Gold Fields Chile 424B3 Prospectus supplement

Filed Pursuant to Rule 424(b)(3)
Registration No. 333-106208

PROSPECTUS

$650,000,000

Peabody Energy Corporation

Offer to Exchange All Outstanding

6 7/8% Senior Notes due 2013

For an Equal Amount of

6 7/8% Series B Senior Notes due 2013

Which Have Been Registered Under the Securities Act of 1933

The Exchange Offer

• We will exchange all outstanding notes that are validly tendered and not validly withdrawn for an equal principal amount of exchange notes that are freely tradeable.

• You may withdraw tenders of outstanding notes at any time prior to the expiration of the exchange offer.

•  The exchange offer expires at midnight, New York City time, on Friday, August 1, 2003, unless extended. We do not currently intend to extend the expiration date.

• The exchange of outstanding notes for exchange notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes.

• We will not receive any proceeds from the exchange offer.

The Exchange Notes

• The exchange notes are being offered in order to satisfy certain of our obligations under the registration rights agreement entered into in connection with the placement of the outstanding notes.

• The terms of the exchange notes to be issued in the exchange offer are substantially identical to the outstanding notes, except that the exchange notes will be freely tradeable.

Resales of Exchange Notes

• The exchange notes may be sold in the over-the-counter market, in negotiated transactions or through a combination of such methods. We do not plan to list the exchange notes on a national market.

If you are a broker-dealer and you receive exchange notes for your own account, you must acknowledge that you will deliver a prospectus in connection with any resale of such exchange notes. By making such acknowledgment, you will not be deemed to admit that you are an “underwriter” under the Securities Act of 1933, as amended. Broker-dealers may use this prospectus in connection with any resale of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired by the broker-dealer as a result of market-making activities or trading activities. We have agreed that, for a period of 90 days after the expiration of the exchange offer or until any broker-dealer has sold all registered notes held by it, we will make this prospectus available to such broker-dealer for use in connection with any such resale. A broker-dealer may not participate in the exchange offer with respect to outstanding notes acquired other than as a result of market-making activities or trading activities. See “Plan of Distribution.”

If you are an affiliate of ours or are engaged in, or intend to engage in, or have an agreement or understanding to participate in, a distribution of the exchange notes, you cannot rely on the applicable interpretations of the Securities and Exchange Commission and you must comply with the registration requirements of the Securities Act in connection with any resale transaction.

You should consider carefully the risk factors beginning on page 15 of this prospectus before participating in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is July 2, 2003

TABLE OF CONTENTS

	Page
Where You Can Find Additional Information		i
Cautionary Notice Regarding Forward-Looking Statements		iii
Summary		1
Risk Factors		15
Use of Proceeds		25
Capitalization		27
Selected Financial Data		28
Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Coal Industry Overview		44
Business		57
Regulatory Matters		76
Management		83
Related Party Transactions		87
Description of Other Indebtedness		89
The Exchange Offer		91
Description of the Notes		100
Certain United States Federal Income Tax Considerations		137
Certain ERISA Considerations		139
Plan of Distribution		140
Legal Matters		141
Experts		141
Glossary of Selected Terms		142
Index to Financial Statements		F-1

WHERE YOU CAN FIND ADDITIONAL INFORMATION

     We file annual, quarterly and current reports and other information with the Securities and Exchange Commission, or SEC. You may access and read our SEC filings, through the SEC’s Internet site at www.sec.gov. This site contains reports and other information that we file electronically with the SEC. 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.

     Our descriptions in this prospectus of the provisions of documents filed with the SEC are only summaries of the terms of those documents that we consider material. If you want a complete description of the content of the documents, you should obtain the documents yourself by following the procedures described above.

     We have elected to “incorporate by reference” certain information into this prospectus, which means we can disclose important information to you by referring you to another document filed separately with the SEC. The information incorporated by reference is deemed to be part of this prospectus.

     We incorporate by reference our:

•  quarterly report on Form 10-Q for the quarter ended March 31, 2003, filed with the SEC on May 13, 2003;

•  annual report on Form 10-K for the year ended December 31, 2002, filed with the SEC on March 7, 2003;

•  current reports on Form 8-K, filed with the SEC on January 17, 2003, February 27, 2003, March 10, 2003, March 17, 2003, April 10, 2003 and May 5, 2003; and

•  proxy statement on Schedule 14A, filed with the SEC on April 2, 2003.

     Any statement contained in a document incorporated or deemed to be incorporated by reference in this prospectus will be deemed to be modified or superseded for purposes of this prospectus to the extent that a statement contained in this prospectus or in any other subsequently filed document which also is or is deemed to be incorporated by reference in this prospectus modifies or supersedes that statement. Any statement that is

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modified or superseded will not be deemed, except as so modified or superseded, to constitute a part of this prospectus.

     You may request copies of the filings, at no cost, by telephone at (314) 342-3400 or by mail at: Peabody Energy Corporation, 701 Market Street, Suite 700, St. Louis, Missouri 63101, attention: Investor Relations.

     This prospectus does not constitute an offer to sell, or a solicitation of an offer to buy, any exchange notes offered hereby in any jurisdiction where, or to any person to whom, it is unlawful to make such offer or solicitation. The information contained in this prospectus speaks only as of the date of this prospectus unless the information specifically indicates that another date applies. No dealer, salesperson or other person has been authorized to give any information or to make any representations other than those contained or incorporated by reference in this prospectus in connection with the offer contained herein and, if given or made, such information or representations must not be relied upon as having been authorized by us. Neither the delivery of this prospectus nor any sale made hereunder shall under any circumstances create an implication that there has been no change in our affairs or that of our subsidiaries since the date hereof.

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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

     Some of the information included in this prospectus and the documents we have incorporated by reference contain forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended, and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance. We use words such as “anticipate,” “believe,” “expect,” “may,” “intend,” “plan,” “project,” “will” or other similar words to identify forward-looking statements.

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

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

•  growth in coal and power markets;

•  coal’s market share of electricity generation;

•  the pace and extent of the economic recovery;

•  lower than normal heating and cooling degree days;

•  railroad and other transportation performance and costs;

•  the ability to renew sales contracts upon expiration or renegotiation;

•  the ability to successfully implement operating strategies;

•  the effectiveness of our cost-cutting measures;

•  regulatory and court decisions;

•  future legislation;

•  changes in postretirement benefit and pension obligations;

•  credit, market and performance risk associated with our customers;

•  modification or termination of our long-term coal supply agreements;

•  reductions of purchases by major customers;

•  risks inherent to mining, including geologic conditions or unforeseen equipment problems;

•  terrorist attacks or threats affecting our or our customers’ operations;

•  replacement of recoverable reserves;

•  implementation of new accounting standards;

•  inflationary trends and interest rates;

•  the effects of acquisitions or divestitures; and

•  other factors, including those discussed in “Risk Factors.”

     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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SUMMARY

     This summary highlights only some of the information in this prospectus and may not contain all of the information you need to consider. For a more complete description of the legal terms of the exchange offer, you should read the entire prospectus carefully, including the matters discussed under the caption “Risk Factors” and the detailed information and financial statements included or incorporated by reference in this prospectus. When used in this prospectus, the terms “we,” “our” and “us,” except as otherwise indicated or as the context otherwise indicates, refer to Peabody Energy Corporation and/or its applicable subsidiary or subsidiaries. The estimates of our proven and probable reserves included in this prospectus have been reviewed by Marshall Miller & Associates. For the definitions of certain technical terms used in this prospectus, please refer to “Glossary of Selected Terms.”

Peabody Energy Corporation

     We are the largest private sector coal company in the world. Our sales of 197.9 million tons of coal in 2002 accounted for 17.9% of all U.S. coal sales and were more than 70% greater than the sales of our closest U.S. competitor. During the period, we sold coal to more than 280 electric generating and industrial plants, fueling the generation of more than 9% of all electricity in the United States and 2% of all electricity in the world. At December 31, 2002, we had 9.1 billion tons of proven and probable coal reserves, approximately double the reserves of any other U.S. coal producer. During 2002, our total revenues, net income and net cash provided by operating activities were $2.7 billion, $105.5 million and $231.2 million, respectively.

     As of December 31, 2002, we owned majority interests in 33 active coal operations located throughout all major U.S. coal producing regions, with 73% of our U.S. 2002 coal sales shipped from the western United States and the remaining 27% from the eastern United States. Most of our production in the western United States is low sulfur coal from the Powder River Basin, the largest and fastest-growing major U.S. coal-producing region. Our overall western U.S. coal production has increased from 37.0 million tons in fiscal year 1990 to 128.0 million tons during 2002, representing a compounded annual growth rate of 11%. In the West, we own and operate mines in Arizona, Colorado, Montana, New Mexico and Wyoming. In the East, we own and operate mines in Illinois, Indiana, Kentucky and West Virginia. We produced 78% of our 2002 sales volume from non-union mines.

     During 2002, 94% of our sales were to U.S. electricity generators. The U.S. coal industry continues to fuel more electricity generation than all other energy sources combined. In 2002, coal-fueled plants generated an estimated 50.2% of the nation’s electricity, followed by nuclear (20.3%), gas-fired (17.9%) and hydroelectric (6.9%) units. We believe that competition for cost-efficient energy will strengthen the demand for coal. We also believe that U.S. and world coal consumption will continue to increase as coal-fueled generating plants utilize their existing excess capacity and as new coal-fueled plants are constructed. Coal is an attractive fuel for electricity generation because it is:

•  Abundant: Coal makes up more than 85% of fossil fuel reserves in the United States. The nation has an estimated 250-year supply of coal, based on current usage rates.

•  Low-Cost: At an average delivered price of $1.23 per million British thermal units, or Btu, in 2001, and $1.22 in 2002, coal’s cost advantage over natural gas is significant. The delivered price of natural gas averaged $4.49 per million Btu in 2001 and $3.65 in 2002, while market prices have recently exceeded $10.00. In 2001, 20 of the 25 lowest cost major generating plants in the United States were coal-fueled.

•  Increasingly Clean: Aggregate emissions from U.S. coal-fueled plants have declined significantly since 1970, even as coal consumption by electricity generators has more than tripled.

     Approximately 97% of our coal sales during 2002 were under long-term contracts. As of December 31, 2002, our sales backlog, including backlog subject to price reopener and/or extension provisions, approximated one billion tons. The remaining terms of our long-term contracts range from one to 18 years and have an average volume weighted remaining term of approximately 4.4 years. As of March 31, 2003, we

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had entered into commitments to sell 175 million tons, or approximately 98%, of our expected 2003 coal production and 134 million tons, or approximately 69%, of our expected 2004 coal production.

     In addition to mining operations, our other energy-related businesses include marketing, brokering and trading coal and emissions allowances, coalbed methane production, transportation-related services, third-party coal contract restructuring and the development of coal-fueled generating plants.

Competitive Strengths

     We are the world’s largest private-sector producer and marketer of coal and the largest reserve holder of any U.S. coal company.In 2002, our U.S. coal sales volume market share was 17.9%, more than 70% greater than our closest U.S. competitor. Our reserve base of 9.1 billion tons of proven and probable coal reserves is the largest of any U.S. coal producer, and we believe that we have significant expansion opportunities in areas adjacent to our existing reserves. Based on current production rates, we believe our reserves could last for approximately 50 years.

     We are the largest producer and marketer of low sulfur coal in the United States, with the number one position in the Powder River Basin, the fastest growing U.S. coal producing region.The demand for low-sulfur coal has grown dramatically since the adoption of the Clean Air Act Amendments of 1990, which led to reduced sulfur dioxide emissions from coal-fueled power plants. We have gained a leading position in the market for low sulfur coal, the fastest growing segment of the coal market. In 2002, we were the largest seller of low sulfur coal in the United States; our 153.0 million tons of low sulfur coal sales represented 77% of our total sales volume for that period. As of December 31, 2002, 4.0 billion tons of our proven and probable coal reserves were low in sulfur, which are substantially greater than the low sulfur reserves of any of our competitors. More than half of our total sales volume comes from the Powder River Basin, America’s largest known source of low-cost, low sulfur coal.

     We have a large portfolio of long-term coal supply agreements that are complemented by available production in attractive markets for sale at market prices.We have a large portfolio of coal supply agreements that provides us with reliable revenues. During 2002, approximately 97% of our coal sales were sold under long-term contracts, defined as contracts of one year or more. As of December 31, 2002, our sales backlog totaled approximately one billion tons, including backlog subject to price reopener and/or extension provisions. The average volume weighted remaining term of our long-term contracts is approximately 4.4 years. We also have a significant amount of uncommitted production that will be available for sale beginning in 2004, which could enable us to benefit from favorable future market prices for coal. As of March 31, 2003, we had approximately three million tons and 61 million tons of expected production unpriced for 2003 and 2004, respectively. We have the ability to increase 2003 production by an additional four to five million tons each quarter by running our current operations at their full capacity.

     We are one of the most productive and lowest-cost producers of coal in the United States.Through a shift to lower-cost operations, economies of scale, investments in advanced production technologies and centralized purchasing, information technology systems, marketing programs and land management functions, we achieve operating and corporate efficiencies. From 1990 to 2002, we increased our sales volume from 93.0 million tons to 197.9 million tons, while reducing the number of employees in our operations from approximately 10,200 to approximately 6,500. During this same period, we also increased our average productivity, in terms of coal production per miner shift, by 185%, while our safety accident rate declined from 16.1 to 5.4 incidents per 200,000 work hours.

     We serve a broad range of high quality customers with mining operations located throughout all major U.S. coal producing regions.As of December 31, 2002, we owned majority interests in 33 active coal operations in the United States, selling coal to more than 280 electric generating and industrial plants. We supply coal to customers in 14 countries, and we have strong, long-term relationships with many of our customers. We have historically experienced minimal bad debt expense, and we continue to mitigate exposure to higher risk customers through letters of credit, cash collateral, prepayments and customer payment trust

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accounts. Because of the geographical mix of our reserves and production, we can source coal from multiple regions, giving us greater flexibility to meet the needs of our customers and reduce their transportation costs. Our geographical diversity and extensive market knowledge also enable us to provide customized products, services and solutions to our customer network.

     Our emphasis on innovative research and development has increased our productivity.Since we are one of the largest users of equipment in the industry, manufacturers work with us to design and produce equipment that will bring added value to the coal industry. Our efforts have led to technological innovations, including state-of-the-art haul trucks, the adaptation of global positioning satellite technology and nuclear quality analysis equipment, and higher horsepower, continuous mining machines and a continuous haulage machine. As a result of these efforts, many of our mines are among the most productive in the industry.

     We are a leader in reclamation management and have received numerous state and national awards for our commitment to environmental excellence.We have a long-standing commitment to protecting the environment. We consistently restore mined lands to a condition as good as, or better than, their condition prior to mining. As a result of our efforts, we have received 30 state and national reclamation awards over the past five years. In 2002, we received six major awards for reclamation excellence, including the prestigious U.S. Department of the Interior’s Director’s Award, which was presented to the Kayenta Mine for preserving cultural, historic and archaeological resources. This is the third consecutive year that we have been awarded the Director’s Award for outstanding achievement in a specific area of reclamation.

     Our management team has a proven record of success.Our management team has a proven record of increasing productivity and reducing costs, making strategic acquisitions, developing and maintaining strong customer relationships, meeting financial commitments and deleveraging our company through repayment of approximately $1.5 billion of debt over the past five years. Our senior executives have an average of 19 years of experience in the coal industry and 16 years of experience with our company.

Transformation of Peabody

     Since 1990, we have grown significantly and our management has transformed our company from a largely high sulfur, high-cost coal company to a predominantly low sulfur, low-cost coal producer, marketer and trader. We have increased our sales of low sulfur coal from 57% of our total volume in 1990 to 77% in 2002. We are also well positioned to continue selling higher sulfur coal to customers that invest in emissions control technology, buy emissions allowances or blend higher sulfur coal with low sulfur coal. Our average cost per ton sold decreased 42% from 1990 to 2002. The following chart demonstrates our transformation:

							Percent
	1990			2002			Improvement
Sales volume (million tons)		93.0			197.9			113	%
U.S. market share(1)		9.1	%		17.9	%		97
Low sulfur sales volume (million tons)		52.7			153.0			190
Total coal reserves (billion tons)(2)		7.0			9.1			30
Low sulfur reserves (billion tons)(2)(3)		2.5			4.0			60
Safety (incidents per 200,000 hours)		16.1			5.4			66
Productivity (tons per miner shift)		33.5			95.6			185
Average cost per ton sold(4)	$	19.25		$	11.25			42
Employees (approximate)		10,200			6,500			36

(1)	Market share is calculated by dividing our U.S. sales volume by estimated total U.S. coal demand, as reported by the Energy Information Administration.
(2)	As of January 1, 1990 and as of December 31, 2002.
(3)	Represents our estimated proven and probable coal reserves with a sulfur content of 1% or less by weight.
(4)	Represents operating costs and expenses.

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Business Strategies

     Our transformation discussed above has resulted in part from the successful implementation of our three core business strategies:

     Managing safe, low-cost operations. Our first priority is the safety of our employees, and our safety record, as measured by frequency of incidents, has improved 66% since 1990. Productivity at our operations has nearly tripled since 1990, while operating costs have been reduced by 42%. To improve costs, we:

•  rely on a skilled employee base;

•  continually streamline processes;

•  invest in state-of-the-art technologies;

•  apply new production techniques; and

•  use our consolidated purchasing power, which gives us economies of scale.

     Adding value through world-class sales, brokerage and trading techniques. With sales to more than 280 electric generating and industrial plants in 14 countries, we utilize our extensive and geographically diverse coal operations, as well as access third-party-produced coal, to meet our customers’ energy needs. Our sales backlog of nearly one billion tons offers our customers a reliable supply source. We strategically balance our long-term contract position with uncommitted production based on our view of the market, which is derived from our industry-leading market presence and our analytical capabilities. Our coal brokerage and trading operations access third-party-produced coal through forward purchase and option agreements and provide structured multi-party transactions to the energy industry. Our goal is to optimize production and contract profitability while minimizing risk through our sound credit and risk management practices.

     Aggressively managing our vast natural resource position. With 9.1 billion tons of coal reserves and 300,000 acres of surface lands, we aggressively manage our resource position to add value. We grow our coal production base through development of our existing asset base and acquisitions. Over the past five years, we have acquired a number of coal operations at attractive prices and intend to continue to upgrade and sell non-strategic assets. Over the same period, we have made total acquisitions of approximately $400 million, while selling approximately $1.0 billion in assets, allowing us to meet our growth objectives while continuing to strengthen our balance sheet. In addition, we are pursuing the development of mine-mouth generating projects using our land and coal resources to help meet America’s growing needs for inexpensive electricity generation.

The Refinancing Transactions

     We completed a series of transactions, including the offering of the outstanding notes, in order to refinance a substantial portion of our outstanding indebtedness. In addition to the offering of the outstanding notes, we:

•  conducted a tender offer to repurchase any and all of our 8 7/8% Senior Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008;

•  redeemed the 8 7/8% Senior Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008 remaining outstanding after the tender offer;

•  entered into a new credit facility;

•  repaid a substantial portion of the indebtedness, including related make-whole premiums, of our subsidiary, Black Beauty Coal Company; and

•  paid the fees and expenses related to these transactions.

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     We believe that our new capitalization structure, after the Transactions, provides us with important financial and strategic benefits. As used in this prospectus, the term “Transactions” means, collectively, the series of transactions described above.

     Notes Offering. On March 21, 2003, we completed the sale of the outstanding notes in a private offering to qualified institutional buyers in reliance on Rule 144A and outside the United States in reliance on Regulation S under the Securities Act through Lehman Brothers Inc., Morgan Stanley & Co. Incorporated, Wachovia Securities, Inc., Fleet Securities, Inc., PNC Capital Markets, Inc., U.S. Bancorp Piper Jaffray Inc., BMO Nesbitt Burns Corp., Credit Lyonnais Securities (USA) Inc., ABN AMRO Incorporated and Fortis Investment Services, LLC as the initial purchasers. In connection with that offering, the initial purchasers and we entered into a registration rights agreement for the benefit of the holders of the outstanding notes providing for, among other things, this exchange offer. The exchange offer is intended to make the exchange notes freely transferable by their holders without further registration or any prospectus delivery requirements under the Securities Act.

     Tender Offer.On March 27, 2003, we completed a tender offer to purchase any and all of the $317.1 million aggregate principal amount of our 8 7/8% Senior Notes due 2008 and any and all of the $392.2 million aggregate principal amount of our 9 5/8% Senior Subordinated Notes due 2008. The tender offer provided that our 8 7/8% Senior Notes due 2008 and our 9 5/8% Senior Subordinated Notes due 2008 would be purchased at 101.75% and 102.125%, respectively, of the aggregate principal amounts of the notes, plus accrued interest up to the date of purchase. The tender offer also provided that holders of either series of notes who tendered their notes on or prior to a specified deadline would receive a premium of 3.0% of the aggregate principal amount of notes tendered. We accepted for purchase tenders of $109.1 million aggregate principal amount of the senior notes and $134.0 million aggregate principal amount of the senior subordinated notes pursuant to the tender offer. All of the notes accepted for purchase received the 3.0% premium.

     Redemption. On April 10, 2003, we initiated the full redemption of the remaining $208.0 million aggregate principal amount of the senior notes and the remaining $258.3 million aggregate principal amount of the senior subordinated notes that were not tendered pursuant to the tender offer. All remaining senior notes were redeemed on May 15, 2003 at a redemption price of 104.438% of the principal amount thereof, plus accrued and unpaid interest to May 15, 2003, and all remaining senior subordinated notes were redeemed on May 15, 2003 at a redemption price of 104.813% of the principal amount thereof, plus accrued and unpaid interest to May 15, 2003.

     New Credit Facility.On March 21, 2003, we entered into a new credit facility. The new credit facility consists of a $600.0 million revolving credit facility expiring in 2008 and a $450.0 million term loan B facility maturing in 2010. We had letters of credit of $231.2 million outstanding under the revolving credit facility and the entire term loan balance of $450.0 million outstanding as of March 31, 2003. We had no borrowings outstanding under the revolving credit facility as of March 31, 2003.

     Black Beauty.A portion of the proceeds from the offering of the outstanding notes and the new credit facility were used to repay a substantial portion of the indebtedness of Black Beauty, including its senior unsecured notes, revolving credit facility and certain indebtedness of its subsidiaries. In addition, on April 7, 2003 we acquired the 18.3% interest in Black Beauty that we did not previously own for $90.0 million.

     Our principal executive offices are located at 701 Market Street, St. Louis, Missouri 63101-1826, telephone (314) 342-3400.

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The Exchange Offer

     On March 21, 2003, we completed the private offering of the outstanding notes. References to the “notes” in this prospectus are references to both the outstanding notes and the exchange notes. This prospectus is part of a registration statement covering the exchange of the outstanding notes for the exchange notes.

     We and the guarantors entered into a registration rights agreement with the initial purchasers in the private offering in which we and the guarantors agreed to deliver to you this prospectus as part of the exchange offer and we agreed to complete the exchange offer within 180 days after the date of original issuance of the outstanding notes. You are entitled to exchange in the exchange offer your outstanding notes for exchange notes that are identical in all material respects to the outstanding notes except (1) the exchange notes have been registered under the Securities Act; and the exchange notes are not entitled to certain registration rights and liquidated damages that are applicable to the outstanding notes under the registration rights agreement.

The Exchange Offer	We are offering to exchange up to $650.0 million aggregate principal amount of our 6 7/8% Series B Senior Notes due 2013, which we refer to in this prospectus as the exchange notes, for up to $650.0 million aggregate principal amount of our 6 7/8% Senior Notes due 2013, which we refer to in this prospectus as the outstanding notes. The exchange offer is being made with respect to all of the outstanding notes. Outstanding notes may be exchanged only in integral multiples of $1,000.
Resale of the Exchange Notes	Based on an interpretation of the staff of the Securities and Exchange Commission set forth in no action letters issued to unrelated third parties, we believe that exchange notes issued pursuant to the exchange offer in exchange for outstanding notes may be offered for resale, resold and otherwise transferred by you (unless you are an “affiliate” of ours, within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that the exchange notes are acquired in the ordinary course of your business and you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the exchange notes.
	Each participating broker-dealer that receives exchange notes for its own account pursuant to the exchange offer in exchange for outstanding notes that were acquired as a result of market-making or other trading activity must acknowledge that it will deliver a prospectus in connection with any resale of the exchange notes.
	Any holder of outstanding notes who:
	• is an “affiliate” of ours;
	• does not acquire exchange notes in the ordinary course of business; or
	• tenders in the exchange offer with the intention to participate, or for the purpose of participating, in the distribution of the exchange notes;
	cannot rely on the position of the staff of the SEC enunciated inExxon Capital Holdings Corporation, Morgan Stanley & Co.

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Incorporated or similar interpretive letters and, in the absence of an exemption therefrom, must comply with the registration and prospectus delivery requirements of the Securities Act in connection with the resale of the exchange notes. See “The Exchange Offer — Resales of the Exchange Notes.”

Expiration Date; Withdrawal of Tender	The exchange offer will expire at midnight, New York City time, on Friday, August 1, 2003, or such later date and time to which we extend it (the “expiration date”). We do not currently intend to extend the expiration date. Tenders of outstanding notes pursuant to the exchange offer may be withdrawn at any time prior to the expiration date. Any outstanding notes not accepted for exchange for any reason will be returned without expense to the tendering holder promptly after the expiration or termination of the exchange offer. See “The Exchange Offer — Expiration Date; Extensions; Amendments” and “The Exchange Offer — Withdrawal of Tenders.”
Certain Conditions to the Exchange Offer	The exchange offer is subject to certain customary conditions, which we may waive. Please read carefully the section captioned “The Exchange Offer — Certain Conditions to the Exchange Offer” of this prospectus for more information regarding the conditions to the exchange offer.
Procedures for Tendering Outstanding Notes	If you wish to accept the exchange offer, you must complete, sign and date the accompanying letter of transmittal, or a facsimile of the letter of transmittal according to the instructions contained in this prospectus and the letter of transmittal. You must also mail or otherwise deliver the letter of transmittal, or a facsimile of the letter of transmittal, together with the outstanding notes and any other required documents, to the exchange agent at the address set forth on the cover page of the letter of transmittal. If you hold outstanding notes through The Depository Trust Company, or DTC, and wish to participate in the exchange offer, you must comply with the Automated Tender Offer Program procedures of DTC, by which you will agree to be bound by the letter of transmittal. By signing, or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:
	• any exchange notes that you receive will be acquired in the ordinary course of your business;
	• you have no arrangement or understanding with any person or entity to participate in a distribution of the exchange notes;
	• if you are a broker-dealer that will receive exchange notes for your own account in exchange for outstanding notes that were acquired as a result of market-making activities, that you will deliver a prospectus, as required by law, in connection with any resale of the exchange notes; and
	• you are not an “affiliate,” as defined in Rule 405 of the Securities Act, of ours or, if you are an affiliate of ours, you

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	will comply with any applicable registration and prospectus delivery requirements of the Securities Act.
	See “The Exchange Offer — Procedures for Tendering.”
Special Procedures for Beneficial Owners	If you are a beneficial owner of outstanding notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender the outstanding notes in the exchange offer, you should contact that registered holder promptly and instruct that registered holder to tender on your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your outstanding notes, either make appropriate arrangements to register ownership of the outstanding notes in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration date. See “The Exchange Offer — Procedures for Tendering.”
Guaranteed Delivery Procedures	If you wish to tender your outstanding notes and your outstanding notes are not immediately available or you cannot deliver your outstanding notes, the letter of transmittal or any other documents required by the letter of transmittal or comply with the applicable procedures under DTC’s Automated Tender Offer Program prior to the expiration date, you must tender your outstanding notes according to the guaranteed delivery procedures set forth in this prospectus under “The Exchange Offer — Guaranteed Delivery Procedures.”
Effect on Holders of Outstanding Notes	As a result of the making of, and upon acceptance for exchange of all validly tendered outstanding notes pursuant to the terms of the exchange offer, we will have fulfilled a covenant contained in the registration rights agreement and, accordingly, there will be no increase in the interest rate on the outstanding notes under the circumstances described in the registration rights agreement. If you are a holder of outstanding notes and you do not tender your outstanding notes in the exchange offer, you will continue to hold the outstanding notes and you will be entitled to all the rights and limitations applicable to the outstanding notes in the indenture, except for any rights under the registration rights agreement that by their terms terminate upon the consummation of the exchange offer.
	To the extent that outstanding notes are tendered and accepted in the exchange offer, the trading market for outstanding notes could be adversely affected.
Consequence of Failure to Exchange	All untendered outstanding notes will continue to be subject to the restrictions on transfer provided for in the outstanding notes and in the indenture. In general, the outstanding notes may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offer, we do not currently anticipate

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	that we will register the outstanding notes under the Securities Act. See “The Exchange Offer — Consequences of Failure to Exchange.”
Certain United States Federal Income Tax Considerations	The exchange of the outstanding notes for the exchange notes pursuant to the exchange offer will not be a taxable event for United States federal income tax purposes. See “Certain United States Federal Income Tax Considerations.”
Use of Proceeds	We will not receive any proceeds from the issuance of exchange notes pursuant to the exchange offer.
Exchange Agent	US Bank National Association is serving as exchange agent in connection with the exchange offer. The address and telephone number of the exchange agent are set forth in the section captioned “The Exchange Offer — Exchange Agent” of this prospectus.

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The Exchange Notes

Issuer	Peabody Energy Corporation.
Notes Offered	$650,000,000 in aggregate principal amount of 6 7/8% Series B Senior Notes due 2013.
Maturity	March 15, 2013.
Interest Payment Dates	March 15 and September 15 of each year, commencing on September 15, 2003.
Rankings	The exchange notes and subsidiary guarantees are senior obligations of ours and our subsidiary guarantors. Accordingly, they rank:
	• equally with all of our and our subsidiary guarantors’ existing and future unsecured senior debt;
	• ahead of any of our and our subsidiary guarantors’ debt that expressly provides for subordination to the notes or the guarantees;
	• subordinated to any of our and our subsidiary guarantors’ secured indebtedness to the extent of the value of the security for that indebtedness; and
	• subordinated to all indebtedness and other liabilities (including trade payables) of our non-guarantor subsidiaries.
	As of May 31, 2003:
	• we and our subsidiary guarantors had approximately $1,189.5 million of total indebtedness;
	• we and our subsidiary guarantors had approximately $1,100.0 million of senior indebtedness, $450.0 million of which is secured indebtedness under our new credit facility to which the exchange notes will be effectively subordinated (we also have letters of credit of $230.2 million outstanding and available borrowings of $369.8 million under our new revolving credit facility, which will be secured if drawn); and
	• our non-guarantor subsidiaries had aggregate indebtedness and other liabilities (including trade payables and accrued expenses) of $39.3 million.
Guarantees	Subject to certain exceptions, our obligations under the exchange notes are jointly and severally guaranteed on a senior unsecured basis by our existing and future restricted domestic subsidiaries. See “Description of the Notes — Subsidiary Guarantees.”
	For the five months ended May 31, 2003, the entities that guarantee the exchange notes as of the issue date generated approximately 95.5% of our revenues and our non-guarantor subsidiaries generated approximately 4.5% of our revenues.
Optional Redemption	On or after March 15, 2008, we may redeem some or all of the exchange notes at any time at the redemption prices described in the section “Description of the Notes — Optional Redemption.” Before March 15, 2006, we may redeem up to 35% of the

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	aggregate principal amount of the exchange notes issued under the indenture with the net cash proceeds of certain public or private offerings of equity, provided at least 65% of the aggregate principal amount of the exchange notes remains outstanding after the redemption. Before March 15, 2008, we may redeem some or all of the exchange notes at any time at a redemption price equal to 100% of the principal amount of the exchange notes being redeemed plus a make-whole premium and accrued and unpaid interest and liquidated damages, if any, to the redemption date. See “Description of the Notes — Optional Redemption.”
Change of Control	If we experience specific kinds of changes in control and the credit rating assigned to the exchange notes declines below specified levels within 90 days of that time, we must offer to repurchase the exchange notes at 101% of the principal amount thereof, plus accrued and unpaid interest and liquidated damages, if any, to the date of redemption.
Covenants	We will issue the exchange notes under an indenture among us, the guarantors and the trustee. The indenture will (among other things) limit our ability and that of our restricted subsidiaries to:
	• incur additional indebtedness and issue preferred stock;
	• pay dividends or make other distributions;
	• make other restricted payments and investments;
	• create liens;
	• incur restrictions on the ability of our subsidiaries to pay dividends or make other payments to us;
	• sell assets;
	• merge or consolidate with other entities; and
	• enter into transactions with affiliates.
	Each of the covenants is subject to a number of important exceptions and qualifications. See “Description of the Notes — Certain Covenants.”
	Many of the covenants will terminate before the exchange notes mature if two specified ratings agencies assign the exchange notes investment grade ratings in the future and no event of default exists under the indenture. Any covenants that cease to apply to us as a result of achieving these ratings will not be restored, even if the credit rating assigned to the exchange notes later falls below one or both of these ratings. See “Description of the Notes — Covenant Termination.”
Absence of a Public Market for the Exchange Notes	The exchange notes generally will be freely transferable but will also be new securities for which there will not initially be a market. Accordingly, we cannot assure you whether a market for the exchange notes will develop or as to the liquidity of any market. We do not intend to apply for a listing of the exchange notes on any securities exchange or automated dealer quotation

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system. The initial purchasers in the private offering of the outstanding notes have advised us that they currently intend to make a market in the exchange notes. However, they are not obligated to do so, and any market-making activities with respect to the exchange notes may be discontinued without notice.

     For a discussion of certain risks that should be considered in connection with an investment in the exchange notes, see “Risk Factors.”

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Summary Financial and Operating Data

     In July 2001, we changed our fiscal year end from March 31 to December 31. The change was first effective with respect to the nine months ended December 31, 2001. We have derived the summary historical financial data for our company for the years ended and as of March 31, 2000 and 2001, the nine months ended and as of December 31, 2001, the year ended and as of December 31, 2002 and the quarter ended and as of March 31, 2003 from our audited and unaudited financial statements. The historical results are not necessarily indicative of our future operating results. You should read the following table in conjunction with the financial statements, which have been audited by Ernst & Young LLP, independent auditors, and our unaudited financial statements and the notes to those statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” which are incorporated by reference and included elsewhere in this prospectus.

     In anticipation of the sale of our power marketing subsidiary, Citizens Power, which occurred in August 2000, we classified Citizens Power as a discontinued operation as of March 31, 2000, and recorded an estimated loss on the sale of $78.3 million, net of income taxes. We have adjusted our results of operations to reflect the classification of Citizens Power as a discontinued operation for all periods presented.

     Results of operations for the year ended March 31, 2000 included a $144.0 million income tax benefit associated with an increase in the tax basis of a subsidiary’s assets due to a change in federal income tax regulations.

     On January 29, 2001, we sold our Australian operations. The following summary financial and other data includes results of operations from this Australian operation prior to the date of sale and also includes the gain on this sale. Results of operations for the year ended March 31, 2001 included a pretax gain of $171.7 million, or $124.2 million net of income taxes, from the sale of our Australian operations. In August 2002, we re-entered Australia by purchasing a coal mine in Queensland.

     Results of operations for the year ended December 31, 2002 included an income tax benefit of $40.0 million. This benefit resulted primarily from significant tax benefits realized as a result of utilizing net operating loss carryforwards to offset taxable gains recognized in connection with property sale transactions. Utilization of the loss carryforwards required the reduction of a previously recorded valuation allowance that had reduced the book value of the loss carryforwards. Also in 2002, due to a change in accounting principle, we began recording revenues related to all coal trading activities on a net basis in “Other revenues,” and all prior period amounts were reclassified. Had our physically settled trading transactions been recorded on a gross basis, total revenues and operating costs would have been $41.6 million, $88.8 million and $161.9 million higher for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

     Results of operations for the quarter ended March 31, 2003 included early debt extinguishment costs of $21.2 million incurred in connection with the March 2003 refinancing transactions.

     For purposes of the computation of the ratio of earnings to fixed charges, earnings consist of income before income taxes and minority interests plus fixed charges. Fixed charges consist of interest expense on all indebtedness plus the interest component of lease rental expense.

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								Nine Months
		Year Ended			Year Ended			Ended			Year Ended			Quarter
		March 31,			March 31,			December 31,			December 31,			Ended March 31,
		2000			2001			2001			2002			2003
(Dollars in thousands)														(Unaudited)
Statement of Operations Data:
Total revenues		$	2,710,500		$	2,628,128		$	1,937,940		$	2,717,098		$	681,294
Operating profit			193,237			341,839			115,531			173,688			34,531
Income (loss) from continuing operations			118,570			102,680			19,287			105,519			(937	)
Other Data:
Tons sold (unaudited, in millions):
	United States		179.2			181.6			146.5			197.5			47.8
	Australia		11.1			10.8			—			0.4			0.2
	Total		190.3			192.4			146.5			197.9			48.0
Net cash provided by (used in):
	Operating activities	$	262,911		$	151,980		$	114,492		$	231,204		$	57,551
	Investing activities		(185,384	)		388,462			(172,989	)		(144,078	)		(53,059	)
	Financing activities		(205,181	)		(543,337	)		34,396			(54,798	)		(4,353	)
Operating profit:
	United States		144,882			288,462			115,531			170,909			32,819
	Australia		48,355			53,377			—			2,779			1,712
	Total		193,237			341,839			115,531			173,688			34,531
Depreciation, depletion and amortization:
	United States		216,327			215,450			174,587			232,177			55,855
	Australia		33,455			25,518			—			236			192
	Total		249,782			240,968			174,587			232,413			56,047
Capital expenditures:
	United States		150,130			151,358			194,246			208,390			58,502
	Australia		28,624			35,702			—			172			342
	Total		178,754			187,060			194,246			208,562			58,844
Ratio of Earnings to Fixed Charges (unaudited)(1)			0.97	x		1.63	x		1.23	x		1.50	x		0.68	x
Balance Sheet Data (at end of period):
Total assets		$	5,826,849		$	5,209,487		$	5,150,902		$	5,140,177		$	5,783,864
Total debt			2,076,166			1,405,621			1,031,067			1,029,211			1,659,583
Total stockholders’ equity			508,426			631,238			1,035,472			1,081,138			1,065,980

(1)  Earnings were insufficient to cover fixed charges by $7.4 million for the year ended March 31, 2000. Excluding $21.2 million of early debt extinguishment costs incurred in the quarter ended March 31, 2003, the ratio of earnings to fixed charges was 1.2x during this period.

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RISK FACTORS

     An investment in our exchange notes involves risks. You should consider carefully, in addition to the other information contained in or incorporated by reference into this prospectus, the following risk factors before deciding to invest in the exchange notes.

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, 2002, 97% of our sales volume was sold under long-term coal supply agreements. At December 31, 2002, our coal supply agreements had remaining terms ranging from one to 18 years and an average volume-weighted remaining term of approximately 4.4 years.

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

     The operating profits we realize from coal sold under supply agreements depend on a variety of factors. In addition, price adjustment and other provisions may increase our exposure to short-term coal price volatility provided by those contracts. If a substantial portion of our coal supply agreements were modified or terminated, we could be materially adversely affected to the extent that we are unable to find alternate buyers for our coal at the same level of profitability. Some of our coal supply agreements are for prices above current market prices. Although market prices for coal increased in most regions in 2001, market prices for coal decreased in most regions in 2002. Pricing has improved slightly for eastern coal regions and remained stable for western coal regions during the first quarter of 2003. As a result, we cannot predict the future strength of the coal market and cannot assure you that we will be able to replace existing long-term coal supply agreements at the same prices or with similar profit margins when they expire. In addition, two of our coal supply agreements are the subject of ongoing litigation and arbitration.

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

     For the year ended December 31, 2002, we derived 28% of our total coal revenues from sales to our five largest customers. At December 31, 2002, we had 31 coal supply agreements with these customers that expire at various times from 2003 to 2015. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be

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successful and those customers may not continue to purchase coal from us under long-term coal supply agreements. If a number of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially.

     In addition, we sold 4.6 million tons of coal to the Mohave Generating Station in 2002. We have a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005, but may be renewed as provided in the agreement. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of coal by pipeline to the Mohave Generating Station. Also, Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utility Commission proceeding related to recovery of future capital expenditures for new pollution abatement equipment for the station. As a result of these issues, the operator of the Mohave Generating Station has announced that it expects to idle the plant for at least 12 to 18 months beginning in 2006. We are in active discussions to resolve the complex issues critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. We cannot assure you that the issues critical to the continued operation of the Mohave Generating Station will be resolved. If the issues are not resolved in a timely manner, the Mohave Generating Station will cease or be suspended on December 31, 2005. The Mohave Generating Station is the sole customer of our Black Mesa Mine, which produces and sells 4.5 to 5.0 million tons of coal per year. If we are unable to renew the coal supply agreement with the Mohave Generating Station, our financial condition and results of operations could be adversely affected after 2005.

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

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

     Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to deliver coal to markets. While U.S. coal customers typically arrange and pay for transportation of coal from the mine to the point of use, disruption of these transportation services because of weather-related problems, strikes, lock-outs or other events could temporarily impair our ability to supply coal to our customers and thus could adversely affect our results of operations. For example, the high volume of coal shipped from all Powder River Basin mines could create temporary congestion on the rail systems servicing that region.

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

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

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

     Federal, state and local authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon

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the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. The possibility exists that new legislation and/or regulations and orders may be adopted that may materially adversely affect our mining operations, our cost structure and/or our customers’ ability to use coal. New legislation or administrative regulations (or judicial interpretations of existing laws and regulations), including proposals related to the protection of the environment that would further regulate and tax the coal industry, may also require us or our customers to change operations significantly or incur increased costs. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use. These factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations.

     In addition, the United States and over 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on U.S. greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely impact the price of and demand for coal. According to the Energy Information Administration’s Emissions of Greenhouse Gases in the United States 2001, coal accounts for 32% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to sources of fuel with lower carbon dioxide emissions. Further developments in connection with regulations or other limits on carbon dioxide emissions could have a material adverse effect on our financial condition or results of operations.

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

     We provide postretirement health and life insurance benefits to eligible union and non-union employees. We calculated the total accumulated postretirement benefit obligation under Statement of Financial Accounting Standards No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” which we estimate had a present value of $1,031.7 million as of December 31, 2002, $72.1 million of which was a current liability. We have estimated these unfunded obligations based on assumptions described in the notes to our consolidated financial statements. If our assumptions do not materialize as expected, cash expenditures and costs that we incur could be materially higher. Moreover, regulatory changes could increase our obligations to provide these or additional benefits.

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

     In addition, certain of our subsidiaries participate in two multi-employer pension funds and have an obligation to contribute to a multi-employer defined contribution benefit fund. Contributions to these funds could increase as a result of future collective bargaining with the United Mine Workers of America, a

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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. Certain of our subsidiaries are statutorily obligated to contribute to the 1992 Fund under the Coal Industry Retiree Health Benefit Act of 1992.

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

     Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserve base through acquisitions of government and other leases and producing properties and continuing to use our existing properties. The federal government also leases natural gas and coalbed methane reserves in the west, including in the Powder River Basin. Some of these natural gas and coalbed methane reserves are located on, or adjacent to, some of our Powder River Basin reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees’ rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. As of December 31, 2002, we leased or had applied to lease a total of 69,402 acres from the federal government. The limit could restrict our ability to lease additional federal lands.

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

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

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

Our financial condition could be negatively affected if we fail to maintain satisfactory labor relations.

     As of December 31, 2002, the United Mine Workers of America represented approximately 31% of our employees, who produced 19% of our coal sales volume during 2002. An additional 4% of our employees are represented by labor unions other than the United Mine Workers of America. These employees produced 3% of our coal sales volume during 2002. Because of the higher labor costs and the increased risk of strikes and other work-related stoppages that may be associated with union operations in the coal industry, our non-unionized competitors may have a competitive advantage in areas where they compete with our unionized operations. If some or all of our current non-union operations were to become unionized, we could incur an increased risk of work stoppages, reduced productivity and higher labor costs. The 10-month United Mine Workers of America strike in 1993 had a material adverse effect on us. Two of our subsidiaries, Peabody Coal

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Company and Eastern Associated Coal Corp., operate under a union contract that is in effect through December 31, 2006. Peabody Western Coal Company operates under a union contract that is in effect through September 1, 2005.

Our operations could be adversely affected if we fail to maintain required surety bonds.

     Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, to secure coal lease obligations and to satisfy other miscellaneous obligations. As of December 31, 2002, we had outstanding surety bonds with third parties for post-mining reclamation totaling $622.6 million. Furthermore, we had an additional $164.4 million of surety bonds in place for workers’ compensation and retiree healthcare obligations and $69.0 million of surety bonds securing coal leases. These bonds are typically renewable on a yearly basis. It has become increasingly difficult for us to secure new surety bonds or renew bonds without the posting of partial collateral. In addition, surety bond costs have increased while the market terms of surety bonds have generally become less favorable to us. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material adverse effect on us. That failure could result from a variety of factors including the following:

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

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

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

Lehman Brothers Merchant Banking has significant influence on all stockholder votes.

     At June 1, 2003, Lehman Brothers Merchant Banking and its affiliates beneficially owned approximately 29.8% of our common stock. As a result, Lehman Brothers Merchant Banking will effectively continue to be able to influence the election of our directors and determine our corporate and management policies and actions, including potential mergers or acquisitions, asset sales and other significant corporate transactions. We have retained affiliates of Lehman Brothers Merchant Banking to perform advisory and financing services for us in the past, and may continue to do so in the future.

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

     We manage our business with a number of key personnel, 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 our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our

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

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

     Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties. These new power plant owners may have credit ratings that are below investment grade. In addition, the creditworthiness of certain of our customers and trading counterparties has deteriorated due to lower than anticipated demand for energy and lower volume and volatility in the traded energy markets in 2002. If deterioration of the creditworthiness of other electric power generator customers or trading counterparties continues, our $140.0 million accounts receivable securitization program and our business could be adversely affected.

Risks Relating to the Exchange Offer and the Notes

If you choose not to exchange your outstanding notes, the present transfer restrictions will remain in force and the market price of your outstanding notes could decline.

     If you do not exchange your outstanding notes for exchange notes under the exchange offer, then you will continue to be subject to the transfer restrictions on the outstanding notes as set forth in the offering memorandum distributed in connection with the private offering of the outstanding notes. In general, the outstanding notes may not be offered or sold unless they are registered or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the outstanding notes under the Securities Act. You should refer to the section of the prospectus entitled “The Exchange Offer” for information about how to tender your outstanding notes.

     The tender of outstanding notes under the exchange offer will reduce the principal amount of the outstanding notes, which may have an adverse effect upon, and increase the volatility of, the market price of the outstanding notes due to reduction in liquidity.

You must comply with the exchange offer procedures in order to receive freely tradable exchange notes.

     Delivery of the exchange notes in exchange for the outstanding notes tendered and accepted for exchange pursuant to the exchange offer will be made only after timely receipt by the exchange agent of the following:

•  Certificates for the outstanding notes or a book-entry confirmation of a book-entry transfer of the outstanding notes into the exchange agent’s account at DTC, as a depository, including an agent’s message, as defined in this prospectus, if the tendering holder does not deliver a letter of transmittal;

•  A completed and signed letter of transmittal, or facsimile copy, with any required signature guarantees, or, in the case of a book-entry transfer, an agent’s message in place of the letter of transmittal; and

•  Any other documents required by the letter of transmittal.

     Therefore, holders of the outstanding notes who would like to tender the outstanding notes in exchange for exchange notes should be sure to allow enough time for the outstanding notes to be delivered on time. We are not required to notify you of defects or irregularities in tenders of outstanding notes for exchange. Outstanding notes that are not tendered or that are tendered but we do not accept for exchange will, following consummation of the exchange offer, continue to be subject to the existing transfer restrictions under the

20

Securities Act and will no longer have the registration and other rights under the registration rights agreement. See “The Exchange Offer — Procedures for Tendering.”

Some holders who exchange their outstanding notes may be deemed to be underwriters and these holders will be required to comply with the registration and prospectus delivery requirements in connection with any resale transaction.

     If you exchange your outstanding notes in the exchange offer for the purpose of participating in a distribution of the exchange notes, you may be deemed to have received restricted securities. If you are deemed to have received restricted securities, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Our substantial indebtedness could adversely affect our financial health and prevent us from fulfilling our obligations under the notes.

     Our financial performance could be affected by our substantial indebtedness. As of March 31, 2003, our total indebtedness was approximately $1,659.6 million, and we had $368.8 million of borrowings available under our new 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, research and development or other general corporate uses;

•  limiting our ability to obtain additional financing to fund future working capital, capital expenditures, research and development 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 will secure our indebtedness under our new credit facility.

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

We will require a significant amount of cash to service our indebtedness. Our ability to generate cash depends on many factors beyond our control.

     Our ability to pay principal and interest on and to refinance our debt, including the notes, depends upon the operating performance of our subsidiaries, which will be affected by, among other things, general economic, financial, competitive, legislative, regulatory and other factors, some of which are beyond our control.

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     Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our new credit facility, will be adequate to meet our future liquidity needs for at least the next year, barring any unforeseen circumstances that are beyond our control. We cannot assure you, however, that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our new credit facility or otherwise in an amount sufficient to enable us to pay our indebtedness, including the notes, or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the notes, on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our credit facility and the notes, on commercially reasonable terms, on terms acceptable to us or at all.

The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors’ existing and future secured indebtedness.

     The notes and the guarantees are general unsecured obligations ranking effectively junior in right of payment to all existing and future secured debt of ours and that of each subsidiary guarantor, respectively, including obligations under the new credit facility to the extent of the collateral securing the debt. As of March 31, 2003, we and our subsidiary guarantors had approximately $450.0 million of secured debt outstanding under our new credit facility and an additional $368.8 million was available for future borrowings under our new secured revolving credit facility. In addition, the indenture governing the exchange notes permits the incurrence of additional debt, some of which may be secured debt.

     In the event that we or a subsidiary guarantor is declared bankrupt, becomes insolvent or is liquidated or reorganized, any debt that ranks ahead of the notes and the guarantees will be entitled to be paid in full from our assets or the assets of the guarantor, as applicable, before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably with all holders of our unsecured indebtedness that is deemed to be of the same class as the notes, and potentially with all of our other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of the notes may receive less, ratably, than holders of secured indebtedness.

The notes are structurally subordinate to all indebtedness of our subsidiaries that are not guarantors of the notes.

     You will not have any claim as a creditor against our subsidiaries that are not guarantors of the notes, and indebtedness and other liabilities, including trade payables, whether secured or unsecured, of those subsidiaries will effectively be senior to your claims against those subsidiaries.

     We derive substantially all of our revenue from our subsidiaries. All obligations of our non-guarantor subsidiaries will have to be satisfied before any of the assets of such subsidiaries would be available for distribution, upon a liquidation or otherwise, to us or a guarantor of the notes. As of March 31, 2003, our non-guarantor subsidiaries had approximately $110.7 million of total indebtedness and other liabilities (including trade payables and accrued expenses and excluding amounts payable to affiliates).

     We also have joint ventures and subsidiaries in which we own less than 100% of the equity so that, in addition to the structurally senior claims of creditors of those entities, the equity interests of our joint venture partners or other shareholders in any dividend or other distribution made by these entities would need to be satisfied on a proportionate basis with us. These joint ventures and less than wholly-owned subsidiaries may also be subject to restrictions on their ability to distribute cash to us in their financing or other agreements and, as a result, we may not be able to access their cash flow to service our debt obligations, including in respect of the notes.

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Despite our and our subsidiaries’ current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

     We and our subsidiaries may be able to incur substantial additional indebtedness in the future. The terms of the new indenture do not prohibit us or our subsidiaries from doing so. Our new revolving credit facility provides commitments of up to $600.0 million, of which $231.2 million of letters of credit was outstanding at March 31, 2003 and $368.8 million of which was available for future borrowing. These borrowings are secured, and as a result, are effectively senior to the notes and the guarantees of the notes by our subsidiary guarantors. If we incur any additional indebtedness that ranks equally with the notes, the holders of that debt will be entitled to share ratably with the holders of the notes in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of us. This may have the effect of reducing the amount of proceeds paid to you. If new debt is added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

The covenants in our new credit facility and the indenture governing the notes impose restrictions that may limit our operating and financial flexibility.

     Our new credit facility, the indenture governing the notes and the instruments governing our other indebtedness contain a number of significant restrictions and covenants that limit our ability and our subsidiaries’ ability to:

•  incur liens and debt or provide guarantees in respect of obligations of any other person;

•  issue redeemable preferred stock and non-guarantor subsidiary preferred stock;

•  increase our common stock dividends above specified levels;

•  make redemptions and repurchases of capital stock;

•  make loans and investments;

•  prepay, redeem or repurchase debt;

•  engage in mergers, consolidations and asset dispositions;

•  engage in affiliate transactions;

•  amend certain debt and other material agreements, and issue and sell capital stock of subsidiaries; and

•  restrict distributions from subsidiaries.

     Operating results below current levels or other adverse factors, including a significant increase in interest rates, could result in our being unable to comply with our financial covenants. If we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms, on terms that are acceptable to us or at all. If our debt is in default for any reason, our business, financial condition and results of operations could be materially and adversely affected. In addition, complying with these covenants may also cause us to take actions that are not favorable to holders of the notes and may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.

Federal and state fraudulent transfer laws permit a court to void the notes and the guarantees, and, if that occurs, you may not receive any payments on the notes.

     The issuance of the notes and the guarantees may be subject to review under federal and state fraudulent transfer and conveyance statutes. While the relevant laws may vary from state to state, under such laws the payment of consideration will be a fraudulent conveyance if (1) we paid the consideration with the intent of hindering, delaying or defrauding creditors or (2) we or any of our guarantors, as applicable, received less

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than reasonably equivalent value or fair consideration in return for issuing either the notes or a guarantee, and, in the case of (2) only, one of the following is also true:

•  we were or any of our guarantors was insolvent or rendered insolvent by reason of the incurrence of the indebtedness; or

•  payment of the consideration left us or any of our guarantors with an unreasonably small amount of capital to carry on the business; or

•  we or any of our guarantors intended to, or believed that we or it would, incur debts beyond our or its ability to pay as they mature.

     If a court were to find that the issuance of the notes or a guarantee was a fraudulent conveyance, the court could void the payment obligations under the notes or such guarantee or further subordinate the notes or such guarantee to presently existing and future indebtedness of ours or such guarantor, or require the holders of the notes to repay any amounts received with respect to the notes or such guarantee. In the event of a finding that a fraudulent conveyance occurred, you may not receive any repayment on the notes. Further, the voidance of the notes could result in an event of default with respect to our and our subsidiaries’ other debt that could result in acceleration of that debt.

     Generally, an entity would be considered insolvent if, at the time it incurred indebtedness:

•  the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets; or

•  the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts and liabilities, including contingent liabilities, as they become absolute and mature; or

•  it could not pay its debts as they become due.

     We cannot be certain as to the standards a court would use to determine whether or not we or the guarantors were solvent at the relevant time, or regardless of the standard that a court uses, that the issuance of the notes and the guarantees would not be further subordinated to our or any of our guarantors’ other debt.

     If the guarantees were legally challenged, any guarantee could also be subject to the claim that, since the guarantee was incurred for our benefit, and only indirectly for the benefit of the guarantor, the obligations of the applicable guarantor were incurred for less than fair consideration. A court could thus void the obligations under the guarantees, subordinate them to the applicable guarantor’s other debt or take other action detrimental to the holders of the notes.

We may be unable to purchase the notes upon a change of control coupled with a ratings decline.

     Upon a change of control, if the credit rating assigned to the notes declines beyond specified levels within 90 days of the change of control, we will be required to offer to purchase all of the notes then outstanding for cash at 101% of the principal amount thereof plus accrued and unpaid interest. If a change of control/ratings trigger were to occur, we may not have sufficient funds to pay the change of control purchase price and we may be required to secure third-party financing to do so. However, we may not be able to obtain such financing on commercially reasonable terms, on terms acceptable to us or at all. A change of control/ratings trigger under the indenture may also result in an event of default under our new credit facility, which may cause the acceleration of our other indebtedness, in which case, we would be required to repay in full our secured indebtedness before we repay the notes. Our future indebtedness may also contain restrictions on our ability to repurchase the notes upon certain events, including transactions that could constitute a change of control/ratings trigger under the indenture. Our failure to repurchase the notes upon a change of control/ratings trigger would constitute an event of default under the indenture and would have a material adverse effect on our financial condition.

     The change of control/ratings trigger provision in the indenture may not protect you in the event we consummate a highly leveraged transaction, reorganization, restructuring, merger or other similar transaction,

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unless such transaction constitutes a change of control and results in a ratings decline under the indenture. Such a transaction may not involve a ratings decline or a change in voting power or beneficial ownership or, even if it does, may not involve a change of the magnitude required under the definition of change of control triggering event in the indenture to trigger our obligation to repurchase the notes. Except as described above, the indenture does not contain provisions that permit the holders of the notes to require us to repurchase or redeem the notes in an event of a takeover, recapitalization or similar transaction.

USE OF PROCEEDS

     We will not receive any cash proceeds from the issuance of the exchange notes. In consideration for issuing the exchange notes as contemplated in this prospectus, we will receive in exchange a like principal amount of outstanding notes, the terms of which are identical in all material respects to the exchange notes. The outstanding notes surrendered in exchange for the exchange notes will be retired and canceled and cannot be reissued. Accordingly, issuance of the exchange notes will not result in any change in our capitalization.

     The net proceeds to us from the issuance of the outstanding notes was approximately $638.6 million, after deducting discounts, commissions and expenses. The net proceeds from the offering of the outstanding notes, together with borrowings under the new credit facility, were used to:

•  fund the tender offer to repurchase our 8 7/8% Senior Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008;

•  fund the redemption of our 8 7/8% Senior Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008 remaining outstanding after the tender offer;

•  repay a substantial portion of the indebtedness of Black Beauty, including related make-whole premiums;

•  acquire the 18.3% interest in Black Beauty that we did not previously own; and

•  pay the fees and expenses related to the Transactions.

     The following table sets forth the sources and uses of the Transactions as of March 31, 2003 (dollars in thousands):

Sources:
	New revolving credit facility(1)		$	—
	New term loan B facility			450,000
	Notes offered hereby			650,000
		Total Sources	$	1,100,000
Uses:
	Repayment of 9 5/8% Senior Subordinated Notes(2)		$	133,964
	Repayment of 8 7/8% Senior Notes(2)			109,082
	Repayment of Black Beauty indebtedness(3)			203,215
	Fees and prepayment premiums paid in connection with refinancing			41,023
	Cash restricted for notes redeemed May 15, 2003(4)			509,592
	Cash(5)			103,124
		Total	$	1,100,000

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(1)	The new revolving credit facility provides for maximum aggregate borrowings of $600.0 million. We replaced approximately $223.8 million of letters of credit under our old credit facility with new letters of credit under the new revolving credit facility.
(2)	Represents the face amount of the notes repurchased in the tender offer completed on March 28, 2003.
(3)	The repayment of Black Beauty’s indebtedness consisted of the following:

•  $112.6 million outstanding under the revolving credit facility, which had an effective average interest rate of 3.0% (as of December 31, 2002) and would have matured in April 2004;

•  $5.0 million outstanding principal amount of 7.40% Senior Unsecured Note Series B due November 2003;

•  $15.7 million outstanding principal amount of 9.24% Senior Unsecured Notes due December 2004;

•  $37.5 million outstanding principal amount of 7.54% Senior Unsecured Notes Series A due November 2007;

•  $2.3 million outstanding under Arclar Company, LLC’s, a majority owned subsidiary of Black Beauty, revolving credit facility, which had an effective average interest rate of 3.76% (as of December 31, 2002) and would have matured in March 2004;

•  $15.2 million outstanding under Arclar’s term loan A facility, which had an effective average interest rate of 3.76% (as of December 31, 2002) and would have matured in March 2004;

•  $14.9 million outstanding under Arclar’s term loan B facility, which had an effective average interest rate of 3.76% (as of December 31, 2002) and would have matured in March 2004;

(4)  As of March 31, 2003, $509.6 million of proceeds were restricted to redeem the remaining 8 7/8% Senior Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008. The restricted proceeds were used on May 15, 2003 as follows:

•  to repay $208.0 million of 8 7/8% Senior Notes and $258.3 million of 9 5/8% Senior Subordinated Notes;

•  to pay accrued interest on the notes redeemed of $21.6 million; and

•  to pay premiums of $21.7 million related to the early repayment of the notes.

