----------      -----------      -----------      -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Net change in revolving lines of credit                                    -         (121,584)               -         (121,584)
Proceeds from long-term debt                                       1,100,000            2,735                -        1,102,735
Payments of long-term debt                                          (746,384)        (120,910)          (1,092)        (868,386)
Proceeds from stock options exercised                                 31,329                -                -           31,329
Proceeds from employee stock purchases                                 1,737                -                -            1,737
Decrease of securitized interests in accounts receivable                   -                -          (46,400)         (46,400)
Payment of debt issuance costs                                       (23,700)               -                -          (23,700)
Distributions to minority interests                                        -           (4,186)               -           (4,186)
Dividends paid                                                       (24,058)               -                -          (24,058)
Transactions with affiliates, net                                   (244,257)         218,863           25,394                -
Other                                                                  1,111                -                -            1,111
                                                                 -----------      -----------      -----------      -----------
Net cash provided by (used in) financing activities                   95,778          (25,082)         (22,098)          48,598
Effect of exchange rate changes on cash and cash equivalents               -                -            1,113            1,113
                                                                 -----------      -----------      -----------      -----------
Net increase (decrease) in cash and cash equivalents                  53,909           (3,973)          (3,644)          46,292
Cash and cash equivalents at beginning of year                        60,666            5,365            5,179           71,210
                                                                 -----------      -----------      -----------      -----------
Cash and cash equivalents at end of year                         $   114,575      $     1,392      $     1,535      $   117,502
                                                                 ===========      ===========      ===========      ===========


                                       56


                           PEABODY ENERGY CORPORATION
          SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS



                                                                                YEAR ENDED DECEMBER 31, 2002
                                                                 ---------------------------------------------------------
                                                                   PARENT          GUARANTOR    NON-GUARANTOR
                                                                  COMPANY        SUBSIDIARIES    SUBSIDIARIES   CONSOLIDATED
                                                                 ---------       ------------   -------------   ------------
                                                                                     (Dollars in Thousands)
                                                                                                    
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by (used in) operating activities              $ (66,070)        $ 270,972      $  29,902      $ 234,804
                                                                 ---------         ---------      ---------      ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant, equipment and
   mine development                                                      -          (203,291)        (5,271)      (208,562)
Additions to advance mining royalties                                    -           (14,872)           (17)       (14,889)
Acquisitions, net                                                        -           (45,537)             -        (45,537)
Investments in joint ventures                                            -              (475)             -           (475)
Proceeds from sale of coal reserves                                      -            72,500              -         72,500
Proceeds from disposal of assets                                         -            52,085            800         52,885
                                                                 ---------         ---------      ---------      ---------
Net cash used in investing activities                                    -          (139,590)        (4,488)      (144,078)
                                                                 ---------         ---------      ---------      ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Net change in revolving lines of credit                                  -            14,647              -         14,647
Proceeds from long-term debt                                             -             1,488            327          1,815
Payments of long-term debt                                               -           (46,477)        (1,272)       (47,749)
Proceeds from stock options exercised                                2,650                 -              -          2,650
Proceeds from employee stock purchases                               3,251                 -              -          3,251
Decrease of securitized interests in accounts receivable                 -            (3,600)             -         (3,600)
Distributions to minority interests                                      -            (9,800)             -         (9,800)
Dividends paid                                                     (20,863)                -              -        (20,863)
Transactions with affiliates, net                                  112,326           (88,776)       (23,550)             -
Other                                                                1,251                 -              -          1,251
                                                                 ---------         ---------      ---------      ---------
Net cash provided by (used in) financing activities                 98,615          (132,518)       (24,495)       (58,398)
Effect of exchange rate changes on cash and cash equivalents             -                 -            260            260
                                                                 ---------         ---------      ---------      ---------
Net increase (decrease) in cash and cash equivalents                32,545            (1,136)         1,179         32,588
Cash and cash equivalents at beginning of year                      28,121             6,501          4,000         38,622
                                                                 ---------         ---------      ---------      ---------
Cash and cash equivalents at end of year                         $  60,666         $   5,365      $   5,179      $  71,210
                                                                 =========         =========      =========      =========


(28)  SUBSEQUENT EVENT

      On March 2, 2005, the Company announced that its board of directors
authorized a two-for-one stock split on all shares of its common stock.
Shareholders of record at the close of business on March 16, 2005 will be
entitled to a dividend of one share of stock for every share held. The
additional shares will be distributed on March 30, 2005, and the stock will
begin trading ex-split on March 31, 2005. All share and per share amounts in
these consolidated financial statements and related notes reflect the stock
split.