(5)  We primarily used these proceeds to acquire the 18.3% interest in Black Beauty that we did not previously own on April 7, 2003 for $90.0 million and to buy out the remaining term of a Black Beauty operating lease for $9.7 million.

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CAPITALIZATION

     The following table presents our capitalization as of March 31, 2003 (1) on an actual basis and (2) on a pro forma as adjusted basis to reflect the redemption on May 15, 2003 of our 8 7/8% Senior Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008 and the acquisition on April 7, 2003 of the 18.3% minority interest in Black Beauty.

     You should read this table in conjunction with our financial statements and the notes to those statements appearing elsewhere in this prospectus, “Use of Proceeds,” “Selected Financial Data” and “Management’s Discussion and Analysis of Financial Conditions and Results of Operations.”

				As of March 31, 2003
										Pro Forma
				Actual			Adjustments			as Adjusted
				(Unaudited; dollars in thousands)
Restricted cash				$	509,592		$	(509,592	)	$	—
Cash and cash equivalents					71,718			—			71,718
New revolving credit facility(1)				$	—		$	—		$	—
New term loan B facility					450,000			—			450,000
6 7/8% Senior Notes due 2013					650,000			—			650,000
8 7/8% Senior Notes due 2008					207,451			(207,451	)		—
9 5/8% Senior Subordinated Notes due 2008					257,553			(257,553	)		—
5% Subordinated Note					76,207			—			76,207
Other long-term debt					18,372			—			18,372
		Total debt			1,659,583			(465,004	)		1,194,579
Minority interests					36,821			(35,398	)		1,423
Stockholders’ equity:
	Common stock				524			—			524
	Additional paid-in capital				958,993			—			958,993
	Retained earnings(2)				184,536			(18,804	)		165,732
	Employee stock loans				(407	)		—			(407	)
	Accumulated other comprehensive loss				(77,623	)		—			(77,623	)
	Treasury stock				(43	)		—			(43	)
		Total stockholders’ equity			1,065,980			(18,804	)		1,047,176
			Total capitalization	$	2,762,384		$	(519,206	)	$	2,243,178

(1)	The new revolving credit facility provides for maximum aggregate borrowings of $600.0 million. We replaced approximately $223.8 million of letters of credit under our old credit facility with new letters of credit under the new revolving credit facility. Letters of credit outstanding at March 31, 2003 under the new credit facility were $231.2 million.
(2)	Reflects the projected net decrease in stockholders’ equity resulting from the payment of redemption premiums of $21.7 million, the write-off of $9.4 million of debt issuance costs and unamortized note discounts related to the early extinguishment of debt and the $12.3 million increase in income tax benefits recognized.

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SELECTED FINANCIAL DATA

     In July 2001, we changed our fiscal year end from March 31 to December 31. The change was first effective with respect to the nine months ended December 31, 2001. We have derived the selected historical financial data for our predecessor for the period from April 1, 1998 to May 19, 1998 and as of May 19, 1998 and the selected historical financial data for our company for the period from May 20, 1998 to March 31, 1999 and as of March 31, 1999, the years ended and as of March 31, 2000 and 2001, the nine months ended and as of December 31, 2001, the year ended and as of December 31, 2002 and the quarter ended and as of March 31, 2003 from our predecessor company’s and our audited and unaudited financial statements.

     In early 1999, we increased our equity interest in Black Beauty from 43.3% to 81.7%. Our results of operations include the consolidated results of Black Beauty, effective January 1, 1999. Prior to that date, we accounted for our investment in Black Beauty under the equity method, under which we reflected our share of Black Beauty’s results of operations as a component of “Other revenues” in the statements of operations, and our interest in Black Beauty’s net assets within “Investments and other assets” in the balance sheets.

     In anticipation of the sale of Citizens Power, which occurred in August 2000, we classified Citizens Power as a discontinued operation as of March 31, 2000, and recorded an estimated loss on the sale of $78.3 million, net of income taxes. We have adjusted our results of operations to reflect the classification of Citizens Power as a discontinued operation for all periods presented.

     Results of operations for the year ended March 31, 2000 included a $144.0 million income tax benefit associated with an increase in the tax basis of a subsidiary’s assets due to a change in federal income tax regulations.

     On January 29, 2001, we sold our Australian operations. The following selected financial and other data includes results of operations from this Australian operation prior to the date of sale and also includes the gain on this sale. Results of operations for the year ended March 31, 2001 included a pretax gain of $171.7 million, or $124.2 million net of income taxes, from the sale of our Australian operations. In August 2002, we re-entered Australia by purchasing a coal mine in Queensland.

     Results of operations for the year ended December 31, 2002 included an income tax benefit of $40.0 million. This benefit resulted primarily from significant tax benefits realized as a result of utilizing net operating loss carryforwards to offset taxable gains recognized in connection with property sale transactions. Utilization of the loss carryforwards required the reduction of a previously recorded valuation allowance that had reduced the book value of the loss carryforwards. Also in 2002, due to a change in accounting principle, we began recording revenues related to all coal trading activities on a net basis in “Other revenues,” and all prior period amounts were reclassified. Had our physically settled trading transactions been recorded on a gross basis, total revenues and operating costs would have been $41.6 million, $88.8 million and $161.9 million higher for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

     Results of operations for the quarter ended March 31, 2003 included early debt extinguishment costs of $21.2 million incurred in connection with the March 2003 refinancing transactions.

     For purposes of the computation of the ratio of earnings to fixed charges, earnings consist of income before income taxes and minority interests plus fixed charges. Fixed charges consist of interest expense on all indebtedness plus the interest component of lease rental expense.

     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.”

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				Predecessor
				Company																					(Unaudited)
																			Nine Months						Quarter
				April 1, 1998			May 20, 1998			(Unaudited)			Year Ended			Year Ended			Ended			Year Ended			Ended
				to May 19,			to March 31,			Total Fiscal			March 31,			March 31,			December 31,			December 31,			March 31,
				1998			1999			1999(1)			2000(2)			2001(3)			2001			2002(4)			2003
				(Dollars in thousands)
Statement of Operations Data:
Revenues:
	Sales			$	278,930		$	1,970,957		$	2,249,887		$	2,610,991		$	2,534,964		$	1,869,321		$	2,630,371		$	657,829
	Other revenues				11,728			85,875			97,603			99,509			93,164			68,619			86,727			23,465
			Total revenues		290,658			2,056,832			2,347,490			2,710,500			2,628,128			1,937,940			2,717,098			681,294
	Costs and expenses
		Operating costs and expenses			244,128			1,643,718			1,887,846			2,178,664			2,123,526			1,588,596			2,225,344			566,620
		Depreciation, depletion and amortization			25,516			179,182			204,698			249,782			240,968			174,587			232,413			56,047
		Asset retirement obligation expense			—			—			—			—			—			—			—			6,490
		Selling and administrative expenses			12,017			76,888			88,905			95,256			99,267			73,553			101,416			25,324
		Gain on sale of Australian operations			—			—			—			—			(171,735	)		—			—			—
		Net gain on property and equipment disposals			(328	)		—			(328	)		(6,439	)		(5,737	)		(14,327	)		(15,763	)		(7,718	)
Operating profit					9,325			157,044			166,369			193,237			341,839			115,531			173,688			34,531
	Interest expense				4,222			176,105			180,327			205,056			197,686			88,686			102,458			26,152
	Early debt extinguishment costs(5)				—			—			—			—			—			—			—			21,184
	Interest income				(1,667	)		(18,527	)		(20,194	)		(4,421	)		(8,741	)		(2,155	)		(7,574	)		(672	)
Income (loss) before income taxes and minority interests					6,770			(534	)		6,236			(7,398	)		152,894			29,000			78,804			(12,133	)
	Income tax provision (benefit)				4,530			3,012			7,542			(141,522	)		42,690			2,465			(40,007	)		(12,246	)
	Minority interests				—			1,887			1,887			15,554			7,524			7,248			13,292			1,050
Income (loss) from continuing operations					2,240			(5,433	)		(3,193	)		118,570			102,680			19,287			105,519			(937	)
	Income (loss) from discontinued operations				(1,764	)		6,442			4,678			(90,360	)		12,925			—			—			—
Income (loss) before extraordinary item					476			1,009			1,485			28,210			115,605			19,287			105,519			(937	)
	Extraordinary loss from early extinguishment of debt				—			—			—			—			(8,545	)		(28,970	)		—			—
Income (loss) before accounting changes					476			1,009			1,485			28,210			107,060			(9,683	)		105,519			(937	)
Cumulative effect of accounting changes					—			—			—			—			—			—			—			(10,144	)
Net income (loss)				$	476		$	1,009		$	1,485		$	28,210		$	107,060		$	(9,683	)	$	105,519		$	(11,081	)
Basic earnings (loss) per share from continuing operations																			$	0.40		$	2.02		$	(0.02	)
Diluted earnings (loss) per share from continuing operations																			$	0.38		$	1.96		$	(0.02	)
Basic and diluted earnings (loss) per Class A/B share from continuing operations(6)							$	(0.16	)				$	3.43		$	2.97
Dividends declared per share																			$	0.20		$	0.40		$	0.10
Adjusted EBITDA(7)				$	34,841		$	336,226		$	371,067		$	443,019		$	582,807		$	290,118		$	406,101		$	97,068
Ratio of Earnings to Fixed Charges (unaudited)(8):					2.02	x		1.00	x		1.03	x		0.97	x		1.63	x		1.23	x		1.50	x		0.68	x
Balance Sheet Data (at end of period):
Total assets				$	6,406,587		$	7,023,931		$	7,023,931		$	5,826,849		$	5,209,487		$	5,150,902		$	5,140,177		$	5,783,864
Total debt					633,562			2,542,379			2,542,379			2,076,166			1,405,621			1,031,067			1,029,211			1,659,583
Total stockholders’ equity/invested capital					1,497,374			495,230			495,230			508,426			631,238			1,035,472			1,081,138			1,065,980

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(1)	For comparative purposes, we derived the “Total Fiscal 1999” column by adding the period from May 20, 1998 to March 31, 1999 with our predecessor company results for the period from April 1, 1998 to May 19, 1998. The effects of purchase accounting have not been reflected in the results of our predecessor company.
(2)	Results of operations for the year ended March 31, 2000 included a $144.0 million income tax benefit associated with an increase in the tax basis of a subsidiary’s assets due to a change in federal income tax regulations.
(3)	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.
(4)	Results of operations for the year ended December 31, 2002 included an income tax benefit of $40.0 million. This benefit results primarily from significant tax benefits realized as a result of utilizing net operating loss carryforwards to offset taxable gains recognized in connection with property sale transactions. Utilization of the loss carryforwards required the reduction of a previously recorded valuation allowance that had reduced the book value of the loss carryforwards.
(5)	Results of operations for the quarter ended March 31, 2003 included early debt extinguishment costs of $21.2 million incurred in connection with the March 2003 refinancing transactions.
(6)	On May 22, 2001, concurrent with our initial public offering, we converted our Class A and Class B common stock into a single class of common stock, all on a one-for-one basis.
(7)	EBITDA, a measure used by management to measure operating performance, is defined as income from continuing operations before deducting net interest expense, income taxes, and depreciation, depletion and amortization. EBITDA is further adjusted to exclude minority interests, asset retirement obligation expense and early debt extinguishment costs to arrive at Adjusted EBITDA. We believe that the supplementary adjustments to EBITDA are appropriate to provide additional information to investors about our ability to meet debt service and capital expenditure requirements.

EBITDA and Adjusted EBITDA are not recognized terms under GAAP and do not purport to be alternatives to operating income, net income or cash flows from operating activities as determined in accordance with GAAP as a measure of profitability or liquidity. Because not all companies use identical calculations, these presentations of EBITDA and Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. Additionally, EBITDA and Adjusted EBITDA are not intended to be measures of free cash flow for management’s discretionary use, as they do not consider certain cash requirements such as interest payments, tax payments and debt service requirements.

EBITDA and Adjusted EBITDA are calculated as follows (unaudited):

	Predecessor
	Company
	April 1,			May 20												Nine Months						Quarter
	1998 to			1998, to						Year Ended			Year Ended			Ended			Year Ended			Ended
	May 19,			March 31,			Total			March 31,			March 31,			December 31,			December 31,			March 31,
	1998			1999			Fiscal 1999			2000			2001			2001			2002			2003
Income (loss) from continuing operations	$	2,240		$	(5,433	)	$	(3,193	)	$	118,570		$	102,680		$	19,287		$	105,519		$	(937	)
Income tax provision (benefit)		4,530			3,012			7,542			(141,522	)		42,690			2,465			(40,007	)		(12,246	)
Interest expense		4,222			176,105			180,327			205,056			197,686			88,686			102,458			26,152
Interest income		(1,667	)		(18,527	)		(20,194	)		(4,421	)		(8,741	)		(2,155	)		(7,574	)		(672	)
Depreciation, depletion and amortization		25,516			179,182			204,698			249,782			240,968			174,587			232,413			56,047
EBITDA		34,841			334,339			369,180			427,465			575,283			282,870			392,809			68,344
Asset retirement obligation expense		—			—			—			—			—			—			—			6,490
Early debt extinguishment costs		—			—			—			—			—			—			—			21,184
Minority interests		—			1,887			1,887			15,554			7,524			7,248			13,292			1,050
Adjusted EBITDA	$	34,841		$	336,226		$	371,067		$	443,019		$	582,807		$	290,118		$	406,101		$	97,068

(8)  For purposes of this computation, earnings consist of income before income taxes and minority interests plus fixed charges. Fixed charges consist of interest expense on all indebtedness plus the interest component of lease rental expense. Earnings were insufficient to cover fixed charges by $0.5 million for the period from May 20, 1998 to March 31, 1999, $7.4 million for the year ended March 31, 2000, and $12.1 million for the quarter ended March 31, 2003, due to the $21.2 million in early debt extinguishment costs discussed above.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

Fiscal Year Change

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

Factors Affecting Comparability

Sale of Peabody Resources Limited Operations

     In December 2000, we signed a share purchase agreement for the sale of the stock in two U.K. holding companies, which, in turn, owned our Peabody Resources Limited subsidiaries in Australia, to a subsidiary of Rio Tinto Limited. These operations consisted of interests in six coal mines, as well as a mining services operation in Brisbane, Australia. The sale price was $455.0 million in cash, plus the assumption of all liabilities. The sale closed on January 29, 2001.

Discontinued Operations

     In August 2000, we sold Citizens Power, our subsidiary that marketed and traded electric power and energy-related commodity risk management products, to Edison Mission Energy. We classified Citizens Power as a discontinued operation as of March 31, 2000, and recorded an estimated loss on the sale of $78.3 million, net of income taxes.

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 ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

Employee-Related Liabilities

     Our subsidiaries have significant long-term liabilities for postretirement benefit costs, workers’ compensation obligations and defined benefit pension plans. Detailed information related to these liabilities is included in the notes to our consolidated financial statements. Liabilities for postretirement benefit costs and workers’ compensation obligations are not funded. Our pension obligations are funded in accordance with the provisions of federal law.

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

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

     If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could differ materially from our current estimates. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. Expense for the year ended December 31, 2002 for these liabilities totaled $134.6 million, while payments were $143.9 million.

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Reclamation

     Our subsidiaries have significant long-term liabilities relating to mine reclamation and end-of-mine closure costs. Liabilities are recorded for the estimated costs to reclaim land as the acreage is disturbed during the ongoing surface mining process. The estimated costs to reclaim support acreage and perform other functions at both surface and underground mines are recorded ratably over the lives of the mines. Reclamation liabilities are not funded.

     The liability is determined on a by-mine basis and we use various assumptions, including estimates of disturbed acreage as determined from engineering data and the costs to reclaim the disturbed acreage. If our assumptions do not materialize as expected, actual cash expenditures and costs that we incur could be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to perform reclamation and mine closing activities. Expense related to reclamation liabilities for the year ended December 31, 2002 was $11.0 million, and payments totaled $21.4 million.

     Our method for accounting for reclamation activities changed on January 1, 2003 as a result of the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations.” The adoption of SFAS No. 143 is discussed in Note 3 to our unaudited financial statements for the quarter ended March 31, 2003.

Trading Activities

     We engage in the buying and selling of coal and emissions allowances in over-the-counter markets. During 2002, accounting requirements related to our trading activities changed due to the rescission of Emerging Issues Task Force (EITF) Issue No. 98-10 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” Contracts we entered into after October 25, 2002 were only accounted for on a fair value basis if they met the SFAS No. 133 definition of a derivative. This accounting change is discussed in Note 1 to our consolidated financial statements for the year ended December 31, 2002 and in Note 3 to our unaudited financial statements for the quarter ended March 31, 2003.

     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 emissions allowance positions. Prices from these sources are then averaged to obtain trading position values. We would experience difficulty in valuing our market positions if the number of third party brokers should decrease or market liquidity is reduced.

     As of March 31, 2003, all of our contracts were valued based on over-the-counter market source prices adjusted for differences in coal quality and content, as well as contract duration.

     As of March 31, 2003, the timing of trading portfolio contract expirations was as follows:

Year of Expiration	Percentage of Portfolio
2003		34	%
2004		63	%
2005		2	%
2006		1	%
		100	%

Quarter Ended March 31, 2003 Compared to Quarter Ended March 31, 2002

     Sales. Sales for the quarter ended March 31, 2003 of $657.8 million were $5.5 million above the prior year quarter, as higher pricing and higher broker sales volume overcame reduced production related to the continued soft economy and customer outages. Heavy snowfall in Appalachia and the Powder River Basin also reduced shipments and disrupted production.

     U.S. mining and broker operations’ sales volume of 46.3 million tons for the current quarter was comparable to the 46.5 million tons for the prior year quarter. Lower volume at our U.S. mining operations was offset by higher brokerage volume. Our average sales price increased 1.2% over the prior year quarter.

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The pricing increase was partially mitigated by sales mix, as higher priced tons in the Appalachia and Midwest regions represented a lower percentage of overall sales in the current year compared to prior year.

     U.S. mining operations sales were $45.6 million below prior year quarter, primarily as a result of lower sales volumes in the Appalachian and Midwest regions. Sales in the Appalachian region were $32.5 million lower than the prior year quarter, primarily due to lower production from geologic difficulties at our Harris mine and lower shipments as a result of heavy snowfall. Midwest sales decreased $8.6 million, primarily due to lower volume as the Highland mine’s production has not yet reached levels comparable with production in the prior year quarter at the predecessor Camp No. 11 mine, which ceased operations during the fourth quarter of 2002.

     Sales in the Southwest region decreased $2.7 million primarily due to an outage at a customer plant in the current year quarter. Sales in the Powder River Basin operations decreased $1.8 million as lower volume from decreased production as a result of heavy snowfall was mostly offset by improved pricing in the region during the current year quarter.

     Sales from broker operations increased $44.8 million over the prior year quarter due to higher U.S. and Australian export sales levels. Our Australian Mining Operations, which were acquired in the third quarter of 2002, had sales of $6.4 million for the current year quarter.

     Asset Retirement Obligation Expense. We recognized asset retirement obligation expense, discussed in Note 3 to the unaudited condensed consolidated financial statements, of $6.5 million during the current year quarter, comprised of the accretion of the asset retirement obligation liability and the amortization of the asset retirement obligation asset recognized in accordance with SFAS No. 143. Expense in the prior year related to reclamation activities was $4.6 million and was included in “operating costs and expenses” in the statement of operations for the quarter ended March 31, 2002.

     Net Gain on Property and Equipment Disposals. Net gain on property and equipment disposals related to our resource management business increased $7.4 million as a result of the sale of oil and gas rights in Appalachia in the quarter ended March 31, 2003.

     Operating Profit. Operating profit decreased $20.4 million to $34.5 million for the quarter ended March 31, 2003. U.S. mining operations’ (excluding operating costs related to past mining activities and net gains on property disposals) operating profit decreased $20.8 million. The decrease was driven by the effects of lower production levels, heavy snowfall and geologic difficulties, discussed in more detail below.

     In the west, the Southwest region’s operating profit decreased $3.7 million, as lower repair costs partially offset lower production due to an outage at a customer plant in the current year quarter. The Powder River Basin region’s operating profit increased $3.4 million as improved prices and quality premiums offset lower sales and production due to heavy snowfall.

     In the east, the Appalachia region’s operating profit decreased $16.5 million due to geologic difficulties and mechanical problems at the Harris Mine, reduced shipments due to heavy snowfall and lower production levels associated with the suspension of operations at the Big Mountain mine for most of the quarter ended March 31, 2003. The Big Mountain mine was reopened late in the quarter. Operating profit in the Midwest region decreased $4.0 million compared to the prior year quarter due to higher fuel costs at our Black Beauty operations and lower volume due to the ramp-up of the Highland No. 9 Mine, which has not reached its full production capacity.

     Operating profit from trading and brokerage operations increased $5.7 million over the prior year quarter, primarily due to higher profit from brokerage activities, combined with favorable pricing movements on the trading portfolio in the current year quarter and the impact of adopting EITF Issue 02-3 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.”

     Operating profit for the current year quarter was also effected by higher net gains on property and equipment disposals of $7.4 million discussed above, asset retirement obligation expense of $6.5 million discussed above and lower selling and administrative expenses of $1.0 million.

33

     Operating costs related to past mining activities were $7.2 million higher in the current quarter, primarily due to $5.6 million of higher, non-cash retiree healthcare costs, driven by lower discount rate and higher trend rate assumptions in the current year quarter.

     Interest Expense. Interest expense increased $1.2 million over the prior year quarter, to $26.2 million. The increase in interest expense was primarily due to higher costs in the quarter ended March 31, 2003 related to surety bonds and letters of credit used to secure our obligations for reclamation, workers’ compensation and lease commitments.

     Early Debt Extinguishment Costs. Pursuant to our debt refinancing transactions discussed in Note 2 to the unaudited condensed consolidated financial statements, we incurred early debt extinguishment costs of $21.2 million during the quarter, comprised of $18.9 million of bond premiums paid to retire debt, $8.1 million of debt issuance costs that were written off in conjunction with early extinguishment of existing debt, partially offset by a gain on the termination of related interest rate swaps of approximately $5.8 million.

     Income Taxes. For the quarter ended March 31, 2003, there was an income tax benefit of $12.2 million on a loss before income taxes and minority interests of $12.1 million, compared to income tax expense of $4.6 million on income before income taxes and minority interests of $30.6 million in the prior year quarter. The tax benefit recorded in the first quarter of 2003 as a percentage of pre-tax income are greater than the tax expense recorded in the same quarter for the prior year primarily as a result of the magnitude of the percentage depletion deduction (which is a permanent difference) relative to pre-tax income. We are currently projecting pretax income but also an income tax benefit for the full year. The income tax benefit for the current year quarter results primarily from the magnitude of the percentage depletion deduction and is calculated on a discrete quarterly basis.

     Minority Interests. For the quarter ended March 31, 2003, minority interests expense decreased $2.6 million to $1.1 million. The reduction was due to the purchase of the remaining 25% of Arclar Coal Company in the third quarter of 2002 and the impact of $7.3 million of early debt extinguishment charges incurred at Black Beauty during the quarter.

     Cumulative Effect of Accounting Changes, Net of Taxes. For the quarter ended March 31, 2003, we recognized 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, as discussed in Note 3 to the unaudited condensed consolidated financial statements.

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

     Sales. Sales for the year ended December 31, 2002 increased $115.8 million, or 4.6%, to $2,630.4 million. U.S. sales increased $121.9 million, a 4.9% increase from the prior year. Pricing increases in all regions drove the sales increase. Our average sales price was 5.6% higher than the prior year. The average price increase was impacted by higher priced contracts signed in 2001 and a $27.7 million increase in sales related to a favorable arbitration ruling that resulted in a retroactive price increase on our Navajo station coal supply agreement. This ruling is discussed in detail in Note 24 to our consolidated financial statements. The pricing increase was partially mitigated by sales mix, as higher priced tons in the Appalachia and Midwest regions represented a lower percentage of overall sales in the current year compared to the prior year.

     U.S. mining and broker operations’ sales volume for the year ended December 31, 2002 was 183.5 million tons, which was 2.2 million tons below the prior year. We had lower sales volume at our Appalachia and Midwest operations, driven by soft market demand as a result of mild weather early in the year, a slower U.S. economy and more aggressive management of coal stockpile levels by customers. Volume decreases at our eastern operations more than offset a 1.4 million ton increase in sales volume at our western operations.

34

     Powder River Basin sales increased $130.3 million, due to improved pricing and slightly higher volume in the current year, driven by continued strong customer demand. Sales in the Southwest region were $33.9 million higher than the prior year, primarily due to the effect of the arbitration ruling relating to our Navajo station coal supply agreement, combined with slightly higher pricing and volume. Appalachia region sales increased $7.7 million, as higher pricing offset lower volume from softer demand, which resulted in suspension of the Big Mountain Mine twice during the year and the Colony Bay Mine during the fourth quarter. Midwest region sales decreased $31.0 million, as higher prices were more than offset by lower volume due to geologic problems at the Camp No. 11 Mine and delays in the startup of two new mines in the region, combined with softer coal demand in the current year. Finally, sales from coal brokerage activities decreased $20.3 million due to a change in sales mix and slightly lower volume.

     Sales from our Australian mining operations decreased $6.1 million compared to the prior year. The current year includes $9.9 million of sales related to the Wilkie Creek mining operations purchased in 2002, while the prior year included $16.0 million of sales from our Peabody Resources Limited operations that were sold in January 2001.

     Other Revenues. Other revenues for the year ended December 31, 2002 decreased $7.9 million from the prior year, to $86.7 million. The current year included a $15.1 million gain from a mediated settlement related to the Mohave generating station coal supply agreement. This settlement is discussed in detail in Note 24 to our consolidated financial statements. Revenues from trading operations increased $9.0 million, primarily due to $10.0 million related to a forward sale that will settle during 2003 and 2004. These improvements were offset by significantly lower coal royalty revenues. Other revenues in the prior year included higher coal royalties of $12.0 million, primarily due to two non-refundable advance royalties, $9.9 million related to the monetization of coal brokerage agreements that had increased in value due to favorable market conditions and $4.5 million of mining services revenues from our Peabody Resources Limited operations.

     Selling and Administrative Expenses. Selling and administrative expenses of $101.4 million for the year ended December 31, 2002 were $4.5 million lower than the prior year, due to the reduction of corporate expenses in response to difficult market conditions in the current year, combined with stock compensation charges recorded in the prior year related in part to our initial public offering.

     Gain on Sale of Peabody Resources Limited Operations. On January 29, 2001, we sold our Peabody Resources Limited operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto Limited. The selling price was $455.0 million, plus the assumption of all liabilities. We recorded a pretax gain of $171.7 million on the sale ($124.2 million after taxes).

     Net Gain on Property and Equipment Disposals. Net gain on property and equipment disposals of $15.8 million was $0.8 million higher than the prior year. The current year included a $10.1 million gain related to the sale of a landfill site that we developed and permitted using idle assets to serve Los Angeles County. The prior year included a $6.4 million gain on the sale of certain idle coal reserves and other reserve and equipment sales.

     Operating Profit. Excluding the effect of the $171.7 million gain on the sale of our Peabody Resources Limited operations, operating profit increased $21.1 million, or 13.8%, to $173.7 million. Operating profit from U.S. operations increased $22.6 million, or 15.3%, to $170.9 million for the year ended December 31, 2002. The increase at the U.S. operations was driven by higher operating profit of $75.8 million from U.S. mining operations (excluding operating costs related to post-mining activities and net gains on property disposals) as a result of higher overall pricing due to contracts signed in 2001, combined with the effects of the Navajo station arbitration ruling and Mohave station mediated settlement, which increased operating profit by $37.1 million.

     In the west, the Powder River Basin region’s operating profit increased $31.5 million as improved prices and higher volume overcame higher royalty and tax expenses associated with improved prices, higher repair and maintenance costs and higher fixed costs associated with running mines at lower than anticipated capacity in the current year. The Southwest region’s operating profit increased $21.6 million as the $37.1 million

35

increase related to the Navajo arbitration ruling and Mohave mediated settlement was partially offset by higher truck, dragline and shovel maintenance and repairs expense. In addition, two outages of the Southwest region’s coal transportation pipeline contributed to higher costs in the current year.

     In the east, both regions’ profits were negatively impacted by running mines at lower than anticipated capacity in the current year and charges in the fourth quarter related to the suspension of two mines in Appalachia due to lower than anticipated demand and the early closure of the Camp No. 11 Mine in the Midwest, due to geologic difficulties. Despite these issues, operating profit in the Midwest region increased $12.1 million compared to the prior year, as lower overall sales levels in the region and geologic difficulties at the Camp No. 11 mine were more than offset by improved pricing and lower fuel and maintenance and repair costs at Black Beauty. The Appalachia region’s operating profit increased $10.6 million due to strong sales price improvement, which overcame higher per ton mining costs due to lower than planned production volume, the mine suspensions previously mentioned and production difficulties at the Harris Mine’s longwall.

     Operating profit from trading and brokerage operations increased $7.3 million over the prior year, primarily due to the $10.0 million related to a forward sale that will settle during 2003 and 2004. Our trading volume increased to 66.9 million tons in 2002 from 53.7 million tons traded in the prior year.

     Operating costs related to post-mining activities were $36.2 million higher in the year ended December 31, 2002, primarily due to $14.1 million of higher excise tax refunds in the prior year and a $17.2 million charge in the current year related to an adverse U.S. Supreme Court decision which assigned us responsibility for the health care premiums of certain beneficiaries previously withdrawn by the Social Security Administration as a result of a prior U.S. Circuit Court of Appeals decision. The remainder of the year-over-year increase related primarily to higher retiree healthcare costs.

     U.S. operations’ operating profit was also affected by lower coal royalty income of $12.8 million and lower results from other commercial activities of $7.3 million.

     The current year also included $2.8 million from our Wilkie Creek operations in Australia, while the prior year included operating profit of $4.3 million from Peabody Resources Limited operations prior to their sale in January 2001.

     Interest Expense. Interest expense for 2002 was $102.5 million, a decrease of $30.5 million, or 22.9%, from the prior year. The decrease in borrowing cost was due to the significant long-term debt repayments made during 2001, and lower short-term interest rates in the current year. Utilizing proceeds from the sale of our Peabody Resources Limited operations in January 2001 and our initial public offering in May 2001, we reduced long-term debt by approximately $835.5 million during 2001. As of December 31, 2002, our debt totaled approximately $1.0 billion.

     Interest Income. Interest income increased $3.7 million, to $7.6 million, for 2002. The current year included $4.6 million in interest income received related to excise tax refunds, while the prior year included interest earned on cash received from the sale of our Peabody Resources Limited operations in January 2001.

     Income Taxes. For 2002, we had an income tax benefit of $40.0 million on income before income taxes and minority interests of $78.8 million, compared to income tax expense of $41.5 million on income before income taxes and minority interests of $195.3 million in the prior year. Overall, our effective tax rate is sensitive to the benefit of the percentage depletion tax deduction relative to our annual profitability, as well as our ability to utilize our existing net operating loss carryforwards of over $500.0 million available for federal income tax purposes. In the prior year, the provision was affected by the sale of our Peabody Resources Limited operations. In 2002, our tax provision reflected significant tax benefits realized as a result of utilizing net operating loss carryforwards to offset taxable gains recognized in connection with the Penn Virginia and landfill sale transactions. Utilization of these net operating loss carryforwards allowed for the reduction of a previously recorded valuation allowance that had reduced the carrying value of our net operating loss carryforward tax benefits.

     Gain from Disposal of Discontinued Operations. During the year ended December 31, 2001, we reduced our loss on the sale of Citizens Power by $1.2 million.

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     Extraordinary Loss from Early Extinguishment of Debt. During the year ended December 31, 2001, we repaid debt using proceeds from the sale of our Australian operations and our initial public offering. We recorded an extraordinary loss of $37.5 million, net of income taxes, which represented the excess of cash paid over the carrying value of the debt retired and the write-off of debt issuance costs associated with the debt retired.

Nine Months Ended December 31, 2001 Compared to Nine Months Ended December 31, 2000 (Not Presented Herein)

     Sales.Sales for the nine months ended December 31, 2001 for our U.S. operations (represents all of our operations, except for our Australian operations sold in January 2001) increased $153.8 million, to $1,869.3 million, a 9.0% increase from the prior year nine-month period. Improved sales volume in all mining operating regions and price improvements in all regions except the Midwest, where pricing remained level with the prior year nine-month period, led to the increase.

     Sales volume for the U.S. operations was 146.5 million tons for the nine months ended December 31, 2001, compared to 133.7 million tons for the prior year nine-month period, an increase of 9.6%. Higher sales volume at our Powder River Basin, Southwest and Midwest operations led to the increase, as our previous capital investments in these regions allowed us to meet increased customer demand.

     Overall U.S. operations’ average sales price was 2.8% higher than the prior year nine-month period due to improved prices in the Appalachia and Powder River Basin markets that were driven by strong customer demand in those regions. The average pricing increase was slightly mitigated by sales mix, as the Appalachia and Midwest regions’ higher priced tons represented a lower percentage of overall sales in the nine months ended December 31, 2001 compared to the prior year nine-month period.

     Total sales for the nine months ended December 31, 2001 decreased $20.4 million, or 1.1%, from the prior nine-month period, as the prior period included $174.2 million in sales from our Peabody Resources Limited operations, from sales volume of 9.8 million tons.

     Powder River Basin sales increased $58.8 million, due to improved pricing and volume from strong customer demand. Sales in the Midwest region increased $35.0 million, led by improved operational performance and higher sales volume at our Black Beauty operations. This improvement was partially offset by lower production at the Camps operating unit related to equipment problems in the nine months ended December 31, 2001, combined with the closure of the Camp No. 1 Mine in October 2000. Appalachian sales increased $33.0 million, as a result of improved demand-driven pricing. Sales in the Southwest region increased $28.1 million, as we expanded production at the Lee Ranch Mine to meet new sales commitments, and had higher demand at both of our Arizona mines.

     Other Revenues.Other revenues for the nine months ended December 31, 2001 for U.S. operations increased $45.2 million over the prior year nine-month period. The increase was primarily driven by higher revenues from trading and brokerage operations, and $9.9 million in proceeds from the profitable monetization of coal brokerage agreements with Enron. In addition, coal royalty income increased $10.9 million, primarily due to two non-refundable advance coal royalties received during the nine months ended December 31, 2001. Other revenues from Peabody Resources Limited operations included in the prior nine-month period were $43.8 million.

     Depreciation, Depletion and Amortization.Depreciation, depletion and amortization expense at U.S. operations increased $17.7 million in the nine months ended December 31, 2001, as compared with the prior year nine-month period. Higher production volume, combined with $3.6 million of additional depletion associated with the new coal royalty agreements discussed above, and $2.0 million of depletion associated with coalbed methane operations acquired early in 2001 led to the increase. Total depreciation, depletion and amortization expense of $174.6 million decreased $5.6 million, as the nine months ended December 31, 2000 included $23.3 million of expense from our Australian operations.

     Selling and Administrative Expenses.Selling and administrative expenses of $73.6 million in the nine months ended December 31, 2001 increased $6.6 million compared to the nine months ended December 31,

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2000. Selling and administrative expenses associated with increased volume, power plant development projects, higher insurance costs, and additional costs associated with being a public company drove the increase.

     Net Gain on Property and Equipment Disposals.Net gain on property and equipment disposals increased $9.3 million, mainly due to gains on the sale of certain idle coal reserves in the nine months ended December 31, 2001.

     Operating Profit.Operating profit from U.S. operations increased $31.5 million, or 37.6%, for the nine months ended December 31, 2001. Overall operating profit decreased $17.5 million, or 13.2%, compared to the prior year nine-month period, which included $49.0 million of operating profit from our Australian operations.

     Operating profit from U.S. mining operations increased $17.0 million for the nine months ended December 31, 2001, driven primarily by increased sales prices, especially in Appalachia and the Powder River Basin. The profit increase was achieved despite increased royalty and tax expense, increased energy-related mining costs, and higher maintenance, repair, and overtime costs. Royalty and tax expense, driven by higher sales prices, increased $20.5 million. Energy-related mining costs, particularly explosives costs, increased $17.4 million. Finally, maintenance and repair costs and overtime costs increased in most regions due to extended periods of producing at peak levels.

     In the west, the Powder River Basin region’s operating profit increased $14.0 million, as higher volume and improved prices overcame higher explosives, fuel and repair and maintenance costs. In the Southwest region, operating profit was flat as higher sales volume was offset by higher explosives and power costs.

     In the east, the Appalachia region’s operating profit increased $12.7 million due to strong sales prices, which overcame higher maintenance and repairs and labor costs driven by certain production difficulties and severe flooding in the current nine-month period. Operating profit in the Midwest region declined $9.3 million, as higher sales volume and improved productivity at our Black Beauty operations were more than offset by higher fuel and explosives costs at Black Beauty and production and equipment problems at the Camps operating unit in the nine months ended December 31, 2001.

     Operating costs related to post-mining activities were $9.8 million higher in the nine months ended December 31, 2001, primarily due to a $10.0 million reduction of our UMWA Combined Fund liability related to the withdrawal of certain beneficiaries by the Social Security Administration in the prior year nine-month period. In the nine months ended December 31, 2001, savings from prescription drug costs as a result of the implementation of a mail order drug program were offset by an $8.0 million reduction in the prior year nine-month period of our liability for environmental cleanup-related costs.

     Operating profit from trading and brokerage operations increased $16.4 million, as increased market volatility, liquidity and improved sourcing flexibility provided product and price arbitrage opportunities. The increase was achieved despite a $6.6 million charge related to the Enron bankruptcy in the nine months ended December 31, 2001.

     Operating profit also improved due to higher gains on the sale of coal reserves and increased coal royalties, discussed above. Increased selling and administrative costs decreased operating profit by $6.6 million.

     Interest Expense.Interest expense for the nine months ended December 31, 2001 was $88.7 million, a $64.8 million decrease, or 42.2%, from the prior year nine-month period. The decrease was due to the significant long-term debt repayments made since December 31, 2000. Utilizing proceeds from the sale of our Australian operations, combined with proceeds from our initial public offering in May 2001, we reduced long-term debt by $835.0 million from December 31, 2000 to December 31, 2001. We also benefited from a decrease in our average borrowing rate on our variable rate debt in the nine months ended December 31, 2001. Additionally, we entered into fixed to floating rate interest rate swaps with notional amounts totaling $150.0 million in October 2001, and realized interest savings of $0.6 million.

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     Interest Income.Interest income decreased $4.8 million, to $2.2 million, for the nine months ended December 31, 2001. The decrease was mainly due to $3.6 million of interest income included in the prior year nine-month period associated with excise tax refunds for the period from January 1, 1994 to March 31, 1998.

     Income Taxes.For the nine months ended December 31, 2001, income tax expense was $2.5 million on income before income taxes and minority interests of $29.0 million, compared to income tax expense of $3.7 million on a loss before income taxes and minority interests of $13.4 million in the prior year nine-month period. Excluding the effect of Australian operating results included in the prior year nine-month period, there was an income tax benefit of $13.8 million on a loss before income taxes and minority interests of $57.4 million.

     Overall, our effective tax rate is sensitive to the benefit of the percentage depletion tax deduction relative to our annual profitability, as well as our ability to utilize our existing net operating loss carryforwards. Income taxes for the nine months ended December 31, 2001 reflected a reduction in our effective income tax rate from 25.0% to 8.5%, primarily resulting from the impact of the allowance for percentage depletion for tax purposes in relation to pre-tax income from continuing operations.

     Gain from Disposal of Discontinued Operations.During the nine months ended December 31, 2000, we reduced our estimated loss on the sale of Citizens Power by $11.8 million, net of income taxes. The reduction reflected a decrease in the estimated operating losses of Citizens Power during the disposal period due to higher income from electricity trading activities driven by increased volatility and prices for electricity in the western U.S. power markets ($8.8 million) and higher estimated proceeds from the monetization of power contracts as part of the wind-down of Citizens Power’s operations ($3.0 million). Citizens Power was classified as a discontinued operation effective March 31, 2000, and the sale was completed during the fiscal year ended March 31, 2001.

     Extraordinary Loss from Early Extinguishment of Debt.During the nine months ended December 31, 2001, we recorded an extraordinary loss of $29.0 million, net of income taxes, which represented the excess of cash paid over the carrying value of the debt retired and the write-off of debt issuance costs associated with the debt retired.

Liquidity and Capital Resources

     Cash provided by operating activities was $57.6 million for the quarter ended March 31, 2003, an increase of $36.2 million from the prior year quarter. The improvement was primarily due to improved working capital cash flows in the current year quarter. The current year quarter included a net working capital usage of $0.3 million, compared to a usage of $69.3 million in the prior year quarter. The working capital change was primarily due to an increase in accounts payable and accrued expenses of $43.1 million in the current year quarter, compared to a $17.9 million decrease in the prior year quarter. The remainder of the year-over-year operating cash flow variance primarily related to lower current year income results, after excluding the effects of accounting changes, early debt extinguishment costs and deferred income taxes.

     Net cash used in investing activities was $53.1 million for the quarter ended March 31, 2003, $4.3 million higher than the prior year quarter. Capital expenditures increased $11.7 million, to $58.8 million, in the current year quarter. Higher than normal quarterly capital expenditures were incurred in the quarter ended March 31, 2003 related to the startup of the Highland No. 9 Mine and the development of a new reserve area at our Federal Mine. Other capital expenditures were primarily for the replacement of mining equipment, the expansion of capacity at certain mines and projects to improve the efficiency of mining operations. Finally, the current year quarter included $7.3 million higher proceeds from property and equipment disposals as a result of the sale of oil and gas rights during the quarter, partially offsetting higher capital spending.

     Net cash used by financing activities was $4.4 million for the quarter ended March 31, 2003, compared with cash provided by financing activities of $4.9 million in the prior year quarter. The current year includes proceeds from long-term debt (net of restricted cash proceeds of $509.6 million) of $591.3 million. These

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proceeds related to the issuance of $1.1 billion of new debt in connection with the refinancing discussed in Note 2 to the unaudited condensed consolidated financial statements. The $591.3 million of net proceeds were used to repay line of credit borrowings of $121.6 million, repay long-term debt of $361.9 million, repurchase interests in accounts receivable previously sold under our accounts receivable securitization program of $83.9 million and pay $22.7 million in debt issuance costs in connection with the new debt issued. Financing cash flows in both quarters reflect dividends paid of $5.2 million. The prior year also includes net borrowings of $12.7 million.

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

	December 31, 2002		March 31, 2003
Term Loan under Senior Secured Credit Facility	$	—	$	450,000
6 7/8% Senior Notes due 2013		—		650,000
9 5/8% Senior Subordinated Notes redeemed May 15, 2003		391,490		257,553
8 7/8% Senior Notes redeemed May 15, 2003		316,498		207,451
5.0% Subordinated Note		85,055		76,207
Senior unsecured notes under various agreements		58,214		—
Unsecured revolving credit agreement		116,584		—
Other		61,370		18,372
	$	1,029,211	$	1,659,583

     In March 2003, we completed a comprehensive debt refinancing to lower our borrowing costs, expand our borrowing capacity, extend our debt maturities and simplify our capital structure. A discussion of transactions entered into related to the refinancing and descriptions of the new debt instruments is included in Note 2 to the unaudited condensed consolidated financial statements for the quarter ended March 31, 2003. Our Senior Secured Credit Facility and 6 7/8% Senior Notes have been rated Ba1 and BB-, respectively, by Moody’s Investors Service, BB+ and BB- by Standard & Poor’s and BB+ and BB by Fitch.

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

     As of March 31, 2003, there were no outstanding borrowings under the new revolving credit facility. We had letters of credit outstanding under the facility of $231.2 million, leaving $368.8 million available for borrowing. We were in compliance with all of the covenants of the new credit facility as of March 31, 2003.

     We had $73.9 million of commitments for capital expenditures at March 31, 2003 that are primarily related to acquiring additional coal reserves and mining equipment. The majority of these commitments relate to spending targeted for 2003. Total capital expenditures for calendar year 2003 are expected to range from $175 million to $200 million, and have been and will be primarily used to develop existing reserves, replace or add equipment and fund cost reduction initiatives. We anticipate funding capital expenditures primarily through operating cash flow. We believe the risk of generating lower than anticipated operating cash flow in 2003 is reduced by our high level of sales commitments (approximately 98% of 2003 planned production is committed) and lower future borrowing costs as a result of our recent debt refinancing.

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     The following is a summary of commercial commitments available to us under our revolving credit facility as of March 31, 2003 (in thousands):

			Expiration Per Year
	Total Amounts		Within
	Committed		1 Year		2-3 Years	4-5 Years		Over 5 Years
Lines of credit	$	600,000		—		$	600,000		—
Standby Letters of credit	$	600,000		—		$	600,000		—

     The following is a summary of our debt obligations, due by calendar year, as of March 31, 2003 (in thousands):

	Within 1 Year		2-3 Years		4-5 Years		After 5 Years
Long-term debt	$	474,197	$	38,055	$	65,270	$	1,082,061

     The $474.2 million of repayments due within one year includes $465.0 million related to the remaining 9 5/8% senior subordinated notes due 2008 and 8 7/8% senior notes due 2008 that were repaid on May 15, 2003 using restricted cash held by us as of March 31, 2003.

     The following is a summary of our significant contractual obligations, except for debt obligations shown above, as of December 31, 2002 (in thousands):

	Payments Due by Year
	Within 1 Year		2-3 Years		4-5 Years		After 5 Years
Capital lease obligations	$	3,879	$	976	$	372	$	16
Operating leases		100,526		165,158		100,863		87,505
Unconditional purchase obligations		56,825		—		—		—
Coal reserve obligations		24,676		51,696		48,617		66,027
Total contractual cash obligations	$	233,421	$	414,332	$	220,415	$	868,179

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

Estimated Expenditures
Within 1 Year	$	201,200
2-3 Years	$	378,300
4-5 Years	$	410,000

Off-Balance Sheet Arrangements

     In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds and our $140.0 million accounts receivable securitization. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

     We use surety bonds to secure our reclamation, workers’ compensation, postretirement benefits and coal lease obligations. As of December 31, 2002, we had outstanding surety bonds with third parties for post-mining reclamation totaling $622.6 million. We had an additional $164.4 million of surety bonds in place for workers’ compensation and retiree healthcare obligations and $69.0 million of surety bonds securing coal leases. Recently, surety bond costs increased, while the market terms of surety bonds have generally become less favorable to us. To the extent that surety bonds become unavailable, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral.

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     We have guaranteed $14.9 million of debt of an affiliate in which we have a 49% equity investment, as described in Note 22 to our consolidated financial statements. We maintained letters of credit as of December 31, 2002 totaling $223.8 million to secure lease, workers’ compensation, postretirement benefits, and other obligations, as discussed in Notes 11, 15, 17 and 22, respectively, to our consolidated financial statements. Our remaining guarantees and indemnifications are discussed in Note 22 to our consolidated financial statements for the year ended December 31, 2002.

     In March 2000, we established an accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been contributed to our wholly-owned, bankruptcy-remote subsidiary are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (the “Conduit”). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We used proceeds from the sale of the accounts receivable to repay long-term debt, effectively reducing our overall borrowing costs. The securitization program is currently scheduled to expire in 2007. Under the provisions of SFAS No. 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” the securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheet. The amount of undivided interests in accounts receivable sold to the Conduit was $52.5 million and $136.4 million as of March 31, 2003 and December 31, 2002, respectively. As discussed in Note 2 to the unaudited condensed consolidated financial statements, utilizing excess proceeds from the refinancing transactions, we significantly reduced outstanding securitized interests in accounts receivable as of March 31, 2003. On April 7, 2003, the securitization returned to near its total capacity of $140.0 million as we used securitization proceeds to fund the acquisition of the remaining 18.3% of Black Beauty. This acquisition is discussed in Note 10 to the unaudited condensed consolidated financial statements for the quarter ended March 31, 2003.

     Apart from the activity discussed above related to our accounts receivable securitization, there were no other material changes to our off-balance sheet arrangements during the quarter ended March 31, 2003.

Accounting Pronouncements Not Yet Implemented

     In December 2002, the Financial Accounting Standards Board (FASB) issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock Based Compensation,” and provides alternative methods for accounting for a change by registrants to the fair value method of accounting for stock-based compensation. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require more prominent and more frequent disclosures in financial statements about the effects of stock-based compensation. The transition guidance and annual disclosure provisions of the statement became effective as of December 31, 2002 and interim disclosure provisions are effective for interim financial reports starting in 2003 and are included in the Note 6 to the unaudited condensed consolidated financial statements for the quarter ended March 31, 2003.

Other

Mohave Generating Station

     See Note 9 to the unaudited condensed consolidated financial statements for the quarter ended March 31, 2003 relating to the potential cessation or suspension of the operations of the Mohave Generating Station on December 31, 2005. The Mohave Generating Station is the sole customer of our Black Mesa Mine, which sold 4.6 million tons of coal in 2002.

Quantitative and Qualitative Disclosures About Market Risk

Trading Activities

     We market and trade coal and emissions allowances. These activities give rise to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits

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prescribed by management. For example, we have policies in place that limit the amount of total exposure we may assume at any point in time.

     We account for coal trading derivatives under SFAS No. 133, which requires us to reflect derivatives, such as forwards, futures, options and swaps at market value in the consolidated financial statements.

     We perform a value at risk analysis on our trading portfolio, which includes over-the-counter and brokerage trading of coal and emissions allowances. The use of value at risk allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. Our value at risk model is based on the industry standard risk-metrics variance/co-variance approach. This captures our exposure related to both option and forward positions. Our value at risk model assumes a 15-day holding period and a 95% one-tailed confidence interval.

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

     During the quarter ended March 31, 2003, the low, high and average values at risk for our coal trading portfolio were $0.7 million, $1.2 million and $1.0 million, respectively. As of March 31, 2003, 34% of the value of our trading portfolio was scheduled to be realized by the end of calendar year 2003, and 97% of the value of our trading portfolio was scheduled to be realized by the end of calendar year 2004.

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

Non-trading Activities

     We manage our commodity price risk for non-trading purposes through the use of long-term coal supply agreements rather than through the use of derivative instruments. As of March 31, 2003, we had sales commitments for 98% of our planned calendar 2003 production.

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

     We have exposure to changes in interest rates due to our existing level of indebtedness. As of March 31, 2003, we had $1,204.8 million of fixed-rate borrowings and $454.8 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $4.5 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 $47.9 million decrease in the fair value of these borrowings. The fixed rate borrowings of $1,204.8 million include $465.0 million of notes that were redeemed on May 15, 2003.

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COAL INDUSTRY OVERVIEW

     We obtained the information provided in this “Coal Industry Overview” regarding future coal production and consumption and future electricity generation from the Energy Information Administration, the International Energy Agency, the National Mining Association, Energy Ventures Analysis, Inc., Resource Data International, Inc. and the National Energy Technology Laboratory. The Energy Information Administration is the independent statistical and analytical agency within the U.S. Department of Energy. The International Energy Agency is an autonomous agency linked with the Organization for Economic Cooperation and Development whose member countries cooperate in the development of rational energy programs. The National Mining Association is a national trade organization that represents the interests of mining before Congress, the Administration, federal agencies, the judiciary and the media. Energy Ventures Analysis, Inc. and Resource Data International, Inc. are private market research firms. The National Energy Technology Laboratory is an agency of the U.S. Department of Energy. For the definitions of certain technical terms used in this prospectus, please refer to “Glossary of Terms.”

     The Energy Information Administration, the primary source of the data, bases its forecasts on assumptions about, among other things, trends in various economic sectors (residential, transportation, industrial, etc.), economic growth rates, technological improvements and demand for other energy sources. The Energy Information Administration’s Annual Energy Outlook 2003 and International Energy Outlook 2002 more fully describe these assumptions. Our other sources do not describe the assumptions upon which they base their projections.

Introduction

     Coal is one of the world’s most abundant, efficient and affordable natural resources, and is used primarily as fuel for the generation of electricity. According to the International Energy Agency, in 2000, coal provided 26% of the world’s primary energy supply and was responsible for approximately 39% of the world’s power generation. Coal’s share of electricity generation in the United States was estimated at 50% in 2002.

     As the table below indicates, coal fueled more electricity in the United States in 2001 than all other fuels combined.

Electricity Fuel Sources

		1990			1995			2001			2002
		(Based on net generation)
Coal			52.5	%		51.0	%		50.9	%		50.2	%
Nuclear			19.0			20.1			20.6			20.3
Hydro			9.6			9.3			5.8			6.9
Natural Gas			12.3			14.8			17.1			17.9
Other			6.6			4.8			5.6			4.7
	Total		100	%		100	%		100	%		100	%

E = Estimated

Source: Energy Information Administration Monthly Energy Review, April 2003.

     The United States is the second largest coal producer in the world, exceeded only by China. Other leading coal producers include Australia, India and South Africa. The United States has the largest coal reserves in the world, with an estimated 250 years of supply based on current usage rates. U.S. coal reserves are more plentiful than U.S. oil or natural gas reserves, with coal representing more than 85% of the nation’s fossil fuel reserves.

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     U.S. coal production has nearly doubled during the past 30 years. In 2002, total U.S. coal production was estimated to be 1.1 billion tons. Approximately 66% of U.S. coal is produced by surface mining methods, while the remaining 34% is produced by underground mining methods.

     The U.S. coal industry operates under a highly developed regulatory regime that governs all mining and mine safety activities, including land reclamation, which requires mined lands to be restored to a condition equal to or better than that existing before mining. Coal mining in the United States has become a relatively safe occupation, relying on sophisticated technology and a skilled work force to become one of the safest, most productive industries in the world.

     In recent years, the coal industry has experienced significant gains in mining productivity, changes in air quality laws, growth in coal consumption and industry consolidation. According to the Energy Information Administration, the number of operating mines declined 52% over the past 10 years, while overall coal production increased approximately 8% over that period. During the same period, average coal mine productivity nearly doubled due to changes in work practices, new technologies and an increase in production in the Powder River Basin coal region, where thick, easily accessible coal seams result in high productivity. The overall productivity gains contributed to stability in coal prices during the 1990s. Recent increases in the price of natural gas and other energy commodities, however, have resulted in the price of coal increasing in most regions where we operate. A notable industry trend has been the shift to low sulfur coal production, particularly in the Powder River Basin, driven by the significant regulatory restrictions on sulfur dioxide emissions from coal-fueled electric generating plants.

Coal Markets

     The Energy Information Administration estimates that approximately 1.1 billion tons of coal were consumed in the United States in 2002 and expects domestic consumption of coal by electric generators to grow at a rate of 1.4% per year from 2001 through 2025, predicated on natural gas price assumptions of $2.88 per million Btu in 2005 and $3.30 in 2010. Demand from domestic electric generators accounts for more than 90% of domestic coal consumption. The Energy Information Administration projects annual coal use growth by electric generators of nearly 400 million tons by 2025.

U.S. Coal Consumption by Sector

		Historical				Projected
		2001		2002		2005		2010		2015		2020		2025
		(Tons in millions)
Electric generators			957		982		1,012		1,123		1,187		1,263		1,350
Industrial/ Residential/ Commercial			67		68		69		71		72		74		76
Coke plants/steel mills			26		22		25		24		22		20		18
	Total domestic		1,050		1,072		1,106		1,218		1,281		1,357		1,444
Export			49		40		39		35		29		29		26
	Total		1,099		1,112		1,145		1,253		1,310		1,386		1,470

Source:  Energy Information Administration, U.S. Coal Supply and Demand: 2002 Review and Energy Information Administration, Annual Energy Outlook 2003

     Coal-fueled generation is used in most cases to meet baseload requirements, so coal use generally grows at the pace of electricity growth. Gas-fired electric generation, which is used primarily for intermediate and peak-load demand, is anticipated to gain market share at the expense of nuclear generation or where peak-load capacity is needed.

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Electricity Generation By Fuel Source

Source:  Energy Information Administration Annual Energy Review 2001, 1970-1999.

Annual Energy Outlook 2003 Reference Case Tables, 2000-2025.

Sources of Coal Demand Growth

     In the aggregate, coal-fueled plants currently utilize approximately 70% of their capacity, although the optimal sustainable capacity utilization is estimated at 85% for a typical plant, and most plants can run at higher rates for short periods. An increase from 70% capacity utilization to 85% capacity utilization would translate into approximately 200 million tons of additional annual coal consumption.

     In addition to expected greater utilization of existing plants, a number of new coal-fueled generating plants have been announced in recent years to meet America’s needs for inexpensive baseload generating capacity.

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Announced Coal Generating Plants

Number of proposed new coal-fueled generating plants and gigawatts of capacity.

Source: U.S. Department of Energy, National Energy Technology Laboratory, December 2002.

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Regional Coal Markets

     Over the past several years, largely as a result of sulfur dioxide emissions limitations mandated by the Clean Air Act, demand has shifted toward lower sulfur coal. In 1995, Phase I of the Clean Air Act required high sulfur coal plants to reduce their emissions of sulfur dioxide to 2.5 pounds or less of sulfur dioxide per million Btu. As a result of a significant switch to very low sulfur Powder River Basin coal, many Phase I-affected plants overcomplied with the sulfur dioxide requirements, creating a surplus of emission allowances that could be traded within a market for sulfur dioxide emissions credits. In 2000, Phase II of the Clean Air Act tightened restrictions on sulfur dioxide emissions from 2.5 pounds or less to 1.2 pounds or less of sulfur dioxide per million Btu. Surplus emission credits from Phase I allow some generators to delay retrofitting old plants with scrubbers. Eventually, owners of these plants will have to retrofit or switch to Phase II compliance coal, including Powder River Basin or other low sulfur coal. The following table indicates that the ongoing shift to Powder River Basin coal is expected to continue.

U.S. Coal Production by Supply Region

	Historical		Projected
	2001		2005		2010		2015		2020		2025
	(Tons in millions)
Powder River Basin		408		410		509		563		632		686
Central/ Southern Appalachia		290		272		286		286		280		282
Northern Appalachia		143		131		124		120		128		137
Illinois Basin		95		103		102		104		107		118
Other Western United States		103		99		104		117		118		124
Lignite		91		101		96		88		86		84
Other		9		9		9		8		8		9
		1,139		1,125		1,230		1,286		1,359		1,440

Source: Energy Information Administration, Annual Energy Outlook 2003.

Coal Characteristics

     There are four types of coal: lignite, subbituminous, bituminous and anthracite. Each has characteristics that make it more or less suitable for different end uses. In general, coal of all geological composition is characterized by end use as either “steam coal” or “metallurgical coal,” sometimes known as “met coal.” Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coking coal, which is used in the production of steel. Heat value and sulfur content, the most important coal characteristics, determine the best end use of particular types of coal.