                                       57

EX-21

                                                                               .
                                                                               .
                                                                               .
                                                                      EXHIBIT 21




NAME OF SUBSIDIARY                      JURISDICTION OF FORMATION
- --------------------------------------  -------------------------
                                    
Affinity Mining Company                 West Virginia
American Land Holdings of Indiana, LLC  Delaware
Appalachia Mine Services, LLC           Delaware
Arclar Company, LLC                     Indiana
Arid Operations Inc.                    Delaware
Beaver Dam Coal Company                 Delaware
Big Ridge, Inc.                         Illinois
Big Sky Coal Company                    Delaware
Black Beauty Coal Company               Indiana
Black Beauty Equipment Company          Indiana
Black Beauty Holding Company, LLC       Delaware
Black Beauty Mining, Inc.               Indiana
Black Beauty Resources, Inc.            Indiana
Black Beauty Underground, Inc.          Indiana
Black Hills Mining Company, LLC         Illinois
Black Stallion Coal Company, LLC        Delaware
Black Walnut Coal Company               Delaware
Bluegrass Coal Company                  Delaware
BTU Empire Corporation                  Delaware
BTU International B.V.                  Netherlands
BTU Venezuela LLC                       Delaware
BTU Western Resources, Inc.             Delaware
Caballo Coal Company                    Delaware
Carbones Peabody de Venezuela, C.A.     Venezuela
Charles Coal Company                    Delaware
CL Hartford, L.L.C.                     Delaware
CL Power Sales Three, L.L.C.            Delaware
Cleaton Coal Company                    Delaware
Coal Properties Corp.                   Delaware
Coal Reserve Holding Limited            Delaware
Liability Company No. 1
Coal Reserve Holding Limited            Delaware
Liability Company No. 2
COALSALES II, LLC                       Delaware
COALSALES, LLC                          Delaware
COALTRADE International, LLC            Delaware
COALTRADE, LLC                          Delaware
Colony Bay Coal Company                 West Virginia
Colorado Coal Resources, LLC            Delaware
Colorado Yampa Coal Company             Delaware
Cook Mountain Coal Company              Delaware
Cottonwood Land Company                 Delaware
Coulterville Coal Company, LLC          Delaware
CP Power Sales Sixteen, L.L.C.          Delaware
Cyprus Creek Land Company               Delaware
Cyprus Creek Land Resources, LLC        Delaware
Dixon Mining Company, LLC               Kentucky








Dodge Hill Holding JV, LLC              Delaware
Dodge Hill Mining Company, LLC          Kentucky
Dodge Hill of Kentucky, LLC             Delaware
EACC Camps, Inc.                        West Virginia
Eagle Coal Company                      Indiana
Eastern Associated Coal Corp.           West Virginia
Eastern Royalty Corp.                   Delaware
Empire Marine, LLC                      Indiana
Falcon Coal Company                     Indiana
Gallo Finance Company                   Delaware
Gold Fields Chile, S.A.                 Delaware
Gold Fields Mining, LLC                 Delaware
Gold Fields Operating Co.-Ortiz         Delaware
Grand Eagle Mining, Inc.                Kentucky
Hayden Gulch Terminal, Inc.             Delaware
Highland Mining Company                 Delaware
Highwall Mining Services Company        Delaware
Hillside Mining Company                 West Virginia
HMC Mining, LLC                         Delaware
Independence Material Handling Company  Delaware
Indian Hill Company                     Delaware
Interior Holdings Corp.                 Delaware
James River Coal Terminal Company       Delaware
Jarrell's Branch Coal Company           Delaware
Juniper Coal Company                    Delaware
Kanawha River Ventures I, LLC           West Virginia
Kayenta Mobile Home Park, Inc.          Delaware
Lemon Grove Investments Pty. Ltd.       Queensland
Logan Fork Coal Company                 Delaware
Martinka Coal Company                   Delaware
Midco Supply and Equipment Corporation  Illinois
Midwest Coal Acquisition Corp.          Delaware
Mountain View Coal Company              Delaware
Mustang Energy Company, L.L.C.          Delaware
New Whitwood Collieries Pty. Ltd.       Queensland
Newhall Funding Company                 Massachusetts
North Page Coal Corp.                   West Virginia
NRGenerating Holdings (No.17) B.V.      Netherlands
NRGenerating Holdings (No.9) B.V.       Netherlands
Ohio County Coal Company                Kentucky
P&L Receivables Company, LLC            Delaware
Patriot Coal Company, L.P.              Delaware
PDC Partnership Holdings, Inc.          Delaware
Peabody (Kogan Creek) Pty Ltd.          Queensland
Peabody (Wilkie Creek) Pty Ltd.         South Australia
Peabody America, Inc.                   Delaware
Peabody Archveyor, L.L.C.               Delaware
Peabody Baralaba Investments Pty        New South Wales
Limited








Peabody Coal Company                    Delaware
Peabody COALTRADE Australia Pty         New South Wales
Limited
Peabody Development Company, LLC        Delaware
Peabody Development Land Holdings, LLC  Delaware
Peabody Energy Australia Coal Pty       New South Wales
Limited
Peabody Energy Corporation              Delaware
Peabody Energy Generation Holding       Delaware
Company
Peabody Energy Investments, Inc.        Delaware
Peabody Energy Solutions, Inc.          Delaware
Peabody Fuels Pty Ltd                   Victoria
Peabody Holding Company, Inc.           New York
Peabody Investments Corp.               Delaware
Peabody Minerals Pty. Limited           Queensland
Peabody Natural Gas, LLC                Delaware
Peabody Natural Resources Company       Delaware
Peabody Pacific Pty Limited             New South Wales
Peabody PowerTree Investments, LLC      Delaware
Peabody Recreational Lands, L.L.C.      Delaware
Peabody Southwestern Coal Company       Delaware
Peabody Surat Pty Ltd.                  Queensland
Peabody Terminals, Inc.                 Delaware
Peabody Venezuela Coal Corp.            Delaware
Peabody Western Coal Company            Delaware
Peabody-Waterside Development, L.L.C.   Delaware
PEC Equipment Company, LLC              Delaware
PG INVESTMENTS FIVE, L.L.C.             Delaware
PG INVESTMENTS FOUR, L.L.C.             Delaware
PG INVESTMENTS ONE, L.L.C.              Delaware
PG INVESTMENTS SIX, L.L.C.              Delaware
PG INVESTMENTS THREE, L.L.C.            Delaware
PG INVESTMENTS TWO, L.L.C.              Delaware
PG POWER SALES EIGHT, L.L.C.            Delaware
PG POWER SALES ELEVEN, L.L.C.           Delaware
PG POWER SALES FIVE, L.L.C.             Delaware
PG POWER SALES FOUR, L.L.C              Delaware
PG POWER SALES NINE, L.L.C.             Delaware
PG POWER SALES SEVEN, L.L.C.            Delaware
PG POWER SALES SIX, L.L.C.              Delaware
PG POWER SALES TEN, L.L.C.              Delaware
PG POWER SALES THREE, L.L.C.            Delaware
PG POWER SALES TWELVE, L.L.C.           Delaware
PG POWER SALES TWO, L.L.C.              Delaware
PHC Acquisition Corp.                   Delaware
Pine Ridge Coal Company                 Delaware
Point Pleasant Dock Company, LLC        Delaware
Pond Creek Land Resources, LLC          Delaware
Pond River Land Company                 Delaware