Heat Value

     The heat value of coal is commonly measured in Btu per pound of coal. Coal found in the eastern and midwestern regions of the United States tends to have a heat content ranging from 10,000 to 15,000 Btu per pound. Most coal found in the western United States ranges from 8,000 to 10,000 Btu per pound. The weight of moisture in coal, as sold, is included in references to Btu per pound of coal in this prospectus, unless otherwise indicated.

     Lignite is a brownish-black coal with a heat content that generally ranges from 4,500 to 8,500 Btu per pound. Major lignite operations are located in Louisiana, Montana, North Dakota and Texas. Lignite is used almost exclusively in power plants located adjacent to or near these mines because any transportation costs, coupled with mining costs, would render its use uneconomical. We do not have any lignite reserves.

     Subbituminous coal is a black coal with a heat content that ranges from 8,000 to 12,000 Btu per pound. Most subbituminous reserves are located in Alaska, Colorado, Montana, New Mexico, Washington and

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Wyoming. Subbituminous coal is used almost exclusively by electric generators and some industrial consumers. We have extensive subbituminous reserves in the Powder River Basin of Wyoming.

     Bituminous coal is a “soft” black coal with a heat content that ranges from 9,500 to 15,000 Btu per pound. This coal is located primarily in Appalachia, Arizona, the Midwest, Colorado and Utah, and is the type most commonly used for electric generation in the United States. Bituminous coal is also used for industrial steam purposes and is used in steel production. All of our reserves in Arizona, Colorado, Illinois, Indiana, Kentucky and West Virginia are categorized as bituminous coal.

     Anthracite is a “hard” coal with a heat content that can be as high as 15,000 Btu per pound. A limited amount of anthracite deposits is located primarily in the Appalachian region of Pennsylvania. Anthracite is used primarily for industrial and home heating purposes. We do not have any anthracite reserves.

Sulfur Content

     Sulfur content can vary from seam to seam and sometimes within each seam. Coal combustion produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Low sulfur coal has a variety of definitions, but we use it in this prospectus to refer to coal with a sulfur content of 1.0% or less by weight. Compliance coal refers to coal with a sulfur content of less than 1.2 pounds per million Btu. The strict emissions standards of the Clean Air Act have increased demand for low sulfur coal. We expect continued high demand for low sulfur coal as electric generators meet the current Phase II requirements of the Clean Air Act (1.2 pounds or less of sulfur dioxide per million Btu). U.S. sulfur dioxide emissions from electricity generation have decreased 30% from 1990 to 2000 levels, while coal consumed by U.S. electric generators has increased 26% during the same period.

     Subbituminous coal typically has a lower sulfur content than bituminous coal, but some bituminous coal in Colorado, eastern Kentucky, southern West Virginia and Utah also has a low sulfur content.

     Plants equipped with sulfur-reduction technology, known as “scrubbers,” which reduce sulfur dioxide emissions by 50% to 95%, can use higher sulfur coal. Plants without scrubbers can use medium and high sulfur coal by purchasing emission allowances on the open market or blending that coal with low sulfur coal. Each allowance permits the user to emit a ton of sulfur dioxide. Some older coal-fueled plants have been retrofitted with scrubbers. Any new coal-fueled generation built in the United States will likely use clean coal technologies to remove the majority of sulfur dioxide, nitrogen oxide and particulate matter emissions.

Other

     Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion.

     Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby making it more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal’s weight.

     When some types of coal are super-heated in the absence of oxygen, they form a hard, dry, caking form of coal called coke. Steel production uses coke as a fuel and reducing agent to smelt iron ore in a blast furnace.

Coal Mining Techniques

     Coal mining operations commonly use four distinct techniques to extract coal from the ground. The most appropriate technique is determined by coal seam characteristics such as location and recoverable reserve base. Drill hole data are used initially to define the size, depth and quality of the coal reserve area before committing to a specific extraction technique. All coal mining techniques rely heavily on technology;

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consequently, technological improvements have resulted in increased productivity. The four most common mining techniques are continuous mining, longwall mining, truck-and-shovel mining and dragline mining.

     It is generally easier to mine coal seams that are thick and located close to the surface than thin underground seams. Typically, coal mining operations will begin at the part of the coal seam that is easiest and most economical to mine. In the coal industry, this characteristic is referred to as “low ratio.” As the seam is mined, it becomes more difficult and expensive to mine because the seam either becomes thinner or protrudes more deeply into the earth, requiring removal of more material over the seam, known as the “overburden.” For example, many seams of coal in the Midwest are five to 10 feet thick and located hundreds of feet below the surface. In contrast, seams in the Powder River Basin of Wyoming may be 80 feet thick and located only 50 feet below the surface.

     Once the raw coal is mined, it is often crushed, sized and washed in preparation plants where the product consistency and heat content are improved. This process involves crushing the coal to the required size, removing impurities and, where necessary, blending it with other coal to match customer specifications.

Continuous Mining

     Continuous mining is an underground mining method in which main airways and transportation entries are developed and remote-controlled continuous miners extract coal from “rooms,” leaving “pillars” to support the roof. Shuttle cars transport coal from the face to a conveyor belt for transport to the surface. This method is often used to mine smaller coal blocks or thin seams, and seam recovery is typically approximately 50%. Productivity for continuous mining averages 25 to 50 tons per miner shift.

Longwall Mining

     Longwall mining is an underground mining method that uses hydraulic jacks or shields, varying from five feet to 12 feet in height, to support the roof of the mine while a mobile-cutting sheerer advances through the coal. Chain belts then move the coal to a standard deep mine conveyer system for delivery to the surface. Continuous mining is used to develop access to long rectangular panels of coal, which are then mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive, but it is effective only for large blocks of medium to thick coal seams. High capital costs associated with longwall mining demand a large, contiguous reserve base. Seam recovery using longwall mining is typically 70%, and productivity averages 40 to 80 tons per miner shift.

Truck-and-Shovel Mining

     Truck-and-shovel mining is an open-cast method that uses large electric-powered shovels to remove overburden, which is used to backfill pits after coal removal. Shovels load coal in haul trucks for transportation to the preparation plant or rail loadout. Seam recovery using the truck-and-shovel method is typically 90%. Productivity depends on equipment, geological composition and the ratio of overburden to coal. Productivity varies between 250 to 400 tons per miner shift in the Powder River Basin to 30 to 80 tons per miner shift in eastern U.S. regions.

Dragline Mining

     Dragline mining is an open-cast method that uses large capacity electric-powered draglines to remove overburden to expose the coal seams. Shovels load coal in haul trucks for transportation to the preparation plant and then to the rail loadout. Truck capacity can range from 80 to 400 tons per load. Seam recovery using the dragline method is typically 90% or more, and productivity levels are similar to those for truck-and-shovel mining.

Technology

     Coal mining technology is continually evolving and improving, among other things, underground mining systems and larger earth-moving equipment for surface mines. For example, longwall mining technology has

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increased the average recovery of coal from large blocks of underground coal from 50% to 70%. At larger surface mines, haul trucks have capacities of 240 to 400 tons, which is nearly double the maximum capacity of the largest haul trucks used a decade ago. This increase in capacity, along with larger shovels and draglines, has increased overall mine productivity. According to National Mining Association data, overall coal mine productivity, measured in tons produced per miner shift, increased 85% from 1990 to 2001.

Coal Regions

     Coal is mined from coalfields throughout the United States, with the major production centers located in the Powder River Basin, Central Appalachia, Northern Appalachia, the Illinois Basin and in other western coalfields. We operate mines in all of these major coal-producing regions.

Powder River Basin

     The Powder River Basin contains some of the most economical coal reserves in the world. The Powder River Basin covers more than 12,000 square miles in northeastern Wyoming and 7,000 square miles in southeastern Montana. Demonstrated coal reserves total approximately 188 billion tons. Within the Powder River Basin, there are various qualities of subbituminous coal, with current production of subbituminous coal ranging from 8,300 Btu per pound to 9,200 Btu per pound and from 0.8% sulfur to 0.2% sulfur. The mines located just north and south of Gillette, Wyoming are categorized as Southern Powder River Basin mines. The coal in the Southern Powder River Basin is ranked as subbituminous with an extremely low sulfur content.

     Production in the Southern Powder River Basin has increased from approximately seven million tons in 1970 to approximately 360 million tons in 2002, and coal production in the Powder River Basin now accounts for approximately 30% of U.S. coal consumption by volume. The Southern Powder River Basin has grown into the largest coal supply region in the United States. From 1990 to 2000, the region’s compounded annual production growth rate was 7.0% compared to an overall compounded annual production growth rate of 0.5% for the total U.S. coal industry. The Southern Powder River Basin markets more than 95% of its coal to U.S. electricity generators, principally in this region between the Rocky Mountains and the Appalachian Mountains. We have four active mining operations in the Powder River Basin: one in Montana and three in northeastern Wyoming.

Central/ Southern Appalachia

     Central/ Southern Appalachia contains coalfields in eastern Kentucky, southwestern Virginia and central and southern West Virginia. Production in Central/ Southern Appalachia has decreased from approximately 305 million tons in 1996 to approximately 290 million tons in 2001. Production declined in all major sections of Central/ Southern Appalachia except for southern West Virginia, which has grown due to the expansion of more economically attractive surface mines. The region has experienced significant consolidation in the past several years due to modest demand growth and strong competition from western coal. Central/ Southern Appalachian operators market approximately 67% of their coal to electric generators, principally in the southeastern United States. Central/ Southern Appalachia also sells extensively to the export market and industrial customers. The coal of Central/ Southern Appalachia has an average heat content of 12,500 Btu per pound and is generally low sulfur. We operate five coal operations in southern West Virginia producing low sulfur steam and metallurgical coal.

Northern Appalachia

     High and medium sulfur coal is found in the Northern Appalachian coalfields of western Pennsylvania, southeastern Ohio and northern West Virginia. Demand for coal from this region has in recent years been and is expected to remain relatively stable. Production in the region was approximately 143 million tons in 2001. Much of the production in this region is concentrated in a few highly productive longwall mining operations in southeastern Pennsylvania and northern West Virginia. Despite its sulfur content of 1.5% to 2.0%, which is considered medium sulfur coal, coal from the Pittsburgh seam produced from these mines is considered

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attractive to electricity generators because of its high heat content of approximately 13,000 Btu per pound. We operate one mine in this region.

Illinois Basin

     The Illinois Basin consists of approximately 48,000 square miles throughout Illinois, southern Indiana and western Kentucky. There has been significant consolidation among coal producers in the Illinois Basin over the past several years. Production in the Illinois Basin peaked at 141 million tons in 1990. Since 1990 and until recently, production had decreased by over 33% due to displacement by lower sulfur, lower-cost coal. However, recently, production in the Illinois Basin has stabilized. Illinois Basin coal is sold primarily to local customers. Demonstrated reserves total an estimated 135 billion tons of bituminous coal. Approximately 16 coal seams have been identified in this region. Current production quality ranges from 9,000 to 12,700 Btu per pound and 0.8% to 4.5% sulfur, with production averaging approximately 11,400 Btu per pound and 2.5% sulfur. We have extensive reserves and five active mining operations in the Illinois Basin coal region, all located in western Kentucky. In addition, we own Black Beauty, Indiana’s largest coal producer. Black Beauty has 12 active mines in this region.

Western Bituminous Coal Regions

     The western bituminous coal regions include the Uinta Basin of northwestern Colorado and Utah, the Four Corners Region in New Mexico and Arizona and the Raton Basin in southern Colorado. These regions produce high-quality, low sulfur steam coal for selected markets in these regions, for export through West Coast ports and for shipment to some midwestern customers. Production in these regions has decreased from 104 million tons in 1996 to 103 million tons in 2001. We have extensive reserves and four operating mines in these regions.

Lignite Production Regions

     Lignite is mined in Louisiana, Montana, North Dakota and Texas. We do not have any lignite reserves.

Coal Prices

     Coal prices vary dramatically by region and are determined by a number of factors. The two principal components of the delivered price of coal are the price of coal at the mine, which is influenced by mine operating costs and coal quality, and the cost of transporting coal from the mine to the point of use. Electric generators purchase coal on the basis of its delivered cost per million Btu.

Price at the Mine

     The price of coal at the mine is influenced by geological characteristics such as seam thickness, overburden ratios and depth of underground reserves. Powder River Basin coal is relatively inexpensive to mine, at $4 to $6 per ton, based on our estimates, because the seams are thick and are typically located close to the surface, enabling mining companies to use open-pit mining methods. The large capital costs associated with truck-and-shovel and dragline mining (a dragline can cost up to $50 million and a truck-and-shovel spread can cost up to $20 million) are amortized over millions of tons of coal produced. Powder River Basin mines are highly productive and require less labor than underground mines, thus reducing the labor component of mining costs. By contrast, eastern U.S. coal is more expensive to mine (at $15 to $30 per ton, based on our estimates) than western coal, because of thinner coal seams and thicker overburden. Underground mining, prevalent in the eastern United States, has higher labor costs than surface mining, including costs for labor benefits and health care, and high capital costs, including modern mining equipment and construction of extensive ventilation systems.

     In addition to the cost of mine operations, the price of coal at the mine is also a function of quality characteristics such as heat value and sulfur, ash and moisture content. Metallurgical coal has higher carbon and lower ash content and is usually priced $4 to $10 per ton higher than steam coal produced in the same regions. Higher prices are paid for special coking coal with low volatility characteristics.

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     As indicated in the table below, the price of steam coal at the mine in the major regions in which we compete ranged from $4.85 to $26.75 per ton in 2002, depending upon the quality and source region of the coal. The following table summarizes historical steam coal prices at the mine by supply region.

Historical Steam Coal Prices

			Pounds
	Btu		SO2per		Historical
	Per		Million
Region/Basin	Pound		Btu		1997		1998		1999		2000		2001		2002
	(Dollars per ton, free on board at mine)
Southern Powder River Basin		8,800		0.5	$	4.25	$	4.55	$	4.55	$	4.75	$	9.50	$	6.05
Southern Powder River Basin		8,500		0.8		3.40		3.50		3.65		3.60		7.60		4.85
Central Appalachia		12,500		1.5		24.00		24.75		23.75		23.25		41.25		26.25
Northern Appalachia		13,300		3.5		24.00		23.00		20.75		22.00		37.25		26.75
Western Kentucky		11,200		5.0		21.00		21.75		20.50		20.00		29.25		23.25
Indiana		11,000		5.0		16.75		17.25		16.75		16.25		24.50		18.75

Source: Energy Ventures Analysis, Inc., February 2003.

Transportation Costs

     Coal used for domestic consumption is generally sold free on board at the mine, as described above, and the purchaser normally bears the transportation costs. Export coal, however, is usually sold at the loading port, and coal producers are responsible for shipment to the export coal-loading facility and the buyer pays the ocean freight.

     Most electric generators arrange long-term shipping contracts with rail or barge companies to assure stable delivered costs. Transportation can be a large component of the buyer’s cost. Although the customer pays the freight, transportation cost is still important to coal mining companies because the customer may choose a supplier largely based on the cost of transportation. According to the National Mining Association, railroads account for nearly two-thirds of total U.S. coal shipments. Trucks and overland conveyors haul coal over shorter distances, while lake carriers and ocean vessels move coal to export markets. Some domestic coal is shipped over the Great Lakes. Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two competing rail carriers, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. Rail competition in this major coal-producing region is important because rail costs constitute up to 75% of the delivered cost of Powder River Basin coal in remote markets.

Cost of Electricity Generation

Cost Comparison of Fuel Types

     Coal price at the mine and transportation costs together constitute coal’s delivered price to customers. Coal attained its leading market share because of its relative low cost and its availability throughout the United States. The cost of fuel is the largest variable cost involved in electricity generation. As indicated in the chart below, the delivered cost of coal to electric generators is relatively stable as compared to the cost of natural gas and oil.

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Delivered Cost of Fossil Fuel at Electric Generating Plants

Source:  Resource Data International Fossil-Fuel Receipts at Steam-Electric Utility Plants Through January 2003; Energy Information Administration and Peabody estimates with respect to February 2003 - May 2003 data.

Generating Costs

     In addition to fuel, electric generators incur other variable and fixed costs in electricity production. On average, the total cost per megawatt-hour of coal-fueled electricity generation is less expensive than for electricity generated from natural gas or nuclear power. According to Resource Data International Inc., 20 of the 25 major electric generation plants with the lowest operating costs in the United States in 2001 were coal-fueled. Hydroelectric power is inexpensive but is limited geographically, and there are few suitable sites for new hydroelectric dams. Moreover, because coal-fueled electric generating plants, on average, are operating below maximum capacity, these plants can increase their electricity generation without substantial incremental capital costs, thus improving coal’s overall cost competitiveness. The following table illustrates the average cost of coal-fueled generation relative to other electric generating sources.

Average U.S. Generating Costs⁽¹⁾

	1990		1995		1999		2000		2001
	(Dollars per megawatt-hour)
Coal	$	20.02	$	18.74	$	17.45	$	17.39	$	18.15
Nuclear		22.34		19.91		17.95		17.54		17.32
Hydro		3.08		3.69		4.16		4.67		6.97
Natural Gas		28.37		26.00		31.13		47.62		52.09

Source: Resource Data International Power Dat, FERC Form 1 Data.

(1)  Average annual generating costs per megawatt-hour produced for all U.S. electric generating plants; costs include fuel and operation and maintenance, but exclude depreciation.

Deregulation of the Electricity Generation Industry

     Congress enacted the Energy Policy Act of 1992 to stimulate competition in electricity markets by giving wholesale suppliers access to the transmission lines of U.S. electricity generators. In April 1996, the Federal Energy Regulatory Commission issued the first of a series of orders establishing rules providing for open access to electricity transmission systems. The federal government is currently exploring a number of options

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concerning utility deregulation. Some individual states are also proceeding with their own deregulation initiatives.

     The pace of deregulation differs significantly from state to state. As of December 2002, 17 states and the District of Columbia had either enacted legislation leading to the deregulation of the electricity market or issued a regulatory order to implement retail access that would allow customers to choose their own supplier of generation. Five states have delayed restructuring and 27 are not actively pursuing deregulation. In California, where supply and demand imbalances created electricity supply shortages, the California Public Utilities Commission suspended deregulation.

     A possible consequence of deregulation is downward pressure on fuel prices. However, because of coal’s cost advantage and because some coal-fueled generating facilities are underutilized in the current regulated electricity market, we believe that additional coal demand would arise as electricity markets are deregulated if the most efficient coal-fueled power plants are operated at greater capacity.

Recent Coal Market Conditions

Customer Stockpiles

     In 2002, customer inventories (stockpiles) rose due to the soft economy and mild winter weather. Inventories decreased in the second half of 2002 given higher cooling degree days in the summer and heating degree days in the fall. We estimate that stockpiles have been reduced to near normal levels by the end of April 2003.

Electric Generator Coal Stockpiles

Source:  EIA Electric Power Sector Coal Stocks, January 2000-November 2002; Peabody estimates with respect to December 2002 - April 2003 data.

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Forward Pricing

     Through May 28, 2003, traded prices for coal to be delivered in the next calendar year showed increases over those in 2002.

Appalachian Coal Traded Prices

12,000 Btu, <1% Sulfur Steam Coal (Free on Board Barge)

Source:  Third-party OTC price quotes for rateable delivery in subsequent calendar year (this is a thinly traded market for small quantities of a particular quality of coal and may not be representative of the prices that we can receive on our coal supply agreements).

Powder River Coal Traded Prices

8,800 Btu, 0.8 lb. Sulfur Dioxide

Source:  Third-party OTC price quotes for rateable delivery in subsequent calendar year (this is a thinly traded market for small quantities of a particular quality of coal and may not be representative of the prices that we can receive on our coal supply agreements).

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BUSINESS

Overview

     We are the largest private sector coal company in the world. Our sales of 197.9 million tons of coal in 2002 accounted for 17.9% of all U.S. coal sales and were more than 70% greater than the sales of our closest U.S. competitor. During the period, we sold coal to more than 280 electric generating and industrial plants, fueling the generation of more than 9% of all electricity in the United States and 2% of all electricity in the world. At December 31, 2002, we had 9.1 billion tons of proven and probable coal reserves, approximately double the reserves of any other U.S. coal producer. During 2002, our total revenues, net income and net cash provided by operating activities were $2.7 billion, $105.5 million and $231.2 million, respectively.

     As of December 31, 2002 we owned majority interests in 33 active coal operations located throughout all major U.S. coal producing regions, with 73% of our U.S. 2002 coal sales shipped from the western United States and the remaining 27% from the eastern United States. Most of our production in the western United States is low sulfur coal from the Powder River Basin, the largest and fastest-growing major U.S. coal-producing region. Our overall western U.S. coal production has increased from 37.0 million tons in fiscal year 1990 to 128.0 million tons during 2002, representing a compounded annual growth rate of 11%. In the West, we own and operate mines in Arizona, Colorado, Montana, New Mexico and Wyoming. In the East, we own and operate mines in Illinois, Indiana, Kentucky and West Virginia. We produced 78% of our 2002 sales volume from non-union mines.

     During 2002, 94% of our sales were to U.S. electricity generators. The U.S. coal industry continues to fuel more electricity generation than all other energy sources combined. In 2002, coal-fueled plants generated an estimated 50.2% of the nation’s electricity, followed by nuclear (20.3%), gas-fired (17.9%) and hydroelectric (6.9%) units. We believe that competition for cost-efficient energy will strengthen the demand for coal. We also believe that U.S. and world coal consumption will continue to increase as coal-fueled generating plants utilize their existing excess capacity and as new coal-fueled plants are constructed. Coal is an attractive fuel for electricity generation because it is:

•  Abundant: Coal makes up more than 85% of fossil fuel reserves in the United States. The nation has an estimated 250-year supply of coal, based on current usage rates.

•  Low-Cost: At an average delivered price of $1.23 per million British thermal units, or Btu, in 2001, and $1.22 in 2002, coal’s cost advantage over natural gas is significant. The delivered price of natural gas averaged $4.49 per million Btu in 2001 and $3.65 in 2002, while market prices have recently exceeded $10.00. In 2001, 20 of the 25 lowest cost major generating plants in the United States were coal-fueled.

•  Increasingly Clean: Aggregate emissions from U.S. coal-fueled plants have declined significantly since 1970, even as coal consumption by electricity generators has more than tripled.

     Approximately 97% of our coal sales during 2002 were under long-term contracts. As of December 31, 2002, our sales backlog, including backlog subject to price reopener and/or extension provisions, approximated one billion tons. The remaining terms of our long-term contracts range from one to 18 years and have an average volume weighted remaining term of approximately 4.4 years. As of March 31, 2003, we had entered into commitments to sell 175 million tons, or approximately 98%, of our expected 2003 coal production and 134 million tons, or approximately 69%, of our expected 2004 coal production.

     In addition to mining operations, our other energy-related businesses include marketing, brokering and trading coal and emissions allowances, coalbed methane production, transportation-related services, third-party coal contract restructuring and the development of coal-fueled generating plants.

Competitive Strengths

     We are the world’s largest private-sector producer and marketer of coal and the largest reserve holder of any U.S. coal company.In 2002, our U.S. coal sales volume market share was 17.9%, more than 70% greater than our closest U.S. competitor. Our reserve base of 9.1 billion tons of proven and probable coal reserves is the largest of any U.S. coal producer, and we believe that we have significant expansion

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opportunities in areas adjacent to our existing reserves. Based on current production rates, we believe our reserves could last for approximately 50 years.

     We are the largest producer and marketer of low sulfur coal in the United States, with the number one position in the Powder River Basin, the fastest growing U.S. coal producing region.The demand for low-sulfur coal has grown dramatically since the adoption of the Clean Air Act Amendments, which led to reduced sulfur dioxide emissions from coal-fueled power plants. We have gained a leading position in the market for low sulfur coal, the fastest growing segment of the coal market. In 2002, we were the largest seller of low sulfur coal in the United States; our 153.0 million tons of low sulfur coal sales represented 77% of our total sales volume for that period. As of December 31, 2002, 4.0 billion tons of our proven and probable coal reserves were low in sulfur, which are substantially greater than the low sulfur reserves of any of our competitors. More than half of our total sales volume comes from the Powder River Basin, America’s largest known source of low-cost, low sulfur coal.

     We have a large portfolio of long-term coal supply agreements that are complemented by available production in attractive markets for sale at market prices.We have a large portfolio of coal supply agreements that provides us with reliable revenues. During 2002, approximately 97% of our coal sales were sold under long-term contracts, defined as contracts of one year or more. As of December 31, 2002, our sales backlog totaled approximately one billion tons, including backlog subject to price reopener and/ or extension provisions. The average volume weighted remaining term of our long-term contracts is approximately 4.4 years. We also have a significant amount of uncommitted production that will be available for sale beginning in 2004, which could enable us to benefit from favorable future market prices for coal. As of March 31, 2003, we had approximately three million tons and 61 million tons of expected production unpriced for 2003 and 2004, respectively. We have the ability to increase 2003 production by an additional four to five million tons each quarter by running our current operations at their full capacity.

     We are one of the most productive and lowest-cost producers of coal in the United States.Through a shift to lower-cost operations, economies of scale, investments in advanced production technologies and centralized purchasing, information technology systems, marketing programs and land management functions, we achieve operating and corporate efficiencies. From 1990 to 2002, we increased our sales volume from 93.0 million tons to 197.9 million tons, while reducing the number of employees in our operations from approximately 10,200 to approximately 6,500. During this same period, we also increased our average productivity, in terms of coal production per miner shift, by 185%, while our safety accident rate declined from 16.1 to 5.4 incidents per 200,000 work hours.

     We serve a broad range of high quality customers with mining operations located throughout all major U.S. coal producing regions.As of December 31, 2002, we owned majority interests in 33 active coal operations in the United States, selling coal to more than 280 electric generating and industrial plants. We supply coal to customers in 14 countries, and we have strong, long-term relationships with many of our customers. We have historically experienced minimal bad debt expense, and we continue to mitigate exposure to higher risk customers through letters of credit, cash collateral, prepayments and customer payment trust accounts. Because of the geographical mix of our reserves and production, we can source coal from multiple regions, giving us greater flexibility to meet the needs of our customers and reduce their transportation costs. Our geographical diversity and extensive market knowledge also enable us to provide customized products, services and solutions to our customer network.

     Our emphasis on innovative research and development has increased our productivity.Since we are one of the largest users of equipment in the industry, manufacturers work with us to design and produce equipment that will bring added value to the coal industry. Our efforts have led to technological innovations, including state-of-the-art haul trucks, the adaptation of global positioning satellite technology and nuclear quality analysis equipment, and higher horsepower, continuous mining machines and a continuous haulage machine. As a result of these efforts, many of our mines are among the most productive in the industry.

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     We are a leader in reclamation management and have received numerous state and national awards for our commitment to environmental excellence.We have a long-standing commitment to protecting the environment. We consistently restore mined lands to a condition as good as, or better than, their condition prior to mining. As a result of our efforts, we have received 30 state and national reclamation awards over the past five years. In 2002, we received six major awards for reclamation excellence, including the prestigious U.S. Department of the Interior’s Director’s Award, which was presented to the Kayenta Mine for preserving cultural, historic and archaeological resources. This is the third consecutive year that we have been awarded the Director’s Award for outstanding achievement in a specific area of reclamation.

     Our management team has a proven record of success.Our management team has a proven record of increasing productivity and reducing costs, making strategic acquisitions, developing and maintaining strong customer relationships, meeting financial commitments and deleveraging our company through repayment of approximately $1.5 billion of debt over the past five years. Our senior executives have an average of 19 years of experience in the coal industry and 16 years of experience with our company.

Transformation of Peabody

     Since 1990, we have grown significantly and our management has transformed our company from a largely high sulfur, high-cost coal company to a predominantly low sulfur, low-cost coal producer, marketer and trader. We have increased our sales of low sulfur coal from 57% of our total volume in 1990 to 77% in 2002. We are also well positioned to continue selling higher sulfur coal to customers that invest in emissions control technology, buy emissions allowances or blend higher sulfur coal with low sulfur coal. Our average cost per ton sold decreased 42% from 1990 to 2002. The following chart demonstrates our transformation:

							Percent
	1990			2002			Improvement
Sales volume (million tons)		93.0			197.9			113	%
U.S. market share(1)		9.1	%		17.9	%		97
Low sulfur sales volume (million tons)		52.7			153.0			190
Total coal reserves (billion tons)(2)		7.0			9.1			30
Low sulfur reserves (billion tons)(2)(3)		2.5			4.0			60
Safety (incidents per 200,000 hours)		16.1			5.4			66
Productivity (tons per miner shift)		33.5			95.6			185
Average cost per ton sold(4)	$	19.25		$	11.25			42
Employees (approximate)		10,200			6,500			36

(1)	Market share is calculated by dividing our U.S. sales volume by estimated total U.S. coal demand, as reported by the Energy Information Administration.
(2)	As of January 1, 1990 and as of December 31, 2002.
(3)	Represents our estimated proven and probable coal reserves with a sulfur content of 1% or less by weight.
(4)	Represents operating costs and expenses.

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Business Strategies

     Our transformation discussed above has resulted in part from the successful implementation of our three core business strategies:

     Managing safe, low-cost operations. Our first priority is the safety of our employees, and our safety record, as measured by frequency of incidents, has improved 66% since 1990. Productivity at our operations has nearly tripled since 1990, while operating costs have been reduced by 42%. To improve costs, we:

•  rely on a skilled employee base;

•  continually streamline processes;

•  invest in state-of-the-art technologies;

•  apply new production techniques; and

•  use our consolidated purchasing power, which gives us economies of scale.

     Adding value through world-class sales, brokerage and trading techniques. With sales to more than 280 electric generating and industrial plants in 14 countries, we utilize our extensive and geographically diverse coal operations, as well as access third-party-produced coal, to meet our customers’ energy needs. Our sales backlog of nearly one billion tons offers our customers a reliable supply source. We strategically balance our long-term contract position with uncommitted production based on our view of the market, which is derived from our industry-leading market presence and our analytical capabilities. Our coal brokerage and trading operations access third-party-produced coal through forward purchase and option agreements and provide structured multi-party transactions to the energy industry. Our goal is to optimize production and contract profitability while minimizing risk through our sound credit and risk management practices.

     Aggressively managing our vast natural resource position. With 9.1 billion tons of coal reserves and 300,000 acres of surface lands, we aggressively manage our resource position to add value. We grow our coal production base through development of our existing asset base and acquisitions. Over the past five years, we have acquired a number of coal operations at attractive prices and intend to continue to upgrade and sell non-strategic assets. Over the same period, we have made total acquisitions of approximately $400 million, while selling approximately $1.0 billion in assets, allowing us to meet our growth objectives, while continuing to strengthen our balance sheet. In addition, we are pursuing the development of mine-mouth generating projects using our land and coal resources to help meet America’s growing needs for inexpensive electricity generation.

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Mining Operations

     The following map outlines our U.S. operations, along with 2002 market share, sales volume and proven and probable reserves organized by the four major coal regions of the United States.

Reserves & 2002 sales volume in millions of tons.

Source: Peabody analysis & industry reports.

     The following provides a description of the operating characteristics of the principal mines and reserves of each of our operating units and affiliates in the United States.

Powder River Basin Operations

     We control approximately 2.9 billion tons of coal reserves in the Powder River Basin, the largest and fastest growing major U.S. coal-producing region. Our subsidiaries, Powder River Coal Company and Caballo Coal Company, own and manage three low sulfur, non-union surface mining complexes in Wyoming that sold approximately 104.8 million tons of coal during the year ended December 31, 2002, or approximately 53% of our total coal sales volume. The North Antelope Rochelle and Caballo mines are serviced by both major western railroads, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway.

     Our Wyoming Powder River Basin reserves are classified as surface mineable, subbituminous coal with seam thickness varying from 70 to 105 feet. The sulfur content of the coal in current production ranges from 0.2% to 0.4% and the heat value ranges from 8,300 to 8,900 Btu per pound.

     Our subsidiary, Big Sky Coal Company, operates the Big Sky Mine in Montana in the Northern Powder River Basin. Coal is shipped from this mine to customers in the upper Midwest by the Burlington Northern & Santa Fe railroad.

North Antelope Rochelle

     The North Antelope Rochelle Mine is located 65 miles south of Gillette, Wyoming. This mine is the largest in the United States, selling 75.4 million tons during 2002. The North Antelope Rochelle facility is

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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 a dragline along with six truck-and-shovel fleets. We added a second dragline at this mine in 2002 to improve productivity.

Caballo

     The Caballo Mine is located 20 miles south of Gillette, Wyoming. During 2002, it sold approximately 26.0 million tons of compliance coal (defined as having sulfur dioxide content of 1.2 pounds or less per million Btu). Caballo is a truck-and-shovel operation with a coal handling system that includes two 12,000-ton silos and two 11,000-ton silos.

Rawhide

     The Rawhide Mine is located ten miles north of Gillette, Wyoming and uses truck-and-shovel mining methods. Operations were suspended at the Rawhide mine in 1999, but the mine reopened in January 2002 as a result of improved demand for Powder River Basin coal. During 2002, it sold approximately 3.4 million tons of compliance coal.

Big Sky

     The Big Sky Mine is located in the Northern Powder River Basin near Colstrip, Montana, and uses dragline mining equipment. The mine sold 2.8 million tons of medium sulfur coal during 2002. Coal is shipped by rail to several major electricity generating customers in the upper midwestern United States. This mine is near the exhaustion of its economically recoverable reserves, and we may close it in the next several years, depending upon market and mining conditions. Hourly workers at the Big Sky Mine are members of the United Mine Workers of America.

Southwest Operations

     We own and manage three mines in the western bituminous coal region — two in Arizona and one in Colorado. The Colorado mine, which is owned and managed by Seneca Coal Company, and the Arizona mines, which are owned and managed by Peabody Western Coal Company, supply primarily compliance coal for long-term coal supply agreements to electricity generating stations in the region. In New Mexico, we own and manage, through our Peabody Natural Resources subsidiary, the Lee Ranch Mine, which mines and produces subbituminous medium sulfur coal. Together, these mines sold 21.0 million tons of coal during 2002.

Black Mesa

     The Black Mesa Mine, which is located on the Navajo Nation and Hopi Tribe reservations in Arizona, uses two draglines and sold 4.6 million tons of coal during 2002. The Black Mesa Mine coal is crushed, mixed with water and then transported 273 miles through the underground Black Mesa Pipeline (which is owned by a third party) to the Mohave Generating Station near Laughlin, Nevada, which is operated and partially owned by Southern California Edison. The mine and pipeline were designed to deliver coal exclusively to the plant, which has no other source of coal. The Mohave Generating Station coal supply agreement extends until December 31, 2005. Hourly workers at this mine are members of the United Mine Workers of America.

Kayenta

     The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines in three mining areas. It sold approximately 8.3 million tons of coal during 2002. The Kayenta Mine coal is crushed, then carried 17 miles by conveyor belt to storage silos where it is loaded on to a private rail line and transported 83 miles to the Navajo Generating Station, operated by the Salt River Project near Page, Arizona. The mine and railroad were designed to deliver coal exclusively to the power plant, which has no other source of coal. The Navajo coal supply agreement extends until 2011. Hourly workers at this mine are members of the United Mine Workers of America.

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Seneca

     The Seneca Mine near Hayden, Colorado shipped 1.8 million tons of compliance coal during 2002, operating with two draglines in two separate mining areas. The mine’s coal is hauled by truck to the nearby Hayden Generating Station, operated by the Public Service of Colorado, under a coal supply agreement that extends until 2011. Hourly workers at this mine are members of the United Mine Workers of America.

Lee Ranch Mine

     The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 6.3 million tons of medium sulfur coal during 2002. Lee Ranch shipped the majority of its coal to two customers in Arizona and New Mexico under coal supply agreements extending until 2010 and 2014, respectively. Lee Ranch is a non-union surface mine that uses a combination of dragline and truck-and-shovel mining techniques.

Appalachia Operations

     We own and manage six wholly-owned operating units and related facilities in West Virginia. Our subsidiary, Pine Ridge Coal Company, owns and manages the Big Mountain Operating Unit, and our subsidiary, Eastern Associated Coal Corp., owns and manages the remaining wholly-owned facilities, except the River’s Edge mine, which is owned by Peabody Holding Company, Inc. During 2002, these operations sold approximately 16.7 million tons of compliance, medium sulfur and high sulfur steam and metallurgical coal to customers in the United States and abroad. Hourly workers at these operations are members of the United Mine Workers of America. In addition to our wholly-owned facilities, we own a 49% interest in another underground mine in West Virginia.

Big Mountain Operating Unit

     The Big Mountain Operating Unit is based near Prenter, West Virginia. This operating unit’s primary mine is Big Mountain No. 16, and includes a small amount of contract mine production from coal reserves we control. During 2002, the Big Mountain Operating Unit sold approximately 1.2 million tons of steam coal. Big Mountain No. 16 is an underground mine using continuous mining equipment. Processed coal is loaded on the CSX railroad. During the fourth quarter of 2002, we suspended operations of the unit in response to market conditions. The mine was reopened in February 2003.

Harris Operating Unit

     The Harris Operating Unit consists of the Harris No. 1 Mine near Bald Knob, West Virginia, which sold approximately 3.2 million tons of primarily metallurgical product during 2002. This mine uses both longwall and continuous mining equipment.

Rocklick Operating Unit and Contract Mines

     The Rocklick preparation plant, located near Wharton, West Virginia, processes coal produced by the Harris No. 1 Mine, the Colony Bay Mine and contract mining operations from coal reserves that we control. This preparation plant shipped approximately 2.6 million tons of steam and metallurgical coal sourced from the contract mines during 2002. Processed coal is loaded at the plant site on the CSX railroad or transferred via conveyor to our Kopperston loadout facility and loaded on the Norfolk Southern railroad.

Wells Operating Unit

     The Wells Operating Unit, in Boone County, West Virginia, sold approximately 3.9 million tons of metallurgical and steam coal during 2002. The unit consists of the River’s Edge Mine, contract mine production and the Wells preparation plant, located near Wharton, West Virginia. Processed coal is loaded on the CSX railroad. The River’s Edge mine replaced the Lightfoot No. 2 Mine, which depleted its economically recoverable reserves in the fourth quarter of 2002.

Federal No. 2 Mine

     The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining equipment and shipped approximately 5.0 million tons of steam coal during 2002. Coal shipped from the Federal No. 2 Mine has a sulfur content only slightly above that of medium sulfur coal and has an above average heating content. As a

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result, it is more marketable than some other medium sulfur coals. The CSX and Norfolk Southern railroads jointly serve the mine.

Colony Bay Mine

     The Colony Bay Mine is located in Boone County, West Virginia. The mine, which reopened in January 2002, utilized one spread of surface mining equipment and one highwall miner. Coal produced from the mine is transported to the Rocklick preparation plant prior to shipment to customers. The mine produced 0.8 million tons in 2002, but production was suspended during the fourth quarter of 2002 in response to market conditions.

Kanawha Eagle Coal Joint Venture

     We have a 49% interest in Kanawha Eagle Coal, LLC, which owns and manages an underground mine, preparation plant and barge-and-rail loading facilities near Marmet, West Virginia. The mine is non-union and uses continuous mining equipment. It shipped 1.5 million tons during 2002.

Midwest Operations

     We operated seven wholly-owned mines in the midwestern United States during 2002, which collectively sold 7.3 million tons of coal. These operations include five underground and two surface mines, along with three preparation plants and three barge loading facilities, located in western Kentucky, southern Illinois and southwestern Indiana. We ship coal from these mines primarily to electricity generators in the midwestern United States and to industrial customers that generate their own power. Our Camp and Midwest operating units are owned and managed by our Peabody Coal Company subsidiary.

Camp Operating Unit

     The Camp Operating Unit, located near Morganfield, Kentucky, operated the Camp No. 11 Mine, an underground mine, and a large preparation plant and barge loading facility. The Camp No. 11 Mine sold 2.4 million tons of coal during 2002 before exhausting its economically recoverable reserves in December 2002. The Camp No. 11 Mine used both longwall and continuous mining equipment. We sold most of the Camp No. 11 production under contract to the Tennessee Valley Authority. This mine’s production will be replaced with production from the Highland Operating Unit. Hourly workers at these operations were members of the United Mine Workers of America.

Highland Operating Unit

     The Highland Operating Unit, which is owned and managed by our Highland Mining Company subsidiary, is located near Waverly, Kentucky, and consists of two underground mines. The Highland No. 11 Mine produced 0.6 million tons from the No. 11 coal seam during 2002. The Highland No. 9 Mine is ramping up production following initial production from the mine in March 2003. Hourly workers at these operations are members of the United Mine Workers of America.

Midwest Operating Unit

     The Midwest Operating Unit near Graham, Kentucky sold 1.4 million tons of coal during 2002. In 2002, the unit included the Gibraltar surface mining operation, which uses truck-and-shovel equipment, and the Gibraltar Highwall Mine, which used continuous mining equipment. We sold coal from these mines under contract to the Tennessee Valley Authority. The Gibraltar Highwall Mine was closed in the summer of 2002 as the mine reached the end of its economically recoverable reserves. Hourly workers at these operations are members of the United Mine Workers of America.

Patriot Coal Company

     Our subsidiary, Patriot Coal Company, owns and manages Patriot, a surface mine, and Freedom, an underground mine, in Henderson County, Kentucky, and sold approximately 2.6 million tons of coal during 2002. The Big Run underground mine in Ohio County, Kentucky began operations in the fourth quarter of 2002 and sold approximately 0.3 million tons. The underground mines use continuous mining equipment, and

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the surface mine uses truck-and-shovel equipment. Patriot Coal Company also operates a preparation plant and a dock. The Patriot Coal Company mines utilize non-union labor.

Black Beauty Coal Company

     Our subsidiary, Black Beauty, is the largest coal producer in the Illinois Basin and currently manages eight active mines in Indiana and four active mines in Illinois. Black Beauty’s operations produced and sold 24.1 million tons of compliance, medium sulfur and high sulfur steam coal during 2002. We purchased a one-third interest in Black Beauty in 1994, and increased our interest to 43.3% in 1998, 81.7% in 1999 and 100% in 2003.

     Black Beauty’s principal Indiana mines include Air Quality No. 1, Farmersburg, Francisco and three mines near Somerville, Indiana. Air Quality No. 1 is an underground coal mine located near Monroe City, Indiana that shipped 1.8 million tons of compliance coal during 2002. Farmersburg is a surface mine situated in Vigo and Sullivan counties in Indiana that sold 4.1 million tons of medium sulfur coal during 2002. Francisco, a surface mine located in Gibson county, Indiana, sold 2.4 million tons during 2002, and the three Somerville surface mines, also located in Gibson county, shipped a total of 7.0 million tons in fiscal year 2002.

     During 2002, Black Beauty began production at a new underground mining facility, the Vermilion Grove Mine, in east-central Illinois. Together with the existing Riola No. 1 Mine, these operations sold 1.8 millions tons during 2002. Black Beauty’s remaining mines sold 2.7 million tons during 2002. All of Black Beauty’s wholly-owned operations utilize non-union labor.

     Black Beauty owns a 75% equity interest in Arclar Company, LLC, which operates the Cottage Grove surface mine and Willow Lake underground mining complex situated in Gallatin and Saline counties in southern Illinois. During 2002, these facilities sold 4.3 million tons of coal, primarily shipped by barge to downriver utility plants. Black Beauty provides a contract workforce for the Arclar surface operations; the workforce at the underground operations is represented under non-UMWA labor agreements. The Willow Lake Mine began operations during the first half of 2002. Willow Lake replaced Arclar’s existing operations at Eagle Valley and Big Ridge. Once it reaches full capacity, Willow Lake is expected to produce about 3.5 million tons per year. In September 2002, we purchased the 25% interest in Arclar Company, LLC not owned by Black Beauty for $14.9 million.

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

Australian Mining Operations

Wilkie Creek Mine

     On August 22, 2002, we purchased the 1.4 million ton per year Wilkie Creek Coal Mine and coal reserves in Queensland, Australia. From the acquisition date to December 31, 2002, the mine sold 0.4 million tons. Evaluations are complete with respect to 147 million tons of proven and probable reserves acquired surrounding the Wilkie Creek Mine. We continue to evaluate other coal resources that were obtained in this acquisition to finalize the estimate of our total proven and probable reserves in Australia.

Strategic Partnerships and Other Businesses

Penn Virginia Resource Partners, L.P.

     On December 19, 2002, we formed an alliance with Penn Virginia Resource Partners, L.P. (PVR) whereby we contributed 120 million tons of coal reserves in exchange for $72.5 million in cash and 2.76 million units, or 15%, of the publicly traded PVR master limited partnership. Our subsidiaries subsequently leased the coal and will pay royalties as the coal is mined.

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Power Plant Development

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

     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 over-comply with all current clean air standards using advanced emissions control technologies.

     In 2002, we received the final air quality permit from the Commonwealth of Kentucky for the development of the 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky. Certain environmental groups are challenging the air permit. In 2002, we also signed a transmission agreement and received a water withdrawal permit for the 1,500 megawatt Prairie State Energy Campus in Washington County, Illinois.

Resource Development

     We hold approximately 9.1 billion tons of proven and probable coal reserves. Our Resource Development group constantly reviews this reserve base for opportunities to generate revenues through the sale of non-strategic coal reserves and surface land. In addition, we generate revenue through royalties from coal reserves leased to third parties and farm income from surface land under third party contracts.

Coalbed Methane

     Our subsidiary, Peabody Natural Gas, LLC, produces coalbed methane from its operations located in the Southern Powder River Basin near our Caballo Mine. We purchased these coalbed methane assets in January 2001 for approximately $10 million. We will continue to evaluate further development of this business through acquisitions and development of our own reserves.

Properties

Coal Reserves

     We had an estimated 9.1 billion tons of proven and probable coal reserves as of December 31, 2002. An estimated 8.9 billion tons of our proven and probable coal reserves are in the United States, and 38% is compliance coal and 62% is non-compliance coal. We own approximately 46% of these reserves and lease property containing the remaining 54%. Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emission allowance credits or blending higher sulfur coal with lower sulfur coal.

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

			Proven and Probable
			Reserves as of December 31,
			2002(1)
			Owned		Leased		Total
Operating Regions	Locations		Tons		Tons		Tons
			(Tons in millions)
Powder River Basin		Wyoming and Montana		190		2,732		2,922
Southwest		Arizona, Colorado and New Mexico		603		641		1,244
Appalachia		West Virginia		210		480		690
Midwest		Illinois, Indiana and Kentucky		3,131		946		4,077
Australia		Queensland		—		147		147
Total Proven and Probable Coal Reserves				4,134		4,946		9,080

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

     Proven and probable coal reserves are classified as follows:

     Proven Reserves — Reserve estimates in this category have the highest degree of geologic assurance. Proven coal lies within one-quarter mile of a valid point of measurement or point of observation (such as exploratory drill holes or previously mined areas) supporting such measurements. The sites for thickness measurement are so closely spaced, and the geologic character is so well defined, that the average thickness, area extent, size, shape and depth of coalbeds are well established.

     Probable Reserves — Reserve estimates in this category have a moderate degree of geologic assurance. There are no sample and measurement sites in areas of indicated coal. However, a single measurement can be used to classify coal lying beyond measured as probable. Probable coal lies more than one-quarter mile, but less than three quarters of a mile from a point of thickness measurement. Further exploration is necessary to place probable coal into the proven category.

     In areas where geologic conditions indicate potential inconsistencies related to coal reserves, we perform additional drilling to ensure the continuity and mineability of the coal reserves. Consequently, sampling in those areas involves drill holes that are spaced closer together than those distances cited above.

     We prepare our reserve estimates based on geological data assembled and analyzed by our staff, which includes various geologists and engineers. We periodically update our reserve estimates to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time to reflect mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors. We maintain reserve information, including the quantity and quality (where available) of reserves as well as production rates, surface ownership, lease payments and other information relating to our coal reserve and land holdings, through a computerized land management system that we developed.

     Our reserve estimates are predicated on information obtained from our extensive drilling program, which totals nearly 500,000 individual drill holes. We compile data from individual drill holes in a computerized drill-hole system from which the depth, thickness and, where core drilling is used, the quality of the coal are determined. The density of the drill pattern determines whether the reserves will be classified as proven or probable. The drill hole data are then input into our computerized land management system, which overlays the geological data with data on ownership or control of the mineral and surface interests to determine the extent of our reserves in a given area. In addition, we periodically engage independent mining and geological consultants to review estimates of our coal reserves. The most recent of these reviews, which was completed in March 2001, included a review of the procedures used by us to prepare our internal estimates, verification of the accuracy of selected property reserve estimates and retabulation of reserve groups according to standard classifications of reliability. This study confirmed that we controlled approximately 9.5 billion tons of proven and probable reserves as of April 1, 2000. After adjusting for acquisitions and production through December 31, 2002, proven and probable reserves totaled 9.1 billion tons.

     We have numerous federal coal leases that are administered by the U.S. Department of the Interior under the Federal Coal Leasing Amendments Act of 1976. These leases cover our principal reserves in Wyoming and other reserves in Montana and Colorado. Each of these leases continues indefinitely, provided there is diligent development of the property and continued operation of the related mine or mines. The Bureau of Land Management has asserted the right to adjust the terms and conditions of these leases, including rent and royalties, after the first 20 years of their term and at 10-year intervals thereafter. Annual rents under our federal coal leases are now set at $3.00 per acre. Production royalties on federal leases are set by statute at 12.5% of the gross proceeds of coal mined and sold for surface-mined coal and 8% for underground-mined coal. The federal government limits by statute the amount of federal land that may be leased by any company and its affiliates at any time to 75,000 acres in any one state and 150,000 acres nationwide. As of December 31, 2002, we leased or had applied to lease 23,384 acres of federal land in Colorado, 11,252 acres in Montana and 34,766 acres in Wyoming, for a total of 69,402 nationwide.

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

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

Long-Term Coal Supply Agreements

     We currently have a sales backlog of nearly one billion tons of coal, including backlog subject to price reopener and/or extension provisions, and our coal supply agreements have remaining terms ranging from one to 18 years and an average volume-weighted remaining term of approximately 4.4 years. For 2002, we sold 97% of our sales volume under coal supply agreements. In 2002, we sold coal to more than 280 electricity generating and industrial plants in 14 countries. Our primary customer base is in the United States. Two of our coal supply agreements are the subject of ongoing litigation and arbitration.

     We expect to continue selling a significant portion of our coal under long-term supply agreements. Our strategy is to selectively renew, or enter into new, long-term supply contracts when we can do so at prices we believe are favorable. As of March 31, 2003, we had approximately three million tons and 61 million tons of expected production available for sale at market-based prices in 2003 and 2004, respectively.

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

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

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

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

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

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

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

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

Sales and Marketing

     Our sales, trading and marketing operations include Peabody COALSALES and Peabody COALTRADE. Through these entities, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and agent, trade coal and emission allowances, and provide transportation-related services. We also restructure coal supply agreements by acquiring rights to receive coal under a coal supply agreement, reselling that coal, and supplying coal from other sources. As of December 31, 2002, we had 60 employees in our sales, marketing, trading and transportation operations, including personnel dedicated to performing market research, contract administration and risk/credit management activities.

Transportation

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

     The majority of our sales volume is shipped by rail, but a portion of our production is shipped by other modes of transportation. For example, coal from our Highland operating unit in Kentucky is shipped by barge to the Tennessee Valley Authority’s Cumberland plant in Tennessee. Coal from our Black Mesa Mine in Arizona is transported by a 273-mile coal-water pipeline to the Mohave Generating Station in southern Nevada. Coal from the Seneca Mine in Colorado is transported by truck to a nearby electricity generating plant. Other mines transport coal by rail and barge or by rail and lake carrier on the Great Lakes. All coal

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from our Southern Powder River Basin mines in Wyoming is shipped by rail, and two competing railroads, the Burlington Northern Santa Fe Railway and the Union Pacific Railroad, serve our North Antelope Rochelle and Caballo mines. The Rawhide Mine is serviced by the Burlington Northern Santa Fe Railway. Approximately 8,000 unit trains are loaded each year to accommodate the coal shipped by these mines. A unit train generally consists of 100 to 140 cars, each of which can hold 100 to 120 tons of coal.

     Our transportation department manages the loading of trains and barges. We believe we enjoy good relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation coordinators.

Suppliers

     The main types of goods we purchase are mining equipment and replacement parts, explosives, fuel, tires and lubricants. We have many long, established relationships with our key suppliers, and do not believe that we are dependent on any of our individual suppliers except as noted below. The supplier base providing mining materials has been relatively consistent in recent years, although there has been some consolidation. Recent consolidation of suppliers of explosives has limited the number of sources for these materials; however, we are not dependent on any one supplier for explosives. Further, purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop.

Technical Innovation

     We place great emphasis on the application of technical innovation to improve new and existing equipment performance. This research and development effort is typically undertaken and funded by equipment manufacturers using our input and expertise. Our engineering, maintenance and purchasing personnel work together with manufacturers to design and produce equipment that we believe will add value to the business. We have worked with manufacturers to design larger trucks to haul overburden and coal at various mines throughout the company. In Wyoming, we were the first coal company to use the current, state-of-the-art 400-ton haul trucks. Additionally, we worked with manufacturers to develop higher horsepower, underground continuous mining machines and a continuous haulage machine, which mine the coal more effectively, at a lower cost per ton.

     We are a leader in retrofitting existing equipment to increase performance and extend the lives of assets. For example, a dragline from the Midwest was relocated to Wyoming and was upgraded with new motors and digital controllers to increase productivity. We also deploy extensive lubrication analysis technology, finite element analysis and remote monitoring to ensure full productive life of our equipment. As a result of these efforts, many of our mines have become among the most productive in the industry.

     We use sophisticated software to schedule and monitor trains, mine/pit blending, quality and customer shipments. The integrated software has been developed in-house and provides a competitive tool to differentiate our reliability and product consistency. We are the largest user of advanced coal quality analyzers among coal producers, according to the manufacturer of this sophisticated equipment. These analyzers allow continuous analysis of certain coal quality parameters, such as sulfur content. Their use helps ensure consistent product quality and helps customers meet stringent air emission requirements. We also support the Power Systems Development Facility, a highly efficient electricity generating plant using advanced emissions reduction technology funded primarily through the U.S. Department of Energy and operated by an affiliate of Southern Company.

Competition

     The markets in which we sell our coal are highly competitive. According to the Energy Information Administration’s “Annual Coal Report 2001,” the top 10 coal producers in the United States produced approximately 62% of total domestic coal in 2001. Our principal competitors are other large coal producers, including Arch Coal, Inc., Kennecott Energy Co., a subsidiary of Rio Tinto, RAG Coal International AG, CONSOL Energy Inc., Horizon Natural Resources, Inc. and Massey Energy Company, which collectively accounted for approximately 40% of total U.S. coal production in 2001.

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

Certain Liabilities

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

  Reclamation

     Reclamation liabilities primarily represent the future costs to restore surface lands to productivity levels equal to or greater than pre-mining conditions, as required by the Surface Mining Control and Reclamation Act. Our reclamation costs and mine-closing liabilities totaled approximately $386.8 million as of December 31, 2002. Expense for the fiscal year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002 was $4.1 million, $9.6 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 SFAS (Statement of Financial Accounting Standards) No. 143, “Accounting for Asset Retirement Obligations” and is discussed in detail in Note 3 to our unaudited financial statements for the quarter ended March 31, 2003.

  Workers’ Compensation

     These liabilities represent the actuarial estimates for compensable, work-related injuries (traumatic claims) and occupational disease, primarily black lung disease (pneumoconiosis). The Federal Black Lung Benefits Act requires employers to pay black lung awards to former employees who filed claims after June 1973. These liabilities totaled approximately $252.4 million as of December 31, 2002, $42.6 million of which was a current liability. Expense for the fiscal year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002 was $41.4 million, $36.6 million and $55.4 million, respectively.

  Pension-Related Provisions

     Pension-related costs represent the actuarially-estimated cost of pension benefits. Annual contributions to the pension plans are determined by consulting actuaries based on the Employee Retirement Income Security Act minimum funding standards and an agreement with the Pension Benefit Guaranty Corporation. Pension-related liabilities totaled approximately $127.6 million as of December 31, 2002, $7.4 million of which was a current liability. Expense for the fiscal year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002 was $0.3 million, $3.0 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 the United Mine Workers of America Combined Fund created by federal law in 1992. This multi-employer fund provides health care benefits to a closed group of former employees who retired prior to 1976; no new

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retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries.

     Our retiree health care liabilities totaled approximately $1,031.7 million as of December 31, 2002, $72.1 million of which was a current liability. Expense for the fiscal year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002 was $70.7 million, $49.8 million and $74.4 million, respectively. Obligations to the United Mine Workers of America Combined Fund totaled $67.3 million as of December 31, 2002, $17.5 million of which was a current liability. Expense for the nine months ended December 31, 2001 and the year ended December 31, 2002 was $3.3 million and $16.7 million, respectively. For the fiscal year ended March 31, 2001, income of $8.0 million was recorded, primarily due to the withdrawal by the Social Security Administration of certain beneficiaries previously assigned to us. The expense recorded during the year ended December 31, 2002 reflects the expected reassignment of these beneficiaries to us as a result of an adverse U.S. Supreme Court decision in January 2003.

Employees

     As of December 31, 2002, we and our subsidiaries had approximately 6,500 employees. As of December 31, 2002, the United Mine Workers of America represented approximately 31% of our employees, who produced 19% of our coal sales volume during the year ended December 31, 2002. An additional 4% of our employees are represented by labor unions other than the United Mine Workers of America. These employees produced 3% of our coal sales volume during the year ended December 31, 2002. Relations with organized labor are important to our success and we believe our relations with our employees are satisfactory. Hourly workers at our mines in Arizona, Colorado and Montana are represented by the United Mine Workers of America under the Western Surface Agreement, which was ratified in 2000 and is effective through September 1, 2005. Our union labor east of the Mississippi River is also primarily represented by the United Mine Workers of America and is subject to the National Bituminous Coal Wage Agreement. The current five-year labor agreement was ratified in December 2001 and is effective from January 1, 2002 through December 31, 2006.

Legal Proceedings

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

     Navajo Nation

     On June 18, 1999, the Navajo Nation served our subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company, with a complaint that had been filed in the U.S. District Court for the District of Columbia. Other defendants in the litigation are one customer, one current employee and one former employee. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act, or RICO, violations and fraud and tortious interference with contractual relationships. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. Plaintiff also alleges that defendants interfered with the fiduciary relationship between the United States and the Navajo Nation. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases for the Kayenta and Black Mesa mines have terminated due to Peabody Western’s breach of these leases and a reformation of the two coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted seven claims including fraud and is seeking various remedies including unspecified actual damages, punitive damages and reformation of its coal lease.

     On February 21, 2002, our subsidiaries commenced a lawsuit against the Navajo Nation in the U.S. District Court for the District of Arizona seeking enforcement of an arbitration award or, alternatively, to compel arbitration pursuant to the April 1, 1998 Arbitration Agreement with the Navajo Nation. On

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January 14, 2003, the Arizona District Court dismissed the lawsuit. Our subsidiaries have filed an appeal of this decision with the Ninth Circuit Court of Appeals.

     On February 22, 2002, our subsidiaries filed in the U.S. District Court for the District of Columbia a motion for leave to file an amended answer and conditional counterclaim. The counterclaim is conditional because our subsidiaries contend that the lease provisions the Navajo Nation seeks to invalidate have previously been upheld in an arbitration proceeding and are not subject to further litigation. On March 4, 2002, our subsidiaries filed in the U.S. District Court for the District of Columbia a motion to transfer that case to Arizona or, alternatively, to stay the District of Columbia litigation. The District of Columbia District Court denied our motion for a stay and we appealed that ruling to the District of Columbia Court of Appeals. On April 23, 2003, the appellate court denied the appeal.