Porcupine Production, LLC               Delaware
Porcupine Transportation, LLC           Delaware
Powder River Coal Company               Delaware
Prairie State Generating Company, LLC   Delaware
Randolph Land Holding Company, LLC      Delaware
Rio Escondido Coal Corp.                Delaware
Rivers Edge Mining, Inc.                Delaware
Riverview Coal Terminal Pty. Ltd.       Queensland
Riverview Terminal Company              Delaware
Seneca Coal Company                     Delaware
Sentry Mining Company                   Delaware
Shoshone Coal Corporation               Delaware
Snowberry Land Company                  Delaware
Star Lake Energy Company, L.L.C.        Delaware
Sterling Smokeless Coal Company         West Virginia
Sugar Camp Properties                   Indiana
Thoroughbred Generating Company, LLC    Delaware
Thoroughbred Mining Company, L.L.C.     Delaware
Thoroughbred, L.L.C.                    Delaware
Tiaro Coal Pty. Ltd.                    Queensland
Twentymile Coal Company                 Delaware
Union County Coal Company, LLC          Kentucky
Yankeetown Dock Corporation             Indiana

EX-23

                                                                      EXHIBIT 23


            Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in this Annual Report (Form 10-K)
of Peabody Energy Corporation of our reports dated March 7, 2005; with respect
to the consolidated financial statements of Peabody Energy Corporation, Peabody
Energy Corporation management's assessment of internal control over financial
reporting, and the effectiveness of internal control over financial reporting of
Peabody Energy Corporation, included in the 2004 Annual Report to Stockholders
of Peabody Energy Corporation.

We consent to the incorporation by reference in the following Registration
Statements:

     1.  Registration Statement (Form S-8 No. 333-61406) pertaining to the
         Peabody Energy Corporation Employee Stock Purchase Plan, Long-Term
         Equity Incentive Plan and Equity Incentive Plan for Non-Employee
         Directors,

     2.  Registration Statement (Form S-8 No. 333-70910) pertaining to the
         Peabody Holding Company, Inc. Employee Retirement Account, Lee Ranch
         Coal Company Retirement and Savings Plan for Salaried Employees, and
         Western Surface Agreement-UMWA 401(k) Plan,

     3.  Registration Statement (Form S-8 No. 333-75058) pertaining to the
         Peabody Energy Corporation Deferred Compensation Plan,

     4.  Registration Statement (Form S-8 No. 333-109305) pertaining to the
         Black Beauty Coal Company 401(k) Plan,

     5.  Registration Statement (Form S-8 No. 333-105455) pertaining to the 1998
         Stock Purchase and Option Plan for Key Employees of Peabody Energy
         Corporation,

     6.  Registration Statement (Form S-8 No. 333-105456) pertaining to the 1998
         Stock Purchase and Option Plan for Key Employees of Peabody Energy
         Corporation, and

     7.  Registration Statement (Form S-3 No. 333-109906) and related combined
         prospectus of Peabody Energy Corporation,

     of our reports dated March 7, 2005, with respect to the consolidated
     financial statements and schedule of Peabody Energy Corporation, and to our
     report dated March 7, 2005 with respect to Peabody Energy Corporation
     management's assessment of internal control over financial reporting, and
     the effectiveness of internal control over financial reporting of Peabody
     Energy Corporation incorporated by reference in this Annual Report (Form
     10-K) for the year ended December 31, 2004.


                                             /s/ Ernst & Young LLP


St. Louis, Missouri
March 11, 2004

EX-31.1

                                                                    EXHIBIT 31.1

                                  CERTIFICATION

I, Irl F. Engelhardt, certify that:

1. I have reviewed this annual report on Form 10-K of Peabody Energy Corporation
("the registrant");

2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:

     (a) designed such disclosure controls and procedures, or caused such
     disclosure controls and procedures to be designed under our supervision, to
     ensure that material information relating to the registrant, including its
     consolidated subsidiaries, is made known to us by others within those
     entities, particularly during the period in which this report is being
     prepared;

     (b) designed such internal control over financial reporting, or caused such
     internal control over financial reporting to be designed under our
     supervision, 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;

     (c) evaluated the effectiveness of the registrant's disclosure controls and
     procedures and presented in this report our conclusions about the
     effectiveness of the disclosure controls and procedures, as of the end of
     the period covered by this report based on such evaluation; and

     (d) disclosed in this report any change in the registrant's internal
     control over financial reporting that occurred during the registrant's most
     recent fiscal quarter (the registrant's fourth fiscal quarter in the case
     of an annual report) that has materially affected, or is reasonably likely
     to materially affect, the registrant's internal control over financial
     reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):

     (a) all significant deficiencies and material weaknesses in the design or
     operation of internal control over financial reporting which are reasonably
     likely to adversely affect the registrant's ability to record, process,
     summarize and report financial information; and

     (b) any fraud, whether or not material, that involves management or other
     employees who have a significant role in the registrant's internal control
     over financial reporting.