     On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit brought by the Navajo Nation against the United States. The Court rejected the Navajo Nation’s allegations that the U.S. breached its trust responsibilities to the Navajo Nation in approving the coal lease amendments and was liable for money damages. On May 2, 2003, our subsidiaries filed a renewed motion to dismiss the Navajo Nation’s lawsuit against them based on the Supreme Court’s decision.

     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.

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

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

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

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

     Mohave Generating Station

     We have a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline to the Mohave plant. Also, Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utility Commission proceeding related to recovery of the future capital expenditures for new pollution abatement equipment for the station. The operator of the Mohave Generating Station has stated that it expects to idle the plant for at least 12 to 18 months beginning in 2006. We are in active discussions to resolve the complex issues critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. If these issues are not resolved in a timely manner, the operation of the Mohave plant will cease or be suspended beginning on December 31, 2005. The Mohave plant is the sole customer of our Black Mesa Mine, which sold 4.6 million tons of coal in 2002.

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     Indiana Michigan Power Company

     On September 27, 2001, our subsidiaries, Caballo Coal Company and Peabody COALSALES Company, filed suit in the U.S. District Court for the Eastern District of Missouri against Indiana Michigan Power Company, AEP Energy Services, Inc. and American Electric Power Service Corporation. Our subsidiaries contend that Indiana Michigan Power and American Electric Power Service Corporation breached their obligations under a coal supply agreement dated January 17, 1974. The agreement provides for a price renegotiation every five years. Our subsidiaries called for a price renegotiation in 2001, effective for coal delivered during 2002 through 2006. Our subsidiaries assert that Indiana Michigan Power and American Electric Power Service Corporation did not negotiate in good faith in that they did not submit a competitive offer to supply coal, as required under the contract, when they did not accept the offer submitted by our subsidiaries. Our subsidiaries are seeking specific performance of the agreement, injunctive relief, declaratory judgment, and damages for breach of contract and damages for tortious interference committed by AEP Energy Services. In January 2002, the court denied our motion for a preliminary injunction and the court’s decision on the preliminary injunction was upheld on appeal. The case is now in the discovery phase. Trial is currently scheduled for December 8, 2003.

     We are no longer shipping any coal to Indiana Michigan Power under this contract. Indiana Michigan Power contends that the contract terminated on December 31, 2001, which ended its obligation to purchase 3.5 million tons of coal annually. While the outcome of litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe that the only potential adverse impact on us, if Indiana Michigan Power is ultimately successful, will be our inability to ship further coal to the utility under the contract.

     West Virginia Flooding Litigation

     Three of our subsidiaries have been named in four separate complaints filed in Boone, Kanawha and Wyoming Counties, West Virginia. These cases collectively include 622 plaintiffs who are seeking damages for property damage and personal injuries arising out of flooding that occurred in southern West Virginia in July 2001. The plaintiffs have sued coal, timber, railroad and land companies under the theory that mining, construction of haul roads and removal of timber caused natural surface waters to be diverted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that these four cases, along with over 10 additional flood damage cases not involving our subsidiaries, be handled pursuant to the Court’s Mass Litigation rules. As a result of this ruling, the cases have been transferred to the Circuit Court of Raleigh County in West Virginia to be handled by a panel consisting of three circuit court judges. Oral argument has been held before the panel, which will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts.

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

Oklahoma Lead Litigation

     Although it has not yet been served with the complaint, one of our subsidiaries, Gold Fields Mining Corporation, has been named 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 a claim alleging intentional lead exposure by the defendants, including Gold Fields, and are seeking compensatory and punitive damages and the implementation of a medical monitoring program and a relocation program. A predecessor of Gold Fields formerly operated a lead milling facility near Picher, Oklahoma. The plaintiff classes include all persons who have lived in the vicinity of Picher within a specified time period. Gold Fields has agreed to indemnify one of the other defendants, which is a former subsidiary of our company.

     Environmental

     Federal and State Superfund Statutes. Superfund and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to

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natural resources. Under that legislation and many state Superfund statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault.

     Our subsidiary, Gold Fields Mining Corporation, its predecessors and its former parent company are or may become parties to environmental proceedings that have commenced or may commence in the United States in relation to certain sites previously owned or operated by those entities or companies associated with them. We have agreed to indemnify Gold Fields’ former parent company for any environmental claims resulting from any activities, operations or conditions that occurred prior to the sale of Gold Fields to us. Gold Fields and other potentially responsible parties are currently involved in environmental investigation, litigation or remediation at 11 sites.

     These 11 sites were formerly owned or operated by Gold Fields or Gold Fields’ predecessors, associated companies and its former parent company. The Environmental Protection Agency has placed two of these sites on the National Priorities List, promulgated pursuant to Superfund, and one of the sites is on a similar state priority list. There are a number of additional sites in the United States that were previously owned or operated by such companies that could give rise to environmental proceedings in which Gold Fields could incur liabilities.

     Where the sites were identified, independent environmental consultants were employed in 1997 in order to assess the estimated total amount of the liability per site and the proportion of those liabilities that Gold Fields is likely to bear. The available information on which to base this review was very limited since all of the sites except for two sites (on which no remediation is currently taking place) are no longer owned by Gold Fields. Independent environmental consultants conducted another assessment in 2002. We have accrued liabilities of $40.3 million as of March 31, 2003 for the environmental liabilities described above relating to Gold Fields that are included as part of “other noncurrent liabilities” in our consolidated balance sheet. Significant uncertainty exists as to whether these claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than this provision. We believe that the remaining amount of the provision is adequate to cover these environmental liabilities.

     Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of Superfund and similar legislation, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed by the statute. 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.

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REGULATORY MATTERS

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

     We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of the violations to date or the monetary penalties assessed upon us has been material.

Mine Safety and Health

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

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

     Our goal is to achieve excellent safety and health performance. We measure our success in this area primarily through the use of accident frequency rates. We believe that a superior safety and health regime is inherently tied to achieving our productivity and financial goals. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in establishing safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence.

Black Lung

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

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     In December 2000, the Department of Labor issued new amendments to the regulations implementing the federal black lung laws that, among other things, establish a presumption in favor of a claimant’s treating physician and limit a coal operator’s ability to introduce medical evidence regarding the claimant’s medical condition. Industry reports anticipate that the number of claimants who are awarded benefits will increase, as will the amounts of those awards. The National Mining Association filed a lawsuit challenging these regulations, and the U.S. District Court of the District of Columbia upheld the regulations. The National Mining Association filed an appeal with the U.S. Court of Appeals for the District of Columbia, but the regulations were upheld, with some exceptions as to the retroactivity of the regulations.

Coal Industry Retiree Health Benefit Act of 1992

     The Coal Act provides for the funding of health benefits for certain United Mine Workers of America retirees. The Coal Act established the Combined Fund into which “signatory operators” and “related persons” are obligated to pay annual premiums for beneficiaries. The Coal Act also created a second benefit fund for miners who retired between July 21, 1992 and September 30, 1994 and whose former employers are no longer in business. Companies that are liable under the Coal Act must pay premiums to these funds. Annual payments made by certain of our subsidiaries under the Coal Act totaled $4.2 million, $5.4 million and $11.1 million, respectively, during the fiscal year ended March 31, 2001, nine months ended December 31, 2001 and the year ended December 31, 2002.

     In 1995, in a case filed by the National Coal Association on behalf of its members and others, a federal district court in Alabama ordered the Commissioner of Social Security to recalculate the per-beneficiary premium which the Combined Fund charges assigned operators. The Commissioner applied the recalculated premium to all assigned operators. In 1996, the Combined Fund sued the Social Security Administration in the District of Columbia seeking a declaration that the Social Security Administration’s original premium calculation was proper. Certain coal companies, but not our subsidiaries, intervened in the lawsuit. On February 25, 2000, the federal district court ruled in favor of the Combined Fund. In a decision dated December 16, 2002, the Court of Appeals for the District of Columbia Circuit affirmed in part and reversed in part the lower court’s ruling and remanded the case for further proceedings. Among other things, the Court of Appeals directed the Commissioner of Social Security to void the agency’s 1995 premium recalculation with respect to all assigned operators except those that had been parties to the 1995 Alabama litigation, including National Coal Association member companies. If the Combined Fund is able to obtain a court decision that would retroactively assess the higher premium rate to our subsidiaries, our subsidiaries will be required to pay an additional premium to the Combined Fund of approximately $5.7 million. In that event, the prospective annual premium would also increase by approximately 10%.

Environmental Laws

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

Surface Mining Control and Reclamation Act

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

     SMCRA permit provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and

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grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation.

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

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

     Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The Abandoned Mine Land Fund, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed prior to 1977 and to pay health care benefit costs of orphan beneficiaries of the Combined Fund. The fee, which partially expires on September 30, 2004, is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. After that date, a fee will be assessed each year to cover the expected health care benefit costs of the orphan beneficiaries.

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

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

     On March 29, 2002, the U.S. District Court for the District of Columbia issued a ruling on SMCRA Section 522(e) banning underground coal mining under certain protected lands that were originally applicable only to surface coal mining operations. The U.S. Department of Interior filed an appeal. If the ruling is upheld, mining costs could increase and in some cases make portions of coal reserves infeasible to mine.

Clean Air Act

     The Clean Air Act, the Clean Air Act Amendments and the corresponding state laws that regulate the emissions of materials into the air, affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations may occur through Clean Air Act permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 10 micrometers in diameter or smaller. The Clean Air Act indirectly

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affects coal mining operations by extensively regulating the air emissions of sulfur dioxide, nitrogen oxides, mercury and other compounds emitted by coal-fueled electricity generating plants.

     In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for very fine particulate matter and ozone. As a result, some states will be required to change their existing implementation plans to attain and maintain compliance with the new air quality standards. Our mining operations and electricity generating customers are likely to be directly affected when the revisions to the air quality standards are implemented by the states. State and federal regulations relating to implementation of the new air quality standards may restrict our ability to develop new mines or could require us to modify our existing operations. The extent of the potential direct impact of the new air quality standards on the coal industry will depend on the policies and control strategies associated with the state implementation process under the Clean Air Act, but could have a material adverse effect on our financial condition and results of operations.

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

     The Clean Air Act Amendments also require electricity generators that currently are major sources of nitrogen oxides in moderate or higher ozone non-attainment areas to install reasonably available control technology for nitrogen oxides, which are precursors of ozone. In addition, the EPA promulgated the final rules that would require coal-burning power plants in 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions beginning in May 2004. Installation of additional control measures required under the final rules will make it more costly to operate coal-fueled electricity generating plants.

     The Clean Air Act Amendments provisions for new source review require electricity generators to install the best available control technology if they make a major modification to a facility that results in an increase in its potential to emit regulated pollutants. From 1990 to 1999, the EPA interpreted the new source review criteria in a relatively consistent manner; however, the EPA changed their interpretation during 1999. The Justice Department, on behalf of the EPA, filed a number of lawsuits since November 1999, alleging that 10 electricity generators violated the new source review provisions of the Clean Air Act Amendments at power plants in the midwestern and southern United States. The EPA issued an administrative order alleging similar violations by the Tennessee Valley Authority, affecting seven plants and notices of violation for an additional eight plants owned by the affected electricity generators. Many electricity generators have announced settlements with the Justice Department requiring the installation of additional control equipment on selected generating units. If the remaining electricity generators are found to be in violation, they could be subject to civil penalties and be required to install the required control equipment or cease operations. Our customers are among the named electricity generators and if found not to be in compliance, or as a result of the settlements, the fines and requirements to install additional control equipment could adversely affect the amount of coal they would burn if the plant operating costs were to increase to the point that the plants were operated less frequently. At the end of 2002, the EPA issued proposed new source review rules for sources that include electricity generators. These new rules define routine maintenance, repair and replacement. If these rules are finalized without material revisions, electricity generators should be better able to make needed repairs and improvements to their plants without the uncertainty of triggering cost-prohibitive environmental rules.

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     The Clean Air Act Amendments set a national goal for the prevention of any future, and the remedying of any existing, impairment of visibility in 156 national parks and wildlife areas across the country. Under regulations issued by the EPA in 1999, states are required to set a goal of restoring natural visibility conditions in these Class I areas in their states by 2064 and to explain their reasons to the extent they determine that this goal cannot be met. The state plans may require the application of “Best Available Retrofit Technology” after 2010 on sources found to be contributing to visibility impairment of regional haze in these areas. The control technology requirements could cause our customers to install equipment to control sulfur dioxide and nitrogen oxide emissions. The requirement to install control equipment could affect the amount of coal supplied to those customers if they decide to switch to other sources of fuel to lower emission of sulfur dioxides and nitrogen oxides.

     The Clean Air Act Amendments require a study of electricity generating plant emissions of certain toxic substances, including mercury, and direct the EPA to regulate these substances, if warranted. In December 2000, the EPA decided that mercury air emissions from power plants should be regulated. The EPA will propose regulations by December 2003 and will issue final regulations by December 2004. It is possible that future regulatory activity may seek to reduce mercury emissions and these requirements, if adopted, could result in reduced use of coal if electricity generators switch to other sources of fuel.

     In addition, Vice President Cheney, as the head of the National Energy Policy Development Group, submitted to the President a National Energy Policy which recommended, among other things, that the President direct the EPA Administrator to work with Congress to propose legislation that would significantly reduce and cap emissions of sulfur dioxide, nitrogen oxide and mercury from electricity power generators. In February 2002, the President proposed to cut electricity power generator emissions by approximately 70% by 2018 using a cap and trade system similar to that now in effect for acid deposition control. The President’s proposal has been translated into a legislative proposal. In addition, similar emission reduction proposals have been introduced in Congress, some of which propose to regulate the three pollutants and carbon dioxide, but no such legislation has passed either house of the Congress. If this type of legislation were enacted into law, it could impact the amount of coal supplied to those electricity generating customers if they decide to switch to other sources of fuel whose use would result in lower emission of sulfur dioxides, nitrogen oxides, mercury and carbon dioxide.

     In February 2003, a number of states notified the EPA that they plan to sue the agency to force it to set new source performance standards for utility emissions of carbon dioxide and to tighten existing standards for sulfur dioxide and particulate matter for utility emissions. In June 2003, Massachusetts, Connecticut and Maine filed a law suit against the EPA seeking a court order requiring the EPA to designate carbon dioxide as a criteria pollutant. If these states are successful in obtaining a court order and the EPA agrees to set emission limitations for carbon dioxide, it could adversely affect the amount of coal our customers would purchase from us.

     Clean Water Act

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

     On May 8, 2002, the U.S. District Court for the Southern District of West Virginia issued an injunction banning new Section 404 permits by the Huntington, West Virginia Office of the Army Corp of Engineers (COE). Section 404 permits are required for coal companies to place any material in streams for the purpose of creating slurry ponds, water impoundments, refuse areas, valley fills or other mining activities. The COE filed for an appeal of the Court’s order with the U.S. Court of Appeals for the Fourth Circuit. The COE Huntington office issues permits for portions of Ohio, Kentucky and West Virginia where our mining operations are located. On January 29, 2003, the Fourth Circuit Court of Appeals vacated the District Court’s injunction.

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

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

  Resource Conservation and Recovery Act

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

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

     Federal and State Superfund Statutes

     Superfund and similar state laws affect coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liabilities may be imposed on waste generators, site owners or operators and others regardless of fault.

Global Climate Change

     The United States, Australia and more than 160 other nations are signatories to the 1992 Framework Convention on Climate Change, which is intended to limit emissions of greenhouse gases, such as carbon dioxide. In December 1997, in Kyoto, Japan, the signatories to the convention established a binding set of emission targets for developed nations. Although the specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year budget period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. According to the Energy Information Administration’s Emissions of Greenhouse Gases in the United States 2001, coal accounts for 32% of greenhouse gas emissions in the United States, and efforts to control greenhouse gas emissions could result in reduced use of coal if electricity generators switch to lower carbon sources of fuel. In March 2001, President Bush reiterated his opposition to the Kyoto Protocol and further stated that he did not believe that the government should impose mandatory carbon dioxide emission reductions on power plants. In February 2002, President Bush announced a new approach to climate change, confirming the Administration’s opposition to the Kyoto

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Protocol and proposing voluntary actions to reduce the greenhouse gas intensity of the United States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The President’s climate change initiative calls for a reduction in greenhouse gas intensity over the next 10 years which is approximately equivalent to the reduction that has occurred over each of the past two decades.

Permitting

     Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with coal mining. These provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and revegetation.

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

     Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review, technical review and public notice and comment period before it can be approved. Some Surface Mining Control and Reclamation Act mine permits can take over a year to prepare, depending on the size and complexity of the mine and often take six months to sometimes two years to receive approval. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

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

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MANAGEMENT

Directors and Executive Officers

     Set forth below are the names, ages as of June 1, 2003 and current positions with us and our subsidiaries of our executive officers and directors. Directors are elected at the annual meeting of stockholders. Executive officers are appointed by, and hold office at, the discretion of the directors.

Name	Age		Position
Irl F. Engelhardt		56	Chairman, Chief Executive Officer and Director
Richard M. Whiting		48	Executive Vice President — Sales, Marketing and Trading
Roger B. Walcott, Jr.		47	Executive Vice President — Corporate Development
Richard A. Navarre		42	Executive Vice President and Chief Financial Officer
Fredrick D. Palmer		59	Executive Vice President — Legal and External Affairs and Secretary
Jeffery L. Klinger		56	Vice President — Legal Services and Assistant Secretary
Sharon D. Fiehler		46	Executive Vice President — Human Resources and Administration
Henry E. Lentz		58	Director
Bernard J. Duroc-Danner		49	Director
Roger H. Goodspeed		52	Director
William E. James		57	Director
Robert B. Karn III		61	Director
William C. Rusnack		58	Director
James R. Schlesinger		74	Director
Blanche M. Touhill		71	Director
Sandra Van Trease		42	Director
Alan H. Washkowitz		62	Director

     Irl F. Engelhardthas been a director of our company since 1998. He is Chairman and Chief Executive Officer of our company, a position he has held since 1998. He served as Chief Executive Officer of a predecessor of our company from 1990 to 1998. He also served as Chairman of a predecessor of our company from 1993 to 1998 and as President from 1990 to 1995. Since joining a predecessor of our company in 1979, he has held various officer level positions in the executive, sales, business development and administrative areas, including serving as Chairman of Peabody Resources Ltd. (Australia) and Chairman of Citizens Power LLC. Mr. Engelhardt also served as Co-Chief Executive Officer and executive director of The Energy Group from February 1997 to May 1998, Chairman of Cornerstone Construction & Materials, Inc. from September 1994 to May 1995 and Chairman of Suburban Propane Company from May 1995 to February 1996. He also served as a director and Group Vice President of Hanson Industries from 1995 to 1996. Mr. Engelhardt is Co-Chairman of the Coal Utilization Research Council and Co-Chairman of the Coal Based Generators Stakeholders Group. He has previously served as Chairman of the National Mining Association and the Coal Industry Advisory Board of the International Energy Agency. He is also a director of U.S. Bank, N.A.

     Richard M. Whitingbecame Executive Vice President — Sales, Marketing and Trading in October 2002. Previously, Mr. Whiting served as President and Chief Operating Officer of our company. He joined a predecessor of our company in 1976 and has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Mr. Whiting is currently a member of the Board of Directors of Penn Virginia Resource GP, LLC, the general partner of Penn Virginia Resource Partners, L.P.

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He is Chairman of the Bituminous Coal Operators’ Association and Chairman of the National Mining Association’s Safety and Health Committee.

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

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

     Fredrick D. Palmerbecame Executive Vice President — Legal and External Affairs of our company in February 2001. He is responsible for our legal and governmental affairs. Prior to joining our company, 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 bachelor’s degree and a juris doctor degree from the University of Arizona.

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

     Sharon D. Fiehlerhas been Executive Vice President of Human Resources and Administration of our company since April 2002, with executive responsibility for information services, employee development, benefits, compensation, employee relations and affirmative action programs. She joined our company in 1981 as Manager-Salary Administration and has held a series of employee relations, compensation and salaried benefits positions. Prior to joining our company, Ms. Fiehler, who earned degrees in social work and psychology and a master’s degree, was a personnel representative for Ford Motor Company. Ms. Fiehler is a member of the National Mining Association’s Human Resource Committee.

     Henry E. Lentzhas been a director of our company since 1998. Mr. Lentz is a consultant to Lehman Brothers Inc., an investment banking firm. He joined Lehman Brothers in 1971 and became a Managing Director in 1976. He left the firm in 1988 to become Vice Chairman of Wasserstein Perella Group, Inc. In 1993, he returned to Lehman Brothers as a Managing Director and served as head of the firm’s worldwide energy practice. In 1996, he joined Lehman Brothers’ Merchant Banking Group as a Principal and in January 2003 became a consultant to the Merchant Banking Group. Mr. Lentz is also a director of Rowan Companies, Inc., Carbo Ceramics, Inc. and Consort Holdings plc.

     Bernard J. Duroc-Dannerhas been a director of our company since 2001. He is Chairman, President and Chief Executive Officer of Weatherford International, Inc., one of the world’s largest oilfield services companies, a position he has held since 1998. From 1991 to 1998, Mr. Duroc-Danner served as President and Chief Executive Officer of EVI, Inc., an oilfield service and equipment provider that merged with Weatherford

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Enterra, Inc. in 1998. Previously, Mr. Duroc-Danner held positions at Arthur D. Little and Mobil Oil, Inc. He is also Chairman of the Board and a director of Grant Prideco, Inc., and he serves as a director of Parker Drilling Company, Cal-Dive International, Inc., Dresser, Inc. and Universal Compression Holdings, Inc.

     Roger H. Goodspeedhas been a director of our company since 1998. Prior to his retirement in May 2003, Mr. Goodspeed served as a Managing Director, and subsequently as an Advisory Director, of Lehman Brothers Inc., an investment banking firm. He joined Lehman Brothers in 1974 and became a Managing Director in 1984. During his tenure at Lehman Brothers he had management responsibility for several investment banking groups and served as a member of the Operating Committee of the Investment Banking Division. In 1994, Mr. Goodspeed became the first Chairman of Citizens Lehman Power, an electric power marketing joint venture 50% owned by Lehman Brothers, and continued in that role until the joint venture was sold to The Energy Group in 1997 and changed its name to Citizens Power LLC. Mr. Goodspeed served on the Board of Directors of Citizens Power LLC from 1997 until 2000 when it was sold to Edison Mission Energy.

     William E. Jameshas been a director of our company since 2001. Since July 2000, Mr. James has been Founding Partner of RockPort Capital Partners LLC, a venture fund specializing in energy and environmental technology and advanced materials. He is also Chairman of RockPort Group, an international oil trading and banking company. Prior to joining RockPort, Mr. James co-founded and served as Chairman and Chief Executive Officer of Citizens Power LLC, a leading power marketer. He also co-founded the non-profit Citizens Energy Corporation and served as the Chairman and Chief Executive Officer of Citizens Corporation, its for-profit subsidiary, from 1987 to 1996.

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

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

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

     Blanche M. Touhillhas been a director of our company since 2001. Dr. Touhill is Chancellor Emeritus and Professor Emeritus at the University of Missouri – St. Louis. She previously served as Chancellor and Professor of History and Education at the University of Missouri – St. Louis from 1991 through 2002. Prior to her appointment as Chancellor, Dr. Touhill held the positions of Vice Chancellor for Academic Affairs and

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Interim Chancellor at the University of Missouri – St. Louis. Dr. Touhill also has served on the Boards of Directors of Trans World Airlines and Delta Dental. She holds bachelor’s and doctoral degrees in history and a master’s degree in geography from St. Louis University.

     Sandra Van Treasehas been a director of our company since January 2003. Ms. Van Trease is President and CEO of UNICARE, an operating affiliate of WellPoint Health Networks Inc., one of the nation’s largest publicly traded managed care companies. She has held that position since 2002, when her prior employer, RightCHOICE Managed Care, Inc., was acquired by WellPoint. Ms. Van Trease served as President, Chief Financial Officer and Chief Operating Officer of RightCHOICE from 2000 to 2002, and as Executive Vice President, Chief Financial Officer and Chief Operating Officer from 1997 to 2000. Prior to joining RightCHOICE in 1994, she was a Senior Audit Manager with Price Waterhouse LLP. She is a Certified Public Accountant and Certified Management Accountant. Ms. Van Trease is also a director of U.S. Bank, N.A.

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

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RELATED PARTY TRANSACTIONS

     As of June 1, 2003, Lehman Brothers Merchant Banking Partners II L.P. and its affiliates, collectively Lehman Brothers Merchant Banking Fund, owned 29.8% of our outstanding common stock. Messrs. Goodspeed, Lentz and Washkowitz, each being one of our directors, are investors in the Lehman Brothers Merchant Banking Fund. Mr. Goodspeed and Mr. Lentz are consultants to, and Mr. Washkowitz is a Managing Director of, Lehman Brothers Inc.

Transactions with Affiliates of Lehman Brothers Inc.

     In May 2003, Lehman Brothers Inc. served as the lead underwriter in connection with the secondary offering discussed in Note 10 to the unaudited condensed consolidated financial statements for the quarter ended March 31, 2003. Fees paid to Lehman Brothers Inc. for their services were paid by the selling shareholders and not by us. We paid incidental expenses customarily incurred by a registering company in connection with the secondary offering.

     As discussed in Note 2 to the unaudited condensed consolidated financial statements for the quarter ended March 31, 2003, we refinanced a substantial portion of our 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 our Board of Directors not affiliated with Lehman Brothers Inc., we appointed Wachovia Securities, Inc., Fleet Securities, Inc. and Lehman Brothers Inc. as lead arrangers for the new credit facility, Lehman Brothers Inc. and Morgan Stanley as joint book running managers for the notes and Lehman Brothers Inc. as Dealer Manager in connection with the tender offer. Lehman Brothers Inc. received total fees of $7.4 million for their services in connection with the refinancing; those fees were consistent with the fees paid to other parties to the transaction for their respective services.

     In April 2002, Lehman Brothers Inc. served as the lead underwriter in connection with an offering of our common stock by Lehman Brothers Merchant Banking Fund and certain other selling stockholders. Lehman Brothers Inc. received customary fees, plus reimbursement of certain expenses, for those services.

     Lehman Brothers Inc. has been retained to serve as financial advisor in connection with our efforts to develop mine-mouth electric facilities in Kentucky and certain other locations. During the nine months ended December 31, 2001, Lehman Brothers Inc. received $0.5 million plus reimbursement of expenses for services rendered in connection with those projects, and has not received any fees or expense reimbursement since that time.

     Lehman Brothers Inc. served as the dealer manager in connection with our tender offer for $80 million principal amount of each of our senior notes and senior subordinated notes, which was completed in June 2001. Lehman Brothers Inc. received a fee of $0.4 million, plus reimbursement of expenses, for those services.

     Lehman Brothers Inc. served as the lead underwriter in connection with the initial public offering of our common stock, which was completed in May 2001. Lehman Brothers Inc. received customary fees, plus reimbursement of expenses, for those services.

     Lehman Commercial Paper Inc. is a participant in our existing senior credit facility, which was amended in April 2001. Lehman Commercial Paper Inc. received $0.06 million of the $1.4 million credit facility amendment fee.

Transactions with Management

     During the fiscal years ended March 31, 1999, 2000 and 2001, some of our executive officers and 18 other employees purchased or were granted shares of class B common stock under our 1998 Stock Purchase and Option Plan for Key Employees. All of these class B shares were subsequently converted into our common stock on a one-for-one basis at the time of our initial public offering. In connection with these purchases and grants, we, affiliates of Lehman Brothers Holdings and our executives who received class B common stock entered into stockholder agreements providing rights relating to the registration of shares in

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connection with sales of our capital stock by affiliates of Lehman Brothers Holdings. The stockholders agreements provide the investors with the right to register and sell their unregistered stock in the event we conduct certain types of registered offerings.

     In conjunction with the purchases and grants of class B common stock, our executive officers and employees executed term notes. The term notes related to the grants were due on May 19, 2003 and the term notes executed for purchases were due on February 1, 2006. Subsequently, the term notes executed for purchases were replaced with term notes related to the grants. All of the term notes bear interest at an applicable United States federal rate used by the Internal Revenue Service for loans to employees. The maturity of the promissory notes will accelerate upon the occurrence of certain events, including six months following any termination of employment or disposition of the stock.

     The following table indicates the amounts due under the term notes for our executive officers with aggregate indebtedness in excess of $60,000:

			Largest Aggregate Indebtedness
	Outstanding Indebtedness at		During Fiscal Year Ended
Name	June 1, 2003		December 31, 2002
Irl F. Engelhardt		—	$	680,426
Roger B. Walcott, Jr.		—		226,158
Richard M. Whiting		—		221,384
Richard A. Navarre		—		188,202
Jeffery L. Klinger		—		131,497
Sharon D. Fiehler		—		130,552

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DESCRIPTION OF OTHER INDEBTEDNESS

     The following are summaries of the material terms and conditions of our principal indebtedness.

New Credit Facility

     Our new credit facility provides for a $600.0 million revolving credit facility and a $450.0 million term loan B facility. The revolving credit facility includes borrowing capacity available for letters of credit and for swingline loan borrowings on same-day notice. The revolving credit facility commitment is scheduled to terminate in March 2008. The term loan B facility is scheduled to mature in March 2010.

     All borrowings under the new credit facility bear interest, at our option, at either: (A) an “alternate base rate” equal to, for any day, the higher of: (a) 0.50% per year above the overnight federal funds effective rate, as published by the Board of Governors of the Federal Reserve System, as in effect from time to time; and (b) the annual rate of interest in effect for that day as publicly announced by the administrative agent as its “base rate”plusa rate, dependent on the ratio of our debt as compared to our cash flow, (1) in the case of the revolving credit loans and the swingline loans, ranging from 1.50% to 0.50% per year or (2) in the case of the term loan B facility, ranging from 1.50% to 1.25% per year or (B) a “LIBOR rate” equal to the rate (adjusted for statutory reserve requirements for eurocurrency liabilities) at which eurodollar deposits for the relevant interest period (which will be one, two, three, six or, subject to availability, nine or 12 months, as selected by us) are offered in the interbank eurodollar market, as determined by the administrative agent,plusa rate, dependent on the ratio of our debt as compared to our cash flow, (1) in the case of the revolving credit loans, ranging from 2.50% to 1.50% per year or (2) in the case of the term loan, ranging from 2.50% to 2.25% per year.

     We pay a usage-dependent commitment fee on the available unused commitment under the revolving credit facility. The fee equals (a) 0.25% per year, in the event that the usage of the revolving credit facility is at least 66.67%, (b) 0.375% per year, in the event that the usage of the revolving credit facility is at least 33.33% but less than 66.67%, and (c) 0.50% per year, in the event that the usage of the revolving credit facility is less then 33.33%. For purposes of calculating the commitment fee, swingline loans are not be considered usage of the revolving credit facility. The fee accrues quarterly and is payable within 15 days after the end of each calendar quarter.

     We also pay a letter of credit fee calculated at a rate, dependent on the ratio of our debt as compared to our cash flow, ranging from 2.50% to 1.50% per year of the face amount of each letter of credit and a fronting fee equal to the greater of $150 and 0.125% per year of the face amount of each letter of credit. These fees are payable quarterly in arrears within 15 days after the end of each calendar quarter. In addition, we are paying customary transaction charges in connection with any letters of credit.

     The rates that depend on the ratio of our debt as compared to our cash flow range from the high rate specified if the ratio is greater than or equal to 3.75 to 1.0 to the low rate specified if the ratio is less than 2.25 to 1.0.

     The term loan B facility amortizes as follows:

	Scheduled Repayment of
Year	Term Loans
2003	$	3,375,000
2004		4,500,000
2005		4,500,000
2006		4,500,000
2007		4,500,000
2008		4,500,000
2009		318,375,000
Termination Date		105,750,000

     Borrowings under our new credit facility are subject to mandatory prepayment (1) with 100% of the net proceeds received by us from the issuance of debt securities, excluding the notes offered hereby and certain other indebtedness, (2) with 100% of the net proceeds received from our sale of or disposition of certain of our assets and (3) on an annual basis with (A) 50% of our excess cash flow, if the ratio of our debt to cash flow is greater than or equal to 3.0 to 1.0 or (B) 25% of our excess cash flow, if the ratio is greater than or equal to 2.0 to 1.0 and less than 3.0 to 1.0.

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     Our obligations under the new credit facility are secured by a lien on certain of our and our direct and indirect domestic restricted subsidiaries’ tangible and intangible assets, including: (1) a pledge by us and our direct and indirect domestic restricted subsidiaries of all of the capital stock (or other ownership interests) of our respective domestic restricted subsidiaries and 65% of the capital stock of our first-tier foreign restricted subsidiaries, (2) certain of our and our direct and indirect domestic restricted subsidiaries’ coal reserves, mineral rights, leasehold interests and other real property and all related as-extracted collateral, (3) certain coal supply agreements and other material contracts to which we or certain of our direct or indirect domestic restricted subsidiaries are a party and (4) substantially all of our personal property and the personal property of certain of our direct and indirect subsidiaries. In addition, indebtedness under the new credit facility is guaranteed by our restricted subsidiaries.

     The new credit facility agreement imposes certain restrictions on us, including restrictions on our ability to: incur debt; grant liens; enter into agreements with negative pledge clauses; provide guarantees in respect of obligations of any other person; pay dividends; make loans, investments, advances and acquisitions; sell our assets; make redemptions and repurchases of capital stock; make capital expenditures; prepay, redeem or repurchase debt; liquidate or dissolve; engage in mergers or consolidations; engage in affiliate transactions; change our business; change our fiscal year; amend certain debt and other material agreements; issue and sell capital stock of subsidiaries; engage in sale and leaseback transactions; and restrict distributions from subsidiaries. In addition, the new credit facility provides that we must meet or exceed certain interest coverage ratios and must not exceed certain leverage ratios. The new credit facility also includes customary events of default.

5.0% Subordinated Note

     The 5.0% subordinated note, which had an original face value of $400.0 million and has a current face value of $90.0 million, is recorded net of discount at an imputed annual interest rate of approximately 12.0%, resulting in a long-term debt carrying amount of $76.2 million as of March 31, 2003. Interest and principal are payable each March 1 and scheduled principal payments of $10.0 million per year are due from 2004 through 2006, with any unpaid amounts due March 1, 2007. The note is a subordinated and unsecured obligation of our subsidiary, Peabody Holding Company, Inc. The terms of the note permit the merger, consolidation or the sale of assets of Peabody Holding Company, Inc., as long as the successor corporation following the merger or consolidation (if Peabody Holding Company, Inc. does not survive) expressly assumes payment of principal and interest on and performance of the covenants and conditions of the note.

Surety Bonds

     Federal and state laws require surety bonds to secure our obligations to reclaim lands disturbed for mining, to pay federal and state workers’ compensation and to satisfy other miscellaneous obligations. The amount of these bonds varies constantly, depending upon the amount of acreage disturbed and the degree to which each property has been reclaimed. Under federal law, partial bond release is provided as mined lands (1) are backfilled and graded to approximate original contour, (2) are re-vegetated and (3) achieve pre-mining vegetative productivity levels on a sustained basis for a period of five to 10 years.

     As of December 31, 2002, we had outstanding surety bonds with third parties for post-mining reclamation totaling $622.6 million, with an additional $291.9 million in self-bonding obligations. We have $156.2 million of surety bonds in place for federal and state workers’ compensation obligations and other miscellaneous obligations.

Accounts Receivable Securitization Program

     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 a bankruptcy remote trust are sold, without recourse, to a Conduit. Purchases by the Conduit are financed with the sale of highly rated commercial paper. We use proceeds from the sale of our accounts receivable securitization program to repay long-term debt, effectively reducing our overall borrowing costs. The securitization program is currently scheduled to expire in 2007. The amount of undivided interests in the accounts receivable sold to the Conduit were $52.5 million as of March 31, 2003.

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THE EXCHANGE OFFER

General

     We hereby offer, upon the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal (which together constitute the exchange offer), to exchange up to $650.0 million aggregate principal amount of our 6 7/8% Senior Notes due 2013, which we refer to in this prospectus as the outstanding notes, for a like aggregate principal amount of our 6 7/8% Series B Senior Notes due 2013, which we refer to in this prospectus as the exchange notes, properly tendered on or prior to the expiration date and not withdrawn as permitted pursuant to the procedures described below. The exchange offer is being made with respect to all of the outstanding notes.

     As of the date of this prospectus, $650.0 million aggregate principal amount of the outstanding notes is outstanding. This prospectus, together with the letter of transmittal, is first being sent on or about July 3, 2003, to all holders of outstanding notes known to us. Our obligation to accept outstanding notes for exchange pursuant to the exchange offer is subject to certain conditions set forth under “— Certain Conditions to the Exchange Offer” below. We currently expect that each of the conditions will be satisfied and that no waivers will be necessary.

Purpose and Effect of the Exchange Offer

     We have entered into a registration rights agreement with the initial purchasers of the outstanding notes in which we agreed, under some circumstances, to file a registration statement relating to an offer to exchange the outstanding notes for exchange notes. We also agreed to use all commercially reasonable efforts to cause the exchange offer registration statement to become effective under the Securities Act as promptly as practicable, but in no event later than 180 days after the closing date and keep the exchange offer registration statement effective for not less than 20 business days. The exchange notes will have terms substantially identical to the outstanding notes, except that the exchange notes will not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement. The outstanding notes were issued on March 21, 2003.

     Under certain circumstances set forth in the registration rights agreement, we will use all commercially reasonable efforts to cause the SEC to declare effective a shelf registration statement with respect to the resale of the outstanding notes and keep the statement, effective for up to two years after the closing date.

     If we fail to comply with certain obligations under the registration rights agreement, we will be required to pay additional interest to holders of the outstanding notes.

     Each holder of outstanding notes that wishes to exchange outstanding notes for transferable exchange notes in the exchange offer will be required to make the following representations:

•  any exchange notes will be acquired in the ordinary course of its business;

•  the holder will have no arrangements or understanding with any person to participate in the distribution of the outstanding notes or the exchange notes within the meaning of the Securities Act;

•  the holder is not an “affiliate,” as defined in Rule 405 of the Securities Act, of ours or if it is an affiliate of ours, that it will comply with applicable registration and prospectus delivery requirements of the Securities Act, to the extent applicable;

•  if the holder is not a broker-dealer, that it is not engaged in, and does not intend to engage in, the distribution of the exchange notes; and

•  if the holder is a broker-dealer, that it will receive exchange notes for its own account in exchange for outstanding notes that were acquired as a result of market-making activities or other trading activities and that it will be required to acknowledge that it will deliver a prospectus in connection with any resale of the exchange notes. See “Plan of Distribution.”

Resale of Exchange Notes

     Based on interpretations of the staff of the SEC set forth in no action letters issued to unrelated third parties, we believe that exchange notes issued under the exchange offer in exchange for outstanding notes

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may be offered for resale, resold and otherwise transferred by any exchange note holder without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

•  the holder is not an “affiliate” of ours within the meaning of Rule 405 under the Securities Act;

•  the exchange notes are acquired in the ordinary course of the holder’s business; and

•  the holder does not intend to participate in the distribution of the exchange notes.

     Any holder who tenders in the exchange offer with the intention of participating in any manner in a distribution of the exchange notes:

•  cannot rely on the position of the staff of the SEC enunciated inExxon Capital Holdings Corporationor similar interpretive letters; and

•  must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction.

     This prospectus may be used for an offer to resell, for the resale or for other retransfer of exchange notes only as specifically set forth in this prospectus. With regard to broker-dealers, only broker-dealers that acquired the outstanding notes as a result of market-making activities or other trading activities may participate in the exchange offer. Each broker-dealer that receives exchange notes for its own account in exchange for outstanding notes, where the outstanding notes were acquired by the broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of the exchange notes. Please read the section captioned “Plan of Distribution” for more details regarding the transfer of exchange notes.

Terms of the Exchange Offer

     Upon the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal, we will accept for exchange any outstanding notes properly tendered and not properly withdrawn prior to the expiration date. We will issue $1,000 principal amount of exchange notes in exchange for each $1,000 principal amount of outstanding notes surrendered under the exchange offer. Outstanding notes may be tendered only in integral multiples of $1,000.

     The form and terms of the exchange notes will be substantially identical to the form and terms of the outstanding notes except the exchange notes will be registered under the Securities Act, will not bear legends restricting their transfer and will not provide for any additional amounts upon our failure to fulfill our obligations under the registration rights agreement to file, and cause to be effective, a registration statement. The exchange notes will evidence the same debt as the outstanding notes. The exchange notes will be issued under and entitled to the benefits of the same indenture that authorized the issuance of the outstanding notes.

     The exchange offer is not conditioned upon any minimum aggregate principal amount of outstanding notes being tendered for exchange.

     As of the date of this prospectus, $650.0 million aggregate principal amount of the outstanding notes are outstanding. This prospectus and a letter of transmittal are being sent to all registered holders of outstanding notes. There will be no fixed record date for determining registered holders of outstanding notes entitled to participate in the exchange offer.

     We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act, the Exchange Act and the rules and regulations of the SEC. Outstanding notes that are not tendered for exchange in the exchange offer will remain outstanding and continue to accrue interest and will be entitled to the rights and benefits the holders have under the indenture relating to the outstanding notes, except for any rights under the registration rights agreement that by their terms terminate upon the consummation of the exchange offer.

     We will be deemed to have accepted for exchange properly tendered outstanding notes when we have given oral or written notice of the acceptance to the exchange agent. The exchange agent will act as agent for the tendering holders for the purposes of receiving the exchange notes from us and delivering exchange notes to the holders. Under the terms of the registration rights agreement, we reserve the right to amend or terminate the exchange offer, and not to accept for exchange any outstanding notes not previously accepted

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for exchange, upon the occurrence of any of the conditions specified below under the caption “— Certain Conditions to the Exchange Offer.”

     Holders who tender outstanding notes in the exchange offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the letter of transmittal, transfer taxes with respect to the exchange of outstanding notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important that you read the section labeled “— Fees and Expenses” below for more details regarding fees and expenses incurred in the exchange offer.

Expiration Date; Extensions; Amendments

     The exchange offer will expire at midnight, New York City time on Friday, August 1, 2003, unless in our sole discretion we extend it.

     In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of outstanding notes of the extension no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

     We reserve the right, in our sole discretion:

•  to delay accepting for exchange any outstanding notes;

•  to extend the exchange offer or to terminate the exchange offer and to refuse to accept outstanding notes not previously accepted if any of the conditions set forth below under “— Certain Conditions to the Exchange Offer” have not been satisfied, by giving oral or written notice of the delay, extension or termination to the exchange agent; or

•  under the terms of the registration rights agreement, to amend the terms of the exchange offer in any manner.

     Any delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice to the registered holders of outstanding notes. If we amend the exchange offer in a manner that we determine constitutes a material change, we will promptly disclose the amendment in a manner reasonably calculated to inform the holder of outstanding notes of the amendment.

     Without limiting the manner in which we may choose to make public announcements of any delay in acceptance, extension, termination or amendment of the exchange offer, we will have no obligation to publish, advertise or otherwise communicate any public announcement, other than by making a timely release to a financial news service.

Certain Conditions to the Exchange Offer

     Despite any other term of the exchange offer, we will not be required to accept for exchange, or exchange any exchange notes for, any outstanding notes, and we may terminate the exchange offer as provided in this prospectus before accepting any outstanding notes for exchange if in our reasonable judgment:

•  the exchange notes to be received will not be tradable by the holder, without restriction under the Securities Act, the Exchange Act and without material restrictions under the blue sky or securities laws of substantially all of the states of the United States;

•  the exchange offer, or the making of any exchange by a holder of outstanding notes, would violate applicable law or any applicable interpretation of the staff of the SEC; or

•  any action or proceeding has been instituted or threatened in any court or by or before any governmental agency with respect to the exchange offer that, in our judgment, would reasonably be expected to impair our ability to proceed with the exchange offer.

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     In addition, we will not be obligated to accept for exchange the outstanding notes of any holder that has not made to us:

•  the representations described under “— Purpose and Effect of the Exchange Offer,” “— Procedures for Tendering” and “Plan of Distribution;” and

•  such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to it an appropriate form for registration of the exchange notes under the Securities Act.

     We expressly reserve the right, at any time or at various times, to extend the period of time during which the exchange offer is open. Consequently, we may delay acceptance of any outstanding notes by giving oral or written notice of the extension to their holders. During any such extensions, all notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange. We will return any outstanding notes that we do not accept for exchange for any reason without expense to their tendering holder as promptly as practicable after the expiration or termination of the exchange offer.

     We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any outstanding notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified above. We will give oral or written notice of any extension, amendment, nonacceptance or termination to the holders of the outstanding notes as promptly as practicable.

     These conditions are for our sole benefit and we may assert them regardless of the circumstances that may give rise to them or waive them in whole or in part at any or at various times in our sole discretion. If we fail at any time to exercise any of the foregoing rights, this failure will not constitute a waiver of this right. Each right will be deemed an ongoing right that we may assert at any time or at various times.

     In addition, we will not accept for exchange any outstanding notes tendered, and will not issue exchange notes in exchange for any outstanding notes if, at the time, any stop order will be threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act.

Procedures for Tendering

     Only a holder of outstanding notes may tender the outstanding notes in the exchange offer. To tender in the exchange offer, a holder must:

•  complete, sign and date the accompanying letter of transmittal, or a facsimile of the letter of transmittal; have the signature on the letter of transmittal guaranteed if the letter of transmittal so requires; and mail or deliver the letter of transmittal or facsimile to the exchange agent prior to the expiration date; or

•  comply with DTC’s Automated Tender Offer Program procedures described below.

     In addition, either:

•  the exchange agent must receive the outstanding notes along with the accompanying letter of transmittal; or

•  the exchange agent must receive, prior to the expiration date, a timely confirmation of book-entry transfer of the outstanding notes into the exchange agent’s account at DTC according to the procedures for book-entry transfer described below or a properly transmitted agent’s message; or

•  the holder must comply with the guaranteed delivery procedures described below.

     To be tendered effectively, the exchange agent must receive any physical delivery of a letter of transmittal and other required documents at the address set forth below under “— Exchange Agent” prior to the expiration date.

     The tender by a holder that is not properly withdrawn prior to the expiration date will constitute an agreement between the holder and us in accordance with the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal.

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     The method of delivery of outstanding notes, the letter of transmittal and all other required documents to the exchange agent is at the holder’s election and risk. Rather than mail these items, we recommend that holders use an overnight or hand delivery service. In all cases, holders should allow sufficient time to assure delivery to the exchange agent before the expiration date. Holders should not send the letter of transmittal or outstanding notes to us. Holders may request their respective brokers, dealers, commercial banks, trust companies or other nominees to effect the above transactions for them.

     Any beneficial owner whose outstanding notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and who wishes to tender should contact the registered holder promptly and instruct it to tender on the owner’s behalf. If the beneficial owner wishes to tender on its own behalf, it must, prior to completing and executing the accompanying letter of transmittal and delivering its outstanding notes either:

•  make appropriate arrangements to register ownership of the outstanding notes in such owner’s name; or

•  obtain a properly completed bond power from the registered holder of outstanding notes.

     The transfer of registered ownership may take considerable time and may not be completed prior to the expiration date.

     Signatures on a letter of transmittal or a notice of withdrawal described below must be guaranteed by a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States or another “eligible institution” within the meaning of Rule 17Ad-15 under the Exchange Act, unless the outstanding notes are tendered:

•  by a registered holder who has not completed the box entitled “Special Issuance Instructions” or “Special Delivery Instructions” on the accompanying letter of transmittal; or

•  for the account of an eligible institution.

     If the accompanying letter of transmittal is signed by a person other than the registered holder of any outstanding notes listed on the outstanding notes, the outstanding notes must be endorsed or accompanied by a properly completed bond power. The bond power must be signed by the registered holder as the registered holder’s name appears on the outstanding notes and an eligible institution must guarantee the signature on the bond power.

     If the accompanying letter of transmittal or any outstanding notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, they should also submit evidence satisfactory to us of their authority to deliver the accompanying letter of transmittal.

     The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC’s system may use DTC’s Automated Tender Offer Program to tender. Participants in the program may, instead of physically completing and signing the accompanying letter of transmittal and delivering it to the exchange agent, transmit their acceptance of the exchange offer electronically. They may do so by causing DTC to transfer the outstanding notes to the exchange agent in accordance with its procedures for transfer. DTC will then send an agent’s message to the exchange agent. The term “agent’s message” means a message transmitted by DTC, received by the exchange agent and forming part of the book-entry confirmation, to the effect that:

•  DTC has received an express acknowledgment from a participant in its Automated Tender Offer Program that is tendering outstanding notes that are the subject of the book-entry confirmation;

•  the participant has received and agrees to be bound by the terms of the accompanying letter of transmittal, or, in the case of an agent’s message relating to guaranteed delivery, that the participant has received and agrees to be bound by the applicable notice of guaranteed delivery; and

•  the agreement may be enforced against that participant.

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     We will determine in our sole discretion all outstanding questions as to the validity, form, eligibility, including time or receipt, acceptance of tendered outstanding notes and withdrawal of tendered outstanding notes. Our determination will be final and binding. We reserve the absolute right to reject any outstanding notes not validly tendered or any outstanding notes the acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defects, irregularities or conditions of tender as to particular outstanding notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the accompanying letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of outstanding notes must be cured within such time as we will determine. Although we intend to notify holders of defects or irregularities with respect to tenders of outstanding notes, neither we, the exchange agent, nor any other person will incur any liability for failure to give the notification. Tenders of outstanding notes will not be deemed made until any defects or irregularities have been cured or waived. Any outstanding notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the exchange agent without cost to the tendering holder, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date.

     In all cases, we will issue exchange notes for outstanding notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

•  outstanding notes or a timely book-entry confirmation of the outstanding notes into the exchange agent’s account at DTC; and

•  a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted agent’s message.

     By signing the accompanying letter of transmittal or authorizing the transmission of the agent’s message, each tendering holder of outstanding notes will represent or be deemed to have represented to us that, among other things:

•  any exchange notes that the holder receives will be acquired in the ordinary course of its business;

•  the holder has no arrangement or understanding with any person or entity to participate in the distribution of the exchange notes;

•  if the holder is not a broker-dealer, that it is not engaged in and does not intend to engage in the distribution of the exchange notes;

•  if the holder is a broker-dealer that will receive exchange notes for its own account in exchange for outstanding notes that were acquired as a result of market-making activities or other trading activities, that it will deliver a prospectus, as required by law, in connection with any resale of any exchange notes. See “Plan of Distribution”; and

•  the holder is not an “affiliate,” as defined in Rule 405 of the Securities Act, of ours or, if the holder is an affiliate, it will comply with any applicable registration and prospectus delivery requirements of the Securities Act.

Book-Entry Transfer

     The exchange agent will make a request to establish an account with respect to the outstanding notes at DTC for purposes of the exchange offer promptly after the date of this prospectus. Any financial institution participating in DTC’s system may make book-entry delivery of outstanding notes by causing DTC to transfer the outstanding notes into the exchange agent’s account at DTC in accordance with DTC’s procedures for transfer. Holders of outstanding notes who are unable to deliver confirmation of the book-entry tender of their outstanding notes into the exchange agent’s account at DTC or all other documents required by the letter of transmittal to the exchange agent on or prior to the expiration date must tender their outstanding notes according to the guaranteed delivery procedures described below.

Guaranteed Delivery Procedures

     Holders wishing to tender their outstanding notes but whose outstanding notes are not immediately available or who cannot deliver their outstanding notes, the accompanying letter of transmittal or any other

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available required documents to the exchange agent or comply with the applicable procedures under DTC’s Automated Tender Offer Program prior to the expiration date may tender if:

•  the tender is made through an eligible institution;

•  prior to the expiration date, the exchange agent receives from the eligible institution either a properly completed and duly executed notice of guaranteed delivery, by facsimile transmission, mail or hand delivery, or a properly transmitted agent’s message and notice of guaranteed delivery;

•  setting forth the name and address of the holder, the registered number(s) of the outstanding notes and the principal amount of outstanding notes tendered;

•  stating that the tender is being made thereby; and

•  guaranteeing that, within three New York Stock Exchange trading days after the expiration date, the accompanying letter of transmittal, or facsimile thereof, together with the outstanding notes or a book-entry confirmation, and any other documents required by the accompanying letter of transmittal will be deposited by the eligible institution with the exchange agent; and

•  the exchange agent receives the properly completed and executed letter of transmittal, or facsimile thereof, as well as all tendered outstanding notes in proper form for transfer or a book-entry confirmation, and all other documents required by the accompanying letter of transmittal, within three New York Stock Exchange trading days after the expiration date.

     Upon request to the exchange agent, a notice of guaranteed delivery will be sent to holders who wish to tender their outstanding notes according to the guaranteed delivery procedures set forth above.

Withdrawal of Tenders

     Except as otherwise provided in this prospectus, holders of outstanding notes may withdraw their tenders at any time prior to the expiration date.

     For a withdrawal to be effective:

•  the exchange agent must receive a written notice of withdrawal, which notice may be by telegram, telex, facsimile transmission or letter of withdrawal at one of the addresses set forth below under “— Exchange Agent,” or

•  holders must comply with the appropriate procedures of DTC’s Automated Tender Offer Program system.

     Any notice of withdrawal must:

•  specify the name of the person who tendered the outstanding notes to be withdrawn;

•  identify the outstanding notes to be withdrawn, including the principal amount of the outstanding notes; and

•  where certificates for outstanding notes have been transmitted, specify the name in which the outstanding notes were registered, if different from that of the withdrawing holder.

     If certificates for outstanding notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of the certificates, the withdrawing holder must also submit:

•  the serial numbers of the particular certificates to be withdrawn; and

•  a signed notice of withdrawal with signatures guaranteed by an eligible institution unless the holder is an eligible institution.

     If outstanding notes have been tendered pursuant to the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn outstanding notes and otherwise comply with the procedures of that facility. We will determine all questions as to the validity, form and eligibility, including time of receipt, of the notices, and our determination will be final and binding on all parties. We will deem any outstanding notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer. Any outstanding notes that have been tendered for exchange but that are not exchanged for any reason will be returned to their holder

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without cost to the holder, or, in the case of outstanding notes tendered by book-entry transfer into the exchange agent’s account at DTC according to the procedures described above, the outstanding notes will be credited to an account maintained with DTC for outstanding notes, as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. Properly withdrawn, outstanding notes may be retendered by following one of the procedures described under “— Procedures for Tendering” above at any time on or prior to the expiration date.

Exchange Agent

     US Bank National Association has been appointed as exchange agent for the exchange offer. You should direct questions and requests for assistance, requests for additional copies of this prospectus or for the letter of transmittal and requests for the notice of guaranteed delivery to the exchange agent as follows:

By Mail or Overnight Delivery:	By Facsimile:	By Hand Delivery:
U.S. Bank National Association 180 East Fifth Street St. Paul, MN 55101 Attention: Specialized Finance Group	(for Eligible Institutions only) (651) 244-1537 Attention: Specialized Finance Group Confirm by Telephone: (800) 934-6802	U.S. Bank National Association 180 East Fifth Street St. Paul, MN 55101 Attention: Specialized Finance Group

Delivery of the letter of transmittal to an address other than as set forth above or transmission via facsimile other than as set forth above does not constitute a valid delivery of the letter of transmittal.

Fees and Expenses

     We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitations by telephone or in person by our officers and regular employees and those of our affiliates.

     We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptance of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

     We will pay the cash expenses to be incurred in connection with the exchange offer. The expenses are estimated in the aggregate to be approximately $350,000. They include:

•  SEC registration fees;

•  fees and expenses of the exchange agent and trustee;

•  accounting and legal fees and printing costs; and

•  related fees and expenses.

Transfer Taxes

     We will pay all transfer taxes, if any, applicable to the exchange of outstanding notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if:

•  certificates representing outstanding notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be issued in the name of, any person other than the registered holder of outstanding notes tendered;

•  tendered outstanding notes are registered in the name of any person other than the person signing the letter of transmittal; or

•  a transfer tax is imposed for any reason other than the exchange of outstanding notes under the exchange offer.

     If satisfactory evidence of payment of the taxes is not submitted with the letter of transmittal, the amount of the transfer taxes will be billed to that tendering holder.

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     Holders who tender their outstanding notes for exchange will not be required to pay any transfer taxes. However, holders who instruct us to register exchange notes in the name of, or request that outstanding notes not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be required to pay any applicable transfer tax.

Consequences of Failure to Exchange

     Holders of outstanding notes who do not exchange their outstanding notes for exchange notes under the exchange offer will remain subject to the restrictions on transfer of the outstanding notes:

•  as set forth in the legend printed on the notes as a consequence of the issuance of the outstanding notes under the exemption from, or in transactions not subject to, the registration requirements of the Securities Act and applicable state securities laws; and

•  otherwise as set forth in the offering memorandum distributed in connection with the private offering of the outstanding notes.

     In general, you may not offer or sell the outstanding notes unless they are registered under the Securities Act, or if the offer or sale is exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the outstanding notes under the Securities Act. Based on interpretations of the staff of the SEC, exchange notes issued under the exchange offer may be offered for resale, resold or otherwise transferred by their holders (other than any holder that is our “affiliate” within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that the holders acquired the exchange notes in the ordinary course of the holders’ business and the holders have no arrangement or understanding with respect to the distribution of the exchange notes to be acquired in the exchange offer. Any holder who tenders in the exchange offer for the purpose of participating in a distribution of the exchange notes:

•  cannot rely on the applicable interpretations of the SEC; and

•  must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction.

Accounting Treatment

     We will record the exchange notes in our accounting records at the same carrying value as the outstanding notes, which is the aggregate principal amount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer. We will record the expenses of the exchange offer as incurred.

Other

     Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

     We may in the future seek to acquire untendered outstanding notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any outstanding notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered outstanding notes.

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DESCRIPTION OF THE NOTES

     You can find the definitions of certain terms used in this description below under “— Certain Definitions.” In this description, the words “we” and “Company” refer only to Peabody Energy Corporation and not to any of its Subsidiaries.

     The Company issued the outstanding notes, and it will issue the exchange notes, under an indenture dated March 21, 2003 among itself, the Guarantors and US Bank National Association, as trustee. The outstanding notes were issued in a private transaction that is not subject to the registration requirements of the Securities Act. See “Notice to Investors.” The terms of the notes include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939 (the“Trust Indenture Act”).

     The following description is a summary of the provisions of the indenture and the registration rights agreement that we consider material. It does not restate those agreements in their entirety. We urge you to read the indenture and the registration rights agreement because they, and not this description, define your rights as a holder of the notes. Copies of the indenture and the registration rights agreement are available as set forth below under “— Additional Information.” Defined terms used in this description but not defined below under “— Certain Definitions” have the meanings assigned to them in the indenture.

     The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture.

Brief Description of the Notes and the Guarantees

The Notes

     The notes are:

•  general unsecured obligations of the Company;

•  senior in right of payment to any subordinated Indebtedness of the Company;

•  pari passuin right of payment with any senior Indebtedness of the Company;

•  effectively junior in right of payment to the Company’s existing and future secured Indebtedness, including Indebtedness under the Credit Agreement, to the extent of the value of the collateral securing that Indebtedness; and

•  guaranteed by all of the Company’s existing Restricted Subsidiaries and future Restricted Subsidiaries that are Domestic Subsidiaries, other than the Specified Subsidiaries.

The Subsidiary Guarantees

     Each Subsidiary Guarantee of the notes is:

•  a senior unsecured obligation of each Subsidiary Guarantor;

•  senior in right of payment to all subordinated Indebtedness of that Subsidiary Guarantor;

•  pari passuin right of payment with all Indebtedness of that Subsidiary Guarantor that is not by its terms expressly subordinated to the guarantee of the Notes; and

•  effectively junior in right of payment to the existing and future secured Indebtedness of that Subsidiary Guarantor, including the guarantee of the Credit Agreement, to the extent of the value of the collateral securing that Indebtedness.

     As of March 31, 2003, the Company had approximately $1,659.6 million of Indebtedness outstanding on a consolidated basis (including the notes and including $465 million of 8 7/8% Senior Notes and 9 5/8% Senior Subordinated Notes, which were redeemed on May 15, 2003), approximately $450.0 million of which was secured Indebtedness under the Credit Agreement. The indenture permits substantial additional borrowings under the Credit Agreement in the future. See “Risk Factors — Risks Relating to the Exchange Offer and the

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Notes — The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors’ existing and future secured indebtedness.”

     The operations of the Company are conducted through its Subsidiaries and, therefore, the Company is dependent upon the cash flow of its Subsidiaries to meet its obligations, including its obligations under the notes. The notes are effectively subordinated to all Indebtedness and other liabilities and commitments (including trade payables and lease obligations) of the Company’s Subsidiaries. Any right of the Company to receive assets of any of its Subsidiaries upon the latter’s liquidation or reorganization (and the consequent right of the holders of the notes to participate in those assets) is effectively subordinated to the claims of that Subsidiary’s creditors, except to the extent that the Company is itself recognized as a creditor of such Subsidiary, in which case the claims of the Company would still be subordinate to any security in the assets of such Subsidiary and any indebtedness of such Subsidiary senior to that held by the Company. See “Risk Factors — Risks Relating to the Exchange Offer and the Notes — The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors’ existing and future secured indebtedness.”

     All of the Company’s existing Subsidiaries, other than the Specified Subsidiaries, are, and all of the Company’s Future Subsidiaries will be, Restricted Subsidiaries. However, under certain circumstances, the Company is able to designate current or future Subsidiaries as Unrestricted Subsidiaries. Unrestricted Subsidiaries are not subject to many of the restrictive covenants set forth in the indenture.

Principal, Maturity and Interest

     The Company issued an aggregate principal amount of $650.0 million of notes in March 2003. The Company may issue an unlimited amount of additional notes under the indenture from time to time after this offering, subject to the covenant described below under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock.” The notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. The Company will issue notes in denominations of $1,000 and integral multiples of $1,000. The notes mature on March 15, 2013.

     Interest on the notes accrues at the rate of 6 7/8% per annum and is payable semi-annually in arrears on March 15 and September 15, commencing on September 15, 2003. The Company will make each interest payment to the holders of record on the immediately preceding March 1 and September 1.

     Interest on the notes accrues from March 21, 2003 or, if interest has already been paid, from the date it was most recently paid. Interest is computed on the basis of a 360-day year comprised of twelve 30-day months.

Methods of Receiving Payments on the Notes

     If a holder has given wire transfer instructions to the Company, it will pay all principal, interest, premium and liquidated damages under the registration rights agreement (“Liquidated Damages”), if any, on that holder’s notes in accordance with those instructions. All other payments on notes will be made at the office or agency of the paying agent and registrar within the City and State of New York unless the Company elects to make interest payments by check mailed to the holders at their addresses set forth in the register of holders.

Exchange Agent and Registrar for the Notes

     The trustee will initially act as exchange agent and registrar. The Company may change the exchange agent or registrar without prior notice to the holders of the notes, and the Company or any of its Subsidiaries may act as exchange agent or registrar.

Transfer and Exchange

     A holder may transfer or exchange notes in accordance with the indenture. The registrar and the trustee may require a holder to furnish appropriate endorsements and transfer documents in connection with a

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transfer of notes. Holders will be required to pay all taxes due on transfer. The Company is not required to transfer or exchange any note selected for redemption. Also, the Company is not required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed. See “— Book-Entry, Delivery and Form” below for additional information.

Subsidiary Guarantees

     The Company’s payment obligations under the notes are fully and unconditionally, and jointly and severally, guaranteed by the Subsidiary Guarantors. Notwithstanding the foregoing, no Subsidiary of the Company is required to endorse a Subsidiary Guarantee unless such Subsidiary is required to, and does, simultaneously execute a Guarantee under the Credit Agreement. The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited to the maximum amount that would not constitute a fraudulent conveyance under applicable law. See “Risk Factors — Risks Relating to the Exchange Offer and the Notes — Federal and state fraudulent transfer laws permit a court to void the guarantees, and, if that occurs, you may not receive any payments on the notes.”

     No Subsidiary Guarantor may 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 the provisions of the following paragraph, the Person formed by or surviving any such consolidation or merger (if other than such Subsidiary Guarantor) 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 registration rights agreement; (ii) immediately after giving effect to such transaction, no Default or Event of Default exists; and (iii) (A) the Company would be permitted by virtue of the Company’s pro forma Fixed Charge Coverage Ratio, immediately after giving effect to such transaction, to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the covenant described below under the caption “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” or (B) the Fixed Charge Coverage Ratio for the Company and its Restricted Subsidiaries would not be less than such ratio immediately prior to such transaction.

     In the event of (a) a sale or other disposition of all of the assets of any Subsidiary Guarantor, by way of merger, consolidation or otherwise, (b) a sale or other disposition of all of the capital stock of any Subsidiary Guarantor or (c) the designation of a Subsidiary Guarantor as an Unrestricted Subsidiary in accordance with the terms of the indenture, then such Subsidiary Guarantor (in the event of a sale or other disposition, by way of such a 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 of the assets of such Subsidiary Guarantor) will be released and relieved of any obligations under its Subsidiary Guarantee;providedthat the Net Proceeds of any such sale or other disposition are applied in accordance with the applicable provisions of the indenture and any such designation of a Subsidiary Guarantor as an Unrestricted Subsidiary complies with all applicable covenants. See “— Repurchase at the Option of Holders — Asset Sales.”

Optional Redemption

     The notes are subject to redemption at any time at the option of the Company, in whole or in part, upon not less than 30 nor more than 60 days’ notice.

     Prior to March 15, 2008, the notes are redeemable at a redemption price equal to 100% of the principal amount thereof plus the applicable Make Whole Premium, plus, to the extent not included in the Make Whole Premium, accrued and unpaid interest and Liquidated Damages, if any, to the date of redemption. For purposes of the foregoing,“Make Whole Premium” means, with respect to a note, an amount equal to the excess of (1) the present value of the remaining interest, premium, if any, and principal payments due on such note as if such note were redeemed on March 15, 2008, computed using a discount rate equal to the Treasury Rate plus 50 basis points, over (2) the outstanding principal amount of such note.

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     On or after March 15, 2008, the notes are redeemable at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest and Liquidated Damages, if any, thereon to the applicable redemption date, if redeemed during the twelve-month period beginning on March 15 of the years indicated below:

Year	Percentage
2008		103.438	%
2009		102.292	%
2010		101.146	%
2011 and thereafter		100.000	%

     Notwithstanding the foregoing, on or prior to March 21, 2006, the Company may on any one or more occasions redeem up to 35% of the aggregate principal amount of notes issued under the indenture at a redemption price of 106.875% of the principal amount thereof, plus accrued and unpaid interest and Liquidated Damages thereon, if any, to the redemption date, with the net cash proceeds of one or more Equity Offerings;providedthat at least 65% of the aggregate principal amount of notes issued remain outstanding immediately after the occurrence of such redemption (excluding notes held by the Company and its Subsidiaries); andprovided further, that such redemption shall occur within 120 days of the date of the closing of such Equity Offering.

Mandatory Redemption

     The Company is not required to make mandatory redemption or sinking fund payments with respect to the notes.

Covenant Termination

     Upon the first date upon which the notes have an Investment Grade Rating from both of the Rating Agencies and no Default or Event of Default has occurred and is continuing under the indenture (the“Investment Grade Date”), the Company and its Restricted Subsidiaries will cease to be subject to the provisions of the indenture described below, which will be deemed to be terminated as of and from such date, under the following captions:

•  “— Repurchase at the Option of Holders — Asset Sales,”

•  “— Certain Covenants — Restricted Payments,”

•  “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock,”

•  “— Certain Covenants — Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries,”

•  “— Certain Covenants — Transactions with Affiliates,”

•  “— Certain Covenants — Business Activities,” and

•  “— Certain Covenants — Payments for Consent,”

     provided, however, that the provisions of the indenture described below under the following captions will not be so terminated:

•  “— Repurchase at the Option of Holders — Change of Control Triggering Event,”

•  “— Certain Covenants — Liens,”

•  “— Certain Covenants — Merger, Consolidation or Sale of Assets” (except as set forth in that covenant),

•  “— Certain Covenants — Additional Subsidiary Guarantees” (except as set forth in that covenant), and

•  “— Certain Covenants — Reports.”

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As a result, the notes will be entitled to substantially less covenant protection from and after the Investment Grade Date.

Repurchase at the Option of Holders

Change of Control Triggering Event

     Upon the occurrence of a Change of Control Triggering Event, each holder of notes has the right to require the Company to repurchase all or any part (equal to $1,000 or an integral multiple thereof) of such holder’s notes pursuant to the offer described below (the“Change of Control Offer”) at an offer price in cash equal to 101% of the aggregate principal amount thereof plus accrued and unpaid interest and Liquidated Damages thereon, if any, to the date of purchase (the“Change of Control Payment”). Within ten days following any Change of Control Triggering Event, the Company will mail a notice to each holder describing the transaction or transactions that constitute the Change of Control Triggering Event and offering to repurchase notes on the date specified in such notice, which date shall be no earlier than 30 days and no later than 60 days from the date such notice is mailed (the“Change of Control Payment Date”), pursuant to the procedures required by the indenture and described in such notice. The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the repurchase of the notes as a result of a Change of Control Triggering Event. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control Triggering Event provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control Triggering Event provisions of the indenture by virtue of such conflict.

     On the Change of Control Payment Date, the Company will, to the extent lawful, (1) accept for payment all notes or portions thereof properly tendered pursuant to the Change of Control Offer, (2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions thereof so tendered and (3) deliver or cause to be delivered to the trustee the notes so accepted together with an officers’ certificate stating the aggregate principal amount of notes or portions thereof being purchased by the Company. The paying agent will promptly mail to each holder of notes so tendered the Change of Control Payment for such notes, and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each such new note will be in a principal amount of $1,000 or an integral multiple thereof. Prior to complying with the provisions of this covenant, but in any event within 90 days following a Change of Control Triggering Event, the Company will either repay all outstanding Senior Debt other than the notes or obtain the requisite consents, if any, under all agreements governing outstanding Senior Debt other than the notes to permit the repurchase of notes required by this covenant. The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date.

     The Change of Control Triggering Event provisions described above will be applicable whether or not any other provisions of the indenture are applicable. Except as described above with respect to a Change of Control Triggering Event, the indenture will not contain provisions that permit the holders of the notes to require that the Company repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

     The Company’s other senior Indebtedness contains, or in the future may contain, prohibitions on certain events that would constitute a Change of Control. In addition, the exercise by the holders of notes of their right to require the Company to repurchase the notes could cause a default under such other senior indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchases on the Company. Finally, the Company’s ability to pay cash to the holders of notes upon a repurchase may be limited by the Company’s then existing financial resources. See “Risk Factors — Risks Relating to the Exchange Offer and the Notes — We may be unable to purchase the notes upon a change of control coupled with a ratings decline.”

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     The Credit Agreement will restrict the Company from purchasing the notes, and also will provide that certain change of control events with respect to the Company would constitute a default thereunder. Indebtedness incurred by the Company in the future may contain similar restrictions and provisions. In the event a Change of Control Triggering Event occurs at a time when the Company is prohibited from purchasing notes, the Company could seek the consent of its lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If the Company does not obtain such a consent or repay such borrowings, the Company will remain prohibited from purchasing notes. In such case, the Company’s failure to purchase tendered notes would constitute an Event of Default under the indenture which would, in turn, constitute a default under the Credit Agreement.

     The Company will not be required to make a Change of Control Offer upon a Change of Control Triggering Event if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by the Company and purchases all notes validly tendered and not withdrawn under such Change of Control Offer or if the Company exercises its option to purchase the notes.

     “Change of Control” means the occurrence of any of the following: (i) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Section 13(d)(3) of the Exchange Act) other than a Principal or a Related Party of a Principal (as defined below), (ii) the adoption of a plan relating to the liquidation or dissolution of the Company, (iii) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any “person” (as defined above), other than the Principals and their Related Parties, becomes the “beneficial owner” (as such term is defined in Rule 13d-3 and Rule 13d-5 under the Exchange Act), directly or indirectly, of more than 50% of the Voting Stock of the Company (measured by voting power rather than number of shares) or (iv) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors.

     The definition of Change of Control includes a phrase relating to the sale, lease, transfer, conveyance or other disposition of “all or substantially all” of the assets of the Company and its Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Company to repurchase such notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Company and its Subsidiaries taken as a whole to another Person or group may be uncertain.

     “Change of Control Triggering Event” means the occurrence of both a Change of Control and a Rating Decline with respect to the Notes.

     “Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company who (i) was a member of such Board of Directors on the date of the indenture or (ii) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election.

     “Principals” means Lehman Brothers Merchant Banking Partners II L.P., any of its respective Affiliates and executive officers of the Company as of the date of the indenture.

     “Related Party” with respect to any Principal means (A) any controlling stockholder, 80% (or more) owned Subsidiary, or spouse or immediate family member (in the case of an individual) of such Principal or (B) any trust, corporation, partnership or other entity, the beneficiaries, stockholders, partners, owners or Persons beneficially holding an 80% or more controlling interest of which consist of such Principal and/or such other Persons referred to in the immediately preceding clause (A).

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     “Rating Date”means the date which is 90 days prior to the earlier of:

     (a) a Change of Control, and

     (b) public notice of the occurrence of a Change of Control or of the intention of the Company to effect a Change of Control.

     “Rating Decline”means the occurrence of the following on, or within, 90 days before or after the earlier of: (i) the date of public notice of the occurrence of a Change of Control or (ii) public notice of the intention of the Company to effect a Change of Control (which 90-day period shall be extended so long as the rating of the Notes is under publicly announced consideration for possible downgrade by any of the Rating Agencies):

     (a) in the event the Notes are assigned an Investment Grade Rating by both Rating Agencies on the Rating Date, the rating of the Notes by one of the Rating Agencies shall be below an Investment Grade Rating; or

     (b) in the event the Notes are rated below an Investment Grade Rating by at least one of the Rating Agencies on the Rating Date, the rating of the Notes by at least one of the Rating Agencies shall be decreased by one or more gradations (including gradations within rating categories as well as between rating categories).

     Asset Sales

     The Company will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless (i) the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of such Asset Sale at least equal to the fair market value as determined in good faith by the Company of the assets or Equity Interests issued or sold or otherwise disposed of and (ii) at least 75% of the consideration therefore received by the Company or such Subsidiary is in the form of cash, Cash Equivalents or Marketable Securities;providedthat the following amounts shall be deemed to be cash: (w) any liabilities (as shown on the Company’s or such Restricted Subsidiary’s most recent balance sheet), of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the notes or any guarantee thereof) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Company or such Restricted Subsidiary from further liability, (x) any securities, notes or other obligations received by the Company or any such Restricted Subsidiary from such transferee that are converted by the Company or such Restricted Subsidiary into cash within 180 days following the closing of such Asset Sale (to the extent of the cash received), (y) any Designated Noncash Consideration received by the Company or any of its Restricted Subsidiaries in such Asset Sale;providedthat the aggregate fair market value (as determined above) of such Designated Noncash Consideration, taken together with the fair market value at the time of receipt of all other Designated Noncash Consideration received pursuant to this clause (y) less the amount of Net Proceeds previously realized in cash from prior Designated Noncash Consideration is less than 10% of Total Assets at the time of the receipt of such Designated Noncash Consideration (with the fair market value of each item of Designated Noncash Consideration being measured at the time received and without giving effect to subsequent changes in value) and (z) Additional Assets received in an exchange of assets transaction.

     Within 360 days after the receipt of any cash Net Proceeds from an Asset Sale, the Company or such Restricted Subsidiary, at its option, may apply such cash Net Proceeds, at its option, (a) to repay Indebtedness of the Company or any Restricted Subsidiary that is not subordinated in right of payment to Indebtedness under a Credit Facility, (b) to the acquisition of a majority of the assets of, or a majority of the Voting Stock of, another Permitted Business, the making of a capital expenditure or the acquisition of other assets or Investments that are used or useful in a Permitted Business or (c) to apply the cash Net Proceeds from such Asset Sale to an Investment in Additional Assets. Any cash Net Proceeds from Asset Sales that are not applied or invested as provided in the first sentence of this paragraph will be deemed to constitute “Excess Proceeds.” When the aggregate amount of Excess Proceeds exceeds $20.0 million, the Company will be required to make an offer to all holders of notes and all holders of other Indebtedness that ranks equally with

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the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase or redeem with the proceeds of sales of assets (an“Asset Sale Offer”) to purchase the maximum principal amount of notes and such other Indebtedness that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount thereof plus accrued and unpaid interest and Liquidated Damages thereon, if any, to the date of purchase, in accordance with the procedures set forth in the indenture and such other Indebtedness. To the extent that any Excess Proceeds remain after consummation of an Asset Sale Offer, the Company may use such Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and such other Indebtedness tendered into such Asset Sale Offer surrendered by holders thereof exceeds the amount of Excess Proceeds, the trustee shall select the notes and such other Indebtedness to be purchased on a pro rata basis. Upon completion of such offer to purchase, the amount of Excess Proceeds shall be reset at zero.

     The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sale provisions of the indenture, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such conflict.

Selection and Notice

     If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption as follows:

     (1) if the notes are listed on any national securities exchange, in compliance with the requirements of the principal national securities exchange on which the notes are listed; or

     (2) if the notes are not listed on any national securities exchange, on a pro rata basis, by lot or by such method as the trustee deems fair and appropriate.

     No notes of $1,000 principal amount or less can be redeemed in part. Notices of redemption will be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be mailed more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture. Notices of redemption may not be conditional.

     If any note is to be redeemed in part only, the notice of redemption that relates to that note will state the portion of the principal amount of that note that is to be redeemed. A new note in principal amount equal to the unredeemed portion of the original note will be issued in the name of the holder of notes upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption. On and after the redemption date, interest ceases to accrue on notes or portions of them called for redemption.

Certain Covenants

     The indenture contains the following covenants:

     Restricted Payments

     The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly: (i) declare or pay any dividend or make any other payment or distribution on account of the Company’s or any of its Restricted Subsidiaries’ Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) or to the direct or indirect holders of the Company’s or any of its Restricted Subsidiaries’ Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company); (ii) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving the Company) any Equity Interests of the Company or

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any direct or indirect parent of the Company; (iii) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness that is subordinated to the notes or any Subsidiary Guarantee, except a payment of interest or principal at Stated Maturity or Indebtedness permitted under clause (vii) of the covenant described under “— Incurrence of Indebtedness and Issuance of Preferred Stock;” or (iv) make any Restricted Investment (all such payments and other actions set forth in clauses (i) through (iv) above being collectively referred to as“Restricted Payments”), unless, at the time of and after giving effect to such Restricted Payment:

     (a) no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof; and

     (b) the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock;” and

     (c) such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by the Company and its Subsidiaries after the date of the May 1998 Senior Note Indenture (excluding Restricted Payments permitted by clauses (ii), (iii), (iv), (v), (ix), (x) and (xi) of the next succeeding paragraph), is less than the sum, without duplication, of (i) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from the beginning of the first fiscal quarter commencing after the date of the May 1998 Senior Note Indenture to the end of the Company’s most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus (ii) 100% of the aggregate net cash proceeds received by the Company (including the fair market value of any Permitted Business or assets used or useful in a Permitted Business to the extent acquired in consideration of Equity Interests (other than Disqualified Stock) of the Company) since the date of the May 1998 Senior Note Indenture as a contribution to its common equity capital or from the issue or sale of Equity Interests of the Company (other than Disqualified Stock and other than sales to a Subsidiary of the Company) or from the issue or sale of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of the Company that have been converted into or exchanged for such Equity Interests (other than Disqualified Stock or debt securities sold to a Subsidiary of the Company), plus (iii) to the extent that any Restricted Investment that reduced the amount available for Restricted Payments under this clause (c) is sold for cash or otherwise liquidated or repaid for cash or any dividend or payment is received by the Company or a Restricted Subsidiary after the date of the date of the May 1998 Senior Note Indenture in respect of such Investment, 100% of the amount of Net Proceeds or dividends or payments (including the fair market value of property) received in connection therewith, up to the amount of the Restricted Investment that reduced this clause (c), as the case may be, and thereafter 50% of the amount of Net Proceeds or dividends or payments (including the fair market value of property) received in connection therewith (except that the amount of dividends or payments received in respect of payments of Obligations in respect of such Investments, such as taxes, shall not increase the amounts under this clause (c)), plus (iv) to the extent that any Unrestricted Subsidiary of the Company is redesignated as a Restricted Subsidiary after the date of the indenture, 100% of the fair market value of the Company’s Investment in such Subsidiary as of the date of such redesignation up to the amount of the Restricted Investments made in such Subsidiary that reduced this clause (c) and 50% of the excess of the fair market value of the Company’s Investment in such Subsidiary as of the date of such redesignation over (1) the amount of the Restricted Investment that reduced this clause (c) and (2) any amounts that increased the amount available as a Permitted Investment;provided, further, that any amounts that increase this clause (c) shall not duplicatively increase amounts available as Permitted Investments.

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     The foregoing provisions will not prohibit:

     (i) the payment of any dividend within 60 days after the date of declaration thereof, if at said date of declaration such payment would have complied with the provisions of the indenture;

     (ii) the redemption, repurchase, retirement, defeasance or other acquisition of any subordinated Indebtedness or Equity Interests of the Company in exchange for, or out of the net cash proceeds of the substantially concurrent sale (other than to a Restricted Subsidiary of the Company) of, other Equity Interests of the Company (other than any Disqualified Stock);providedthat the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement, defeasance or other acquisition shall be excluded from clause (c)(ii) of the preceding paragraph;

     (iii) the defeasance, redemption, repurchase or other acquisition of subordinated Indebtedness with the net cash proceeds from an incurrence of Permitted Refinancing Indebtedness;

     (iv) dividends or distributions by a Restricted Subsidiary of the Company so long as, in the case of any dividend or distribution payable on or in respect of any class or series of securities issued by a Restricted Subsidiary, the Company or a Restricted Subsidiary receives at least its pro rata share of such dividend or distribution in accordance with its Equity Interests in such class or series of securities;

     (v) Investments in Unrestricted Subsidiaries having an aggregate fair market value not to exceed the amount, at the time of such Investment, substantially concurrently contributed in cash or Cash Equivalents to the common equity capital of the Company after the date of the indenture;providedthat any such amount contributed shall be excluded from the calculation made pursuant to clause (c) above;

     (vi) the payment of dividends on the Company’s Common Stock in an amount which, when combined with all such dividends, does not exceed $35.0 million in the aggregate in any calendar year;

     (vii) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company held by any present or former employee or director of the Company (or any of its Restricted Subsidiaries) pursuant to any management equity subscription agreement or stock option agreement or any other management or employee benefit plan in effect as of the date of the indenture;providedthat (A) the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests shall not exceed $5.0 million in any twelve-month period (with unused amounts in any calendar year being carried over to succeeding calendar years subject to a maximum (without giving effect to the following proviso) of $10.0 million in any calendar year);provided furtherthat such amount in any calendar year may be increased by an amount not to exceed (x) the cash proceeds from the sale of Equity Interests of the Company or a Restricted Subsidiary to members of management and directors of the Company and its Subsidiaries that occurs after the date of the indenture, plus (y) the cash proceeds of key-man life insurance policies received by the Company and its Restricted Subsidiaries after the date of the indenture, less (z) the amount of any Restricted Payments previously made pursuant to clauses (x) and (y) of this subparagraph (vii); and,provided further, that cancellation of Indebtedness owing to the Company from members of management of the Company or any of its Restricted Subsidiaries in connection with a repurchase of Equity Interests of the Company or a Restricted Subsidiary will not be deemed to constitute a Restricted Payment for purposes of this covenant or any other provision of the indenture and (B) no Default or Event of Default shall have occurred and be continuing immediately after such transaction;

     (viii) repurchases of Equity Interests deemed to occur upon exercise of stock options if such Equity Interests represent a portion of the exercise price of such options;

     (ix) the repurchase, redemption or other acquisition or retirement for value of the Senior Subordinated Notes;

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     (x) the repurchase, redemption or other acquisition or retirement for value of the 5% Subordinated Note; and

     (xi) other Restricted Payments not otherwise prohibited by this covenant in an aggregate amount not to exceed $25.0 million under this clause (xi).

     All of the Company’s existing Subsidiaries, other than the Specified Subsidiaries, are Restricted Subsidiaries. The Board of Directors may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if such designation would not cause a Default. For purposes of making such determination, all outstanding Investments by the Company and its Restricted Subsidiaries (except to the extent repaid in cash) in the Subsidiary so designated will be deemed to be Restricted Payments at the time of such designation and will reduce the amount available for Restricted Payments under the first paragraph of this covenant. All such outstanding Investments will be deemed to constitute Investments in an amount equal to the fair market value of such Investments at the time of such designation. Such designation will only be permitted if such Restricted Payment would be permitted at such time and if such Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary.

     If, at any time, any Unrestricted Subsidiary would fail to meet the requirements in the definition of “Unrestricted Subsidiary” as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary shall be deemed to be incurred by a Restricted Subsidiary of the Company as of such date (and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock,” the Company shall be in default of such covenant). The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary;providedthat such designation shall be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary and such designation shall only be permitted if (i) such Indebtedness is permitted under the covenant described under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock,” calculated on a pro forma basis as if such designation had occurred at the beginning of the four-quarter reference period, and (ii) no Default or Event of Default would be in existence following such designation.

     The amount of all Restricted Payments (other than cash) shall be the fair market value on the date of the Restricted Payment of the asset(s) or securities proposed to be transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. The fair market value of any noncash Restricted Payment or any adjustment made pursuant to paragraph (c) of this covenant shall be determined by the Board of Directors whose resolution with respect thereto shall be delivered to the trustee, such determination to be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if such fair market value exceeds $25.0 million. Not later than the date of making any Restricted Payment, the Company shall deliver to the trustee an officers’ certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by the covenant “Restricted Payments” were computed.

     If any Restricted Investment is sold or otherwise liquidated or repaid or any dividend or payment is received by the Company or a Restricted Subsidiary and such amounts may be credited to clause (c) above, then such amounts will be credited only to the extent of amounts not otherwise included in Consolidated Net Income and that do not otherwise increase the amount available as a Permitted Investment.

Incurrence of Indebtedness and Issuance of Preferred Stock

     The Company will not, and will not permit any of its Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively,“incur”) any Indebtedness (including Acquired Debt) and that the Company will not issue any Disqualified Stock and will not permit any of its Subsidiaries to issue any shares of preferred stock;provided, however, that the Company may incur Indebtedness (including Acquired Debt) or issue shares of Disqualified Stock and the Company’s Restricted Subsidiaries may incur Indebtedness or issue Disqualified Stock or preferred stock if the Fixed Charge Coverage Ratio for the Company’s most recently ended four full

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fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or preferred stock is issued would have been at least 2.0 to 1.0, determined on a pro forma basis (including a pro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred, or the Disqualified Stock or preferred stock had been issued, as the case may be, at the beginning of such four-quarter period.

     In addition to the foregoing, the provisions of the first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness (collectively,“Permitted Debt”):

     (i) the incurrence by the Company of additional Indebtedness under any Credit Facilities (and the Guarantee thereof by the Subsidiary Guarantors);providedthat the aggregate principal amount of all Indebtedness outstanding under this clause (i) after giving effect to such incurrence does not exceed an amount equal to $1,050.0 million;

     (ii) the incurrence by the Company and its Restricted Subsidiaries of the Existing Indebtedness;

     (iii) the incurrence by the Company and the Subsidiary Guarantors of Indebtedness represented by the outstanding notes and any Exchange Notes issued in respect of outstanding notes under the indenture;

     (iv) (A) the Guarantee by the Company or any of the Subsidiary Guarantors of Indebtedness of the Company or a Restricted Subsidiary of the Company or (B) the incurrence of Indebtedness of a Restricted Subsidiary to the extent that such Indebtedness is supported by a letter of credit, in each case that was permitted to be incurred by another provision of this covenant;

     (v) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness (including Capital Lease Obligations) to finance the acquisition (including by direct purchase, by lease or indirectly by the acquisition of the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of such acquisition) or improvement of property (real or personal) in an aggregate principal amount which, when aggregated with the principal amount of all other Indebtedness then outstanding pursuant to this clause (v) and including all Permitted Refinancing Indebtedness incurred to refund, refinance or replace any Indebtedness incurred pursuant to this clause (v), does not exceed an amount equal to 5% of Total Assets at the time of such incurrence;

     (vi) the incurrence by the Company or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to refund, refinance or replace Indebtedness (other than intercompany Indebtedness) that was permitted by the indenture to be incurred under the first paragraph hereof or clauses (ii), (iii) or (vi) of this paragraph;

     (vii) the incurrence by the Company or any of its Restricted Subsidiaries of intercompany Indebtedness between or among the Company and any of its Restricted Subsidiaries;provided, however, that (i) if the Company is the obligor on such Indebtedness, such Indebtedness is expressly subordinated to the prior payment in full in cash of all Obligations with respect to the notes and (ii)(A) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary thereof and (B) any sale or other transfer of any such Indebtedness to a Person that is not either the Company or a Restricted Subsidiary thereof shall be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (vii);

     (viii) the incurrence by the Company or any of its Restricted Subsidiaries of Hedging Obligations that are incurred in the ordinary course of business for the purpose of risk management and not for the purpose of speculation;

     (ix) the incurrence by the Company’s Unrestricted Subsidiaries of Non- Recourse Debt,provided, however, that if any such Indebtedness ceases to be Non-Recourse Debt of an Unrestricted Subsidiary, such event shall be deemed to constitute an incurrence of Indebtedness by a Restricted Subsidiary of the Company that was not permitted by this clause (ix), and the issuance of preferred stock by Unrestricted Subsidiaries;

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     (x) the incurrence of Indebtedness solely in respect of performance, surety and similar bonds and letters of credit or completion or performance guarantees (including, without limitation, performance guarantees pursuant to coal supply agreements or equipment leases), to the extent that such incurrence does not result in the incurrence of any obligation for the payment of borrowed money to others;

     (xi) the incurrence of Indebtedness arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, adjustment of purchase price or similar obligations, in each case, incurred or assumed in connection with the disposition of any business, assets or a Subsidiary;provided, howeverthat (i) such Indebtedness is not reflected on the balance sheet of the Company or any Restricted Subsidiary (contingent obligations referred to in a footnote to financial statements and not otherwise reflected on the balance sheet will not be deemed to be reflected on such balance sheet for purposes of this clause (i)) and (ii) the maximum assumable liability in respect of all such Indebtedness shall at no time exceed the gross proceeds including noncash proceeds (the fair market value of such noncash proceeds being measured at the time received and without giving effect to any subsequent changes in value) actually received by the Company and its Restricted Subsidiaries in connection with such disposition; and

     (xii) the incurrence by the Company or any of its Restricted Subsidiaries of additional Indebtedness in an aggregate principal amount (or accreted value, as applicable) at any time outstanding, including all Permitted Refinancing Indebtedness incurred to refund, refinance or replace any Indebtedness incurred pursuant to this clause (xii), not to exceed $350.0 million.

     The Company will not incur, and will not permit its Restricted Subsidiaries to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of the Company or such Restricted Subsidiary unless such Indebtedness is also contractually subordinated in right of payment to the notes, or the Subsidiary Guarantees, as the case may be, on substantially identical terms;provided, however, that no Indebtedness of the Company or any Restricted Subsidiary shall be deemed to be contractually subordinated in right of payment to any other Indebtedness of the Company or any Restricted Subsidiary solely by virtue of being unsecured.

     For purposes of determining compliance with this covenant:

     (1) in the event that an item of proposed Indebtedness, including Acquired Debt, meets the criteria of more than one of the categories of Permitted Debt described in clauses (i) through (xii) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, the Company will be permitted to classify such item of Indebtedness on the date of its incurrence (or later classify or reclassify such Indebtedness, in its sole discretion) in any manner that complies with this covenant;

     (2) for the purposes of determining compliance with any dollar-denominated restriction on the incurrence of Indebtedness denominated in a foreign currency, the dollar-equivalent principal amount of such Indebtedness incurred pursuant thereto shall be calculated based on the relevant currency exchange rate in effect on the date that such Indebtedness was incurred; and

     (3) accrual of interest, accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, and the payment of dividends on Disqualified Stock in the form of additional shares of the same class of Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of Disqualified Stock for purposes of this covenant;provided, in each such case, that the amount thereof is included in the Fixed Charges of the Company as accrued.

Liens

     The Company will not and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, assume or otherwise cause or suffer to exist or become effective with respect to any Indebtedness any Lien of any kind (other than Permitted Liens) upon any of their property or assets, now owned or hereafter acquired, unless all payments due under the indenture and the notes are secured on an equal and ratable basis (or, if the Lien secured Indebtedness subordinated to the notes or the Subsidiary

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Guarantees, then senior to the obligations so secured) with the obligations so secured until such time as such obligations are no longer secured by a Lien.

Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

     The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or otherwise cause or suffer to exist or become effective any encumbrance or restriction on the ability of any Restricted Subsidiary that is not a Subsidiary Guarantor to (i)(a) pay dividends or make any other distributions to the Company or any of its Restricted Subsidiaries (1) on its Capital Stock or (2) with respect to any other interest or participation in, or measured by, its profits, or (b) pay any indebtedness owed to the Company or any of its Restricted Subsidiaries, (ii) make loans or advances to the Company or any of its Restricted Subsidiaries or (iii) transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries. However, the foregoing restrictions will not apply to encumbrances or restrictions existing under or by reason of (a) Existing Indebtedness as in effect on the date of the indenture, (b) the Credit Agreement, (c) the indenture, the notes and Subsidiary Guarantees, (d) applicable law or any applicable rule, regulation or order, (e) any instrument governing Indebtedness or Capital Stock of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired,providedthat, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred, (f) customary non-assignment provisions in leases and other agreements entered into in the ordinary course of business and consistent with past practices, (g) purchase money obligations for property acquired in the ordinary course of business that impose restrictions of the nature described in clause (iii) above on the property so acquired, (h) any agreement for the sale of a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending its sale, (i) Permitted Refinancing Indebtedness,providedthat the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are no more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced, (j) secured Indebtedness otherwise permitted to be incurred pursuant to the provisions of the covenant described above under the caption “— Liens” that limits the right of the debtor to dispose of the assets securing such Indebtedness, (k) provisions with respect to the disposition or distribution of assets or property in joint venture agreements and other similar agreements entered into in the ordinary course of business, (l) restrictions on cash or other deposits or net worth imposed by customers or lessors under contracts or leases entered into in the ordinary course of business and (m) any encumbrances or restrictions imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of the contracts, instruments or obligations referred to in clauses (a) through (l) above,providedthat such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of the Company’s Board of Directors, not materially more restrictive in the aggregate with respect to such dividend and other payment restrictions than those (considered as a whole) contained in the dividend or other payment restrictions prior to such amendment, modification, restatement, renewal, increase, supplement, refunding, replacement or refinancing.

Merger, Consolidation or Sale of Assets

     The Company may not consolidate or merge with or into (whether or not the Company is the surviving corporation), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets in one or more related transactions, to another corporation, Person or entity unless (i) the Company is the surviving corporation or the entity or the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made is a corporation organized or existing under the laws of the United States, any state thereof or the District of Columbia; (ii) the entity or Person formed by or surviving any such consolidation or merger (if other than the Company) or the entity or Person to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made assumes all the obligations of the Company under the registration rights agreement, the notes and the indenture pursuant to a

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supplemental indenture in a form reasonably satisfactory to the trustee; (iii) immediately after such transaction no Default or Event of Default exists; and (iv) except in the case of a merger of the Company with or into a Restricted Subsidiary of the Company, immediately after giving pro forma effect to such transaction, as if such transaction had occurred at the beginning of the applicable four-quarter period, (A) the entity surviving such consolidation or merger would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption “— Incurrence of Indebtedness and Issuance of Preferred Stock” or (B) the Fixed Charge Coverage Ratio for the Company or the entity or Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made would, immediately after giving pro forma effect thereto as if such transaction had occurred at the beginning of the applicable four-quarter period, would be not less than such Fixed Charge Coverage Ratio for the Company and its Restricted Subsidiaries immediately prior to such transaction;provided, however, that this clause (iv) shall no longer be applicable from and after any Investment Grade Date. The Company may not, directly or indirectly, lease all or substantially all of its properties or assets, in one or more related transactions, to any other Person. The provisions of this covenant will not be applicable to a sale, assignment, transfer, conveyance or other disposition of assets between or among the Company and its Restricted Subsidiaries.

     Notwithstanding the foregoing clause (iv), (i) any Restricted Subsidiary may consolidate with, merge into or transfer all or part of its properties and assets to the Company and (ii) the Company may merge with an Affiliate that has no significant assets or liabilities and was formed solely for the purpose of changing the jurisdiction of organization of the Company in another State of the United States or the form of organization of the Company so long as the amount of Indebtedness of the Company and its Restricted Subsidiaries is not increased thereby andprovidedthat the successor assumes all the obligations of the Company under the registration rights agreement, the notes and the indenture pursuant to a supplemental indenture in a form reasonably satisfactory to the trustee.

Transactions with Affiliates

     The Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate (each, an“Affiliate Transaction”), unless:

     (1) the Affiliate Transaction is on terms that are materially no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person; and

     (2) the Company delivers to the trustee:

     (a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $15.0 million, a resolution of the Board of Directors set forth in an officers’ certificate certifying that such Affiliate Transaction complies with this covenant and that such Affiliate Transaction has been approved by a majority of the disinterested members of the Board of Directors; and

     (b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $25.0 million, an opinion as to the fairness to the holders of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal or investment banking firm of national standing.

     Notwithstanding the foregoing, the following items shall not be deemed to be Affiliate Transactions: (i) any employment agreement or other compensation plan or arrangement for employees entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business and consistent with the past practice of the Company or such Restricted Subsidiary, (ii) transactions between or among the Company and/or its Restricted Subsidiaries, (iii) payment of reasonable fees to officers, directors, employees or

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consultants of the Company, (iv) Restricted Payments that are permitted by, and Investments that are not prohibited by, the provisions of the indenture described above under the caption “— Restricted Payments,” (v) indemnification payments made to officers, directors and employees of the Company or any Restricted Subsidiary pursuant to charter, bylaw, statutory or contractual provisions; (vi) the payment of customary annual management, consulting and advisory fees and related expenses to Lehman Merchant Bank and its Affiliates; (vii) payments by the Company or any of its Restricted Subsidiaries to Lehman Merchant Bank and its Affiliates made for any financial advisory, financing, underwriting or placement services or in respect of other investment banking activities, including, without limitation, in connection with acquisitions or divestitures which payments are approved by a majority of the Board of Directors of the Company in good faith; (viii) the existence of, or the performance by the Company or any of its Restricted Subsidiaries of its obligations under the terms of, any stockholders’ agreement (including any registration rights agreement or purchase agreement related thereto) to which it is a party as of the date of the indenture and any similar agreements which it may enter into thereafter;provided, however, that the existence of, or the performance by the Company or any of its Restricted Subsidiaries of obligations under any future amendment to any such existing agreement or under any similar agreement entered into after the date of the indenture shall only be permitted by this clause (viii) to the extent that the terms of any such amendment or new agreement are not otherwise disadvantageous to the holders in any material respect; (ix) transactions with Unrestricted Subsidiaries, customers, clients, suppliers, joint venture partners or purchasers or sellers of goods or services, in each case in the ordinary course of business (including, without limitation, pursuant to joint venture agreements) and otherwise in compliance with the terms of the indenture which are, in the aggregate (taking into account all the costs and benefits associated with such transactions), materially no less favorable to the Company or its Restricted Subsidiaries than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person, in the reasonable determination of the Board of Directors of the Company or the senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party; (x) guarantees of performance by the Company and its Restricted Subsidiaries of Unrestricted Subsidiaries in the ordinary course of business, except for guarantees of Obligations in respect of borrowed money; and (xi) pledges of Equity Interests of Unrestricted Subsidiaries for the benefit of lenders of Unrestricted Subsidiaries.

Additional Subsidiary Guarantees

     If the Company or any of its Domestic Subsidiaries shall acquire or create another Domestic Subsidiary after the date of the indenture and such Domestic Subsidiary provides a guarantee under the Credit Agreement, then such newly acquired or created Domestic Subsidiary shall execute a supplemental indenture in form and substance reasonably satisfactory to the trustee providing that such Domestic Subsidiary shall become a Subsidiary Guarantor under the indenture,provided, however, this covenant shall not apply to any Domestic Subsidiary that has been properly designated as an Unrestricted Subsidiary in accordance with the indenture for so long as it continues to constitute an Unrestricted Subsidiary.

Business Activities

     The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than Permitted Businesses, except to such extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

Payments for Consent

     The Company will not, and will not permit any of its Subsidiaries to, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fee or otherwise, to any holder of any notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the indenture or the notes unless such consideration is offered to be paid or is paid to all holders of the notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or agreement.

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Reports

     Whether or not required by the rules and regulations of the SEC, so long as any notes are outstanding, the Company will furnish to the holders of notes (i) all quarterly and annual financial information that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if the Company were required to file such Forms, including a “Management’s Discussion and Analysis of Financial Condition and Results of Operations” that describes the financial condition and results of operations of the Company and its consolidated Subsidiaries (showing in reasonable detail, either on the face of the financial statements or in the footnotes thereto and in Management’s Discussion and Analysis of Financial Condition and Results of Operations, the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company) and, with respect to the annual information only, a report thereon by the Company’s certified independent accountants and (ii) all current reports that would be required to be filed with the SEC on Form 8-K if the Company were required to file such reports, in each case within the time periods specified in the SEC’s rules and regulations. In addition, whether or not required by the rules and regulations of the SEC, the Company will file a copy of all such information and reports with the SEC for public availability within the time periods specified in the SEC’s rules and regulations (unless the SEC will not accept such a filing), make such information available to securities analysts and prospective investors upon request. In addition, the Company and the Subsidiary Guarantors have agreed that, for so long as any notes remain outstanding, they will furnish to the holders and to securities analysts and prospective investors, upon their request, the information, if any, required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of Default and Remedies

     Each of the following constitutes an Event of Default: (i) default for 30 days in the payment when due of interest on, or Liquidated Damages, if any, with respect to, the notes; (ii) default in payment when due of the principal of or premium, if any, on the notes; (iii) failure by the Company or any of its Subsidiaries to make the offer required or to purchase any of the notes as required under the provisions described under the captions “— Repurchase at the Option of Holders — Change of Control Triggering Event,” or “— Repurchase at the Option of Holders — Asset Sales;” (iv) failure by the Company or any of its Subsidiaries for 30 days after notice to comply with the provisions of the covenants entitled “— Certain Covenants — Restricted Payments” or “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock;” or failure by the Company or any of its Subsidiaries for 60 days after notice to comply with any of its other agreements in the indenture or the notes; (v) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries) whether such Indebtedness or guarantee now exists, or is created after the date of the indenture, which default results in the acceleration of such Indebtedness prior to its express maturity and the principal amount of any such Indebtedness aggregates $50.0 million or more; (vi) failure by the Company or any of its Restricted Subsidiaries or any group of Restricted Subsidiaries that, taken as a whole, would be a Significant Subsidiary to pay final judgments aggregating in excess of $50.0 million, which judgments are not paid, discharged or stayed for a period of 60 days; (vii) except as permitted by the indenture, any Subsidiary Guarantee shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Subsidiary Guarantor, or any Person acting on behalf of any Subsidiary Guarantor, shall deny or disaffirm its obligations under its Subsidiary Guarantee; and (viii) certain events of bankruptcy or insolvency with respect to the Company, any of its Significant Subsidiaries that are Restricted Subsidiaries or any group of Restricted Subsidiaries that, taken as a whole, would be a Significant Subsidiary.

     If any Event of Default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding notes may declare all the notes to be due and payable immediately;provided, that so long as any Indebtedness permitted to be incurred pursuant to the Credit Agreement shall be outstanding, such acceleration shall not be effective until the earlier of (i) an acceleration of any such Indebtedness under the Credit Agreement or (ii) five business days after receipt by the Company of written

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notice of such acceleration of the notes. Notwithstanding the foregoing, in the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to the Company, any Significant Subsidiary that is a Restricted Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding notes will become due and payable without further action or notice. Holders of the notes may not enforce the indenture or the notes except as provided in the indenture. Subject to certain limitations, holders of a majority in principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the notes notice of any continuing Default or Event of Default (except a Default or Event of Default relating to the payment of principal or interest) if it determines that withholding notice is in their interest.

     The holders of a majority in aggregate principal amount of the notes then outstanding by notice to the trustee may on behalf of the holders of all of the notes waive any existing Default or Event of Default and its consequences under the indenture except a continuing Default or Event of Default in the payment of interest on, or the principal of, the notes.

     The Company is required to deliver to the trustee annually a statement regarding compliance with the indenture, and the Company is required upon becoming aware of any Default or Event of Default, to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Stockholders

     No director, officer, employee, incorporator or stockholder of the Company or any Person controlling such Person, as such, shall have any liability for any obligations of the Company under the notes, the Subsidiary Guarantees, the indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of 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 SEC that such a waiver is against public policy.

Legal Defeasance and Covenant Defeasance

     The Company may, at its option and at any time, elect to have all of its obligations discharged with respect to the outstanding notes and all obligations of the Subsidiary Guarantors discharged with respect to their Subsidiary Guarantees (“Legal Defeasance”) except for:

     (i) the rights of holders of outstanding notes to receive payments in respect of the principal of, interest or premium, if any, and Liquidated Damages, if any, on such notes when such payments are due from the trust referred to below;

     (ii) the Company’s obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

     (iii) the rights, powers, trusts, duties and immunities of the trustee, and the Company’s and the Subsidiary Guarantor’s obligations in connection therewith; and

     (iv) the Legal Defeasance provisions of the indenture.

     In addition, the Company may, at its option and at any time, elect to have the obligations of the Company released with respect to certain covenants that are described in the indenture (“Covenant Defeasance”) and thereafter any omission to comply with those covenants will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under “— Events of Default and Remedies” will no longer constitute an Event of Default with respect to the notes.

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     In order to exercise either Legal Defeasance or Covenant Defeasance:

     (i) the Company must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, interest or premium, if any, and Liquidated Damages, if any, on the outstanding notes on the stated maturity or on the applicable redemption date, as the case may be, and the Company must specify whether the notes are being defeased to maturity or to a particular redemption date;

     (ii) in the case of Legal Defeasance, the Company shall deliver to the trustee an opinion of counsel reasonably acceptable to the trustee (subject to customary exceptions and exclusions) confirming that (a) the Company has received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the date of the indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

     (iii) in the case of Covenant Defeasance, the Company shall deliver to the trustee an opinion of counsel reasonably acceptable to the trustee (subject to customary exceptions and exclusions) confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

     (iv) no Default or Event of Default shall have occurred and be continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit);

     (v) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under any material agreement or instrument (other than the indenture) to which the Company or any of its Subsidiaries is a party or by which the Company or any of its Subsidiaries is bound;

     (vi) the Company must have delivered to the trustee, at or prior to the effective date of such defeasance, an opinion of counsel to the effect that, assuming no intervening bankruptcy of the Company between the date of deposit and the 91st day following the deposit and assuming that no holder is an “insider” of the Company under applicable bankruptcy law, after the 91st day following the deposit, the trust funds will not be subject to the effect of any applicable bankruptcy, insolvency, reorganization or similar laws affecting creditors’ rights generally;

     (vii) the Company must deliver to the trustee an officers’ certificate stating that the deposit was not made by the Company with the intent of preferring the holders of notes over the other creditors of the Company with the intent of defeating, hindering, delaying or defrauding creditors of the Company or others; and

     (viii) the Company must deliver to the trustee an officers’ certificate and an opinion of counsel, each stating that all conditions precedent relating to the Legal Defeasance or the Covenant Defeasance have been complied with.

Amendment, Supplement and Waiver

     Except as provided in the next two succeeding paragraphs, the indenture or the notes may be amended or supplemented with the consent of the holders of at least a majority in principal amount of the notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer

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or exchange offer for, notes), and any existing default or compliance with any provision of the indenture or the notes may be waived with the consent of the holders of a majority in principal amount of the then outstanding notes (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

     Without the consent of each holder affected, an amendment or waiver may not (with respect to any notes held by a non-consenting holder):

     (i) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

     (ii) reduce the principal of or change the fixed maturity of any note or alter the provisions with respect to the redemption of the notes (other than provisions relating to the covenants described above under the caption “— Repurchase at the Option of Holders”);

     (iii) reduce the rate of or change the time for payment of interest on any note;

     (iv) waive a Default or Event of Default in the payment of principal of, interest or premium, if any, or Liquidated Damages, if any, on the notes (except a rescission of acceleration of the notes by the holders of at least a majority in aggregate principal amount of the notes and a waiver of the payment default that resulted from such acceleration);

     (v) make any note payable in money other than that stated in the notes;

     (vi) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, interest or premium, if any, or Liquidated Damages, if any, on the notes;

     (vii) waive a redemption payment with respect to any note (other than a payment required by one of the covenants described above under the caption “— Repurchase at the Option of Holders”);

     (viii) release any Subsidiary Guarantor from any of its obligations under its Subsidiary Guarantee or the indenture, except in accordance with the terms of the indenture; or

     (ix) make any change in the preceding amendment and waiver provisions.

     Notwithstanding the preceding, without the consent of any holder of notes, the Company and the trustee may amend or supplement the indenture or the notes:

     (i) to cure any ambiguity, defect or inconsistency;

     (ii) to provide for uncertificated notes in addition to or in place of certificated notes;

     (iii) to provide for the assumption of the Company’s obligations to holders of notes in the case of a merger or consolidation or sale of all or substantially all of the Company’s assets;

     (iv) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the indenture of any such holder;

     (v) to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act; or

     (vi) to allow any Subsidiary to execute a supplemental indenture and/or a Guarantee.

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Satisfaction and Discharge

     The indenture will be discharged and will cease to be of further effect as to all notes issued thereunder, when:

     (1) either:

     (a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Company, have been delivered to the trustee for cancellation; or

     (b) all notes that have not been delivered to the trustee for cancellation have become due and payable by reason of the mailing of a notice of redemption or otherwise or will become due and payable within one year, and the Company has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination of cash in U.S. dollars and non-callable Government Securities, in such amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the notes not delivered to the trustee for cancellation for principal, interest or premium, if any, and Liquidated Damages, if any, and accrued interest to the date of maturity or redemption;

     (2) no Default or Event of Default has occurred and is continuing on the date of the deposit or will occur as a result of the deposit and the deposit will not result in a breach or violation of, or constitute a default under, any other instrument to which the Company or any Subsidiary Guarantor is a party or by which the Company or any Subsidiary Guarantor is bound;

     (3) the Company has paid or caused to be paid all sums payable by it under the indenture; and

     (4) the Company has delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the notes at maturity or the redemption date, as the case may be.

In addition, the Company must deliver an officers’ certificate and an opinion of counsel to the trustee stating that all conditions precedent to satisfaction and discharge have been satisfied.

Concerning the Trustee

     If the trustee becomes a creditor of the Company or of any Subsidiary Guarantor, the indenture limits its right to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions;however, if it acquires any conflicting interest, it must (i) eliminate such conflict within 90 days, (ii) apply to the SEC for permission to continue or (iii) resign.

     The holders of a majority in principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. In case an Event of Default occurs and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of notes, unless such holder has offered to the trustee security and indemnity satisfactory to it against any loss, liability or expense.

Additional Information

     Anyone who receives this prospectus may obtain a copy of the indenture and registration rights agreement without charge by writing to the Company at the address set forth in the section of the prospectus entitled “Where You Can Find Additional Information.”

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Book-Entry, Delivery and Form

     The exchange notes will be represented by one or more global notes in registered, global form without interest coupons (collectively, the “Global Exchange Note”). The Global Exchange Note initially will be deposited upon issuance with the Trustee as custodian for The Depository Trust Company (“DTC”), in New York, New York, and registered in the name of DTC or its nominee, in each case for credit to an account of a direct or indirect participant as described below. Except as set forth below, the Global Exchange Notes may be transferred, in whole and not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Exchange Notes may not be exchanged for exchange notes in certificated form except in the limited circumstances described below. See “ — Exchange of Global Exchange Notes for Certificated Notes.”

     In addition, transfer of beneficial interests in the Global Exchange Note will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time. The notes may be presented for registration of transfer and exchange at the offices of the registrar.

Depository Procedures

     The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. The Company takes no responsibility for these operations and procedures and urges investors to contact the system or their participants directly to discuss these matters.

     DTC has advised the Company that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the“Participants”) and to facilitate the clearance and settlement of transactions in those securities between Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC’s system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the“Indirect Participants”). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

     DTC has also advised the Company that, pursuant to procedures established by it:

     (1) upon deposit of the Global Exchange Notes, DTC will credit the accounts of Participants designated by the initial purchasers with portions of the principal amount of the Global Exchange Notes; and

     (2) ownership of these interests in the Global Exchange Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interest in the Global Exchange Notes).

     Investors in the Global Exchange Notes who are Participants in DTC’s system may hold their interests therein directly through DTC. Investors in the Global Exchange Notes who are not Participants may hold their interests therein indirectly through organizations (including Euroclear and Clearstream) that are Participants in such system. All interests in a Global Exchange Note, including those held through Euroclear or Clearstream, may be subject to the procedures and requirements of DTC.

     The laws of some states require that certain Persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer beneficial interests in a Global Exchange Note to such Persons will be limited to that extent. Because DTC can act only on behalf of Participants, which in turn act

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on behalf of Indirect Participants, the ability of a Person having beneficial interests in a Global Exchange Note to pledge such interests to Persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

     Except as described below, owners of interests in the Global Exchange Notes will not have notes registered in their names, will not receive physical delivery of notes in certificated form and will not be considered the registered owners or “holders” thereof under the indenture for any purpose.

     Payments in respect of the principal of, and interest and premium, if any, and Liquidated Damages, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, the Company and the trustee will treat the Persons in whose names the notes, including the Global Exchange Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Company, the trustee nor any agent of the Company or the trustee has or will have any responsibility or liability for:

     (1) any aspect of DTC’s records or any Participant’s or Indirect Participant’s records relating to or payments made on account of beneficial ownership interest in the Global Exchange Notes or for maintaining, supervising or reviewing any of DTC’s records or any Participant’s or Indirect Participant’s records relating to the beneficial ownership interests in the Global Exchange Notes; or

     (2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

     DTC has advised the Company that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee or the Company. Neither the Company nor the trustee will be liable for any delay by DTC or any of its Participants in identifying the beneficial owners of the notes, and the Company and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

     Subject to the transfer restrictions set forth under “Notice to Investors,” transfers between Participants in DTC will be effected in accordance with DTC’s procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

     Subject to compliance with the transfer restrictions applicable to the notes described herein, cross-market transfers between the Participants in DTC, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC’s rules on behalf of Euroclear or Clearstream, as the case may be, by its respective depositary; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Exchange Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositories for Euroclear or Clearstream.

     DTC has advised the Company that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Exchange Notes and only in respect of such portion of the aggregate principal amount of the notes as

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to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Exchange Notes for legended notes in certificated form, and to distribute such notes to its Participants.

     Although DTC, Euroclear and Clearstream have agreed to the foregoing to facilitate transfers of interests in the Global Exchange Notes among participants in DTC, Euroclear and Clearstream, they are under no obligation to perform or to continue to perform such procedures, and may discontinue such procedures at any time. Neither the Company nor the trustee nor any of their respective agents will have any responsibility for the performance by DTC, Euroclear or Clearstream or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

Exchange of Global Exchange Notes for Certificated Notes

     A Global Exchange Note is exchangeable for definitive notes in registered certificated form (“Certificated Notes”) if:

     (1) DTC (a) notifies the Company that it is unwilling or unable to continue as depositary for the Global Exchange Notes and the Company fails to appoint a successor depositary or (b) has ceased to be a clearing agency registered under the Exchange Act;

     (2) the Company, at its option, notifies the trustee in writing that it elects to cause the issuance of the Certificated Notes; or

     (3) there has occurred and is continuing a Default or Event of Default with respect to the notes.

In addition, beneficial interests in a Global Exchange Note may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the indenture. In all cases, Certificated Notes delivered in exchange for any Global Exchange Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend referred to in “Notice to Investors,” unless that legend is not required by applicable law.

Exchange of Certificated Notes for Global Exchange Notes

     Certificated Notes may not be exchanged for beneficial interests in any Global Exchange Note unless the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such notes. See “Notice to Investors.”

Same Day Settlement and Payment

     The Company will make payments in respect of the notes represented by the Global Exchange Notes (including principal, interest or premium, if any, and Liquidated Damages, if any) by wire transfer of immediately available funds to the accounts specified by the Global Exchange Note holder. The Company will make all payments of principal, interest and premium and Liquidated Damages, if any, with respect to Certificated Notes by wire transfer of immediately available funds to the accounts specified by the holders of Certificated Notes or, if no such account is specified, by mailing a check to each such holder’s registered address. The notes represented by the Global Exchange Notes are expected to be eligible to trade in the PORTAL Market and to trade in DTC’s Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds. The Company expects that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Registration Rights; Liquidated Damages

     The following description is a summary of the provisions of the registration rights agreement we consider material. It does not restate that agreement in its entirety. The Company urges you to read the form

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of registration rights agreement in its entirety because it, and not this description, defines your registration rights as holders of these notes. See “Where You Can Find Additional Information.”

     The Company, the Subsidiary Guarantors and the initial purchasers entered into the registration rights agreement on March 21, 2003. Pursuant to the registration rights agreement, the Company agreed to file with the SEC this Exchange Offer Registration Statement on the appropriate form under the Securities Act with respect to the Exchange Notes. Upon the effectiveness of the Exchange Offer Registration Statement, the Company and the Subsidiary Guarantors will offer to the holders of Transfer Restricted Securities pursuant to the Exchange Offer who are able to make certain representations the opportunity to exchange their Transfer Restricted Securities for Exchange Notes pursuant to the Exchange Offer.

     If:

     (1) the Company and the Subsidiary Guarantors are not

     (a) required to file the Exchange Offer Registration Statement; or

     (b) permitted to consummate the Exchange Offer because the Exchange Offer is not permitted by applicable law or SEC policy; or

     (2) any holder of Transfer Restricted Securities notifies the Company prior to the 20th day following consummation of the Exchange Offer that:

     (a) it is prohibited by law or SEC policy from participating in the Exchange Offer; or

     (b) that it may not resell the Exchange Notes acquired by it in the Exchange Offer to the public without delivering a prospectus and the prospectus contained in the Exchange Offer Registration Statement is not appropriate or available for such resales; or

     (c) that it is a broker-dealer and owns notes acquired directly from the Company or an affiliate of the Company,

the Company and the Subsidiary Guarantors will file with the SEC a Shelf Registration Statement to cover resales of the notes by those holders of the notes who satisfy certain conditions relating to the provision of information in connection with the Shelf Registration Statement.

     The Company and the Subsidiary Guarantors will use their respective reasonable best efforts to cause the applicable registration statement to be declared effective as promptly as possible by the SEC.