Date: March 15, 2005


                                                      /s/ IRL F. ENGELHARDT
                                                     ---------------------------
                                                     Irl F. Engelhardt
                                                     Chairman and
                                                     Chief Executive Officer

EX-31.2

                                                                    EXHIBIT 31.2

                                  CERTIFICATION

I, Richard A. Navarre, certify that:

1. I have reviewed this annual report on Form 10-K of Peabody Energy Corporation
("the registrant");

2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact necessary to make the statements
made, in light of the circumstances under which such statements were made, not
misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;

4. The registrant's other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial
reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the
registrant and have:

     (a) designed such disclosure controls and procedures, or caused such
     disclosure controls and procedures to be designed under our supervision, to
     ensure that material information relating to the registrant, including its
     consolidated subsidiaries, is made known to us by others within those
     entities, particularly during the period in which this report is being
     prepared;

     (b) designed such internal control over financial reporting, or caused such
     internal control over financial reporting to be designed under our
     supervision, 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;

     (c) evaluated the effectiveness of the registrant's disclosure controls and
     procedures and presented in this report our conclusions about the
     effectiveness of the disclosure controls and procedures, as of the end of
     the period covered by this report based on such evaluation; and

     (d) disclosed in this report any change in the registrant's internal
     control over financial reporting that occurred during the registrant's most
     recent fiscal quarter (the registrant's fourth fiscal quarter in the case
     of an annual report) that has materially affected, or is reasonably likely
     to materially affect, the registrant's internal control over financial
     reporting; and

5. The registrant's other certifying officer(s) and I have disclosed, based on
our most recent evaluation of internal control over financial reporting, to the
registrant's auditors and the audit committee of the registrant's board of
directors (or persons performing the equivalent functions):

     (a) all significant deficiencies and material weaknesses in the design or
     operation of internal control over financial reporting which are reasonably
     likely to adversely affect the registrant's ability to record, process,
     summarize and report financial information; and

     (b) any fraud, whether or not material, that involves management or other
     employees who have a significant role in the registrant's internal control
     over financial reporting.

Date: March 15, 2005


                                             /s/ RICHARD A. NAVARRE
                                             -------------------------------
                                             Richard A. Navarre
                                             Executive Vice President and
                                             Chief Financial Officer

EX-32.1

                                                                    EXHIBIT 32.1



                   CERTIFICATION OF PERIODIC FINANCIAL REPORTS



I, Irl F. Engelhardt, Chairman and Chief Executive Officer of Peabody Energy
Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)      the Annual Report on Form 10-K for the year ended December 31, 2004
         (the "Periodic Report") which this statement accompanies fully complies
         with the requirements of Section 13(a) or 15(d) of the Securities
         Exchange Act of 1934; and

(2)      information contained in the Periodic Report fairly presents, in all
         material respects, the financial condition and results of operations of
         Peabody Energy Corporation.

Dated:  March 15, 2005



                                            /s/ IRL F. ENGELHARDT
                                            -----------------------------------
                                            Irl F. Engelhardt
                                            Chairman and Chief Executive Officer

EX-32.2

                                                                    EXHIBIT 32.2



                   CERTIFICATION OF PERIODIC FINANCIAL REPORTS



I, Richard A. Navarre, Executive Vice President and Chief Financial Officer of
Peabody Energy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)      the Annual Report on Form 10-K for the year ended December 31, 2004
         (the "Periodic Report") which this statement accompanies fully complies
         with the requirements of Section 13(a) or 15(d) of the Securities
         Exchange Act of 1934; and

(2)      information contained in the Periodic Report fairly presents, in all
         material respects, the financial condition and results of operations of
         Peabody Energy Corporation.

Dated:  March 15, 2005



                                                   /s/ RICHARD A. NAVARRE
                                                   ---------------------------
                                                   Richard A. Navarre
                                                   Executive Vice President
                                                   and Chief Financial Officer