     For purposes of the preceding,“Transfer Restricted Securities” means each note until:

     (1) the date on which such note has been exchanged by a Person other than a broker-dealer for an Exchange Note in the Exchange Offer;

     (2) following the exchange by a broker-dealer in the Exchange Offer of a note for an Exchange Note, the date on which such Exchange Note is sold to a purchaser who receives from such broker-dealer on or prior to the date of such confirmation of sale a copy of the prospectus contained in the Exchange Offer Registration Statement;

     (3) the date on which such note has been effectively registered under the Securities Act and disposed of in accordance with the Shelf Registration Statement; or

     (4) the date on which such note is sold pursuant to Rule 144 under the Securities Act.

     The registration rights agreement will provide that:

     (1) the Company and the Subsidiary Guarantors will file an Exchange Offer Registration Statement with the SEC on or prior to 90 days after the date of the indenture;

     (2) the Company and the Subsidiary Guarantors will use their respective reasonable best efforts to have the Exchange Offer Registration Statement declared effective by the SEC on or prior to 180 days after the date of the indenture;

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     (3) unless the Exchange Offer would not be permitted by applicable law or SEC policy, the Company and the Subsidiary Guarantors will:

     (a) commence the Exchange Offer; and

     (b) use their respective reasonable best efforts to issue on or prior to 30 business days, or longer, if required by the federal securities laws, after the date on which the Exchange Offer Registration Statement was declared effective by the SEC, Exchange Notes in exchange for all notes validly tendered and not properly withdrawn prior to the expiration of the Exchange Offer; and

     (4) if obligated to file the Shelf Registration Statement, the Company and the Subsidiary Guarantors will use their respective reasonable best efforts to file the Shelf Registration Statement with the SEC on or prior to 60 days after such filing obligation arises and to cause the Shelf Registration to be declared effective by the SEC on or prior to 180 days after such obligation arises.

     If:

     (1) the Company and the Subsidiary Guarantors fail to file any of the registration statements required by the registration rights agreement on or before the date specified for such filing; or

     (2) any of such registration statements is not declared effective by the SEC on or prior to the date specified for such effectiveness (the“Effectiveness Target Date”); or

     (3) the Company and the Subsidiary Guarantors fail to consummate the Exchange Offer within 30 business days (or such longer period, if any, required by the federal securities laws) of the Effectiveness Target Date with respect to the Exchange Offer Registration Statement; or

     (4) the Shelf Registration Statement or the Exchange Offer Registration Statement is declared effective but thereafter ceases to be effective or usable in connection with resales of Transfer Restricted Securities during the periods specified in the registration rights agreement (each such event referred to in clauses (1) through (4) above, a“Registration Default”),

then the Company and the Subsidiary Guarantors will pay Liquidated Damages to each holder of notes in an mount equal to $.05 per week per $1,000 principal amount of the notes the first 90-day period immediately following the occurrence of a Registration Default, and such rate will increase by an additional $.05 per week per $1,000 principal amount of the notes with respect to each subsequent 90-day period until all Registration Defaults have been cured, up to a maximum additional rate of $.50 per week per $1,000 principal amount of notes. Additional interest will not accrue under more than one of the preceding clauses (1) through (4) at any one time. Any Liquidated Damages payable pursuant to the registration rights agreement will be in addition to any other interest payable from time to time with respect to the notes and the exchange notes.

     All accrued Liquidated Damages will be paid by the Company and the Subsidiary Guarantors on each date on which it otherwise is required to pay interest on the notes, and such amounts will be paid to the Global Note holder by wire transfer of immediately available funds and to holders of Certificated Notes by wire transfer to the accounts specified by them or by mailing checks to their registered addresses if no such accounts have been specified.

     Following the cure of all Registration Defaults, the accrual of Liquidated Damages will cease.

     Holders of outstanding notes will be required to make certain representations to the Company (as described in the registration rights agreement) in order to participate in the Exchange Offer and will be required to deliver certain information to be used in connection with the Shelf Registration Statement and to provide comments on the Shelf Registration Statement within the time periods set forth in the registration rights agreement in order to have their notes included in the Shelf Registration Statement and benefit from the provisions regarding Liquidated Damages set forth above. By acquiring Transfer Restricted Securities, a holder will be deemed to have agreed to indemnify the Company and the Subsidiary Guarantors against certain losses arising out of information furnished by such holder in writing for inclusion in any Shelf Registration Statement. Holders of outstanding notes will also be required to suspend their use of the prospectus included in the Exchange Offer Registration Statement (as to broker-dealers required to deliver a

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prospectus in connection with any sale by them of Exchange Notes) or the Shelf Registration Statement under certain circumstances upon receipt of written notice to that effect from the Company.

Certain Definitions

     Set forth below are certain defined terms used in the indenture. Reference is made to the indenture for a description of all defined terms used in it and in the notes, including any other capitalized terms used in this “Description of the Notes” for which no definition is provided below.

     “Acquired Debt” means, with respect to any specified Person, (i) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, including, without limitation, Indebtedness incurred in connection with, or in contemplation of, such other Person merging with or into or becoming a Subsidiary of such specified Person, and (ii) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

     “Additional Assets” means (i) any property or assets (other than Capital Stock, Indebtedness or rights to receive payments over a period greater than 180 days, other than with respect to coal supply contract restructurings) that is usable by the Company or a Restricted Subsidiary in a Permitted Business or (ii) the Capital Stock of a Person that is at the time, or becomes, a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or another Restricted Subsidiary.

     “Affiliate” of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control” (including, with correlative meanings, the terms “controlling,” “controlled by” and “under common control with”), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise;providedthat beneficial ownership of 10% or more of the Voting Stock of a Person shall be deemed to be control.

     “Asset Sale” means (i) the sale, lease, conveyance or other disposition of any assets or rights (including, without limitation, by way of a sale and leaseback) other than sales of inventory in the ordinary course of business consistent with past practices (providedthat the sale, lease, conveyance or other disposition of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the caption “— Repurchase at the Option of Holders — Change of Control Triggering Event” and/or the provisions described above under the caption “— Certain Covenants — Merger, Consolidation or Sale of Assets” and not by the provisions of the Asset Sale covenant), and (ii) the issue or sale by the Company or any of its Restricted Subsidiaries of Equity Interests of any of the Company’s Restricted Subsidiaries, in the case of either clause (i) or (ii), whether in a single transaction or a series of related transactions (a) that have a fair market value in excess of $5.0 million or (b) for Net Proceeds in excess of $5.0 million. Notwithstanding the foregoing, the following items shall not be deemed to be Asset Sales: (i) a transfer of assets by the Company to a Restricted Subsidiary or by a Restricted Subsidiary to the Company or to another Restricted Subsidiary, (ii) an issuance of Equity Interests by a Restricted Subsidiary to the Company or to another Restricted Subsidiary, (iii) a Restricted Payment that is permitted by, or an Investment that is not prohibited by, the covenant described above under the caption “— Certain Covenants — Restricted Payments,” (iv) a disposition of Cash Equivalents or obsolete, worn out or no longer useful equipment, (v) foreclosures on assets, (vi) the sale or discount, in each case without recourse, of accounts receivable arising in the ordinary course of business, but only in connection with the compromise or collection thereof and (vii) the factoring of accounts receivable arising in the ordinary course of business pursuant to arrangements customary in the industry.

     “Capital Lease Obligation” means, at the time any determination thereof is to be made, the amount of the liability in respect of a capital lease that would at such time be required to be capitalized on a balance sheet in accordance with GAAP.

     “Capital Stock” means (i) in the case of a corporation, corporate stock, (ii) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated)

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of corporate stock, (iii) in the case of a partnership or limited liability company, partnership or membership interests (whether general or limited) and (iv) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person.

     “Cash Equivalents” means (a) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed or insured by the U.S. Government or any agency thereof, (b) certificates of deposit and time deposits with maturities of one year or less from the date of acquisition and overnight bank deposits of any lender under the Credit Agreement or of any commercial bank having capital and surplus in excess of $500.0 million, (c) repurchase obligations of any lender under the Credit Agreement or of any commercial bank satisfying the requirements of clause (b) of this definition, having a term of not more than 90 days with respect to securities issued or fully guaranteed or insured by the United States Government, (d) commercial paper of a domestic issuer rated at least A-2 by S&P or P-2 by Moody’s, or carrying an equivalent rating by a nationally recognized rating agency if both of S&P and Moody’s cease publishing ratings of investments, (e) securities with maturities of one year or less from the date of acquisition issued or fully guaranteed by any state, commonwealth or territory of the United States, by any political subdivision or taxing authority of any such state, commonwealth or territory or by any foreign government, the securities of which state, commonwealth, territory, political subdivision, taxing authority or foreign government (as the case may be) are rated at least A by S&P or A by Moody’s, (f) securities with maturities of one year or less from the date of acquisition backed by standby letters of credit issued by any lender under the Credit Agreement or any commercial bank satisfying the requirements of clause (b) of this definition or (g) shares of money market mutual or similar funds, at least 95% of the assets of which invest exclusively in assets satisfying the requirements of clauses (a) through (f) of this definition.

     “Consolidated Cash Flow” means, with respect to any Person for any period, the Consolidated Net Income of such Person for such period plus (i) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was included in computing such Consolidated Net Income, plus (ii) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued and whether or not capitalized (including, without limitation, amortization of debt issuance costs, deferred financing fees and original issue discount, noncash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers’ acceptance financings, and net payments (if any) pursuant to Hedging Obligations), to the extent that any such expense was deducted in computing such Consolidated Net Income, plus (iii) an amount equal to any extraordinary loss plus any net loss realized in connection with an Asset Sale (to the extent such losses were deducted in computing such Consolidated Net Income), plus (iv) depreciation, depletion, amortization (including amortization of goodwill and other intangibles) and other noncash expenses (including, without limitation, writedowns and impairment of property, plant and equipment and intangibles and other long-lived assets) (excluding any such noncash expense to the extent that it represents an accrual of or reserve for cash expenses in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization and other noncash expenses were deducted in computing such Consolidated Net Income, minus (v) noncash items increasing such Consolidated Net Income for such period (other than accruals in accordance with GAAP). Notwithstanding the foregoing, the provision for taxes on the income or profits of, and the depreciation, depletion and amortization and other noncash expenses of, a Restricted Subsidiary that is not a Subsidiary Guarantor shall be added to Consolidated Net Income to compute Consolidated Cash Flow only to the extent that a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior governmental approval (that has not been obtained), and without direct or indirect restriction pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders.

     “Consolidated Net Income” means, with respect to any Person for any period, the aggregate of the Net Income of such Person and its Subsidiaries for such period, on a consolidated basis, determined in accordance

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with GAAP;providedthat (i) the Net Income of any Unrestricted Subsidiary, any Person that is not a Subsidiary or any Person accounted for by the equity method of accounting shall be included only to the extent of the amount of dividends or distributions paid in cash to the referent Person or a Restricted Subsidiary thereof, (ii) the Net Income of any Restricted Subsidiary that is not a Subsidiary Guarantor shall be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, (iii) the Net Income of any Person acquired in a transaction accounted for in a manner similar to a pooling of interests transaction for any period prior to the date of such acquisition shall be excluded,provided, however, that such Net Income shall not be excluded for purposes of calculating the Fixed Charge Coverage Ratio, and (iv) the cumulative effect of a change in accounting principles shall be excluded.

     “Credit Agreement” means that certain Credit Agreement, which we expect will be dated as of March 21, 2003 by and among the Company, as borrower, Wachovia Securities, Inc., Fleet Securities, Inc. and Lehman Brothers Inc. as Arrangers, Wachovia Bank, National Association and Lehman Commercial Paper Inc., as the Syndication Agents, Fleet National Bank, as the Administrative Agent, Morgan Stanley Senior Funding, Inc., as Documentation Agent, and the other lenders party thereto, including any related notes, guarantees, collateral documents, letters of credit, instruments and agreements executed in connection therewith (and any appendices, annexes, exhibits or schedules to any of the foregoing), and in each case as amended, restated, amended and restated, modified, supplemented, renewed, refunded, replaced, restructured, repaid or refinanced from time to time (whether with the original agents, arrangers and lenders or other agents, arrangers and lenders or otherwise, whether provided under the original credit agreement or other Credit Facilities or otherwise, whether for a greater or lesser principal amount, whether with greater or lesser interest and fees and whether including more or less collateral or guarantors). Indebtedness under the Credit Agreement outstanding on the date on which notes are first issued and authenticated under the indenture shall be deemed to have been incurred on such date in reliance on, and to be permitted by, the exception provided by clause (i) of the definition of Permitted Indebtedness.

     “Credit Facilities” means, with respect to the Company or any of its Restricted Subsidiaries, one or more debt facilities (including, without limitation, the Credit Agreement) or commercial paper facilities with banks or other institutional lenders providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, amended and restated, modified, supplemented, renewed, refunded, replaced, refinanced, repaid or restructured in whole or in part from time to time.

     “Default” means any event that is or with the passage of time or the giving of notice or both would be an Event of Default.

     “Designated Noncash Consideration” means the fair market value of noncash consideration received by the Company or one of its Restricted Subsidiaries in connection with an Asset Sale that is so designated as Designated Noncash Consideration pursuant to an officers’ certificate, setting forth the basis of such valuation, executed by the principal executive officer and the principal financial officer of the Company, less the amount of cash or Cash Equivalents received in connection with a sale of such Designated Noncash Consideration.

     “Disqualified Stock” means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, at the option of the holder thereof), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder thereof, in whole or in part, on or prior to the date on which the notes mature;provided, however, that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a Change of Control Triggering Event or an Asset Sale shall not constitute

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Disqualified Stock if the terms of such Capital Stock provide that the Company may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption “— Certain Covenants — Restricted Payments.”

     “Domestic Subsidiary” means a Subsidiary that is (i) formed under the laws of the United States of America or a state or territory thereof or (ii) as of the date of determination, treated as a domestic entity or a partnership or a division of a domestic entity for United States federal income tax purposes.

     “Equity Interests” means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

     “Equity Offering” means any public or private sale of equity securities (excluding Disqualified Stock) of the Company, other than any private sales to an Affiliate of the Company.

     “Exchange Notes” means new notes of the Company issued in a registered offer made pursuant to a registration statement filed with, and declared effective by, the SEC, offering to exchange such new notes for the notes,providedthat such new notes have terms substantially identical in all material respects to the notes (except that Exchange Notes will not contain terms with respect to transfer restrictions) for which such offer is being made.

     “Exchange Offer” means the registration by the Company under the Securities Act of the Exchange Notes pursuant to a Registration Statement pursuant to which the Company offers the holders of all outstanding Transfer Restricted Securities the opportunity to exchange all such outstanding Transfer Restricted Securities held by such holders for Exchange Notes in an aggregate principal amount equal to the aggregate principal amount of the Transfer Restricted Securities validly tendered in such exchange offer by such holders.

     “Exchange Offer Registration Statement” means the Registration Statement relating to the Exchange Offer, including the related Prospectus.

     “Existing Indebtedness” means up to $1,253.0 million in aggregate principal amount of Indebtedness of the Company and its Restricted Subsidiaries (other than Indebtedness under the Credit Agreement, the notes, the May 1998 Senior Notes, the Senior Subordinated Notes, the Subsidiary Guarantees, the May 1998 Senior Note Guarantees and the Subordinated Subsidiary Guarantees) in existence on the date of the indenture, until such amounts are repaid.

     “Fixed Charges” means, with respect to any Person for any period, the sum, without duplication, of (i) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (including, without limitation, amortization of original issue discount, noncash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, commissions, discounts and other fees and charges incurred in respect of letters of credit or bankers’ acceptance financings, and net payments (if any) pursuant to Hedging Obligations, but excluding amortization of debt issuance costs) and (ii) the consolidated interest of such Person and its Restricted Subsidiaries that was capitalized during such period, and (iii) any interest expense on the portion of Indebtedness of another Person that is Guaranteed by such Person or one of its Restricted Subsidiaries or secured by a Lien on assets of such Person or one of its Restricted Subsidiaries (whether or not such Guarantee or Lien is called upon) and (iv) the product of (a) all dividend payments, whether or not in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividend payments on Equity Interests payable solely in Equity Interests of the Company (other than Disqualified Stock) or to the Company or a Restricted Subsidiary of the Company, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the effective combined federal, state and local tax rate of such Person for such period, expressed as a decimal, in each case, for the Company and its Restricted Subsidiaries on a consolidated basis and in accordance with GAAP.

     “Fixed Charge Coverage Ratio” means with respect to any specified Person for any period, the ratio of the Consolidated Cash Flow of such Person and its Restricted Subsidiaries for such period to the Fixed Charges of such Person and its Restricted Subsidiaries for such period. In the event that the specified Person

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or any of its Restricted Subsidiaries incurs, assumes, Guarantees, repays, repurchases or redeems any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the“Calculation Date”), then the Fixed Charge Coverage Ratio will be calculated giving pro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase or redemption of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom as if the same had occurred at the beginning of the applicable four-quarter reference period.

     In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

     (1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers, consolidations or otherwise (including acquisitions of assets used in a Permitted Business) and including any related financing transactions, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date will be given pro forma effect as if they had occurred on the first day of the four-quarter reference period, including any pro forma expense and cost reductions and other operating improvements that have occurred or are reasonably expected to occur, in the reasonable judgment of the chief financial officer of the Company (regardless of whether those cost savings or operating improvements could then be reflected in pro forma financial statements in accordance with Regulation S-X promulgated under the Securities Act or any other regulation or policy of the SEC related thereto);

     (2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded; and

     (3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date.

     “Foreign Subsidiaries” means Subsidiaries of the Company that are not Domestic Subsidiaries.

     “GAAP” means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect on the date of the indenture.

     “Guarantee” means a guarantee (other than by endorsement of negotiable instruments for collection in the ordinary course of business), direct or indirect, in any manner (including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof), of all or any part of any Indebtedness.

     “Hedging Obligations” means, with respect to any Person, the obligations of such Person under (i) currency exchange, interest rate or commodity swap agreements, currency exchange, interest rate or commodity cap agreements and currency exchange, interest rate or commodity collar agreements and (ii) other agreements or arrangements designed to protect such Person against fluctuations in currency exchange, interest rates or commodity prices, in each case for the purpose of risk management and not for speculation.

     “Indebtedness” means, with respect to any Person, any indebtedness of such Person, whether or not contingent, in respect of borrowed money or evidenced by bonds, notes, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof) or banker’s acceptances or representing Capital Lease Obligations or the balance deferred and unpaid of the purchase price of any property or representing any Hedging Obligations, if and to the extent any of the foregoing (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of such Person prepared in

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accordance with GAAP, as well as all Indebtedness of others secured by a Lien on any asset of such Person (whether or not such Indebtedness is assumed by such Person) and, to the extent not otherwise included, the Guarantee by such Person of any indebtedness of any other Person, but excluding from the definition of “Indebtedness,” any of the foregoing that constitutes (1) an accrued expense, (2) trade payables and (3) Obligations in respect of reclamation, workers’ compensation, including black lung, pensions and retiree health care, in each case to the extent not overdue for more than 90 days. The amount of any Indebtedness outstanding as of any date shall be (i) the accreted value thereof, in the case of any Indebtedness issued with original issue discount, and (ii) the principal amount thereof, together with any interest thereon that is more than 30 days past due, in the case of any other Indebtedness.

     “Investment Grade Rating”means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s or BBB- (or the equivalent) by S&P.

     “Investments” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of direct or indirect loans (including guarantees of any portion of Indebtedness or other obligations), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If the Company or any Restricted Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Restricted Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of the Company, the Company shall be deemed to have made an Investment on the date of any such sale or disposition equal to the fair market value of the Equity Interests of such Restricted Subsidiary not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption “— Certain Covenants — Restricted Payments.”

     “Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law (including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction), but excluding any of the foregoing arising as a result of a sale, contribution, disposition or any other transfer of accounts, chattel paper, payment intangibles, promissory notes and/or related assets otherwise permitted under the terms hereof.

     “Marketable Securities” means, with respect to any Asset Sale, any readily marketable equity securities that are (i) traded on the New York Stock Exchange, the American Stock Exchange or the Nasdaq National Market; and (ii) issued by a corporation having a total equity market capitalization of not less than $250.0 million;providedthat the excess of (A) the aggregate amount of securities of any one such corporation held by the Company and any Restricted Subsidiary over (B) ten times the average daily trading volume of such securities during the 20 immediately preceding trading days shall be deemed not to be Marketable Securities; as determined on the date of the contract relating to such Asset Sale.

     “May 1998 Senior Note Guarantee” means the Guarantees of the May 1998 Senior Notes by each of the Subsidiary Guarantors pursuant to the May 1998 Senior Note Indenture and any additional Guarantee of the May 1998 Senior Notes to be executed by any Subsidiary of the Company pursuant to that indenture.

     “May 1998 Senior Note Indenture” means the indenture among the Company, the Subsidiary Guarantors, US Bank National Association, formerly State Street Bank and Trust Company, as Trustee, dated as of May 18, 1998, governing the May 1998 Senior Notes.

     “May 1998 Senior Notes” means the Company’s Series A and Series B 8 7/8% Senior Notes due 2008.

     “Moody’s” means Moody’s Investors Service, Inc., or any successor to the rating agency business thereof.

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     “Net Income” means, with respect to any Person, the net income or loss of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however, (i) any gain or loss, together with any related provision for taxes on such gain or loss, realized in connection with (a) any Asset Sale (including, without limitation, dispositions pursuant to sale and leaseback transactions) or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries and (ii) any extraordinary or nonrecurring gain or loss, together with any related provision for taxes on such extraordinary or nonrecurring gain or loss.

     “Net Proceeds” means the aggregate proceeds (cash or property) received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of any noncash consideration received in any Asset Sale) or the sale or disposition of any Investment, net of the direct costs relating to such Asset Sale, sale or disposition, (including, without limitation, legal, accounting and investment banking fees, and sales commissions) and any relocation expenses incurred as a result thereof, taxes paid or payable as a result thereof (after taking into account any available tax credits or deductions and any tax sharing arrangements), and any reserve for adjustment in respect of the sale price of such asset or assets established in accordance with GAAP.

     “Non-Guarantor Subsidiaries” means (i) the Specified Subsidiaries, (ii) the Company’s future Unrestricted Subsidiaries and (iii) the Company’s current and future Foreign Subsidiaries.

     “Non-Recourse Debt” means Indebtedness (i) as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness) other than a pledge of the Equity Interests of any Unrestricted Subsidiaries, (b) is directly or indirectly liable (as a guarantor or otherwise) other than by virtue of a pledge of the Equity Interests of any Unrestricted Subsidiaries, or (c) constitutes the lender; and (ii) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness (other than the notes being offered hereby) of the Company or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity.

     “Obligations” means any principal, premium (if any), interest, penalties, fees, charges, expenses, indemnifications, reimbursement obligations, damages, Guarantees and other liabilities and amounts payable under the documentation governing any Indebtedness or in respect thereto.

     “Permitted Business” means coal production, coal mining, coal brokering, coal transportation, mine development, power marketing, electricity generation, power/energy sales and trading, energy transactions/ asset restructurings, risk management products associated with energy, fuel/power integration and other energy-related businesses, ash disposal, environmental remediation and development of related real estate assets, coal, natural gas, petroleum or other fossil fuel exploration, production, marketing, transportation and distribution and other related businesses and activities of the Company and its Subsidiaries, as of the date of the indenture and any business or activity that is reasonably similar thereto or a reasonable extension, development or expansion thereof or ancillary thereto.

     “Permitted Investments” means (a) any Investment in the Company or in a Restricted Subsidiary of the Company; (b) any Investment in Cash Equivalents; (c) any Investment by the Company or any Restricted Subsidiary of the Company in a Person, if as a result of such Investment (i) such Person becomes a Restricted Subsidiary of the Company or (ii) such Person, in one transaction or a series of related transactions, is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Company or a Restricted Subsidiary of the Company; (d) any acquisition of assets solely in exchange for the issuance of Equity Interests (other than Disqualified Stock) of the Company; (e) any Investment existing on the date of the indenture (an“Existing Investment”) and any Investment that replaces, refinances or refunds an Existing Investment,providedthat the new Investment is in an amount that does not exceed the amount replaced, refinanced or refunded and is made in the same Person as the Investment replaced, refinanced or refunded, (f) advances to employees not in excess of $10.0 million

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outstanding at any one time; (g) Hedging Obligations permitted under clause (viii) of the “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” covenant; (h) loans and advances to officers, directors and employees for business-related travel expenses, moving expenses and other similar expenses, in each case incurred in the ordinary course of business; (i) any Investment in a Permitted Business (whether or not an Investment in an Unrestricted Subsidiary) having an aggregate fair market value, when taken together with all other Investments made pursuant to this clause (i), does not exceed in aggregate amount the sum of (1) 15% of Total Assets at the time of such Investment (with the fair market value of each Investment being measured at the time made and without giving effect to subsequent changes in value) plus (2) 100% of the Net Proceeds from the sale or disposition of any Investment previously made pursuant to this clause (i) or 100% of the amount of any dividend, distribution or payment from any such Investment, net of income taxes paid or payable in respect thereof, in each case up to the amount of the Investment that was made pursuant to this clause (i) and 50% of the amount of such Net Proceeds or 50% of such dividends, distributions or payments, in each case received in excess of the amount of the Investments made pursuant to this clause (i); (j) guarantees (including Guarantees) of Indebtedness permitted under the covenant “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock;” (k) any Investment acquired by the Company or any of its Restricted Subsidiaries (A) in exchange for any other Investment or accounts receivable held by the Company or any such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of the issuer of such other Investment or accounts receivable or (B) as a result of the transfer of title with respect to any secured Investment in default as a result of a foreclosure by the Company or any of its Restricted Subsidiaries with respect to such secured Investment; (l) any Investment in joint ventures in an amount, taken together with all other Investments made pursuant to this clause (l), that does not exceed $100.0 million at the time outstanding; and (m) that portion of any Investment by the Company or a Restricted Subsidiary in a Permitted Business to the extent that the Company or such Restricted Subsidiary will receive in a substantially concurrent transaction an amount in cash equal to the amount of such Investment (or the fair market value of such Investment), net of any obligation to pay taxes or other amounts in respect of the receipt of such cash;providedthat the receipt of such cash does not carry any obligation by the Company or such Restricted Subsidiary to repay or return such cash;provided, however, that with respect to any Investment, the Company may, in its sole discretion, allocate all or any portion of any Investment to one or more of the above clauses so that the entire Investment would be a Permitted Investment.

     “Permitted Liens” means (i) Liens securing Indebtedness under the Credit Agreement that was permitted by the terms of the indenture to be incurred; (ii) Liens in favor of the Company; (iii) Liens on property of a Person existing at the time such Person is merged into or consolidated with the Company or any Restricted Subsidiary of the Company;providedthat such Liens were in existence prior to the contemplation of such merger or consolidation and do not extend to any assets other than those of the Person merged into or consolidated with the Company; (iv) Liens on property existing at the time of acquisition thereof by the Company or any Restricted Subsidiary of the Company,providedthat such Liens were in existence prior to the contemplation of such acquisition; (v) Liens to secure the performance of statutory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business; (vi) Liens incurred or deposits made in the ordinary course of business in connection with workers’ compensation, unemployment insurance or other kinds of social security; (vii) Liens existing on the date of the indenture; (viii) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded,providedthat any reserve or other appropriate provision as shall be required in conformity with GAAP shall have been made therefor; (ix) Liens on assets of Subsidiary Guarantors to secure Senior Debt of such Subsidiary Guarantors that was permitted by the indenture to be incurred; (x) Liens incurred in the ordinary course of business of the Company or any Restricted Subsidiary of the Company with respect to obligations that (a) are not incurred in connection with the borrowing of money or the obtaining of advances or credit (other than trade credit in the ordinary course of business) and (b) do not in the aggregate materially detract from the value of the property or materially impair the use thereof in the operation of business by the Company or such Restricted Subsidiary; (xi) Liens on assets of Foreign Subsidiaries to secure Indebtedness that was permitted by the indenture to be incurred; (xii) statutory liens of landlords, mechanics, suppliers,

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vendors, warehousemen, carriers or other like Liens arising in the ordinary course of business; (xiii) judgment Liens not giving rise to an Event of Default so long as any appropriate legal proceeding that may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such legal proceeding may be initiated shall not have expired; (xiv) easements, rights-of-way, zoning and similar restrictions and other similar encumbrances or title defects incurred or imposed, as applicable, in the ordinary course of business and consistent with industry practices which, in the aggregate, are not substantial in amount, and which do not in any case materially detract from the value of the property subject thereto (as such property is used by the Company or its Subsidiaries) or interfere with the ordinary conduct of the business of the Company or such Subsidiaries;provided, however, that any such Liens are not incurred in connection with any borrowing of money or any commitment to loan any money or to extend any credit; (xv) Liens to secure Indebtedness (including Capital Lease Obligations) permitted by clause (vi) of the second paragraph of the covenant entitled “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock” and other purchase money Liens to finance property or assets of the Company or any Restricted Subsidiary acquired in the ordinary course of business;provided that such Liens are only secured by such property or assets so acquired or improved (including, in the case of the acquisition of Capital Stock of a Person who becomes a Restricted Subsidiary, Liens on the assets of the Person whose Capital Stock was so acquired); (xvi) Liens securing Indebtedness under Hedging Obligations;providedthat such Liens are only secured by property or assets that secure the Indebtedness subject to the Hedging Obligation; (xvii) Liens to secure Indebtedness permitted by clause (xii) of the second paragraph of the covenant entitled “— Certain Covenants — Incurrence of Indebtedness and Issuance of Preferred Stock;” and (xviii) Liens on the Equity Interests of Unrestricted Subsidiaries securing obligations of Unrestricted Subsidiaries not otherwise prohibited by the indenture.

     “Permitted Refinancing Indebtedness” means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness of the Company or any of its Restricted Subsidiaries (other than intercompany Indebtedness);providedthat: (i) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount of (or accreted value, if applicable), plus accrued interest and premium, if any, on, the Indebtedness so extended, refinanced, renewed, replaced, defeased or refunded (plus the amount of reasonable expenses incurred in connection therewith); (ii) such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; (iii) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the notes, such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and is subordinated in right of payment to, the notes on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and (iv) such Indebtedness is incurred either by the Company or by the Restricted Subsidiary who is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded.

     “Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

     “Prospectus” means a prospectus included in a Registration Statement as amended or supplemented by any prospectus supplement and by all other amendments thereto, including post-effective amendments, and all material incorporated by reference into such Prospectus.

     “Rating Agency”means each of S&P and Moody’s, or if S&P or Moody’s or both shall not make a rating on the notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by the Company (as certified by a resolution of its Board of Directors) which shall be substituted for S&P or Moody’s or both, as the case may be.

     “Restricted Investment” means an Investment other than a Permitted Investment.

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     “Restricted Subsidiary” of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary.

     “S&P’s” means Standard & Poor’s Rating Group, Inc., or any successor to the rating agency business thereof.

     “Senior Subordinated Note Indenture” means the indenture, among the Company, the Subsidiary Guarantors, US Bank National Association, formerly State Street Bank and Trust Company, as Trustee, dated as of May 18, 1998, governing the Senior Subordinated Notes.

     “Senior Subordinated Notes” means the Company’s 9 5/8% Series B Senior Subordinated Notes due 2008.

     “Significant Subsidiary” means any Subsidiary that would be a “significant subsidiary” as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Securities Act, as such Regulation is in effect on the date hereof.

     “Specified Subsidiaries” means Newhall Funding Company, CL Hartford, L.L.C., CL Power Sales Three, L.L.C., CP Power Sales Sixteen, L.L.C., PG Power Sales One, L.L.C., PG Power Sales Two, L.L.C., PG Power Sales Three, L.L.C., PG Power Sales Four, L.L.C., PG Power Sales Five, L.L.C., PG Power Sales Six, L.L.C., PG Power Sales Seven, L.L.C., PG Power Sales Eight, L.L.C., PG Power Sales Nine, L.L.C., PG Power Sales Ten, L.L.C., PG Power Sales Eleven, L.L.C., PG Power Sales Twelve, L.L.C., PG Investments One, L.L.C., PG Investments Two, L.L.C., PG Investments Three, L.L.C., PG Investments Four, L.L.C., PG Investments Five, L.L.C., PG Investments Six, L.L.C., P&L Receivables Company LLC and United Minerals Company, LLC.

     “Stated Maturity” means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which such payment of interest or principal was scheduled to be paid in the original documentation governing such Indebtedness, and shall not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof.

     “Subordinated Subsidiary Guarantees” means the Guarantees of the Senior Subordinated Notes by each of the Subsidiary Guarantors pursuant to the Senior Subordinated Note Indenture and any additional Guarantee of the Senior Subordinated Notes to be executed by any Subsidiary of the Company pursuant to that indenture.

     “Subsidiary” means, with respect to any Person, (i) any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person (or a combination thereof) and (ii) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are such Person or of one or more Subsidiaries of such Person (or any combination thereof).

     “Subsidiary Guarantee”means the Guarantee of the notes by each of the Subsidiary Guarantors pursuant to the indenture and any additional Guarantee of the notes to be executed by any Subsidiary of the Company pursuant to the covenant described above under “— Certain Covenants — Additional Subsidiary Guarantees.”

     “Subsidiary Guarantors”means all of the Company’s existing Domestic Subsidiaries, except for the Specified Subsidiaries, and any other Subsidiary that executes a Subsidiary Guarantee in accordance with the provisions of the indenture, and their respective successors and assigns.

     “Total Assets” means the total assets of the Company and its Restricted Subsidiaries on a consolidated basis determined in accordance with GAAP, as shown on the most recently available consolidated balance sheet of the Company and its Restricted Subsidiaries.

     “Treasury Rate” means the yield to maturity at the time of the computation of the United States Treasury securities with a constant maturity (as compiled by and published in the most recent Federal Reserve

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Statistical Release H.15(519), which has become publicly available at least two Business Days prior to the date fixed for redemption (or if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the then remaining average life to March 15, 2008;provided, however, that if the average life of such note is not equal to the constant maturity of the United States Treasury security for which weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the average life of such note is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used.

     “Unrestricted Subsidiary” means (i) the Specified Subsidiaries and (ii) any Subsidiary that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution; but only to the extent that such Person: (a) has no Indebtedness other than Non-Recourse Debt; (b) is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company; (c) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any obligation (x) to subscribe for additional Equity Interests in Unrestricted Subsidiaries or (y) to maintain or preserve such Person’s net worth (except with respect to Permitted Investments); and (d) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Company or any of its Restricted Subsidiaries;provided, however, that the Company and its Restricted Subsidiaries may guarantee the performance of Unrestricted Subsidiaries in the ordinary course of business except for guarantees of Obligations in respect of borrowed money. Any such designation by the Board of Directors shall be evidenced to the trustee by filing with the trustee a certified copy of the Board Resolution giving effect to such designation and an officers’ certificate certifying that such designation complied with the foregoing conditions and was permitted by the covenant described above under the caption “— Certain Covenants — Restricted Payments.”

     “Voting Stock” of any Person as of any date means the Capital Stock of such Person that is at the time entitled to vote in the election of the Board of Directors of such Person.

     “Weighted Average Life to Maturity” means, when applied to any Indebtedness at any date, the number of years obtained by dividing (i) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect thereof, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment, by (ii) the then outstanding principal amount of such Indebtedness.

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CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

     The exchange of outstanding notes for exchange notes in the exchange offer will not constitute a taxable event to holders. Consequently, no gain or loss will be recognized by a holder upon receipt of an exchange note, the holding period of the exchange note will include the holding period of the outstanding note and the basis of the exchange note will be the same as the basis of the outstanding note immediately before the exchange.

     In any event, persons considering the exchange of outstanding notes for exchange notes should consult their own tax advisors concerning the United States federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

     The following summary describes the material United States federal income tax consequences of the ownership of exchange notes as of the date hereof by Non-U.S. Holders (as defined below). The discussion below is based upon the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), and regulations, rulings and judicial decisions thereunder as of the date hereof, and such authorities may be repealed, revoked or modified so as to result in United States federal income tax consequences different from those discussed below.Persons considering the ownership of exchange notes should consult their own tax advisors concerning the United States federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

     As used herein, a “Non-U.S. Holder” of an exchange note means a holder that for federal income tax purposes is not (i) a citizen or resident of the United States, (ii) a corporation created or organized in or under the laws of the United States or any political subdivision thereof, (iii) an estate the income of which is subject to United States federal income taxation regardless of its source or (iv) a trust if it (X) is subject to the primary supervision of a court within the United States and one or more United States persons have the authority to control all substantial decisions of the trust or (Y) has a valid election in effect under applicable United States Treasury regulations to be treated as a United States person.

     If a partnership holds our exchange notes, the tax treatment of a partner will generally depend upon the status of the partner and the activities of the partnership. If you are a partner of a partnership holding our exchange notes, you should consult your tax advisors.

     Under present United States federal income and estate tax law, and subject to the discussion below concerning backup withholding:

     (a) no withholding of United States federal income tax will be required with respect to the payment by us or any paying agent of principal or interest on an exchange note owned by a Non-U.S. Holder under the “portfolio interest rule,” provided that (i) interest paid on the exchange note is not effectively connected with the beneficial owner’s conduct of a trade or business in the United States, (ii) the beneficial owner does not actually or constructively own 10% or more of the total combined voting power of all classes of stock of our company entitled to vote within the meaning of section 871(h)(3) of the Code and the regulations thereunder, (iii) the beneficial owner is not a controlled foreign corporation that is related to our company through stock ownership, (iv) the beneficial owner is not a bank whose receipt of interest on an exchange note is described in section 881(c)(3)(A) of the Code and (v) the beneficial owner satisfies the statement requirement (described generally below) set forth in section 871(h) and section 881(c) of the Code and the regulations thereunder.

     (b) no withholding of United States federal income tax generally will be required with respect to any gain realized by a Non-U.S. Holder upon the sale, exchange, retirement or other disposition of an exchange note; and

     (c) an exchange note beneficially owned by an individual who at the time of death is a Non-U.S. Holder will not be subject to United States federal estate tax as a result of such individual’s death, provided that any payment on the exchange notes, including original issue discount, would be eligible for exemption from the 30% federal withholding tax under the rules described in paragraph (a) above without regard to the statement requirement described in (a)(v) above.

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     To satisfy the requirement referred to in (a)(v) above, the beneficial owner of such an exchange note, or a financial institution holding the exchange note on behalf of such owner, must provide, in accordance with specified procedures, our paying agent with a statement to the effect that the beneficial owner is not a United States person. Currently, these requirements will be met if (1) the beneficial owner provides his name and address, and certifies, under penalties of perjury, that he is not a United States person (which certification may be made on an Internal Revenue Service (“IRS”) Form W-8BEN) or (2) a financial institution holding the exchange note on behalf of the beneficial owner certifies, under penalties of perjury, that such statement has been received by it and furnishes a paying agent with a copy thereof. The statement requirement referred to in (a)(v) above may also be satisfied with other documentary evidence with respect to an offshore account or through certain foreign intermediaries.

     If a Non-U.S. Holder cannot satisfy the requirements of the “portfolio interest” exception described in (a) above, payments of premium, if any, and interest made to such Non-U.S. Holder will be subject to a 30% withholding tax unless the beneficial owner of the exchange note provides us or our paying agent, as the case may be, with a properly executed (1) IRS Form W-8BEN claiming an exemption from or reduction in withholding under the benefit of an applicable income tax treaty or (2) IRS Form W-8ECI stating that interest paid on the exchange note is not subject to withholding tax because it is effectively connected with the beneficial owner’s conduct of a trade or business in the United States. Alternative documentation may be applicable in certain situations.

     If a Non-U.S. Holder is engaged in a trade or business in the United States and interest on the exchange note is effectively connected with the conduct of such trade or business, the Non-U.S. Holder, although exempt from the withholding tax discussed above (provided the certification requirements described above are satisfied), will be subject to United States federal income tax on such interest on a net income basis in the same manner as if it were a U.S. Holder. In addition, if such holder is a foreign corporation, it may be subject to a branch profits tax equal to 30% (or lesser rate under an applicable income tax treaty) of such amount, subject to adjustments.

     Any gain realized upon the sale, exchange, retirement or other disposition of an exchange note generally will not be subject to United States federal income tax unless (i) such gain is effectively connected with a trade or business in the United States of the Non-U.S. Holder, or (ii) in the case of a Non-U.S. Holder who is an individual, such individual is present in the United States for 183 days or more in the taxable year of such sale, exchange, retirement or other disposition, and certain other conditions are met.

     Special rules may apply to certain Non-U.S. Holders, such as “controlled foreign corporations,” “passive foreign investment companies,” “foreign personal holding companies” and certain expatriates, that are subject to special treatment under the Code. Such entities should consult their own tax advisors to determine the U.S. federal, state, local and other tax consequences that may be relevant to them.

Information Reporting and Backup Withholding

     Information reporting will generally apply to payments of interest on the exchange notes to Non-U.S. Holders and the amount of tax, if any, withheld with respect to such payments. Copies of the information returns reporting such interest payments and any withholding may also be made available to the tax authorities in the country in which the Non-U.S. Holder resides under the provisions of an applicable income tax treaty.

     In general, no backup withholding will be required with respect to payments made by us or any paying agent to Non-U.S. Holders if a statement described in (a)(v) under “Non-U.S. Holders” has been received (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person).

     In addition, information reporting and, depending on the circumstances, backup withholding, will apply to the proceeds of the sale of an exchange note within the United States or conducted through United States-related financial intermediaries unless the statement described in (a)(v) under “Non-U.S. Holders” has been received (and the payor does not have actual knowledge or reason to know that the beneficial owner is a United States person) or the holder otherwise establishes an exemption.

     Any amounts withheld under the backup withholding rules will be allowed as a refund or a credit against such holder’s United States federal income tax liability provided the required information is furnished to the IRS.

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CERTAIN ERISA CONSIDERATIONS

Certain ERISA Considerations

     The following is a summary of certain considerations associated with the purchase of the notes by employee benefit plans that are subject to Title I of the U.S. Employee Retirement Income Security Act of 1974, as amended (“ERISA”), plans, individual retirement accounts and other arrangements that are subject to Section 4975 of the Code or provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Code or ERISA (collectively, “Similar Laws”), and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements (each, a “Plan”).

General Fiduciary Matters

     ERISA and the Code impose certain duties on persons who are fiduciaries of a Plan subject to Title I of ERISA or Section 4975 of the Code (an “ERISA Plan”) and prohibit certain transactions involving the assets of an ERISA Plan and its fiduciaries or other interested parties. Under ERISA and the Code, any person who exercises any discretionary authority or control over the administration of such an ERISA Plan or the management or disposition of the assets of such an ERISA Plan, or who renders investment advice for a fee or other compensation to such an ERISA Plan, is generally considered to be a fiduciary of the ERISA Plan.

     In considering an investment in the notes of a portion of the assets of any Plan, a fiduciary should determine whether the investment is in accordance with the documents and instruments governing the Plan and the applicable provisions of ERISA, the Code or any Similar Law relating to a fiduciary’s duties to the Plan including, without limitation, the prudence, diversification, delegation of control and prohibited transaction provisions of ERISA, the Code and any other applicable Similar Laws.

Prohibited Transaction Issues

     Section 406 of ERISA and Section 4975 of the Code prohibit ERISA Plans from engaging in specified transactions involving plan assets with persons or entities who are “parties in interest,” within the meaning of ERISA, or “disqualified persons,” within the meaning of Section 4975 of the Code, unless an exemption is available. A party in interest or disqualified person who engaged in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Code. In addition, the fiduciary of the ERISA Plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Code. The acquisition and/or holding of notes by an ERISA Plan with respect to which we, any initial purchaser, joint book-running manager or guarantor, is considered a party in interest or a disqualified person may constitute or result in a direct or indirect prohibited transaction under Section 406 of ERISA and/or Section 4975 of the Code, unless the investment is acquired and is held in accordance with an applicable statutory, class or individual prohibited transaction exemption. In this regard, the U.S. Department of Labor (the “DOL”) has issued prohibited transaction class exemptions, or “PTCEs,” that may apply to the acquisition and holding of the notes. These class exemptions include, without limitation, PTCE 84-14 respecting transactions determined by independent qualified professional asset managers, PTCE 90-1 respecting insurance company pooled separate accounts, PTCE 91-38 respecting bank collective investment funds, PTCE 95-60 respecting life insurance company general accounts and PTCE 96-23 respecting transactions determined by in-house asset managers, although there can be no assurance that all of the conditions of any such exemptions will be satisfied.

     Because of the foregoing, the notes should not be purchased or held by any person investing “plan assets” of any Plan, unless such purchase and holding will not constitute a non-exempt prohibited transaction under ERISA and the Code or similar violation of any applicable Similar Laws.

     The foregoing discussion is general in nature and is not intended to be all-inclusive. Due to the complexity of these rules and the penalties that may be imposed upon persons involved in non-exempt prohibited transactions, it is particularly important that fiduciaries, or other persons considering purchasing the notes on behalf of, or with the assets of, any Plan, consult with their counsel regarding the potential applicability of ERISA, Section 4975 of the Code and any Similar Laws to such investment and whether an exemption would be applicable to the purchase and holding of the notes.

139

PLAN OF DISTRIBUTION

     Each broker-dealer that receives exchange notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange notes received in exchange for outstanding notes where such outstanding notes were acquired as a result of market-making activities or other trading activities. To the extent any such broker-dealer participates in the exchange offer and so notifies us, or causes us to be so notified in writing, we have agreed that a period of 90 days after the date of this prospectus, we will make this prospectus, as amended or supplemented, available to such broker-dealer for use in connection with any such resale, and will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal.

     We will not receive any proceeds from any sale of exchange notes by broker-dealers. Exchange notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange notes or a combination of such methods of resale, at prevailing market prices at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such exchange notes. Any broker-dealer that resells exchange notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange notes may be deemed to be an “underwriter” within the meaning of the Securities Act, and any profit on any such resale of exchange notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

     We have agreed to pay all expenses incident to the exchange offer (other than commissions and concessions of any broker-dealers), subject to certain prescribed limitations, and will indemnify the holders of the outstanding notes against certain liabilities, including certain liabilities that may arise under the Securities Act.

     By its acceptance of the exchange offer, any broker-dealer that receives exchange notes pursuant to the exchange offer hereby agrees to notify us prior to using the prospectus in connection with the sale or transfer of exchange notes, and acknowledges and agrees that, upon receipt of notice from us of the happening of any event which makes any statement in the prospectus untrue in any material respect or which requires the making of any changes in the prospectus in order to make the statements therein not misleading or which may impose upon us disclosure obligations that may have a material adverse effect on us (which notice we agree to deliver promptly to such broker-dealer), such broker-dealer will suspend use of the prospectus until we have notified such broker-dealer that delivery of the prospectus may resume and has furnished copies of any amendment or supplement to the prospectus to such broker-dealer.

140

LEGAL MATTERS

     Certain legal matters with respect to the exchange notes and the guarantees will be passed upon for us by Simpson Thacher & Bartlett LLP, New York, New York.

EXPERTS

     The consolidated financial statements of Peabody Energy Corporation at December 31, 2002 and 2001 and for the year ended December 31, 2002, the nine months ended December 31, 2001, and the year ended March 31, 2001, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given on the authority of such firm as experts in accounting and auditing. The estimates of our proven and probable coal reserves referred to in this prospectus to the extent described in this prospectus, have been prepared by us and reviewed by Marshall Miller & Associates.

141

GLOSSARY OF SELECTED TERMS

     Anthracite.The highest rank of economically usable coal with moisture content less than 15% by weight and heating value as high as 15,000 Btu per pound. It is jet black with a high luster. It is mined primarily in Pennsylvania.

     Appalachia.Coal producing states of Alabama, Georgia, eastern Kentucky, Maryland, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia.

     Ash.Impurities consisting of iron, alumina and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

     Assigned reserves.Coal that has been committed to be mined at operating facilities.

  ��  Bituminous coal.The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btu per pound. It is dense and black and often has well-defined bands of bright and dull material.

     British thermal unit, or “Btu.”A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

     Clean Air Act Amendments of 1990.A comprehensive set of amendments to the federal law governing the nation’s air quality. The Clean Air Act was originally passed in 1970 to address significant air pollution problems in our cities. The 1990 amendments broadened and strengthened the original law to address specific problems such as acid deposition, urban smog, hazardous air pollutants and stratospheric ozone depletion.

     Coal seam.Coal deposits occur in layers. Each layer is called a “seam.”

     Coke.A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts.

     Coking coal.Coal used to make coke and interchangeably referred to as metallurgical coal.

     Compliance coal.Coal having a sulfur dioxide content of 1.2 pounds or less per million Btu, as required by Phase II of the Clean Air Act.

     Continuous mining.A form of underground room-and-pillar mining that uses a continuous mining machine to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.

     Deep mine.An underground coal mine.

     Dragline.A large excavating machine used in the surface mining process to remove overburden.

     Dragline mining.A form of mining where large capacity electric-powered draglines remove overburden to expose the coal seam. Smaller shovels load coal in haul trucks for transportation to the preparation plant and then to the rail loadout.

     Fossil fuel.Fuel such as coal, petroleum or natural gas formed from the fossil remains of organic material.

     Illinois basin.Coal producing area in Illinois, southern Indiana and western Kentucky.

     Lignite.The lowest rank of coal with a high moisture content of up to 45% by weight and heating value of 6,500 to 8,300 Btu per pound. It is brownish black and tends to oxidize and disintegrate when exposed to air.

     Longwall mining.A form of underground mining in which a panel or block of coal, generally at least 700 feet wide and often over one mile long, is completely extracted. The working area is protected by a moveable, powered roof support system.

142

     Metallurgical coal.The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal has a particularly high Btu, but low ash content.

     Nitrogen oxide (NOx).A gas formed in high temperature environments such as coal combustion. It is a harmful pollutant that contributes to acid rain.

     Non-compliance coal.Coal having a sulfur dioxide content of more than 1.2 pounds per million Btu.

     Overburden.Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

     Overburden ratio/stripping ratio.The amount of overburden that must be removed to excavate a given quantity of coal. It is commonly expressed in cubic yards per ton of coal or as a ratio comparing the thickness of the overburden with the thickness of the coal bed.

     Pillar.An area of coal left to support the overlying strata in a mine; sometimes left permanently to support surface structures.

     Powder River Basin.Coal producing area in northeastern Wyoming and southeastern Montana. This is the largest known source of coal reserves and the largest producing region in the United States.

     Preparation plant.Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.

     Probable reserves.Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven 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 reserves, is high enough to assume continuity between points of observation.

     Proven 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 closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established.

     Reclamation.The process of restoring land and the environment to their original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

     Reserve.That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

     Roof.The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place. Same as “back” or “top.”

     Room-and-Pillar Mining.The most common method of underground mining in which the mine roof is supported mainly by coal pillars left at regular intervals. Rooms are placed where the coal is mined; pillars are areas of coal left between the rooms. Room-and-pillar mining is done either by conventional or continuous mining.

     Scrubber (flue gas desulfurization unit).Any of several forms of chemical/physical devices which operate to neutralize sulfur compounds formed during coal combustion. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that must then be removed for disposal. Although effective in substantially reducing sulfur from combustion gases, scrubbers require about 6% to 7% of a power plant’s electrical output and thousands of gallons of water to operate.

143

     Steam coal.Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

     Subbituminous coal.Dull, black coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 30% by weight, and its heat content ranges from 7,800 to 9,500 Btu per pound of coal.

     Sulfur.One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

     Sulfur content.Coal is commonly described by its sulfur content due to the importance of sulfur in environmental regulations. “Low sulfur” coal has a variety of definitions but typically is used to describe coal consisting of 1.0% or less sulfur. A majority of our Appalachian and Powder River Basin reserves are of low sulfur grades.

     Surface mine.A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil (see “Overburden”). About 60% of total U.S. coal production comes from surface mines.

     Tons.A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds; a “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this prospectus.

     Truck-and-shovel mining.A form of mining where large shovels are used to remove overburden, which is used to backfill pits after the coal is removed. Smaller shovels load coal in haul trucks for transportation to the preparation plant or rail loadout.

     Unassigned reserves. Coal at suspended locations and coal that has not been committed, and that would require new mine development, mining equipment or plant facilities before operations could begin on the property.

     Underground mine.Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface. Most underground mines are located east of the Mississippi River and account for about 40% of annual U.S. coal production.

     Unit train. A train of 100 or more cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.

     Western bituminous coal regions. Coal producing area including, the Hanna Basin in Wyoming, the Uinta Basin of northwestern Colorado and Utah, the Four Corners Region in New Mexico and Arizona and the Raton Basin in southern Colorado.

144

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

		Page
Unaudited Financial Statements:
	Unaudited Condensed Consolidated Statements of Operations for the Quarters Ended March 31, 2002 and 2003		F-2
	Condensed Consolidated Balance Sheets as of December 31, 2002 and March 31, 2003 (unaudited)		F-3
	Unaudited Condensed Consolidated Statements of Cash Flows for the Quarters Ended March 31, 2002 and 2003		F-4
	Notes to Unaudited Condensed Consolidated Financial Statements		F-5
Audited Financial Statements:
	Consolidated Statements of Operations — Year ended March 31, 2001, nine months ended December 31, 2001 and year ended December 31, 2002		F-22
	Consolidated Balance Sheets — December 31, 2001 and 2002		F-23
	Consolidated Statements of Changes in Stockholders’ Equity — Year ended March 31, 2001, nine months ended December 31, 2001 and year ended December 31,   2002		F-24
	Consolidated Statements of Cash Flows — Year ended March 31, 2001, nine months ended December 31, 2001 and year ended December 31, 2002		F-25
	Notes to Consolidated Financial Statements		F-26
Report of Independent Auditors			F-68

F-1

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

			Quarter Ended March 31,
			2002			2003
			(In thousands, except share and
			per share information)
Revenues
	Sales		$	652,283		$	657,829
	Other revenues			23,483			23,465
		Total revenues		675,766			681,294
Costs and Expenses
	Operating costs and expenses			536,161			566,620
	Depreciation, depletion and amortization			58,677			56,047
	Asset retirement obligation expense			—			6,490
	Selling and administrative expenses			26,283			25,324
	Net gain on property and equipment disposals			(305	)		(7,718	)
Operating Profit				54,950			34,531
	Interest expense			24,903			26,152
	Early debt extinguishment costs			—			21,184
	Interest income			(519	)		(672	)
Income (Loss) Before Income Taxes and Minority Interests				30,566			(12,133	)
	Income tax provision (benefit)			4,585			(12,246	)
	Minority interests			3,666			1,050
Income (Loss) Before Accounting Changes				22,315			(937	)
	Cumulative effect of accounting changes, net of taxes			—			(10,144	)
Net Income (Loss)			$	22,315		$	(11,081	)
Basic Earnings Per Common Share:
	Income (loss) before accounting changes		$	0.43		$	(0.02	)
	Cumulative effect of accounting changes, net of taxes			—			(0.19	)
	Net income (loss)		$	0.43		$	(0.21	)
Weighted Average Common Shares Outstanding				52,018,238			52,414,041
Diluted Earnings Per Common Share:
	Income (loss) before accounting changes		$	0.42		$	(0.02	)
	Cumulative effect of accounting changes, net of taxes			—			(0.19	)
	Net income (loss)		$	0.42		$	(0.21	)
Weighted Average Common Shares Outstanding				53,731,426			52,414,041
Dividends Declared Per Share			$	0.10		$	0.10

See accompanying notes to unaudited condensed consolidated financial statements.

F-2

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

				December 31, 2002			March 31, 2003
							(Unaudited)
				(In thousands, except share and
				per share information)
ASSETS
Current assets
	Cash and cash equivalents			$	71,210		$	71,718
	Restricted cash				—			509,592
	Accounts receivable, less allowance for doubtful accounts of $1,331 at December 31, 2002 and $1,309 at March 31, 2003				153,212			249,612
	Materials and supplies				39,416			41,623
	Coal inventory				190,272			206,351
	Assets from coal and emission allowance trading activities				69,898			42,272
	Deferred income taxes				10,361			10,380
	Other current assets				15,554			16,477
		Total current assets			549,923			1,148,025
Property, plant, equipment and mine development, net of accumulated depreciation, depletion and amortization of $858,187 at December 31, 2002 and $898,510 at March 31, 2003					4,273,042			4,303,150
Investments and other assets					317,212			332,689
		Total assets		$	5,140,177		$	5,783,864
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Short-term borrowings and current maturities of long-term debt			$	47,515		$	21,522
	Notes called for redemption				—			465,004
	Liabilities from coal and emission allowance trading activities				37,008			31,012
	Accounts payable and accrued expenses				547,013			590,155
		Total current liabilities			631,536			1,107,693
Long-term debt, less current maturities					981,696			1,173,057
Deferred income taxes					499,310			479,661
Asset retirement obligations					386,777			392,205
Workers’ compensation obligations					209,798			214,702
Accrued postretirement benefit costs					959,599			963,469
Obligation to industry fund					49,760			47,814
Other noncurrent liabilities					303,442			302,462
		Total liabilities			4,021,918			4,681,063
Minority interests					37,121			36,821
Stockholders’ equity
	Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of December 31, 2002 or March 31, 2003				—			—
	Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of December 31, 2002 or March 31, 2003				—			—
	Common Stock — $0.01 per share par value; 150,000,000 shares authorized, 52,417,483 shares issued and 52,400,278 shares outstanding as of December 31, 2002 and 150,000,000 shares authorized, 52,440,718 shares issued and 52,423,513 shares outstanding as of March 31, 2003				524			524
	Additional paid-in capital				958,567			958,993
	Retained earnings				200,859			184,536
	Employee stock loans				(1,142	)		(407	)
	Accumulated other comprehensive loss				(77,627	)		(77,623	)
	Treasury shares, at cost: 17,205 shares as of December 31, 2002 and March 31, 2003, respectively				(43	)		(43	)
		Total stockholders’ equity			1,081,138			1,065,980
			Total liabilities and stockholders’ equity	$	5,140,177		$	5,783,864

See accompanying notes to unaudited condensed consolidated financial statements.

F-3

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

			Quarter Ended March 31,
			2002			2003
			(In thousands)
Cash Flows from Operating Activities
Net income (loss)			$	22,315		$	(11,081	)
	Cumulative effect of accounting changes, net of taxes			—			10,144
		Income (loss) before accounting changes		22,315			(937	)
Adjustments to reconcile income (loss) before accounting changes to net cash provided by operating activities:
	Depreciation, depletion and amortization			58,677			56,047
	Deferred income taxes			4,585			(13,112	)
	Early debt extinguishment costs			—			21,184
	Amortization of debt discount and debt issuance costs			2,859			2,289
	Net gain on property and equipment disposals			(305	)		(7,718	)
	Minority interests			3,666			1,050
	Changes in current assets and liabilities:
		Accounts receivable		(14,648	)		(12,500	)
		Materials and supplies		(1,687	)		(2,207	)
		Coal inventory		(21,833	)		(16,079	)
		Net assets from coal and emission allowance trading activities		(9,137	)		(12,014	)
		Other current assets		(4,185	)		(659	)
		Accounts payable and accrued expenses		(17,851	)		43,142
	Asset retirement obligations			(265	)		(2,237	)
	Workers’ compensation obligations			1,362			4,904
	Accrued postretirement benefit costs			477			5,363
	Obligation to industry fund			(761	)		(1,946	)
	Other, net			(1,854	)		(7,019	)
		Net cash provided by operating activities		21,415			57,551
Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development				(47,064	)		(58,844	)
Additions to advance mining royalties				(2,104	)		(2,354	)
Investment in joint venture				(475	)		—
Proceeds from property and equipment disposals				833			8,139
	Net cash used in investing activities			(48,810	)		(53,059	)
Cash Flows from Financing Activities
Net change in revolving lines of credit				25,000			(121,584	)
Proceeds from long-term debt, net of restricted cash proceeds				2,375			591,311
Payments of long-term debt				(14,687	)		(361,915	)
Reduction of securitized interests in accounts receivable				—			(83,900	)
Payment of debt issuance costs				—			(22,687	)
Distributions to minority interests				(2,825	)		(1,350	)
Dividend paid				(5,202	)		(5,242	)
Other				227			1,014
	Net cash provided by (used in) financing activities			4,888			(4,353	)
Effect of exchange rate changes on cash and cash equivalents				—			369
Net increase (decrease) in cash and cash equivalents				(22,507	)		508
Cash and cash equivalents at beginning of year				38,622			71,210
Cash and cash equivalents at end of period			$	16,115		$	71,718

See accompanying notes to unaudited condensed consolidated financial statements.

F-4

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2003

(1) Basis of Presentation

     The condensed consolidated financial statements include the accounts of Peabody Energy Corporation (the “Company”) and its controlled affiliates. All significant intercompany transactions, profits and balances have been eliminated in consolidation. Certain prior year amounts have been reclassified to conform with the current year presentation.

     The accompanying condensed consolidated financial statements as of March 31, 2003 and for the quarters ended March 31, 2002 and 2003, and the notes thereto, are unaudited. However, in the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation of the results of the periods presented. The balance sheet information as of December 31, 2002 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the quarter ended March 31, 2003 are not necessarily indicative of the results to be expected for the year ending December 31, 2003.

(2) Debt Refinancing

     During March 2003, the Company entered into a series of transactions, discussed in detail below, to refinance a substantial portion of its outstanding indebtedness. The refinancing expanded the Company’s revolving line of credit capacity and will lower its overall borrowing costs. The Company’s total indebtedness (in thousands) consisted of the following at:

	December 31,		March 31,
	2002		2003
Term Loan under Senior Secured Credit Facility	$	—	$	450,000
6 7/8% Senior Notes due 2013		—		650,000
9 5/8% Senior Subordinated Notes to be redeemed May 15, 2003		391,490		257,553
8 7/8% Senior Notes to be redeemed May 15, 2003		316,498		207,451
5.0% Subordinated Note		85,055		76,207
Senior unsecured notes under various agreements		58,214		—
Unsecured revolving credit agreement		116,584		—
Other		61,370		18,372
	$	1,029,211	$	1,659,583

     The following table shows the sources and uses (in thousands), through March 31, 2003, of cash related to the refinancing transactions:

Sources:
	Revolving Credit Facility		$	—
	Term Loan under Senior Secured Credit Facility			450,000
	6 7/8% Senior Notes due 2013			650,000
		Total	$	1,100,000
Uses:
	Repayment of 9 5/8% Senior Subordinated Notes		$	133,964
	Repayment of 8 7/8% Senior Notes			109,082
	Repayment of Black Beauty indebtedness			203,215
	Fees and prepayment premiums paid in connection with refinancing			41,023
	Cash restricted for notes to be redeemed May 15, 2003			509,592
	Cash			103,124
		Total	$	1,100,000

F-5

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

Use of Proceeds

     The Company has used and will use the $1.1 billion of proceeds from the $450.0 million term loan under its Senior Secured Credit Facility and the $650.0 million in 6 7/8% Senior Notes to repay and retire the following indebtedness:

•  All of its 9 5/8% Senior Subordinated Notes

•  All of its 8 7/8% Senior Notes

•  Substantially all of Black Beauty’s indebtedness

     During March 2003, the Company completed a tender offer to retire $134.0 million of its 9 5/8% Senior Subordinated Notes and $109.1 million of its 8 7/8% Senior Notes. In addition, $203.2 million of Black Beauty indebtedness was retired. The Company also incurred cash expenses related to the refinancing and prepayment premiums related to the early extinguishment of debt totaling $41.0 million during the quarter. The remaining 9 5/8% Senior Subordinated Notes and 8 7/8% Senior Notes have been called for redemption and will be redeemed on May 15, 2003. The Company’s balance sheet at March 31, 2003 reflects $509.6 million in restricted cash that will be used to pay prepayment premiums, accrued interest and the remaining principal balance of $465.0 million of the 9 5/8% Senior Subordinated Notes and 8 7/8% Senior Notes (classified on the March 31, 2003 balance sheet as “Notes called for redemption”). The remaining cash proceeds of $103.1 million were temporarily used to reduce the Company’s $140.0 million accounts receivable securitization by $83.9 million and for investments in cash equivalents. The reduction in securitized interests in accounts receivable resulted in an $83.9 million increase in accounts receivable as of March 31, 2003. On April 7, 2003, the securitization returned to near its total capacity of $140.0 million as the Company used $90.0 million to acquire the remaining 18.3% of Black Beauty. This acquisition is discussed in Note 10 to the unaudited condensed consolidated financial statements. The Company’s new debt instruments are described in greater detail below.

Senior Secured Credit Facility

     On March 21, 2003, the Company entered into a new Senior Secured Credit Facility that consists of a $600.0 million revolving credit facility and a $450.0 million term loan. The new revolving credit facility, which currently bears interest at LIBOR plus 2.0% and expires in March 2008, provides for maximum borrowings and/or letters of credit of $600.0 million. The Company had letters of credit outstanding under the facility of $231.2 million at March 31, 2003, leaving $368.8 million available for borrowing. The new $450.0 million term loan, which is due in March 2010, currently bears interest at LIBOR plus 2.5%. 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 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 March 31, 2003.

6 7/8% Senior Notes due 2013

     On March 21, 2003, the Company issued $650.0 million in senior notes, which bear interest at 6 7/8% and are due in March 2013. The notes were sold in accordance with Securities and Exchange Commission Rule 144A, and the Company intends to file a registration statement with the Securities and Exchange Commission that will enable the holders of these 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

F-6

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

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.

Early Debt Extinguishment Costs

     In connection with the refinancing, the Company incurred early debt extinguishment costs of $21.2 million during the quarter ended March 31, 2003. These costs are comprised of the following:

•  Payment of prepayment premiums and tender fees totaling $18.9 million;

•  A non-cash charge to write-off debt issuance costs associated with the debt extinguished of $8.1 million; and

•  A $5.8 million gain related to the termination and monetization of interest rate swaps associated with the debt extinguished.

     As a result of the adoption on January 1, 2003 of Statement of Financial Accounting Standards (“SFAS”) No. 145 “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” gains or losses on debt extinguishment previously reported as extraordinary items are presented as a component of results from continuing operations unless the extinguishment meets the criteria for classification as an extraordinary item in Accounting Principles Board Opinion No. 30. The effect of the adoption and application of this new standard in 2003 was to decrease income before accounting changes for the quarter by $21.2 million, before taxes. Prior year results of operations included no debt extinguishment costs.

     Upon the redemption and repayment of the remaining 9 5/8% Senior Subordinated Notes and 8 7/8% Senior Notes on May 15, 2003, the Company will incur early debt extinguishment costs of approximately $31.1 million, consisting of $21.7 million of prepayment premiums and a non-cash charge to write-off $9.4 million of debt issuance costs associated with the debt to be retired.

(3) Cumulative Effect of Accounting Changes

     On January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.

     For the Company, asset retirement obligation expense represents the systematic accretion and depreciation of future mine reclamation costs, which includes the costs to reclaim the land disturbed during the mining process and the removal of mine plant, equipment, transportation and other support facilities.

     SFAS No. 143 requires the fair value of a liability for an asset’s retirement obligation to be recorded in the period in which it is incurred if a reasonable estimate of fair value can be made, and that the corresponding cost is capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated over the useful life of the related asset. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.

     Under its previous accounting method, the Company accrued the estimated future costs to reclaim the land as the acreage was disturbed at surface mine operations and the estimated costs to reclaim support

F-7

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

acreage and to perform other related functions at both surface and underground mines ratably over the lives of the mines.

     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 tax, for the cumulative effect of the accounting change;

•  increased total liabilities by $0.5 million to record the asset retirement obligations;

•  increased assets by $18.6 million to add the asset retirement costs to the carrying amount of our mine properties and 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 previously recognized.

     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 Emerging Issues Task Force (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, “Accounting for Derivative Instruments and Hedging Activities” (as amended) were no longer accounted for on a fair value basis, effective January 1, 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 is currently estimated at 9.5 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 quarter ended March 31, 2003.

     The effect of the changes for the quarter ended March 31, 2003 was to increase income before accounting changes by $5.5 million, or $0.11 per share, net of 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 is included in results of operations for the quarter ended March 31, 2003. Below are pro forma net

F-8

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

income and earnings per share results for the Company assuming the new methods had been retroactively applied (dollars in thousands, except per share data):

		Quarter Ended
		March 31,
		2002		2003
Net income (loss):
	As reported	$	22,315	$	(11,081	)
	Pro forma		18,314		(937	)
Basic earnings (loss) per share:
	As reported	$	0.43	$	(0.21	)
	Pro forma		0.35		(0.02	)
Diluted earnings (loss) per share:
	As reported	$	0.42	$	(0.21	)
	Pro forma		0.34		(0.02	)

(4)  Coal Inventory

     Inventories consisted of the following (dollars in thousands) at:

		December 31,		March 31,
		2002		2003
Raw coal		$	18,076	$	17,965
Work in process			143,963		147,068
Saleable coal			28,233		41,318
	Total	$	190,272	$	206,351

(5)  Assets and Liabilities from Coal and Emission Allowance Trading Activities

     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 (as amended) were no longer accounted for on a fair value basis effective January 1, 2003. The Company recorded a cumulative effect charge of $20.2 million, net of income taxes, in the quarter ended March 31, 2003 to reverse the net unrealized gains on non-derivative energy trading contracts recorded prior to December 31, 2002. Substantially all of these non-derivative energy trading contracts will settle in 2003 and 2004.

     The fair value of coal trading derivatives as of March 31, 2003, are set forth below (dollars in thousands):

		Fair Value
		Assets		Liabilities
Forward contracts		$	39,265	$	29,608
Option contracts			3,007		1,404
	Total	$	42,272	$	31,012

     All of the contracts in the Company’s trading portfolio as of March 31, 2003 were valued utilizing prices from over-the-counter market sources, adjusted for contract duration and coal quality.

F-9

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

     As of March 31, 2003, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:

	Percentage
Year of Expiration	of Portfolio
2003		34	%
2004		63	%
2005		2	%
2006		1	%
		100	%

     At March 31, 2003, 44% of the Company’s credit exposure related to coal and emission allowance trading activities was with counterparties that are investment grade. Where practical, the Company takes steps to reduce its 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 or the creation of customer trust accounts held for the Company’s benefit to fund the payments required under existing contracts. To further reduce credit exposure in its trading business, the Company also seeks to enter into netting agreements with counterparties that permit the Company to offset receivables and payables with such counterparties.

     The Company’s coal trading operations traded 28.2 million tons and 16.6 million tons for the quarters ended March 31, 2002 and 2003, respectively.

(6) Earnings Per Share

     A reconciliation of weighted average shares outstanding follows:

	Quarter Ended
	March 31,
	2002		2003
Weighted average shares outstanding — basic		52,018,238		52,414,041
Dilutive impact of stock options		1,713,188		—
Weighted average shares outstanding — diluted		53,731,426		52,414,041

     Stock Compensation

     The Company applies Accounting Principles Board (“APB”) Opinion No. 25 and related interpretations in accounting for its equity incentive plans. The Company recorded $0.1 million of compensation expense for granted stock options during each of the quarters ended March 31, 2002 and 2003. The following table reflects pro forma net income (loss) and basic and diluted earnings (loss) per share had compensation cost been determined for the Company’s non-qualified and incentive stock options based on the fair value at the

F-10

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

grant dates consistent with the methodology set forth under SFAS No. 123, “Accounting for Stock-Based Compensation” (dollars in thousands, except per share data):

		Quarter Ended
		March 31,
		2002		2003
Net income (loss):
	As reported	$	22,315	$	(11,081	)
	Pro forma		21,104		(12,613	)
Basic earnings (loss) per share:
	As reported	$	0.43	$	(0.21	)
	Pro forma		0.41		(0.24	)
Diluted earnings (loss) per share:
	As reported	$	0.42	$	(0.21	)
	Pro forma		0.39		(0.24	)

(7)  Comprehensive Income

     The following table sets forth the components of comprehensive income (loss) for the quarters ended March 31, 2002 and 2003 (dollars in thousands):

	Quarter Ended
	March 31,
	2002		2003
Net income (loss)	$	22,315	$	(11,081	)
Foreign currency translation adjustment		—		4
Comprehensive income (loss)	$	22,315	$	(11,077	)

(8) Segment Information

     The Company reports its operations primarily through the following reportable operating segments: “U.S. Mining,” “Trading and Brokerage,” and “Australian Mining Operations.” The principal business of the U.S. Mining segment is mining, preparation and sale of its steam coal, sold primarily to electric utilities, and metallurgical coal, sold to steel and coke producers. The Trading and Brokerage segment’s principal business is the marketing and trading of coal and emission allowances. The Australian Mining Operations segment consists of the operations of Allied Queensland Coalfields Party Limited. This segment’s principal business is the same as the U.S. Mining Segment. “Corporate and Other” consists primarily of corporate overhead not directly attributable to the U.S. Mining or Trading and Brokerage operating segments, and resource management activities. In some cases, the Company’s brokerage operation acts as the sales agent for the U.S. and Australian Mining Operations. For purposes of the presentation below, intercompany sales between the mining operations and Trading and Brokerage Operations have been eliminated, and the third party sales are reflected in the mining operations’ revenues.

     The U.S. Mining segment results below also include costs related to past mining activities and a portion of consolidated net gains on property disposals. Past mining activities and net gains on property disposals are discussed separately from U.S. Mining results in “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

F-11

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

     Operating segment results for the quarters ended March 31, 2002 and 2003 are as follows (dollars in thousands):

			Quarter Ended
			March 31,
			2002			2003
Revenues:
	U.S. Mining		$	614,491		$	570,489
	Trading and Brokerage			54,551			100,777
	Australian Mining Operations			—			6,362
	Corporate and Other			6,724			3,666
		Total	$	675,766		$	681,294
Operating Profit:
	U.S. Mining		$	68,120		$	30,802
	Trading and Brokerage			11,247			16,966
	Australian Mining Operations			—			1,712
	Corporate and Other			(24,417	)		(14,949	)
		Total	$	54,950		$	34,531

     A reconciliation of segment operating profit to consolidated income (loss) before income taxes follows (dollars in thousands):

		Quarter Ended
		March 31,
		2002			2003
Total segment operating profit		$	54,950		$	34,531
	Interest expense		24,903			26,152
	Early debt extinguishment costs		—			21,184
	Interest income		(519	)		(672	)
	Minority interests		3,666			1,050
Income (loss) before income taxes		$	26,900		$	(13,183	)

(9)  Commitments and Contingencies

Environmental

     Environmental claims have been asserted against a subsidiary of the Company at 22 sites in the United States. 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 majority of these sites are related to activities of former subsidiaries of the Company.

     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

F-12

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

and, where allegations are based on tentative findings, the reasonableness of the Company’s apportionment. The Company has not anticipated any recoveries from insurance carriers or other potentially responsible third parties in the estimation of liabilities recorded on its consolidated balance sheets. The undiscounted liabilities for environmental cleanup-related costs recorded as part of “Accrued reclamation and other environmental liabilities” were $42.1 million and $40.3 million at December 31, 2002 and March 31, 2003, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable.

Navajo Nation

     On June 18, 1999, the Navajo Nation served the Company’s subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company (“Peabody Western”), with a complaint that had been filed in the U.S. District Court for the District of Columbia. Other defendants in the litigation are one customer, one current employee and one former employee. The Navajo Nation has 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 February 21, 2002, the Company’s subsidiaries commenced a lawsuit against the Navajo Nation in the U.S. District Court for the District of Arizona seeking enforcement of an arbitration award or, alternatively, to compel arbitration pursuant to the April 1, 1998 Arbitration Agreement with the Navajo Nation. On January 14, 2003, the Arizona District Court dismissed the lawsuit. Our subsidiaries have filed an appeal of this decision with the Ninth Circuit Court of Appeals.

     On February 22, 2002, the Company’s subsidiaries filed in the U.S. District Court for the District of Columbia a motion for leave to file an amended answer and conditional counterclaim. The counterclaim is conditional because the Company’s subsidiaries contend that the lease provisions the Navajo Nation seeks to invalidate have previously been upheld in an arbitration proceeding and are not subject to further litigation. On March 4, 2002, the Company’s subsidiaries filed in the U.S. District Court for the District of Columbia a motion to transfer that case to Arizona or, alternatively, to stay the District of Columbia litigation. The District of Columbia District Court denied the Company’s subsidiaries’ motion for a stay and the subsidiaries appealed that ruling to the District of Columbia Court of Appeals. On April 23, 2003, the appellate court denied the appeal.

     On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States. The Court rejected the Navajo Nation’s allegation that the U.S. breached its trust responsibilities to the Tribe in approving the coal lease amendments and was liable for money damages. On May 2, 2003, the Company’s subsidiaries filed a renewed motion to dismiss the Navajo Nation’s lawsuit against them based on the Supreme Court’s decision.

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

F-13

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

Mohave Generating Station

     Peabody Western has a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline to the Mohave plant. Also, Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to recovery of future capital expenditures for new pollution abatement equipment for the station. The operator has stated that it expects to idle the plant for at least 12 to 18 months beginning in 2006. The Company is in active discussions to resolve the complex issues critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. If these issues are not resolved in a timely manner, the operation of the Mohave plant will cease or be suspended on December 31, 2005. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 4.6 million tons of coal in 2002.

Citizens Power

     In connection with the August 2000 sale of the Company’s former subsidiary, Citizens Power LLC, the Company has indemnified the buyer, Edison Mission Energy, from certain losses resulting from specified power contracts and guarantees. Should a party to one of these agreements fail to perform, the Company would be required to reimburse the buyer for any losses incurred as a result of any non-performance that meets the requirements set forth in the indemnity.

     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. 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.

     Also during the ownership period, Citizens Power indemnified a utility against decreases in the value of power deliveries as a result of the implementation of a location-based pricing system in the New England Power Pool in connection with a power supply agreement that runs through 2016. Citizens Power’s successor, an Edison Mission Energy subsidiary, is negotiating with the utility a methodology to calculate decreases in value and the Company is in agreement with the mitigation approach being negotiated by the successor. Edison Mission Energy has not made a claim against the Company under the indemnity.

     Due to the length and specific requirements of the contracts covered by the indemnity, the Company cannot reasonably estimate its future exposure, if any, under the indemnity.

Other

     In addition, the Company at times becomes a party to 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.

     At March 31, 2003, purchase commitments for capital expenditures were approximately $73.9 million.

F-14

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL

STATEMENTS — (Continued)

(10) Subsequent Events

     On April 7, 2003, the Company purchased the remaining 18.3% of Black Beauty Coal Company and affiliated entities for $90.0 million and contingent consideration. The additional consideration is contingent on Black Beauty’s achievement of certain levels of operating profit in 2003 and 2004, as set forth in the purchase and sale agreement. As a result of the acquisition, the Company now owns 100% of Black Beauty Coal Company. The acquisition will be accounted for as a purchase.

     On May 7, 2003, certain shareholders of the Company, including the Company’s largest shareholder, Lehman Brothers Merchant Banking Partners II L.P. and affiliates (collectively “Lehman Brothers”) sold 5,750,000 shares of common stock, including an over-allotment option of 750,000 shares. The selling shareholders received all net proceeds. The Company did not sell any shares through the offering. Lehman Brothers sold, in the aggregate, 5,617,825 shares in the offering, and their beneficial ownership of the Company declined from 41% to 30%.

(11) Related Party Transactions

     As discussed in note 2 to the unaudited condensed consolidated financial statements, 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 Inc., the Company appointed Wachovia Securities, Inc., Fleet Securities, Inc. and Lehman Brothers Inc. as lead arrangers for the Senior Secured Credit Facility, and Lehman Brothers Inc. and Morgan Stanley as joint book running managers for the Senior Notes. Lehman Brothers Inc. 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.

     In May 2003, Lehman Brothers Inc. served as the lead underwriter in connection with the secondary offering discussed in Note 10 above, and fees paid to Lehman Brothers Inc. 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 offering.

(12)  Supplemental Guarantor/Non-Guarantor Financial Information

     In accordance with the indentures governing the 6 7/8% Senior Notes, 8 7/8% Senior Notes and 9 5/8% Senior Subordinated Notes, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed the Senior Notes and Senior Subordinated 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 Senior Notes and Senior Subordinated Notes. The following unaudited condensed historical financial statement information is provided for such Guarantor/ Non-Guarantor Subsidiaries. Black Beauty is included in these supplemental financial statements as a Non-Guarantor subsidiary. After the Company’s acquisition on April 7, 2003 of the remaining 18.3% of Black Beauty, this subsidiary will become a Guarantor subsidiary of all of the indebtedness listed above. Black Beauty represents a significant portion of the Non-Guarantor results of operations, financial position and cash flows presented below.

F-15

PEABODY ENERGY CORPORATION

UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED

STATEMENTS OF OPERATIONS

QUARTER ENDED MARCH 31, 2002

		Parent			Guarantor			Non-Guarantor
		Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
		(In thousands)
Total revenues		$	—		$	523,671		$	167,686		$	(15,591	)	$	675,766
Costs and expenses
	Operating costs and expenses		—			418,235			133,517			(15,591	)		536,161
	Depreciation, depletion and amortization		—			46,364			12,313			—			58,677
	Selling and administrative expenses		161			21,436			4,686			—			26,283
	Net gain on property and equipment disposals		—			(180	)		(125	)		—			(305	)
	Interest expense		33,862			24,525			3,821			(37,305	)		24,903
	Interest income		(17,158	)		(16,870	)		(3,796	)		37,305			(519	)
Income (loss) before income taxes and minority interests			(16,865	)		30,161			17,270			—			30,566
	Income tax provision (benefit)		(2,530	)		4,453			2,662			—			4,585
	Minority interests		—			—			3,666			—			3,666
Net income (loss)		$	(14,335	)	$	25,708		$	10,942		$	—		$	22,315

F-16

PEABODY ENERGY CORPORATION

UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED

STATEMENTS OF OPERATIONS

QUARTER ENDED MARCH 31, 2003

		Parent			Guarantor			Non-Guarantor
		Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
		(In thousands)
Total revenues		$	—		$	499,727		$	188,231		$	(6,664	)	$	681,294
Costs and expenses
	Operating costs and expenses		—			420,553			152,731			(6,664	)		566,620
	Depreciation, depletion and amortization		—			41,354			14,693			—			56,047
	Asset retirement obligation expense		—			5,896			594			—			6,490
	Selling and administrative expenses		165			21,900			3,259			—			25,324
	Net gain on property and equipment disposals		—			(7,606	)		(112	)		—			(7,718	)
	Interest expense		35,274			24,882			3,224			(37,228	)		26,152
	Debt extinguishment costs		13,835			—			7,349			—			21,184
	Interest income		(17,220	)		(17,410	)		(3,270	)		37,228			(672	)
Income (loss) before income taxes and minority interests			(32,054	)		10,158			9,763			—			(12,133	)
	Income tax provision (benefit)		(13,158	)		(2,009	)		2,921			—			(12,246	)
	Minority interests		—			—			1,050			—			1,050
	Cumulative effect of accounting changes, net of taxes		6,762			(13,831	)		(3,075	)		—			(10,144	)
Net income (loss)		$	(12,134	)	$	(1,664	)	$	2,717		$	—		$	(11,081	)

F-17

PEABODY ENERGY CORPORATION

SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2002

			Parent		Guarantor			Non-Guarantor
			Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
			(In thousands)
ASSETS
Current assets
	Cash and cash equivalents		$	60,666	$	420		$	10,124		$	—		$	71,210
	Accounts receivable			836		62,214			90,162			—			153,212
	Inventories			—		211,291			18,397			—			229,688
	Assets from coal and emission allowance trading activities			—		65,153			4,745			—			69,898
	Deferred income taxes			—		10,101			260			—			10,361
	Other current assets			260		8,381			6,913			—			15,554
		Total current assets		61,762		357,560			130,601			—			549,923
Property, plant, equipment and mine development — at cost				—		4,591,811			539,418			—			5,131,229
Less accumulated depreciation, depletion and amortization				—		(751,627	)		(106,560	)		—			(858,187	)
Property, plant, equipment and mine development, net				—		3,840,184			432,858			—			4,273,042
Investments and other assets				3,448,319		248,778			48,273			(3,428,158	)		317,212
		Total assets	$	3,510,081	$	4,446,522		$	611,732		$	(3,428,158	)	$	5,140,177
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Short-term borrowings and current maturities of long-term debt		$	—	$	10,303		$	37,212		$	—		$	47,515
	Payables and notes payable to affiliates, net			1,626,695		(1,643,593	)		16,898			—			—
	Liabilities from coal and emission allowance trading activities			—		37,008			—			—			37,008
	Accounts payable and accrued expenses			9,427		479,441			58,145			—			547,013
		Total current liabilities		1,636,122		(1,116,841	)		112,255			—			631,536
Long-term debt, less current maturities				714,571		75,975			191,150			—			981,696
Deferred income taxes				—		495,284			4,026			—			499,310
Other noncurrent liabilities				623		1,898,581			10,172			—			1,909,376
		Total liabilities		2,351,316		1,352,999			317,603			—			4,021,918
Minority interests				—		—			37,121			—			37,121
Stockholders’ equity				1,158,765		3,093,523			257,008			(3,428,158	)		1,081,138
		Total liabilities and stockholders’ equity	$	3,510,081	$	4,446,522		$	611,732		$	(3,428,158	)	$	5,140,177

F-18

PEABODY ENERGY CORPORATION

UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS

MARCH 31, 2003

			Parent		Guarantor			Non-Guarantor
			Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
			(In thousands)
ASSETS
Current assets
	Cash and cash equivalents		$	59,749	$	385		$	11,584		$	—		$	71,718
	Restricted cash			509,592		—			—			—			509,592
	Accounts receivable			—		109,738			139,874			—			249,612
	Inventories			—		225,676			22,298			—			247,974
	Assets from coal and emission allowance trading activities			—		39,815			2,457			—			42,272
	Deferred income taxes			—		10,101			279			—			10,380
	Other current assets			28		10,673			5,776			—			16,477
		Total current assets		569,369		396,388			182,268			—			1,148,025
Property, plant, equipment and mine development — at cost				—		4,639,997			561,663			—			5,201,660
Less accumulated depreciation, depletion and amortization				—		(784,177	)		(114,333	)		—			(898,510	)
Property, plant, equipment and mine development, net				—		3,855,820			447,330			—			4,303,150
Investments and other assets				3,513,454		228,025			53,698			(3,462,488	)		332,689
		Total assets	$	4,082,823	$	4,480,233		$	683,296		$	(3,462,488	)	$	5,783,864
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Short-term borrowings and current maturities of long-term debt		$	4,500	$	10,303		$	6,719		$	—		$	21,522
	Notes called for redemption			465,004		—			—			—			465,004
	Payables and notes payable to affiliates, net			1,353,360		(1,588,876	)		235,516			—			—
	Liabilities from coal and emission allowance trading activities			—		31,012			—			—			31,012
	Accounts payable and accrued expenses			20,194		501,533			68,428			—			590,155
		Total current liabilities		1,843,058		(1,046,028	)		310,663			—			1,107,693
Long-term debt, less current maturities				1,095,500		67,098			10,459			—			1,173,057
Deferred income taxes				—		475,333			4,328			—			479,661
Other noncurrent liabilities				662		1,899,212			20,778			—			1,920,652
		Total liabilities		2,939,220		1,395,615			346,228			—			4,681,063
Minority interests				—		—			36,821			—			36,821
Stockholders’ equity				1,143,603		3,084,618			300,247			(3,462,488	)		1,065,980
		Total liabilities and stockholders’ equity	$	4,082,823	$	4,480,233		$	683,296		$	(3,462,488	)	$	5,783,864

F-19

PEABODY ENERGY CORPORATION

UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED

STATEMENTS OF CASH FLOWS

QUARTER ENDED MARCH 31, 2002

	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	(317	)	$	(12,954	)	$	34,686		$	21,415
Additions to property, plant, equipment and mine development		—			(24,622	)		(22,442	)		(47,064	)
Additions to advance mining royalties		—			(1,268	)		(836	)		(2,104	)
Investment in joint venture		—			(475	)		—			(475	)
Proceeds from property and equipment disposals		—			182			651			833
Net cash used in investing activities		—			(26,183	)		(22,627	)		(48,810	)
Net change in revolving line of credit		25,000			—			—			25,000
Proceeds from long-term debt		—			1,153			1,222			2,375
Payments of long-term debt		—			(11,177	)		(3,510	)		(14,687	)
Distributions to minority interests		—			—			(2,825	)		(2,825	)
Dividends paid		(5,202	)		—			—			(5,202	)
Transactions with affiliates, net		(36,381	)		48,871			(12,490	)		—
Other		227			—			—			227
Net cash provided by (used in) financing activities		(16,356	)		38,847			(17,603	)		4,888
Net decrease in cash and cash equivalents		(16,673	)		(290	)		(5,544	)		(22,507	)
Cash and cash equivalents at beginning of period		28,121			1,018			9,483			38,622
Cash and cash equivalents at end of period	$	11,448		$	728		$	3,939		$	16,115

F-20

PEABODY ENERGY CORPORATION

UNAUDITED SUPPLEMENTAL CONDENSED CONSOLIDATED

STATEMENTS OF CASH FLOWS

QUARTER ENDED MARCH 31, 2003

	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	(428	)	$	71,584		$	(13,605	)	$	57,551
Additions to property, plant, equipment and mine development		—			(39,585	)		(19,259	)		(58,844	)
Additions to advance mining royalties		—			(1,536	)		(818	)		(2,354	)
Proceeds from property and equipment disposals		—			7,762			377			8,139
Net cash used in investing activities		—			(33,359	)		(19,700	)		(53,059	)
Net change in revolving lines of credit		—			—			(121,584	)		(121,584	)
Proceeds from long-term debt, net of restricted cash proceeds		590,408			—			903			591,311
Payments of long-term debt		(255,094	)		(10,356	)		(96,465	)		(361,915	)
Reduction of securitized interests in accounts receivable		—			(83,900	)		—			(83,900	)
Payment of debt issuance costs		(22,687	)		—			—			(22,687	)
Distributions to minority interests		—			—			(1,350	)		(1,350	)
Dividends paid		(5,242	)		—			—			(5,242	)
Transactions with affiliates, net		(308,888	)		55,996			252,892			—
Other		1,014			—			—			1,014
Net cash provided by (used in) financing activities		(489	)		(38,260	)		34,396			(4,353	)
Effect of exchange rate changes on cash and cash equivalents		—			—			369			369
Net increase (decrease) in cash and cash equivalents		(917	)		(35	)		1,460			508
Cash and cash equivalents at beginning of period		60,666			420			10,124			71,210
Cash and cash equivalents at end of period	$	59,749		$	385		$	11,584		$	71,718

F-21

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

						Nine Months
			Year Ended			Ended			Year Ended
			March 31,			December 31,			December 31,
			2001			2001			2002
			(Dollars in thousands, except share data)
Revenues
	Sales		$	2,534,964		$	1,869,321		$	2,630,371
	Other revenues			93,164			68,619			86,727
		Total revenues		2,628,128			1,937,940			2,717,098
Costs and Expenses
	Operating costs and expenses			2,123,526			1,588,596			2,225,344
	Depreciation, depletion and amortization			240,968			174,587			232,413
	Selling and administrative expenses			99,267			73,553			101,416
	Gain on sale of Peabody Resources Limited operations			(171,735	)		—			—
	Net gain on property and equipment disposals			(5,737	)		(14,327	)		(15,763	)
Operating Profit				341,839			115,531			173,688
	Interest expense			197,686			88,686			102,458
	Interest income			(8,741	)		(2,155	)		(7,574	)
Income Before Income Taxes and Minority Interests				152,894			29,000			78,804
	Income tax provision (benefit)			42,690			2,465			(40,007	)
	Minority interests			7,524			7,248			13,292
Income From Continuing Operations				102,680			19,287			105,519
	Gain from disposal of discontinued operations, net of income tax provision of $4,240			(12,925	)		—			—
Income Before Extraordinary Item				115,605			19,287			105,519
	Extraordinary loss from early extinguishment of debt, net of income tax benefit of $2,480 and $9,658, respectively			8,545			28,970			—
Net Income (Loss)			$	107,060		$	(9,683	)	$	105,519
Basic Earnings (Loss) Per Share
	Income from continuing operations		$	2.97		$	0.40		$	2.02
	Income from discontinued operations			0.38			—			—
	Extraordinary loss from early extinguishment of debt			(0.25	)		(0.60	)		—
		Net income (loss)	$	3.10		$	(0.20	)	$	2.02
Weighted Average Shares Outstanding				27,524,626			48,746,444			52,165,735
Diluted Earnings (Loss) Per Share
	Income from continuing operations		$	2.97		$	0.38		$	1.96
	Income from discontinued operations			0.38			—			—
	Extraordinary loss from early extinguishment of debt			(0.25	)		(0.57	)		—
		Net income (loss)	$	3.10		$	(0.19	)	$	1.96
Weighted Average Shares Outstanding				27,524,626			50,524,978			53,821,760
Dividends Declared Per Share			$	—		$	0.20		$	0.40

See accompanying notes to consolidated financial statements

F-22

PEABODY ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

				December 31,			December 31,
				2001			2002
				(Dollars in thousands,
				except share data)
Assets
Current assets
	Cash and cash equivalents			$	38,622		$	71,210
	Accounts receivable, less allowance of $1,496 and $1,331, respectively				178,076			153,212
	Materials and supplies				38,734			39,416
	Coal inventory				176,910			190,272
	Assets from coal and emission allowance trading activities				60,509			69,898
	Deferred income taxes				14,380			10,361
	Other current assets				20,223			15,554
		Total current assets			527,454			549,923
Property, plant, equipment and mine development
	Land and coal interests				3,844,238			3,827,682
	Building and improvements				517,973			566,300
	Machinery and equipment				659,744			737,247
	Less accumulated depreciation, depletion and amortization				(684,557	)		(858,187	)
Property, plant, equipment and mine development, net					4,337,398			4,273,042
Investments and other assets					286,050			317,212
		Total assets		$	5,150,902		$	5,140,177
Liabilities And Stockholders’ Equity
Current liabilities
	Current maturities of long-term debt			$	46,499		$	47,515
	Liabilities from coal and emission allowance trading activities				45,691			37,008
	Accounts payable and accrued expenses				592,113			547,013
		Total current liabilities			684,303			631,536
Long-term debt, less current maturities					984,568			981,696
Deferred income taxes					564,764			499,310
Accrued reclamation					396,868			386,777
Workers’ compensation obligations					207,720			209,798
Accrued postretirement benefit costs					962,166			959,599
Obligation to industry fund					49,710			49,760
Other noncurrent liabilities					218,251			303,442
		Total liabilities			4,068,350			4,021,918
Minority interests					47,080			37,121
Stockholders’ equity
	Preferred stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of December 31, 2001 or 2002				—			—
	Series Common stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of December 31, 2001 or 2002				—			—
	Common stock — $0.01 per share par value; 150,000,000 shares authorized, 52,027,451 shares issued and 52,010,246 shares outstanding as of December 31, 2001 and 150,000,000 shares authorized, 52,417,483 shares issued and 52,400,278 shares outstanding as of December 31, 2002				520			524
	Additional paid-in capital				951,528			958,567
	Retained earnings				116,203			200,859
	Employee stock loans				(2,391	)		(1,142	)
	Accumulated other comprehensive loss				(30,345	)		(77,627	)
	Treasury stock, at cost: 17,205 shares as of December 31, 2001 and 2002, respectively				(43	)		(43	)
		Total stockholders’ equity			1,035,472			1,081,138
			Total liabilities and stockholders’ equity	$	5,150,902		$	5,140,177

See accompanying notes to consolidated financial statements

F-23

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

															Accumulated
									Additional			Employee			Other									Total
			Preferred			Common			Paid-in			Stock			Comprehensive			Retained			Treasury			Stockholders’
			Stock			Stock			Capital			Loans			Income (Loss)			Earnings			Stock			Equity
			(Dollars in thousands)
March 31, 2000			$	70		$	276		$	494,138		$	(2,391	)	$	(12,667	)	$	29,219		$	(219	)	$	508,426
	Comprehensive income:
		Net income		—			—			—			—			—			107,060			—			107,060
		Foreign currency translation adjustment		—			—			—			—			(26,144	)		—			—			(26,144	)
		Reclassification of foreign currency translation adjustment		—			—			—			—			38,811			—			—			38,811
		Minimum pension liability adjustment (net of $615 tax benefit)		—			—			—			—			(862	)		—			—			(862	)
	Comprehensive income																								118,865
	Stock grants to employees			—			—			3,962			(705	)		—			—			1,260			4,517
	Loan repayments			—			—			—			543			—			—			—			543
	Shares repurchased			—			—			—			—			—			—			(1,113	)		(1,113	)
March 31, 2001				70			276			498,100			(2,553	)		(862	)		136,279			(72	)		631,238
	Comprehensive loss:
		Net loss		—			—			—			—			—			(9,683	)		—			(9,683	)
		Minimum pension liability adjustment (net of $20,367 tax benefit)		—			—			—			—			(29,483	)		—			—			(29,483	)
	Comprehensive loss																								(39,166	)
	Dividends paid			—			—			—			—			—			(10,393	)		—			(10,393	)
	Loan repayments			—			—			—			193			—			—			—			193
	Conversion to common stock			(70	)		70			—			—			—			—			—			—
	Issuance of common stock in connection with initial public offering, net of expenses			—			173			449,659			—			—			—			—			449,832
	Stock options exercised			—			1			2,230			—			—			—			—			2,231
	Stock grants to non-employee directors			—			—			200			—			—			—			—			200
	Employee stock purchases			—			—			1,339			(31	)		—			—			29			1,337
December 31, 2001				—			520			951,528			(2,391	)		(30,345	)		116,203			(43	)		1,035,472
	Comprehensive income:
		Net income		—			—			—			—			—			105,519			—			105,519
		Foreign currency translation adjustment		—			—			—			—			15			—			—			15
		Minimum pension liability adjustment (net of $32,703 tax benefit)		—			—			—			—			(47,297	)		—			—			(47,297	)
	Comprehensive income																								58,237
	Dividends paid			—			—			—			—			—			(20,863	)		—			(20,863	)
	Loan repayments			—			—			—			1,249			—			—			—			1,249
	Stock options exercised			—			5			5,249			—			—			—			—			5,254
	Stock grants to non-employee directors			—			—			50			—			—			—			—			50
	Employee stock purchases			—			1			3,250			—			—			—			—			3,251
	Shares repurchased and retired			—			(2	)		(1,510	)		—			—			—			—			(1,512	)
December 31, 2002			$	—		$	524		$	958,567		$	(1,142	)	$	(77,627	)	$	200,859		$	(43	)	$	1,081,138

See accompanying notes to consolidated financial statements

F-24

PEABODY ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

						Nine Months
			Year Ended			Ended			Year Ended
			March 31,			December 31,			December 31,
			2001			2001			2002
			(Dollars in thousands)
Cash Flows From Operating Activities
Net income (loss)			$	107,060		$	(9,683	)	$	105,519
	Gain from disposal of discontinued operations			(12,925	)		—			—
	Extraordinary loss from early extinguishment of debt			8,545			28,970			—
		Income from continuing operations		102,680			19,287			105,519
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
	Depreciation, depletion and amortization			215,450			174,587			232,413
	Deferred income taxes			31,795			1,902			(41,323	)
	Amortization of debt discount and debt issuance costs			16,709			8,986			9,768
	Gain on sale of Peabody Resources Limited operations			(171,735	)		—			—
	Net gain on property and equipment disposals			(4,782	)		(14,327	)		(15,763	)
	Minority interests			7,524			7,248			13,292
	Stock compensation			3,961			1,204			230
	Changes in current assets and liabilities, net of acquisitions:
		Sale of accounts receivable		40,000			—			—
		Accounts receivable, net of sale		(50,179	)		(30,065	)		22,973
		Materials and supplies		5,677			60			(682	)
		Coal inventory		(15,749	)		(5,431	)		(12,191	)
		Net assets from coal and emission allowance trading activities		(5,805	)		(6,201	)		(18,072	)
		Other current assets		6,912			4,433			6,589
		Accounts payable and accrued expenses		48,249			(3,347	)		(48,928	)
	Federal tax refund			—			22,757			2,420
	Accrued reclamation			(27,106	)		(10,837	)		(12,146	)
	Workers’ compensation obligations			(1,480	)		(3,560	)		(522	)
	Accrued postretirement benefit costs			2,893			(11,913	)		(2,567	)
	Obligation to industry fund			(12,565	)		(2,462	)		(492	)
	Other, net			(20,345	)		(37,829	)		(9,314	)
	Net cash used in assets sold — Peabody Resources Limited operations			(20,124	)		—			—
		Net cash provided by operating activities		151,980			114,492			231,204
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development				(151,358	)		(194,246	)		(208,562	)
Additions to advance mining royalties				(20,260	)		(11,305	)		(14,889	)
Acquisitions, net				(10,502	)		—			(46,012	)
Proceeds from sale of Peabody Resources Limited operations				455,000			—			—
Proceeds from property and equipment disposals				18,925			13,551			52,885
Proceeds from sale of coal reserves to Penn Virginia Resource Partners, L.P.				—			—			72,500
Proceeds from sale-leaseback transactions				28,800			19,011			—
Net cash used in assets sold — Peabody Resources Limited operations				(34,684	)		—			—
Net cash provided by discontinued operations				102,541			—			—
	Net cash provided by (used in) investing activities			388,462			(172,989	)		(144,078	)
Cash Flows From Financing Activities
Proceeds from short-term borrowings and long-term debt				65,302			40,995			16,462
Payments of short-term borrowings and long-term debt				(633,905	)		(446,669	)		(47,749	)
Net proceeds from initial public offering				—			449,832			—
Proceeds from employee stock purchases				—			1,306			3,251
Distributions to minority interests, net				(4,690	)		(1,626	)		(9,800	)
Dividends received				19,916			—			—
Dividends paid				—			(10,393	)		(20,863	)
Repurchase of treasury stock				(1,113	)		—			—
Net cash provided by assets sold — Peabody Resources Limited operations				10,591			—			—
Other				562			951			3,901
	Net cash provided by (used in) financing activities			(543,337	)		34,396			(54,798	)
Effect of exchange rate changes on cash and cash equivalents				—			—			260
Net increase (decrease) in cash and cash equivalents				(2,895	)		(24,101	)		32,588
Cash and cash equivalents at beginning of period				65,618			62,723			38,622
Cash and cash equivalents at end of period			$	62,723		$	38,622		$	71,210

See accompanying notes to consolidated financial statements

F-25

PEABODY ENERGY CORPORATION

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 significant intercompany transactions, profits, and balances have been eliminated in consolidation.

     In May 2000, the Company signed a purchase and sale agreement with Edison Mission Energy to sell Citizens Power LLC (“Citizens Power”) (see Note 8). Results of operations and cash flows for the year ended March 31, 2001 reflect Citizens Power as a discontinued operation.

     The consolidated results of operations and cash flows for the year ended March 31, 2001 include the results of the Company’s Peabody Resources Limited operations, which were sold in January 2001 (see Note 7).

     In April 2001, the Company changed its name from P&L Coal Holdings Corporation to Peabody Energy Corporation.

     In July 2001, the Company changed its fiscal year-end from March 31 to December 31. This change was first effective with respect to the nine months ended December 31, 2001.

Description of Business

     The Company is engaged in the mining of coal for sale primarily to electric utilities. In addition to our mining operations, we market and trade coal and emission allowances. Finally, we are also involved in related energy businesses that include coalbed methane production, transportation-related services, third-party coal contract restructuring and participating in the development of coal-fueled generating plants.

New Pronouncements

     Effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” The adoption of SFAS Nos. 141 and 142 did not have a material effect on the Company’s financial condition or results of operations.

     Also effective January 1, 2002, the Company adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The provisions of this statement provide a single accounting model for measuring impairment of long-lived assets. The adoption of SFAS No. 144 did not have a material effect on the Company’s financial condition or results of operations.

     Effective December 31, 2002, the Company adopted the disclosure requirements of the Financial Accounting Standards Board’s Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). The disclosures required by FIN 45 are included in Note 22 to our consolidated financial statements.

Joint Ventures

     Joint ventures are accounted for using the equity method. Prior to the sale in January 2001, undivided interests in Peabody Resources Limited were reported using pro rata consolidation whereby the Company reported its proportionate share of assets, liabilities, income and expenses. All significant intercompany transactions have been eliminated in consolidation.

F-26

     The financial statements include the following operating amounts for Peabody Resources Limited entities utilizing pro rata consolidation (dollars in thousands):

	Year Ended
	March 31,
	2001
Total revenues	$	144,481
Operating profit		21,111

Sales

     The Company recognizes revenue from coal sales when title passes to the customer. 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, earnings and losses from joint ventures, farm income, contract restructuring payments, coalbed methane extraction, net revenues from coal and emission allowance trading activities and revenues from contract mining services. Royalty income generally results from the lease or sub-lease 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 20 years, or can be for an unspecified period until all reserves are depleted.

Stock Compensation

     The Company applies Accounting Principles Board (“APB”) Opinion No. 25 and related interpretations in accounting for its equity incentive plans. The Company recorded $3.9 million, $1.2 million and $0.2 million of compensation expense during the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively, for stock options granted. The following table reflects pro forma net income (loss) and diluted earnings (loss) 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”:

				Nine Months
		Year Ended		Ended			Year Ended
		March 31,		December 31,			December 31,
		2001		2001			2002
		(Dollars in thousands, except per share data)
Net income (loss):
	As reported	$	107,060	$	(9,683	)	$	105,519
	Pro forma		105,117		(14,023	)		100,639
Basic earnings (loss) per share:
	As reported	$	3.10	$	(0.20	)	$	2.02
	Pro forma		3.04		(0.29	)		1.93
Diluted earnings (loss) per share:
	As reported	$	3.10	$	(0.19	)	$	1.96
	Pro forma		3.04		(0.28	)		1.87

     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.

F-27

     Compensation expense for awards with graded vesting provisions is recognized on a straight-line basis.

              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 and Emission Allowance Trading Activities

     Through October 25, 2002, the Company’s coal and emission allowance trading activities were accounted for using the fair value method required by Emerging Issues Task Force (“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”, 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 is effective January 1, 2003. Accordingly, the effect of the rescission on non-derivative energy trading contracts entered into prior to October 25, 2002 will be recorded as a cumulative effect of a change in accounting principle in the first quarter of 2003. This accounting change will only affect the timing of the recognition of income or losses on contracts that do not meet the definition of a derivative, and will 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 and emission allowance trading activities” in the consolidated balance sheets as of December 31, 2001 and 2002.

     EITF 98-10 previously permitted the reporting of gains or losses on energy trading contracts on a gross or net basis in the consolidated statement of operations. Under EITF 02-3, a new consensus was reached in June 2002 that all mark-to-market gains and losses on energy trading contracts should be shown net in the statement of operations, even if settled physically. This new consensus was effective for financial statements issued for periods ending after July 15, 2002 and required reclassification of amounts in all prior periods presented. Based on this consensus, all realized gains and losses on trading transactions, whether settled physically or financially, and unrealized mark-to-market gains and losses were reported on a net basis in “Other revenues” beginning with the quarter ended September 30, 2002. This accounting change had no effect on operating profit or net income. Had trading transactions been recorded on a gross basis, total revenues and operating costs would have been $41.6 million, $88.8 million and $161.9 million higher for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

     The consensus reached in June 2002 regarding net presentation of trading gains and losses under EITF Issue No. 02-3 was superseded in October 2002 (upon the rescission of EITF 98-10 in EITF 02-3), and was replaced with a new requirement to present all gains and losses on energy trading derivatives on a net basis beginning in 2003. No definitive guidance was provided by the EITF regarding presentation of gains and

F-28

losses on energy trading activities that were not derivatives pursuant to SFAS No. 133. The Company’s consolidated statements of operations reflect revenues related to all trading contracts accounted for on a fair value basis, whether under EITF 98-10 or SFAS No. 133, 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 $0.3 million, $1.7 million and $2.8 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 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. Certain 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.

     The fair value of coal reserves was established by an independent third party review and evaluation at the time of the Company’s acquisition in May 1998. Reserves acquired subsequent to that date are recorded at cost. As of December 31, 2002, the net book value of coal reserves totaled $3.2 billion. This amount includes $1.5 billion attributable to properties where the Company is not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves are not currently being depleted.

     Depletion of coal interests is computed using the units-of-production method utilizing only proven and probable reserves in the depletion base. 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 20
Machinery and equipment		3 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 25 years.

Generation Development Costs

     Development costs, including expenditures for permitting and licensing, related to coal-fueled electricity generation are recorded at cost. Start-up costs, including feasibility studies, are expensed as incurred. Development costs of $5.1 million and $13.4 million were recorded as part of “Investments and other assets” in the consolidated balance sheets as of December 31, 2001 and 2002, respectively.

Accrued Reclamation

     The Company records a liability for the estimated costs to reclaim land as the acreage is disturbed during the ongoing surface mining process. The estimated costs to reclaim support acreage and to perform other related functions at both surface and underground mines are recorded ratably over the lives of the mines. As of December 31, 2002, the Company had $622.6 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 $291.9 million as of December 31, 2002.

F-29

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 known as the liability method. The liability method 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.

Postemployment Benefits

     The Company provides postemployment benefits to qualifying employees, former employees and dependents under the provisions of various benefit plans or as required by state or federal law. The Company accounts for workers’ compensation obligations and other Company-provided postemployment benefits on the accrual basis of accounting.

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. 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.

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.

Foreign Currency Translation

     The assets and liabilities of foreign affiliates are translated at current exchange rates, and related translation adjustments are reported as a component of comprehensive income. Statement of operations accounts are translated at an average rate for each period.

Reclassifications

     Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2002, with no effect on previously reported net income or stockholders’ equity.

F-30

(2) Initial Public Offering

     On May 22, 2001, the Company completed an initial public offering of 17,250,000 shares of common stock. Net proceeds from the offering of $449.8 million were primarily used to repay debt. See further discussion of these debt repayments in Note 14.

(3) 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 and emission allowance trading activities) is mitigated through the use of fixed-price contracts rather than financial instruments, while interest rate and foreign currency exchange risk are managed through the use of forward contracts, swaps and other financial instruments.

Trading Activities

     The Company performs a value at risk analysis of its trading portfolio, which includes over-the-counter and brokerage trading of coal and emission allowances. The use of value at risk allows management to quantify, in dollars, on a daily basis, the pricing risk inherent in its trading portfolio. The Company’s value at risk model is based on the industry standard risk-metrics variance/ co-variance approach, which captures exposure related to both option and forward positions. The value at risk model assumes a fifteen-day holding period and a 95% one-tailed confidence interval.

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

     During the year ended December 31, 2002, the low, high, and average values at risk for our coal trading portfolio were $0.3 million, $3.9 million, and $1.7 million, respectively. Our emission allowance value at risk during the year ended December 31, 2002 never exceeded $0.2 million.

     The Company also monitors other types of risk associated with its coal and emission allowance trading activities, including credit, market liquidity and counterparty nonperformance.

Financial Instruments

     Effective April 1, 2001, the Company adopted SFAS No. 133, which requires the recognition of all derivatives as assets or liabilities within the consolidated balance sheet 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. Since October 2001, the Company has designated interest rate swaps with notional amounts totaling $150.0 million as a fair value hedge of $150.0 million of its Senior Notes.

     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 statement of operations in conjunction with the recognition of the underlying hedged item. Hedge ineffectiveness had no effect on results of operations for the nine months ended December 31, 2001 or the year ended December 31, 2002.

F-31

Credit Risk

     The Company’s concentration of credit risk is substantially with energy producers and marketers and electric utilities. 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 will protect its position by requiring the counterparty to provide appropriate credit enhancement.

     During 2002, the creditworthiness of some of our customers or trading counterparties deteriorated. We have taken steps to reduce our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk, as determined by our credit management function, of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to fund the payment for coal under existing coal supply agreements. To reduce 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 transactions is not considered to be significant based upon the creditworthiness of the participating financial institutions.

Other

     Approximately 31% of the Company’s U.S. coal employees are affiliated with organized labor unions, which accounted for approximately 19% of sales volume in the U.S. during the year ended December 31, 2002. Hourly workers at the Company’s mines in Arizona, Colorado and Montana are represented by the United Mine Workers of America under the Western Surface Agreement, which was ratified in 2000 and is effective through September 1, 2005. Union labor east of the Mississippi is primarily represented by the United Mine Workers of America but is generally subject to the National Bituminous Coal Wage Agreement. The current five-year labor agreement, effective from January 1, 2002 to December 31, 2006, was ratified by the United Mine Workers of America in December 2001.

(4) Assets and Liabilities from Coal and Emission Allowance Trading Activities

     The fair value of the financial instruments related to coal and emission allowance trading activities as of December 31, 2002, which include energy commodities, are set forth below:

		Fair Value
		Assets		Liabilities
		(Dollars in thousands)
Forward contracts		$	64,554	$	33,540
Option contracts			5,344		3,468
	Total	$	69,898	$	37,008

     Approximately 89% of the Company’s net coal and emission allowance trading portfolio value at December 31, 2002 was determined by over the counter market source prices. The remaining 11% of our contracts were valued based on over the counter market source prices adjusted for differences in coal quality and content, as well as contract duration.

F-32

     As of December 31, 2002, the timing of trading portfolio contract expirations is as follows:

	Percentage of
Year of Expiration	Portfolio
2003		48	%
2004		43	%
2005		8	%
2006		1	%
		100	%

     At December 31, 2002, 50% of our credit exposure related to coal and emission allowance trading activities is with counterparties that are investment grade.

     Our coal trading operations traded 55.8 million tons, 39.4 million tons, and 66.9 million tons for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

(5) Accounts Receivable Securitization

     In March 2000, the Company and its wholly-owned, bankruptcy-remote subsidiary (“Seller”) 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. The Company utilized proceeds from the sale of its accounts receivable to repay long-term debt, effectively reducing its overall borrowing costs. The funding cost of the securitization program was $8.7 million, $4.5 million and $3.3 million for the year ended March 31, 2001, the nine months ended December 31, 2001, and the year ended December 31, 2002, respectively. The securitization program is currently scheduled to expire in 2007.

     Under the provisions of SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” the securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheet. The amount of undivided interests in accounts receivable sold to the Conduit was $140.0 million and $136.4 million as of December 31, 2001 and 2002, 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 our domestic subsidiaries, excluding Black Beauty Coal Company (“Black Beauty”), 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’s retained interest in receivables not sold to the Conduit remain an asset of the Seller ($35.1 million as of December 31, 2002). 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 required to repurchase all or a portion of the receivables sold to the Conduit.

(6) Business Combinations

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.

F-33

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 controls the 1.4 million ton per year Wilkie Creek Coal Mine and coal reserves in Queensland, Australia. Evaluations are complete with respect to 147 million tons of proven and probable reserves acquired surrounding the Wilkie Creek Mine. The Company continues to evaluate other coal resources that were obtained in this acquisition to finalize the estimate of its total proven and probable reserves in Australia. The results of AQC’s operations are included in the Company’s Australian Mining Operations segment.

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 81.7%-owned 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 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. Had the acquired entities’ 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.

(7) Sale of Australian Operations

     On January 29, 2001, the Company sold its Peabody Resources Limited operations to Coal & Allied, a subsidiary of Rio Tinto Limited. The selling price was $455.0 million, plus the assumption of all liabilities. The Company used the proceeds from the sale to repay long-term debt. The pretax gain on sale of $171.7 million was included in the consolidated statement of operations for the year ended March 31, 2001. The gain on sale was $124.2 million on an after-tax basis.

(8) Discontinued Operations

     On March 13, 2000, the Board of Directors authorized management to sell Citizens Power, its wholly-owned subsidiary that engaged in power trading and power contract restructuring transactions. Subsequent to March 31, 2000, the Company signed an agreement to sell Citizens Power to Edison Mission Energy. As of March 31, 2000, the Company estimated its loss on disposal of the entity to be $109.5 million on a pretax basis ($78.3 million after-tax), which included an $8.0 million pretax provision for expected operating losses through the expected disposal date. The Company completed the sale of operations and the monetization of non-trading assets held by Citizens Power in March 2001, resulting in an after-tax decrease to the loss on disposal of $12.9 million.

(9) Earnings Per Share

     A reconciliation of weighted average shares outstanding follows:

	Nine Months
	Ended		Year Ended
	December 31,		December 31,
	2001		2002
Weighted average shares outstanding — basic		48,746,444		52,165,735
Dilutive impact of stock options		1,778,534		1,656,025
Weighted average shares outstanding — diluted		50,524,978		53,821,760

     In connection with the Company’s initial public offering in May 2001, all outstanding shares of preferred stock, Class A common stock and Class B common stock were converted into a single class of common

F-34

stock on a one-for-one basis. Prior to its initial public offering, the Company applied the “two-class method” of computing earnings per share as prescribed in SFAS No. 128, “Earnings Per Share.” In accordance with SFAS No. 128, income or loss was allocated to the then existing preferred stock, Class A common stock and Class B common stock on a pro-rata basis. Basic and diluted earnings per share were calculated by dividing income from continuing operations, income from discontinued operations, extraordinary loss from early extinguishment of debt and net income, respectively, that was attributable to the Company’s Class A and Class B common stock by the weighted average number of common shares outstanding for each class of common stock.

     A reconciliation of income from continuing operations, income from discontinued operations, extraordinary loss from early extinguishment of debt and net income follows:

			Year Ended
			March 31,
			2001
			(Dollars in
			thousands)
Income from continuing operations attributed to:
	Preferred stock		$	20,819
	Class A common stock			79,111
	Class B common stock			2,750
		Total	$	102,680
Income from discontinued operations attributed to:
	Preferred stock		$	2,621
	Class A common stock			9,958
	Class B common stock			346
		Total	$	12,925
Extraordinary loss from early extinguishment of debt attributed to:
	Preferred stock		$	(1,733	)
	Class A common stock			(6,583	)
	Class B common stock			(229	)
		Total	$	(8,545	)
Net income attributed to:
	Preferred stock		$	21,707
	Class A common stock			82,486
	Class B common stock			2,867
		Total	$	107,060
Weighted average shares outstanding:
Class A common stock				26,600,000
Class B common stock				924,626
		Total		27,524,626

     Any difference between basic and diluted earnings per share was attributable to stock options. For the years ended March 31, 2001 and December 31, 2002, options for 5.2 million and 1.2 million shares, respectively, 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 0.6 million options to purchase common stock on January 2, 2003.

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(10) Coal Inventory

     Coal inventory consisted of the following:

		December 31,
		2001		2002
		(Dollars in thousands)
Raw coal		$	15,979	$	18,076
Work in process			137,808		143,963
Saleable coal			23,123		28,233
	Total	$	176,910	$	190,272

     Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Work in process 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.

(11) 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 $93.4 million, $79.5 million and $116.3 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively. The net book value of property, plant, equipment and mine development assets under capital leases was $2.1 million and $5.8 million as of December 31, 2001 and 2002, 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 $165.8 million, $129.6 million and $181.1 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

     A substantial amount of the coal mined by the Company is produced from reserves leased from the owner of the coal. One of the major lessors is the U.S. government, from which the Company leases substantially all of the coal it mines in Wyoming, Montana 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 formed an alliance with Penn Virginia Resource Partners, L.P. (“PVR”) whereby the Company contributed 120 million tons of coal reserves in exchange for $72.5 million

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in cash and 2.76 million units, or 15%, 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. A deferred gain of $31.5 million will be recognized 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.”

     During the year ended March 31, 2001 and the nine months ended December 31, 2001, the Company sold certain assets for $28.8 million and $19.0 million, respectively, and those assets were leased back under operating lease agreements from the purchasers over a period of three to eight years. No gains or losses were recognized on these transactions. Each lease agreement contains renewal options at lease termination and purchase options at amounts approximating fair market value during the lease and at lease termination. No such transactions occurred during the year ended December 31, 2002.

     As of December 31, 2002 the Company’s lease obligations were secured by outstanding surety bonds and letters of credit totaling $97.6 million. As of December 31, 2002, the restricted net assets applicable under certain lease agreements of the Company’s consolidated subsidiaries were $500.0 million.

     Future minimum lease and royalty payments as of December 31, 2002 are as follows:

	Capital		Operating		Coal
Year Ended December 31	Leases		Leases		Reserves
	(Dollars in thousands)
2003	$	3,879	$	100,526	$	24,676
2004		348		88,768		25,398
2005		628		76,390		26,298
2006		335		57,802		25,732
2007		37		43,061		22,885
2008 and thereafter		16		87,505		66,027
Total minimum lease payments	$	5,243	$	454,052	$	191,016
Less interest		203
Present value of minimum capital lease payments	$	5,040

(12) Accounts Payable and Accrued Expenses

     Accounts payable and accrued expenses consisted of the following:

		December 31,
		2001		2002
		(Dollars in thousands)
Trade accounts payable		$	224,225	$	167,892
Accrued taxes other than income			76,661		87,735
Accrued payroll and related benefits			51,310		45,197
Accrued health care			78,005		80,273
Accrued interest			16,924		17,722
Workers’ compensation obligations			42,652		42,616
Accrued royalties			20,603		24,260
Accrued lease payments			10,029		9,152
Other accrued expenses			71,704		72,166
	Total accounts payable and accrued expenses	$	592,113	$	547,013

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(13) Income Taxes

     Pretax income from continuing operations consisted of the following:

				Nine Months
		Year Ended		Ended		Year Ended
		March 31,		December 31,		December 31,
		2001		2001		2002
		(Dollars in thousands)
U.S.		$	105,184	$	28,707	$	75,684
Non U.S.			47,710		293		3,120
	Total	$	152,894	$	29,000	$	78,804

     Total income tax provision (benefit) from continuing operations consisted of the following:

					Nine Months
		Year Ended			Ended			Year Ended
		March 31,			December 31,			December 31,
		2001			2001			2002
		(Dollars in thousands)
Current:
	U.S. federal	$	170		$	313		$	—
	Non U.S.		19,150			—			1,066
	State		100			250			250
	Total current		19,420			563			1,316
Deferred:
	U.S. federal		29,284			2,883			(37,847	)
	Non U.S.		(1,039	)		—			12
	State		(4,975	)		(981	)		(3,488	)
	Total deferred		23,270			1,902			(41,323	)
	Total provision (benefit)	$	42,690		$	2,465		$	(40,007	)

     The income tax rate on income (loss) from continuing operations differed from the U.S. federal statutory rate as follows:

					Nine Months
		Year Ended			Ended			Year Ended
		March 31,			December 31,			December 31,
		2001			2001			2002
		(Dollars in thousands)
Federal statutory rate		$	53,513		$	10,150		$	27,581
Changes in valuation allowance			35,775			9,023			(26,865	)
Foreign earnings and disposition gains			(7,079	)		103			(14	)
State income taxes, net of U.S. federal tax benefit			(4,912	)		(818	)		(3,325	)
Depletion			(37,369	)		(19,769	)		(38,136	)
Other, net			2,762			3,776			752
	Total	$	42,690		$	2,465		$	(40,007	)

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     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,
		2001			2002
		(Dollars in thousands)
Deferred tax assets:
	Accrued long-term reclamation and mine closing liabilities	$	78,947		$	81,748
	Accrued long-term workers’ compensation liabilities		99,810			101,967
	Postretirement benefit obligations		422,830			413,730
	Intangible tax asset and purchased contract rights		102,878			81,631
	Tax credits and loss carryforwards		299,369			270,585
	Obligation to industry fund		21,747			24,015
	Additional minimum pension liability		20,982			52,703
	Others		75,564			64,464
	Total gross deferred tax assets		1,122,127			1,090,843
Deferred tax liabilities:
	Property, plant, equipment and mine development principally due to differences in depreciation, depletion and asset writedowns		1,273,926			1,191,567
	Long-term debt		7,992			5,962
	Others		194,102			212,637
	Total gross deferred tax liabilities		1,476,020			1,410,166
Valuation allowance			(196,491	)		(169,626	)
	Net deferred tax liability	$	(550,384	)	$	(488,949	)
Deferred taxes consisted of the following:
	Current deferred income taxes	$	14,380		$	10,361
	Noncurrent deferred income taxes		(564,764	)		(499,310	)
	Net deferred tax liability	$	(550,384	)	$	(488,949	)

     The Company’s deferred tax assets include alternative minimum tax (“AMT”) credits of $51.4 million and net operating loss (“NOL”) carryforwards of $219.2 million as of December 31, 2002. The AMT credits have no expiration date and the majority of the NOL carryforwards expire beginning 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 $169.6 million.

     The total amount of undistributed earnings of foreign subsidiaries for income tax purposes was approximately $0.4 million and $2.6 million at December 31, 2001 and 2002, respectively. It is the Company’s intention to reinvest undistributed earnings of its foreign subsidiaries and thereby indefinitely postpone their remittance. Accordingly, no provision has been made for foreign withholding taxes or U.S. income taxes that may become payable if undistributed earnings of foreign subsidiaries were paid as dividends to the Company.

     The Company made U.S. federal tax payments totaling $0.2 million and $0.5 million for the year ended March 31, 2001 and the nine months ended December 31, 2001, respectively. There were no U.S. federal tax payments in the year ended December 31, 2002. The Company paid state and local income taxes totaling $0.1 million, $0.3 million, and $0.2 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

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     Non-U.S. tax payments were $19.1 million for the year ended March 31, 2001. There were no non-U.S. tax payments in the nine months ended December 31, 2001 or the year ended December 31, 2002.

(14) Long-term Debt

     Long-term debt consisted of the following:

		December 31,
		2001			2002
		(Dollars in thousands)
9 5/8% Senior Subordinated Notes (“Senior Subordinated Notes”) due 2008		$	391,390		$	391,490
8 7/8% Senior Notes (“Senior Notes”) due 2008			316,413			316,498
Unsecured revolving credit agreement of Black Beauty			96,790			116,584
5.0% Subordinated Note			90,026			85,055
Senior unsecured notes under various agreements			83,571			58,214
Other			52,877			61,370
	Total long-term debt		1,031,067			1,029,211
Less current maturities			(46,499	)		(47,515	)
	Long-term debt, less current maturities	$	984,568		$	981,696

Senior Subordinated Notes and Senior Notes

     The Senior Subordinated Notes are general unsecured obligations of the Company and are subordinate in right of payment to all existing and future senior debt (as defined), including borrowings under the Senior Credit Facilities and the Senior Notes. The Senior Notes are general unsecured obligations of the Company, rank senior in right of payment to all subordinated indebtedness (as defined) and rank equally in right of payment with all current and future unsecured indebtedness of the Company. As of December 31, 2002, Lehman Brothers Inc. and its affiliates’ share of the Company’s Senior Subordinated Notes and Senior Notes outstanding was $3.5 million and $5.8 million, respectively. Affiliates of Lehman Brothers Inc. own a significant portion of the Company’s outstanding common stock.

     The indentures governing the Senior Notes and Senior Subordinated Notes permit the Company and its Restricted Subsidiaries to incur additional indebtedness, including secured indebtedness, subject to certain limitations. In addition, among other customary restrictive covenants, the indentures prohibit the Company and its Restricted Subsidiaries from creating or otherwise causing any encumbrance or restriction on the ability of any Restricted Subsidiary that is not a Guarantor to pay dividends or to make certain other upstream payments to the Company or any of its Restricted Subsidiaries (subject to certain exceptions). The indentures permit us to pay annual dividends of up to the greater of 6% ($27.0 million) of the net proceeds from our initial public offering, or additional amounts based on, among other things, the sum of 50% of cumulative defined net income (since July 1, 1998) and 100% of the proceeds of our initial public offering.

Senior Credit Facility

     The Senior Credit Facility is secured by a first priority lien on certain assets of the Company and its domestic subsidiaries. The Company amended its Senior Credit Facility effective May 22, 2001. The amendment permits the payment of cash dividends and other restricted payments subject to specified limitations and increases the amount available for borrowing under the Revolving Credit Facility from $200.0 million to $350.0 million.

     The Revolving Credit Facility also contains certain restrictions and limitations including, but not limited to, financial covenants that will require the Company to maintain and achieve certain levels of financial performance. The facility permits the payment of annual cash dividends of up to the greater of $25.0 million or 10% of consolidated EBITDA, as defined in the facility. In addition, the Senior Credit Facility prohibits

F-40

the Company from allowing its Restricted Subsidiaries (which include all Guarantors) to create or otherwise cause any encumbrance or restriction on the ability of any such Restricted Subsidiary to pay any dividends or make certain other upstream payments subject to certain exceptions.

Secured Revolving Credit Facility

     The Company maintains a $480.0 million Revolving Credit Facility that has a borrowing sub-limit of $350.0 million and a letter of credit sub-limit of $330.0 million. The Company pays quarterly commitment fees at a 0.38% annual rate on the unused portion of its Revolving Credit Facility. Interest rates on the revolving loans under the Revolving Credit Facility are based on the Base Rate or LIBOR (as defined in the Senior Credit Facilities) at the Company’s option. The applicable rate was 2.9% as of December 31, 2002. The Revolving Credit Facility commitment matures in June 2004. As of December 31, 2002, the Company had $186.8 million of letters of credit and no borrowings outstanding under the Revolving Credit Facility.

     Interest paid on the Revolving Credit Facility was $0.9 million, $0.5 million and $2.5 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

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 2003 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 Credit Facilities and the Senior Notes.

Other

     The senior unsecured notes represent obligations of Black Beauty and include $15.7 million of Senior Notes and two series of notes with an aggregate principal amount of $42.5 million. The Senior Notes, due in December 2004, bear interest at 9.2%, payable quarterly, and are prepayable in whole or in part at any time, subject to certain make-whole provisions. The two series of notes include Series A and B Notes, totaling $37.5 million and $5.0 million, respectively. The Series A Notes bear interest at an annual rate of 7.5% and are due in 2007. The Series B Notes bear interest at an annual rate of 7.4% and are due in November 2003.

     Black Beauty maintains a $140.0 million revolving credit facility with several banks that matures on April 17, 2004. Black Beauty may elect one or a combination of interest rates on its borrowings; the effective annual interest rate was 3.0% as of December 31, 2002. Borrowings outstanding as of December 31, 2002 were $116.6 million. Black Beauty paid quarterly commitment fees on the unused portion of its revolving credit facility at a 0.35% average annual rate for the year ended December 31, 2002.

     Other long-term debt, which consists principally of notes payable, is due in installments through 2004. The weighted average effective interest rate of this debt was 3.8% as of December 31, 2002.

     The aggregate amounts of long-term debt maturities subsequent to December 31, 2002 are as follows (dollars in thousands):

Year of Maturity
2003		$	47,515
2004			175,196
2005			21,306
2006			17,814
2007			52,749
2008 and thereafter			714,631
	Total	$	1,029,211

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 ��   Interest paid on long-term debt was $185.5 million, $100.8 million and $93.0 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

Extraordinary Loss from Early Extinguishment of Debt

     During the year ended March 31, 2001, the Company prepaid $565.0 million of term loans under its Senior Credit Facilities. As a result of the prepayments, the Company recorded an extraordinary loss on debt extinguishment of $8.5 million, net of income taxes.

     During the nine months ended December 31, 2001, the Company used substantially all of the $449.8 million of net proceeds from its initial public offering to repay debt. The Company repaid its remaining outstanding term loan under its Senior Credit Facilities of $125.0 million and used $100.0 million to repay borrowings under the revolving credit facility that were used to repay a portion of the Company’s 5% Subordinated Note. The Company used $173.0 million of proceeds from the offering to repurchase $80.0 million in principal of the Senior Notes and $80.0 million in principal of the Senior Subordinated Notes pursuant to a tender offer. Finally, the Company used $3.1 million and $30.2 million of proceeds to repurchase an additional $2.9 million in principal of the Senior Notes and $27.8 million in principal of the Senior Subordinated Notes, respectively, in a private transaction. The repayments resulted in an extraordinary loss of $29.0 million, net of income taxes, which represented the excess of cash paid over the carrying value of the debt retired and the accelerated write-off of debt issuance costs related to the debt repaid.

Interest Rate Swaps

     The Company has designated interest rate swaps with notional amounts totaling $150.0 million as a fair value hedge of its Senior Notes. Under the swaps, the Company pays a floating rate based upon the six-month LIBOR rate for a period of six years ending May 15, 2008. The applicable rate was 5.41% as of December 31, 2002.

     During the year ended March 31, 2001, the Company had in place interest rate swap agreements to fix the rate on a portion of its variable rate debt. These swaps were terminated during the year ended March 31, 2001, and the Company realized a net gain of approximately $5.1 million, which was included as a component of interest expense for that year.

(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.

     As of December 31, 2002, the Company had $156.2 million in surety bonds and letters of credit outstanding to secure workers’ compensation obligations.

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     Workers’ compensation provision consists of the following components:

					Nine Months
		Year Ended			Ended		Year Ended
		March 31,			December 31,		December 31,
		2001			2001		2002
		(Dollars in thousands)
Occupational disease:
	Service cost	$	1,602		$	2,080	$	2,942
	Interest cost		12,180			9,330		12,049
	Net amortization		(1,882	)		299		466
Total occupational disease			11,900			11,709		15,457
	Traumatic injury claims		15,728			13,926		25,722
	State assessment taxes		13,731			10,934		14,204
Total provision		$	41,359		$	36,569	$	55,383

     Workers’ compensation obligations consist of amounts accrued or 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,
		2001			2002
		(Dollars in thousands)
Occupational disease costs		$	164,062		$	167,270
Traumatic injury claims			85,900			84,607
State assessment taxes			410			537
	Total obligations		250,372			252,414
Less current portion			(42,652	)		(42,616	)
	Noncurrent obligations	$	207,720		$	209,798

     The reconciliation of changes in the benefit obligation of the occupational disease liability is as follows:

		December 31,
		2001			2002
		(Dollars in thousands)
Beginning of year obligation		$	167,504		$	172,886
Less insured claims			(6,425	)		(6,513	)
	Net obligation		161,079			166,373
Service cost			2,080			2,942
Interest cost			9,330			12,049
Actuarial loss			1,869			6,854
Benefit and administrative payments			(7,985	)		(11,980	)
	Net obligation at end of year		166,373			176,238
Unamortized loss and prior service cost			(2,311	)		(8,968	)
Accrued cost		$	164,062		$	167,270

     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 nine months ended December 31, 2001 were based on a 7.85% per annum discount rate

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and a 3.5% estimate for the annual rate of inflation. The projections for the year ended December 31, 2002 were based on a 7.4% 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 7.85% and 7.4% for the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively. Liability determinations were based on a discount rate of 7.4% and 7% at December 31, 2001 and December 31, 2002, 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 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 $13.7 million, $21.0 million and $6.8 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively, 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. In addition, related interest income of $3.7 million was recorded during the year ended March 31, 2001.

     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.

(16) Pension and Savings Plans

     One of the Company’s subsidiaries, Peabody Holding Company, sponsors a defined benefit pension plan covering a significant portion of all salaried U.S. employees (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”). 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:

					Nine Months
		Year Ended			Ended			Year Ended
		March 31,			December 31,			December 31,
		2001			2001			2002
		(Dollars in thousands)
Service cost for benefits earned		$	8,916		$	6,361		$	9,592
Interest cost on projected benefit obligation			37,484			30,087			39,919
Expected return on plan assets			(43,932	)		(33,860	)		(45,512	)
Other amortizations and deferrals			(2,174	)		399			831
	Net periodic pension costs	$	294		$	2,987		$	4,830

     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

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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,
		2001			2002
		(Dollars in thousands)
Change in benefit obligation:
	Benefit obligation at beginning of period	$	512,904		$	565,821
	Service cost		6,361			9,592
	Interest cost		30,087			39,919
	Plan amendments		57			1,342
	Benefits paid		(22,612	)		(31,313	)
	Actuarial loss		39,024			16,565
Benefit obligation at end of period			565,821			601,926
Change in plan assets:
	Fair value of plan assets at beginning of period		478,854			488,517
	Actual return on plan assets		24,318			(14,887	)
	Employer contributions		7,957			14,305
	Benefits paid		(22,612	)		(31,313	)
Fair value of plan assets at end of period			488,517			456,622
	Funded status		(77,304	)		(145,304	)
	Unrecognized actuarial loss		69,831			146,376
	Unrecognized prior service cost		1,782			2,712
Accrued pension asset (liability)		$	(5,691	)	$	3,784
Amounts recognized in the consolidated balance sheets:
	Accrued benefit liability	$	(63,112	)	$	(132,961	)
	Intangible asset		6,094			5,418
	Additional minimum pension liability		51,327			131,327
Net amount recognized		$	(5,691	)	$	3,784

     The projected benefit obligation applicable to pension plans with accumulated benefit obligations in excess of plan assets was $565.8 million and $601.9 million as of December 31, 2001 and 2002, respectively. The accumulated benefit obligation related to these plans was $551.2 million and $589.6 million as of December 31, 2001 and 2002, respectively. The fair value of plan assets related to these plans was $488.5 million and $456.6 million as of December 31, 2001 and 2002, respectively. The projected benefit obligation exceeded plan assets for all plans as of December 31, 2001 and 2002.

     The provisions of SFAS No. 87, “Employers’ Accounting for Pensions,” 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, 2001 and 2002, the Company has recorded $51.3 million and $131.3 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, 2001 and 2002 was $16.1 million and $7.4 million, respectively. The noncurrent portion of the Company’s pension liability as

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reflected within “Other noncurrent liabilities” at December 31, 2001 and 2002 was $40.9 million and $120.1 million, respectively.

     The assumptions used to determine the above projected benefit obligation as of the end of each fiscal period were as follows:

	December 31,
	2001			2002
Discount rate		7.4	%		7.0	%
Rate of compensation increase		4.25	%		3.75	%
Expected rate of return on plan assets		9.0	%		8.75	%

     The Company amortizes actuarial gains and losses using a 5% corridor with a five-year amortization period.

     Certain subsidiaries make contributions to multi-employer pension plans, 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. The amounts contributed to the plans and included in operating costs were $0.1 million for the year ended March 31, 2001. There were no contributions during the nine months ended December 31, 2001 or the year ended December 31, 2002.

     The Company sponsors employee retirement accounts under five 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 $6.4 million, $6.2 million and $8.1 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 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:

					Nine Months
		Year Ended			Ended			Year Ended
		March 31,			December 31,			December 31,
		2001			2001			2002
		(Dollars in thousands)
Service cost for benefits earned		$	3,379		$	2,400		$	4,219
Interest cost on accumulated postretirement benefit obligation			74,227			55,766			76,691
Amortization of prior service cost			(2,610	)		(8,352	)		(14,698	)
Amortization of actuarial losses (gains)			(4,339	)		—			8,180
	Net periodic postretirement benefit costs	$	70,657		$	49,814		$	74,392

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     The following table sets forth the plans’ combined funded status reconciled with the amounts shown in the consolidated balance sheets:

		December 31,
		2001			2002
		(Dollars in thousands)
Change in benefit obligation:
	Benefit obligation at beginning of period	$	991,234		$	1,027,124
	Service cost		2,400			4,219
	Interest cost		55,766			76,691
	Plan amendments		(38,376	)		6,013
	Benefits paid		(53,771	)		(74,431	)
	Actuarial loss		69,871			213,571
Benefit obligation at end of period			1,027,124			1,253,187
Change in plan assets:
	Fair value of plan assets at beginning of period		—			—
	Employer contributions		53,771			74,431
	Benefits paid		(53,771	)		(74,431	)
Fair value of plan assets at end of period			—			—
	Funded status		(1,027,124	)		(1,253,187	)
	Unrecognized actuarial loss		42,387			248,576
	Unrecognized prior service cost		(47,796	)		(27,088	)
Accrued postretirement benefit obligation			(1,032,533	)		(1,031,699	)
Less current portion			70,367			72,100
	Noncurrrent obligation	$	(962,166	)	$	(959,599	)

     The assumptions used to determine the accumulated postretirement benefit obligation at the end of each fiscal period were as follows:

	December 31,
	2001			2002
Discount rate		7.40	%		7.00	%
Salary increase rate for life insurance benefit		4.25	%		3.75	%
Health care trend rate		7.15% down to			8.00% down to
		4.75% over 5 years			4.75% over 5 years

     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	$	11,500	$	(9,571	)
Effect on postretirement benefit obligation	$	162,219	$	(135,323	)

     In January 1999, the Company adopted reductions to the salaried employee medical coverage levels for employees retiring before January 1, 2003, which was subsequently changed to January 1, 2005. For employees retiring on or after January 1, 2005, the current medical plan is replaced with a medical premium reimbursement plan. This plan change does 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 is recognizing the effect of the plan amendment over nine years beginning January 1,

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1999. The effect was $2.5 million, $1.9 million and $2.5 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002.

     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 is recognizing the effect of the plan amendment over three years beginning July 1, 2001. Net periodic postretirement benefits costs for the nine months ended December 31, 2001 and the year ended December 31, 2002 were reduced by $6.4 million and $12.8 million, respectively, for this change.

     The Company amortizes actuarial gains and losses using a 5% corridor with an amortization period of three years.

     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 of “Obligation to industry fund” reflected in the consolidated balance sheets as of December 31, 2001 and 2002 was $49.7 million and $49.8 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, 2001 and 2002 was $7.4 million and $17.5 million, respectively.

     A benefit of $8.0 million was recognized for the period ended March 31, 2001, which included interest discount of $4.6 million, net amortization of an actuarial gain of $1.1 million and a gain of $11.5 million related to beneficiaries formerly assigned to the Company by the Social Security Administration and withdrawn in the year ended March 31, 2001. Expense of $3.3 million was recognized for the nine months ended December 31, 2001 related to the interest discount accrual on the Company’s obligation to the Combined Fund. 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 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 $2.0 million, $1.4 million and $4.1 million for the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 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 cost of providing health care benefits for one year 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 surety bonds and letters of credit as of December 31, 2002 of $105.7 million to secure the Company’s obligation.

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(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.

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, 2001 and 2002.

Capitalization Prior to Initial Public Offering

     On May 17, 2001, the Company effected a 1.4-for-one stock split of its then existing preferred and common stock. All references to number of shares, per share amounts and stock option data reflect the stock split.

     Prior to the initial public offering on May 22, 2001, the Company had 7.0 million shares of preferred stock, 26.6 million shares of Class A common stock and 1,010,509 shares of Class B common stock outstanding. All of these shares were converted on a one-for-one basis to shares of $0.01 par value common stock in May 2001 in conjunction with the initial public offering.

     The Company recognized compensation cost related to grants of common stock to management and non-employee directors of $3.9 million, $0.2 million and $0.1 million during the year ended March 31, 2001, the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively.

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     The following table summarizes preferred and common share activity from March 31, 2000 to December 31, 2002:

					Class A			Class B
		Preferred			Common			Common			Common
March 31, 2000			7,000,000			26,600,000			958,263			—
	Stock grants to employees		—			—			284,362			—
	Shares repurchased		—			—			(232,116	)		—
March 31, 2001			7,000,000			26,600,000			1,010,509			—
	Conversion to common stock		(7,000,000	)		(26,600,000	)		(1,010,509	)		34,610,509
	Issuance of common stock in connection with initial public offering		—			—			—			17,250,000
	Stock options exercised		—			—			—			67,066
	Employee stock purchases		—			—			—			75,087
	Stock grants to non-employee directors		—			—			—			7,584
December 31, 2001			—			—			—			52,010,246
	Stock options exercised		—			—			—			291,203
	Employee stock purchases		—			—			—			157,231
	Stock grants to non-employee directors		—			—			—			1,908
	Shares repurchased and retired		—			—			—			(60,310	)
December 31, 2002			—			—			—			52,400,278

(19) Equity Compensation Plans

Long-Term Equity Incentive Plan

     In connection with the initial public offering, the Company adopted the “Long-Term Equity Incentive Plan,” making 2.5 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 0.6 million and 0.7 million non-qualified options to purchase common stock during the nine months ended December 31, 2001 and the year ended December 31, 2002, respectively. These options vest over three years and expire 10 years after date of grant.

     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. The payout is based on the Company’s performance compared to an industry peer group and the S&P Industrial Index. During the nine months ended December 31, 2001 and the year ended December 31, 2002, the Company granted 0.1 million performance units in each period. No compensation expense was recorded for the nine months ended December 31, 2001. As a result of the Company’s performance relative to the measurement group, the Company recognized compensation expense of $2.1 million in 2002.

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 5.6 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 or incentive stock options.

     A portion of the options vest solely on the passage of time (“time options”) to the extent permitted under the Internal Revenue Code. Additionally, a portion of the options vest at the end of nine and one-half years, whether or not the applicable performance targets are achieved, but become exercisable earlier with the

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achievement of performance goals determined by the Board of Directors (“performance options”). Time options become fully vested early upon death, disability, a change in control or a recapitalization event, as defined. Performance options become fully vested early upon a change in control, a recapitalization event or an initial public offering, as defined.

     During the year ended March 31, 2001, the Company granted 1.5 million options to purchase Class A common stock, 0.4 million of which were time options and 1.1 million of which were performance options. All options granted during the year ended March 31, 2001 have an exercise price of $14.29 per share and expire 10 years after date of grant.

     A summary of outstanding option activity is as follows:

							Nine Months
		Year Ended					Ended					Year Ended
		March 31,			Weighted Average		December 31,			Weighted Average		December 31,			Weighted Average
		2001			Exercise Price		2001			Exercise Price		2002			Exercise Price
Beginning balance			5,165,538		$	14.29		5,225,510		$	14.29		5,678,343		$	15.70
	Granted		1,456,542			14.29		604,776			28.00		686,234			26.83
	Exercised		—			14.29		(67,066	)		14.29		(291,203	)		14.29
	Forfeited		(1,396,570	)		14.29		(84,877	)		17.51		(299,545	)		17.14
Outstanding			5,225,510		$	14.29		5,678,343		$	15.70		5,773,829		$	17.02
Exercisable			779,962		$	14.29		2,761,793		$	14.29		2,899,196		$	15.17

     A summary of options outstanding and exercisable as of December 31, 2002 is as follows:

	Options Outstanding						Options Exercisable
			Weighted Average
Range of			Remaining		Weighted Average				Weighted Average
Exercise Prices	Number		Contractual Life		Exercise Price		Number		Exercise Price
$14.29		4,568,000		6.0	$	14.29		2,713,025	$	14.29
$23.64 to $26.59		23,899		9.8		25.17		668		26.15
$26.60 to $29.55		1,181,930		8.7		27.41		185,503		28.01
		5,773,829		6.6	$	17.02		2,899,196	$	15.17

     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 nine months ended December 31, 2001 and the year ended December 31, 2002) and the minimum value method for the year ended March 31, 2001 were as follows:

	March 31,		December 31,		December 31,
	2001		2001		2002
Weighted average fair value		$5.97		$14.71		$13.18
Risk-free interest rate		5.5%		5.3%		4.6%
Expected option life		7 years		7 years		7 years
Expected volatility		—		53%		49%
Dividend yield		0%		1.4%		1.4%

Employee Stock Purchase Plan

     During the nine months ended December 31, 2001, the Company adopted an employee stock purchase plan. Total shares of common stock available for purchase under the plan are 1.5 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.

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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.

(20) Comprehensive Income

     The after-tax components of accumulated other comprehensive income (loss) are as follows:

								Total
		Foreign			Minimum			Accumulated
		Currency			Pension			Other
		Translation			Liability			Comprehensive
		Adjustment			Adjustment			Income (Loss)
		(Dollars in thousands)
March 31, 2000		$	(12,667	)	$	—		$	(12,667	)
	Current period change		(26,144	)		(862	)		(27,006	)
	Reclassification adjustment resulting from the sale of Peabody Resources Limited operations		38,811			—			38,811
March 31, 2001			—			(862	)		(862	)
	Current period change		—			(29,483	)		(29,483	)
December 31, 2001			—			(30,345	)		(30,345	)
	Current period change		15			(47,297	)		(47,282	)
December 31, 2002		$	15		$	(77,642	)	$	(77,627	)

     In conjunction with the sale of the Peabody Resources Limited operations, discussed in Note 7, the Company recorded a reduction of the foreign currency translation adjustment of the Company’s Peabody Resources Limited operations.

(21) Related Party Transactions

     Affiliates (“Lehman Brothers”) of the Company’s largest shareholder, Lehman Brothers Merchant Banking Partners II L.P. and its affiliates, served as one of the Company’s financial advisors in connection with the sale of the Company’s Peabody Resources Limited operations, which was completed on January 29, 2001. The Company paid Lehman Brothers a fee of $2.7 million, plus reimbursement of expenses, for those services.

     Lehman Brothers served as the Company’s financial advisor in connection with the sale of Citizens Power, which was completed in the year ended March 31, 2001. The Company paid Lehman Brothers a fee of approximately $1.5 million, plus reimbursement of expenses, for those services.

     Lehman Commercial Paper Inc. is a participant in the Company’s Senior Credit Facility, which was amended in April 2001. Lehman Commercial Paper Inc. received $0.06 million of the $1.4 million credit facility amendment fee.

     Lehman Brothers served as the lead underwriter in connection with the initial public offering of the Company’s common stock in May 2001. Lehman Brothers received customary fees, plus reimbursement of expenses, for those services.

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     Lehman Brothers served as the Company’s financial advisor in connection with a public tender offer completed in June 2001 to repurchase $80.0 million of principal of the Company’s Senior Notes and $80.0 million in principal of the Company’s Senior Subordinated Notes. The Company paid Lehman Brothers a fee of $0.4 million for those services.

     Lehman Brothers served as the Company’s advisor in its search for a partner for the development of the Thoroughbred Energy Campus, a proposed 1,500 megawatt electricity generating plant in Western Kentucky. For the nine months ended December 31, 2001, the Company paid Lehman Brothers $0.5 million, plus reimbursement of expenses, for those services.

     Lehman Brothers served as the lead underwriter in connection with a secondary public offering of Company Common Stock, which was completed in April 2002. Lehman Brothers 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. Lehman Brothers sold, in the aggregate, 8,155,000 shares in the offering, and their beneficial ownership of the Company’s outstanding common stock declined from 57% to 41% immediately following 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 and, therefore, is of the opinion that their fair value is zero.

     In addition to the guarantees specifically discussed below, the amount of surety bonds currently outstanding related to the Company’s reclamation, coal lease obligations, workers’ compensation, and retiree healthcare are presented in Notes 1, 11, 15 and 17, respectively, to the consolidated financial statements. A discussion of our $140.0 million accounts receivable securitization is included in Note 5 to the consolidated financial statements.

     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 owns a 49.0% interest in a joint venture that operates an underground mine and prep plant facility in West Virginia. The partners have severally agreed to guarantee the debt of the joint venture, which consists of a $28.3 million loan facility with two commercial banks and other bank loans of $2.1 million. Monthly principal payments on the loan facility of approximately $0.5 million are due through December 2004, and a final principal payment of $17.7 million is due on December 31, 2004. Interest payments on the loan facility are due monthly and accrue at prime plus  1/2%, or 4.75% as of December 31, 2002. The total amount of the joint venture’s debt guaranteed by the Company was $14.9 million as of December 31, 2002.

     The Company is the lessee under numerous equipment and property leases, as described in Note 11 to the consolidated financial statements. 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

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Company’s maximum potential obligations under its leases are presented in Note 11 and assume 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 14 to the consolidated financial statements, and supplemental guarantor/non-guarantor financial information is provided in Note 27 to the consolidated financial statements. The maximum amounts payable under the Company’s debt agreements are presented in Note 14 and assume that no amounts could be recovered from third parties.

     At December 31, 2002, the Company had an additional $19.6 million in letters of credit pledged as collateral in support of various surety bonds to secure workers’ compensation obligations and post-retirement and life insurance benefits as discussed in Note 15 and Note 17, respectively, to the consolidated financial statements.

     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 three 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.

     In addition to the letters of credit specifically discussed above, the Company has an additional $124.4 million of letters of credit in support of the Company’s coal lease obligations, workers’ compensation and retiree healthcare as presented in Notes 11, 15 and 17, respectively, to the consolidated financial statements.

     In connection with the sale of Citizens Power, the Company has indemnified the buyer from certain losses resulting from specified power contracts and guarantees. Should a party to one of these power contracts fail to perform under the contract, the Company would be required to reimburse the buyer for any losses incurred as a result of any non-performance that meet the requirements set forth in the indemnity. Due to the length and specific requirements of the contracts covered by the indemnity, we cannot reasonably estimate our future exposure, if any, under the indemnity.

(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, 2001 and 2002:

•  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.

F-54

•  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 value of interest rate swap contracts was based upon the costs that would be incurred to terminate those contracts in a loss position and the estimated consideration that would be received to terminate those contracts in a gain position. The Company could have received $6.6 million upon liquidation of interest rate swap contracts in place as of December 31, 2002, which expire May 15, 2008.

•  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 financial instruments are summarized as follows:

	December 31, 2001				December 31, 2002
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
	(Dollars in thousands)
Long-term debt	$	1,031,067	$	1,108,065	$	1,029,211	$	1,082,428
Deferred purchase obligation		21,790		20,543		16,171		16,100

(24) Commitments and Contingencies

Environmental

     Environmental claims have been asserted against a subsidiary of the Company at 22 sites in the United States. 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 majority of these sites are related to activities of former subsidiaries of the Company.

     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. The undiscounted liabilities for environmental cleanup-related costs recorded as part of “Other noncurrent liabilities” were $46.6 million and $42.1 million at December 31, 2001 and 2002, respectively. This amount represents those costs that the Company believes are probable and reasonably estimable.

     Navajo Nation

     On June 18, 1999, the Navajo Nation served the Company’s subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company (“Peabody Western”), with a complaint that had been filed in the U.S. District Court for the District of Columbia. Other defendants in the litigation are one customer, one current employee and one former employee. The Navajo Nation has 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

F-55

coal leases for the Kayenta and Black Mesa mines have terminated due to a breach of these leases and a reformation of the two coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted seven claims including fraud and is seeking various remedies including unspecified actual damages, punitive damages and reformation of its coal lease.

     On February 21, 2002, the Company’s subsidiaries commenced a lawsuit against the Navajo Nation in the U.S. District Court for the District of Arizona seeking enforcement of an arbitration award or, alternatively, to compel arbitration pursuant to the April 1, 1998 Arbitration Agreement with the Navajo Nation. On January 14, 2003, the Arizona District Court dismissed the lawsuit. Peabody Western has filed an appeal of this decision with the Ninth Circuit Court of Appeals.

     On February 22, 2002, the Company’s subsidiaries filed in the U.S. District for the District of Columbia a motion for leave to file an amended answer and conditional counterclaim. The counterclaim is conditional because the Company’s subsidiaries contend that the lease provisions the Navajo Nation seeks to invalidate have previously been upheld in an arbitration proceeding and are not subject to further litigation. On March 4, 2002, the Company’s subsidiaries filed in the U.S. District Court for the District of Columbia a motion to transfer that case to Arizona or, alternatively, to stay the District of Columbia litigation. The U.S. District Court for the District of Columbia denied the Company’s subsidiaries’ motion to transfer and motion to stay and we appealed that decision with the District of Columbia Court of Appeals. Oral argument on our appeal is scheduled for April 14, 2003.

     Subsequent to year-end, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States. The Court rejected the Navajo Nation’s allegation that the U.S. breached its trust responsibility to the Navajo Nation in approving the coal lease amendments and was liable for money damages.

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

Southern California Edison Company — Mohave Generating Station

     In response to a demand for arbitration by one of our 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.

     Peabody Western filed a motion to compel arbitration that was granted by the trial court. Southern California Edison appealed this order to the Arizona Court of Appeals, which denied its appeal. Southern California Edison then appealed the order to the Arizona Supreme Court, which remanded the case to the Arizona Court of Appeals and ordered the appellate court to determine whether the trial court was correct in determining that Peabody Western’s claims are arbitrable. The Arizona Court of Appeals ruled that neither mine decommissioning costs nor retiree health care costs are to be arbitrated and that both issues should be resolved in litigation. The matter has been remanded to the Superior Court of Maricopa County, Arizona. Peabody Western answered the complaint and asserted counterclaims. The court then permitted Southern California Edison to amend its complaint to add a claim of overcharges of at least $19.2 million by Peabody Western.

     By order filed July 2, 2001, the court granted Peabody Western’s motion for summary judgment on liability with respect to retiree healthcare costs. Southern California Edison filed a motion for reconsideration, which was denied by the court on October 16, 2001. Peabody Western filed a supplemental motion for summary judgment on liability with respect to mine decommissioning costs that was denied by the trial court on February 6, 2002.

F-56

     Peabody Western reached a mediated settlement with the owners of the Mohave Generating Station, which resulted in the recognition of $15.1 million in pre-tax earnings during the quarter ended September 30, 2002. The settlement provides for customer reimbursement of mine decommissioning and certain other post-mining expenditures. The reimbursement commenced in January 2003 and continues on a monthly basis through December 2005. All of the owners except one exercised their option to prepay these reimbursements in 2002.

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

     The Mohave coal supply agreement is scheduled to expire on December 31, 2005. In addition, there is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline to the Mohave plant. The plant’s owners have sought permission from the California Public Utilities Commission for authorization to begin certain interim spending on air pollution controls if the coal supply and water issues were resolved by December 31, 2002. Although those issues were not resolved by that date, the plant’s owners and the Company are in active discussions to resolve the complex issues critical to the continued operation of the Mohave plant 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 delayed beginning on December 31, 2005. The Mohave plant is the sole customer of the Black Mesa Mine, which produces and sells 4.5 to 5.0 million tons of coal per year.

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. Peabody Western sells approximately 7 to 8 million tons of coal per year to the owners of the Navajo Generation Station under a long-term contract. In July 1999, Salt River notified Peabody Western that it believed the owners were entitled to a price decrease of $1.92 per ton as a result of the review. Salt River also claimed entitlement to a retroactive price adjustment to January 1997 and that an overbilling of $50.5 million had occurred during the same five-year period. In October 1999, Peabody Western notified Salt River that it believed it was entitled to a $2.00 per ton price increase as a result of the review. The parties were unable to settle the dispute and Peabody Western filed a demand for arbitration in September 2000. The arbitration hearing was held in April of 2002. On July 20, 2002, Peabody Western received a favorable decision from the arbitrators. The decision increased the price of coal by approximately $0.50 per ton from 1997 through 2001 and thereafter. As a result of the decision, the Company received pre-tax earnings of approximately $22 million during the quarter ended September 30, 2002. The exact impact of the ruling on the pricing of coal sales from January 1, 2002 forward will not be determined until Salt River completes a review of the cumulative cost changes under the contract for the years 1997 through 2001.

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

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

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

F-57

     While the outcome of litigation and arbitration is subject to uncertainties, based on the Company’s 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 the Company’s financial condition or results of operations.

     Other

     Accounts receivable in the consolidated balance sheet as of December 31, 2002 includes $8.6 million of receivables billed during 2001 and 2002 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.

     In addition, the Company at times becomes a party to 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.

     At December 31, 2002, purchase commitments for capital expenditures were approximately $56.8 million.

(25) Summary Quarterly Financial Information (unaudited)

     A summary of the unaudited quarterly results of operations for the nine months ended December  31, 2001 and year ended December 31, 2002 is presented below. Peabody Energy common stock is listed on the New York Stock Exchange under the symbol “BTU.”

	Nine Months Ended December 31, 2001
	First Quarter			Second Quarter		Third Quarter
	(Dollars in thousands except
	per share and stock price data)
Revenues		$636,291			$655,569		$646,080
Operating profit		50,027			36,306		29,198
Income before extraordinary item		9,906			4,060		5,321
Net income (loss)		(17,698	)		4,060		3,955
Basic earnings per share from operations		$0.23			$0.08		$0.10
Diluted earnings per share from operations		$0.22			$0.08		$0.10
Weighted average shares used in calculating basic earnings per share		42,215,878			51,943,624		52,008,851
Weighted average shares used in calculating diluted earnings per share		44,213,833			53,653,950		53,753,645
Stock price — high and low closing prices		$37.95-$26.45			$31.85-$23.25		$31.90-$23.35
Dividends per share		$—			$0.10		$0.10

     Results of operations for the quarter ended June 30, 2001 included an after-tax extraordinary loss of $27.6 million related to debt extinguished utilizing proceeds from the Company’s initial public offering.

F-58

Results of operations for the quarter ended December 31, 2001 included an after-tax extraordinary loss from debt extinguishment of $1.4 million.

	Year Ended December 31, 2002
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(Dollars in thousands except
	per share and stock price data)
Revenues		$675,766		$656,940		$714,611		$669,781
Operating profit		54,950		55,245		51,320		12,173
Net income		22,315		24,497		29,036		29,671
Basic earnings per share from operations		$0.43		$0.47		$0.56		$0.57
Diluted earnings per share from operations		$0.42		$0.45		$0.54		$0.55
Weighted average shares used in calculating basic earnings per share		52,018,238		52,122,455		52,176,646		52,341,924
Weighted average shares used in calculating diluted earnings per share		53,731,426		53,859,275		53,649,383		53,879,044
Stock price – high and low closing prices		$29.76-$23.50		$30.39-$26.18		$28.00-$18.70		$29.23-$23.11
Dividends per share		$0.10		$0.10		$0.10		$0.10

     Operating profit for the third quarter includes $37.1 million due to the successful resolution of disputes related to the Navajo Station and Mohave Station coal supply agreements (discussed in Note 24).

     Net income for the fourth quarter includes an income tax benefit of $44.6 million. This benefit results primarily from significant tax benefits realized as a result of utilizing net operating loss carryforwards to offset taxable gains primarily recognized in connection with the PVR transaction as discussed in Note 11. Utilization of the loss carry-forwards required the reduction of a previously recorded valuation allowance that had reduced the book value of the loss carryforwards.

(26) Segment Information

     The Company reports its operations primarily through the following reportable operating segments: “U.S. Mining,” “Trading and Brokerage,” and “Australian Mining.” The principal business of the U.S. Mining segment is mining, preparation and sale of steam coal, sold primarily to electric utilities, and metallurgical coal, sold to steel and coke producers. The Trading and Brokerage segment’s principal business is the marketing and trading of coal and emission allowances. The Australian Mining segment in 2001 consisted of the operations of Peabody Resources Limited and for 2002 consists of the operations of Allied Queensland Coalfields Party Limited. This segment’s principal business is the same as the U.S. Mining Segment. “Corporate and Other” consists primarily of corporate overhead not directly attributable to the U.S. Mining, Australian Mining or Trading and Brokerage operating segments, and resource management activities.

     The U.S. Mining segment results below also include costs related to past mining activities and a portion of consolidated net gains on property disposals.

     For the year ended December 31, 2002, 94% of the Company’s sales were to U.S. electricity generators, 2% were to the U.S. industrial sector, and 4% were to customers outside the United States. Substantially all of the Company’s physical assets are located in the United States.

F-59

     Operating segment results for the year ended March 31, 2001 were as follows:

					Peabody
					Resources
			Trading and		Limited		Corporate
	U.S. Mining		Brokerage		Operations		and Other			Consolidated
	(Dollars in thousands)
Revenues	$	2,174,925	$	194,766	$	238,498	$	19,939		$	2,628,128
Operating profit		161,991		13,126		53,377		113,345	(1)		341,839
Total assets		4,802,829		198,421		—		208,237			5,209,487
Depreciation, depletion and amortization		204,249		2,676		25,518		8,525			240,968
Capital expenditures		146,653		206		—		4,499			151,358

(1)  Includes the pretax gain on the sale of the Company’s Peabody Resources Limited operations of $171.7 million.

     Operating segment results for the nine months ended December 31, 2001 were as follows:

			Trading and		Corporate
	U.S. Mining		Brokerage		and Other			Consolidated
	(Dollars in thousands)
Revenues	$	1,762,775	$	150,988	$	24,177		$	1,937,940
Operating profit		127,282		22,685		(34,436	)		115,531
Total assets		4,843,336		72,065		235,501			5,150,902
Depreciation, depletion and amortization		162,165		1,675		10,747			174,587
Capital expenditures		180,333		1,129		12,784			194,246

     Operating segment results for the year ended December 31, 2002 were as follows:

			Trading and		Australian		Corporate
	U.S. Mining		Brokerage		Mining		and Other			Consolidated
	(Dollars in thousands)
Revenues	$	2,483,501	$	204,944	$	9,933	$	18,720		$	2,717,098
Operating profit		221,595		36,753		2,779		(87,439	)		173,688
Total assets		4,705,876		88,107		46,036		300,158			5,140,177
Depreciation, depletion and amortization		220,935		287		236		10,955			232,413
Capital expenditures		185,161		2,179		172		21,050			208,562

     Reconciliation of segment operating profit to consolidated income before income taxes follows:

					Nine Months
		Year Ended			Ended			Year Ended
		March 31,			December 31,			December 31,
		2001			2001			2002
		(Dollars in thousands)
Total segment operating profit		$	341,839		$	115,531		$	173,688
	Interest expense		197,686			88,686			102,458
	Interest income		(8,741	)		(2,155	)		(7,574	)
	Minority interests		7,524			7,248			13,292
Income before income taxes		$	145,370		$	21,752		$	65,512

F-60

(27)  Supplemental Guarantor/ Non-Guarantor Financial Information

     In accordance with the indentures governing the Senior Notes and Senior Subordinated Notes, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed the Senior Notes and Senior Subordinated 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 holders of the Senior Notes or the Senior Subordinated Notes. The following condensed historical financial statement information is provided for such Guarantor/ Non-Guarantor Subsidiaries.

Supplemental Condensed Consolidated Statements of Operations

Year Ended March 31, 2001

		Parent			Guarantor			Non-Guarantor
		Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
		(Dollars in thousands)
Total revenues		$	—		$	1,913,302		$	772,343		$	(57,517	)	$	2,628,128
Costs and expenses:
	Operating costs and expenses		—			1,591,707			589,336			(57,517	)		2,123,526
	Depreciation, depletion and amortization		—			175,162			65,806			—			240,968
	Selling and administrative expenses		4,058			77,190			18,019			—			99,267
	Gain on sale of Peabody Resources Limited operations		—			(171,735	)		—			—			(171,735	)
	Net gain on property and equipment disposals		—			(4,667	)		(1,070	)		—			(5,737	)
	Interest expense		158,622			109,420			30,971			(101,327	)		197,686
	Interest income		(68,655	)		(27,915	)		(13,498	)		101,327			(8,741	)
Income (loss) before income taxes and minority interests			(94,025	)		164,140			82,779			—			152,894
	Income tax provision (benefit)		(33,608	)		45,463			30,835			—			42,690
	Minority interests		—			—			7,524			—			7,524
Income (loss) from continuing operations			(60,417	)		118,677			44,420			—			102,680
	Gain from disposal of discontinued operations, net of income taxes		(88	)		(12,837	)		—			—			(12,925	)
Income (loss) before extraordinary item			(60,329	)		131,514			44,420			—			115,605
	Extraordinary loss from early extinguishment of debt, net of income taxes		8,545			—			—			—			8,545
Net income (loss)		$	(68,874	)	$	131,514		$	44,420		$	—		$	107,060

F-61

Supplemental Condensed Consolidated Statements of Operations

Nine Months Ended December 31, 2001

		Parent			Guarantor			Non-Guarantor
		Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
		(Dollars in thousands)
Total revenues		$	—		$	1,529,986		$	473,742		$	(65,788	)	$	1,937,940
Costs and expenses:
	Operating costs and expenses		—			1,261,983			392,401			(65,788	)		1,588,596
	Depreciation, depletion and amortization		—			139,571			35,016			—			174,587
	Selling and administrative expenses		1,297			60,266			11,990			—			73,553
	Net gain on property and equipment disposals		—			(14,327	)		—			—			(14,327	)
	Interest expense		86,618			76,352			14,278			(88,562	)		88,686
	Interest income		(51,422	)		(28,558	)		(10,737	)		88,562			(2,155	)
Income (loss) before income taxes and minority interests			(36,493	)		34,699			30,794			—			29,000
	Income tax provision (benefit)		(3,102	)		2,950			2,617			—			2,465
	Minority interests		—			—			7,248			—			7,248
Income (loss) before extraordinary item			(33,391	)		31,749			20,929			—			19,287
	Extraordinary loss from early extinguishment of debt, net of income taxes		17,940			11,030			—			—			28,970
Net income (loss)		$	(51,331	)	$	20,719		$	20,929		$	—		$	(9,683	)

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		$	—		$	2,123,273		$	665,445		$	(71,620	)	$	2,717,098
Costs and expenses:
	Operating costs and expenses		—			1,764,062			532,902			(71,620	)		2,225,344
	Depreciation, depletion and amortization		—			183,065			49,348			—			232,413
	Selling and administrative expenses		443			82,249			18,724			—			101,416
	Net gain on property and equipment disposals		—			(15,596	)		(167	)		—			(15,763	)
	Interest expense		137,821			99,265			15,494			(150,122	)		102,458
	Interest income		(68,601	)		(73,656	)		(15,439	)		150,122			(7,574	)
Income (loss) before income taxes and minority interests			(69,663	)		83,884			64,583			—			78,804
	Income tax provision (benefit)		37,687			(45,458	)		(32,236	)		—			(40,007	)
	Minority interests		—			—			13,292			—			13,292
Net income (loss)		$	(107,350	)	$	129,342		$	83,527		$	—		$	105,519

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SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS

December 31, 2001

			Parent		Guarantor			Non-Guarantor
			Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
			(Dollars in thousands)
ASSETS
Current assets
	Cash and cash equivalents		$	28,121	$	1,018		$	9,483		$	—		$	38,622
	Accounts receivable			523		50,448			127,105			—			178,076
	Inventories			—		201,771			13,873			—			215,644
	Assets from coal and emission allowance trading activities			—		60,509			—			—			60,509
	Deferred income taxes			—		14,380			—			—			14,380
	Other current assets			1,222		10,704			8,297			—			20,223
		Total current assets		29,866		338,830			158,758			—			527,454
Property, plant, equipment and mine development — at cost				—		4,543,016			478,939			—			5,021,955
Less accumulated depreciation, depletion and amortization				—		(603,953	)		(80,604	)		—			(684,557	)
Property, plant, equipment and mine development, net				—		3,939,063			398,335			—			4,337,398
Investments and other assets				3,296,950		232,521			45,086			(3,288,507	)		286,050
		Total assets	$	3,326,816	$	4,510,414		$	602,179		$	(3,288,507	)	$	5,150,902
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Current maturities of long-term debt		$	—	$	10,400		$	36,099		$	—		$	46,499
	Payables and notes payable to affiliates, net			1,544,519		(1,561,645	)		17,126			—			—
	Liabilities from coal and emission allowance trading activities			—		45,691			—			—			45,691
	Accounts payable and accrued expenses			8,676		528,157			55,280			—			592,113
		Total current liabilities		1,553,195		(977,397	)		108,505			—			684,303
Long-term debt, less current maturities				702,623		81,186			200,759			—			984,568
Deferred income taxes				—		564,764			—			—			564,764
Other noncurrent liabilities				5,181		1,820,580			8,954			—			1,834,715
		Total liabilities		2,260,999		1,489,133			318,218			—			4,068,350
Minority interests				—		—			47,080			—			47,080
Stockholders’ equity				1,065,817		3,021,281			236,881			(3,288,507	)		1,035,472
		Total liabilities and stockholders’ equity	$	3,326,816	$	4,510,414		$	602,179		$	(3,288,507	)	$	5,150,902

F-63

SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS

December 31, 2002

			Parent		Guarantor			Non-Guarantor
			Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
			(Dollars in thousands)
ASSETS
Current assets
	Cash and cash equivalents		$	60,666	$	420		$	10,124		$	—		$	71,210
	Accounts receivable			836		62,214			90,162			—			153,212
	Inventories			—		211,291			18,397			—			229,688
	Assets from coal and emission allowance trading activities			—		65,153			4,745			—			69,898
	Deferred income taxes			—		10,101			260			—			10,361
	Other current assets			260		8,381			6,913			—			15,554
		Total current assets		61,762		357,560			130,601			—			549,923
Property, plant, equipment and mine development — at cost				—		4,591,811			539,418			—			5,131,229
Less accumulated depreciation, depletion and amortization				—		(751,627	)		(106,560	)		—			(858,187	)
Property, plant, equipment and mine development, net				—		3,840,184			432,858			—			4,273,042
Investments and other assets				3,448,319		248,778			48,273			(3,428,158	)		317,212
		Total assets	$	3,510,081	$	4,446,522		$	611,732		$	(3,428,158	)	$	5,140,177
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Current maturities of long-term debt		$	—	$	10,303		$	37,212		$	—		$	47,515
	Payables and notes payable to affiliates, net			1,626,695		(1,643,593	)		16,898			—			—
	Liabilities from coal and emission allowance trading activities			—		37,008			—			—			37,008
	Accounts payable and accrued expenses			9,427		479,441			58,145			—			547,013
		Total current liabilities		1,636,122		(1,116,841	)		112,255			—			631,536
Long-term debt, less current maturities				714,571		75,975			191,150			—			981,696
Deferred income taxes				—		495,284			4,026			—			499,310
Other noncurrent liabilities				623		1,898,581			10,172			—			1,909,376
		Total liabilities		2,351,316		1,352,999			317,603			—			4,021,918
Minority interests				—		—			37,121			—			37,121
Stockholders’ equity				1,158,765		3,093,523			257,008			(3,428,158	)		1,081,138
		Total liabilities and stockholders’ equity	$	3,510,081	$	4,446,522		$	611,732		$	(3,428,158	)	$	5,140,177

F-64

SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended March 31, 2001

		Parent			Guarantor			Non-Guarantor
		Company			Subsidiaries			Subsidiaries			Consolidated
		(Dollars in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by (used in) operating activities		$	(20,172	)	$	113,212		$	58,940		$	151,980
CASH FLOWS FROM INVESTING ACTIVITIES
	Additions to property, plant, equipment and mine development		—			(94,577	)		(56,781	)		(151,358	)
	Additions to advance mining royalties		—			(8,785	)		(11,475	)		(20,260	)
	Acquisitions, net		—			(10,502	)		—			(10,502	)
	Proceeds from sale of Peabody Resources Limited operations		—			455,000			—			455,000
	Proceeds from property and equipment disposals		—			7,711			11,214			18,925
	Proceeds from sale-leaseback transactions		—			28,800			—			28,800
	Net cash used in assets sold — Peabody Resources Limited operations		—			—			(34,684	)		(34,684	)
	Net cash provided by discontinued operations		604			101,937			—			102,541
Net cash provided by (used in) investing activities			604			479,584			(91,726	)		388,462
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from long-term debt		—			—			65,302			65,302
	Payments of long-term debt		(565,000	)		(21,063	)		(47,842	)		(633,905	)
	Distributions to minority interests		—			—			(4,690	)		(4,690	)
	Dividend received		—			19,916			—			19,916
	Repurchase of treasury stock		—			(1,113	)		—			(1,113	)
	Transactions with affiliates, net		584,394			(579,835	)		(4,559	)		—
	Net cash provided by assets sold — Peabody Resources Limited operations		—			—			10,591			10,591
	Other		—			562			—			562
Net cash provided by (used in) financing activities			19,394			(581,533	)		18,802			(543,337	)
Net increase (decrease) in cash and cash equivalents			(174	)		11,263			(13,984	)		(2,895	)
Cash and cash equivalents at beginning of year			347			45,931			19,340			65,618
Cash and cash equivalents at end of year		$	173		$	57,194		$	5,356		$	62,723

F-65

SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Nine Months Ended December 31, 2001

		Parent			Guarantor			Non-Guarantor
		Company			Subsidiaries			Subsidiaries			Consolidated
		(Dollars in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by (used in) operating activities		$	(25,520	)	$	110,725		$	29,287		$	114,492
CASH FLOWS FROM INVESTING ACTIVITIES
	Additions to property, plant, equipment and mine development		—			(117,876	)		(76,370	)		(194,246	)
	Additions to advance mining royalties		—			(7,253	)		(4,052	)		(11,305	)
	Proceeds from property and equipment disposals		—			11,436			2,115			13,551
	Proceeds from sale-leaseback transactions		—			—			19,011			19,011
Net cash used in investing activities			—			(113,693	)		(59,296	)		(172,989	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from short-term borrowings and long-term debt		—			—			40,995			40,995
	Payments of long-term debt		(331,341	)		(100,280	)		(15,048	)		(446,669	)
	Proceeds from employee stock purchases		1,306			—			—			1,306
	Net proceeds from initial public offering		449,832			—			—			449,832
	Distributions to minority interests		—			—			(1,626	)		(1,626	)
	Dividends paid		(10,393	)		—			—			(10,393	)
	Transactions with affiliates, net		(56,825	)		47,010			9,815			—
	Other		889			62			—			951
Net cash provided by (used in) financing activities			53,468			(53,208	)		34,136			34,396
Net increase (decrease) in cash and cash equivalents			27,948			(56,176	)		4,127			(24,101	)
Cash and cash equivalents at beginning of period			173			57,194			5,356			62,723
Cash and cash equivalents at end of period		$	28,121		$	1,018		$	9,483		$	38,622

F-66

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	)	$	176,133		$	121,141		$	231,204
CASH FLOWS FROM INVESTING ACTIVITIES
	Additions to property, plant, equipment and mine development		—			(152,010	)		(56,552	)		(208,562	)
	Additions to advance mining royalties		—			(10,183	)		(4,706	)		(14,889	)
	Acquisitions, net		—			(45,537	)		—			(45,537	)
	Investment in joint venture		—			(475	)		—			(475	)
	Proceeds from property and equipment disposals		—			115,604			9,781			125,385
Net cash used in investing activities			—			(92,601	)		(51,477	)		(144,078	)
CASH FLOWS FROM FINANCING ACTIVITIES
	Proceeds from short-term borrowings and long-term debt		—			—			16,462			16,462
	Payments of long-term debt		—			(10,332	)		(37,417	)		(47,749	)
	Proceeds from employee stock purchases		3,250			—			—			3,250
	Distributions to minority interests		—			—			(9,800	)		(9,800	)
	Dividends paid		(20,863	)		—			—			(20,863	)
	Transactions with affiliates		112,326			(73,798	)		(38,528	)		—
	Other		3,902			—			—			3,902
Net cash provided by (used in) financing activities			98,615			(84,130	)		(69,283	)		(54,798	)
Effect of exchange rate changes on cash and equivalents			—			—			260			260
Net increase (decrease) in cash and cash equivalents			32,545			(598	)		641			32,588
Cash and cash equivalents at beginning of period			28,121			1,018			9,483			38,622
Cash and cash equivalents at end of period		$	60,666		$	420		$	10,124		$	71,210

F-67

REPORT OF INDEPENDENT AUDITORS

The Board of Directors

Peabody Energy Corporation

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

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

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

/s/ Ernst & Young LLP

St. Louis, Missouri

January 18, 2003

F-68