10KT405 1 c67999e10kt405.txt TRANSITION REPORT FOR THE PERIOD ENDED 12/31/2001 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K [ ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended March 31, 2001 or [X] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from April 1, 2001 to December 31, 2001 ------------- ----------------- Commission File Number 1-16463 -------------------------------------------------------- PEABODY ENERGY CORPORATION -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) DELAWARE 13-4004153 ------------------------------- ------------------------ (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 701 MARKET STREET, ST. LOUIS, MISSOURI 63101 --------------------------------------------------------------- -------------- (Address of principal executive offices) (Zip Code) (314) 342-3400 -------------------------------------------------------------------------------- Registrant's telephone number, including area code Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered ------------------- ----------------------------------------- Common Stock, par value $0.01 per share New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: NONE Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- ---- Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] Aggregate market value of the voting stock held by non-affiliates of the Registrant as of March 1, 2002: Common Stock, par value $0.01 per share, $559.7 million. Number of shares outstanding of each of the Registrant's classes of Common Stock, as of March 1, 2002: Common Stock, par value $0.01 per share, 52,020,274 shares outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Peabody Energy Corporation (the "Company") Annual Report for the nine months ended December 31, 2001 are incorporated by reference into Part II hereof. Portions of the Company's Proxy Statement to be filed with the SEC in connection with the Company's Annual Meeting of Stockholders to be held on May 3, 2002 (the "Company's 2002 Proxy Statement") are incorporated by reference into Part III hereof. Other documents incorporated by reference in this report are listed in the Exhibit Index of this Form 10-K. CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS Some of the information included in this prospectus or any prospectus supplement and the documents we have incorporated by reference contain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance. We use words such as "anticipate," "believe," "expect," "may," "project," "will" or other similar words to identify forward-looking statements. Without limiting the foregoing, all statements relating to our: o future outlook; o anticipated capital expenditures; o future cash flows and borrowings; and o 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: o general economic conditions; o modification or termination of our long-term coal supply agreements; o reduction of purchases by major customers; o transportation costs; o risks inherent to mining; o government regulation of the mining industry; o replacement of recoverable reserves; o implementation of new accounting standards; o inflationary trends and interest rates; and o other factors, including those discussed in "Risk Factors" and "Recent Developments." When considering these forward-looking statements, you should keep in mind the cautionary statements in this document, any prospectus supplement or term sheet and the documents incorporated by reference. We will not update these statements unless the securities laws require us to do so. 2 TABLE OF CONTENTS
PART I. Page -------- Item 1. Business........................................................................... 4 Item 2. Properties......................................................................... 19 Item 3. Legal Proceedings.................................................................. 24 Item 4. Submission of Matters to a Vote of Security Holders................................ 27 Item 4A. Executive Officers of the Company.................................................. 27 PART II. Item 5. Market For Registrant's Common Equity and Related Stockholder Matters.............. 29 Item 6. Selected Financial Data............................................................ 29 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations............................................................ 32 Item 7A. Quantitative and Qualitative Disclosures About Market Risk......................... 46 Item 8. Financial Statements and Supplementary Data........................................ 47 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure............................................................. 47 PART III. Item 10. Directors and Executive Officers of the Registrant................................. 47 Item 11. Executive Compensation............................................................. 47 Item 12. Security Ownership of Certain Beneficial Owners and Management..................... 47 Item 13. Certain Relationships and Related Transactions..................................... 47 PART IV. Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................... 47
3 PART I ITEM 1. BUSINESS. OVERVIEW We are the largest private-sector coal company in the world. During the nine months ended December 31, 2001, we sold 146.5 million tons of coal. During this period, we sold coal to more than 250 electric generating and industrial plants in eleven countries, and fueled the generation of more than 9% of all electricity in the United States and 2.5% of all electricity in the world. At December 31, 2001, we had 9.1 billion tons of proven and probable coal reserves. We own majority interests in 33 coal operations located throughout all major U.S. coal producing regions, with 72% of our mining operations' coal sales during the nine months ended December 31, 2001 shipped from the western United States and the remaining 28% from the eastern United States. Most of our production in the western United States is low sulfur coal from the Powder River Basin. Our overall western U.S. coal production has increased from 37.0 million tons in fiscal year 1990 to 127.1 million tons during calendar year 2001, representing a compounded annual growth rate of 12%. 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 79% of our sales volume for the nine months ended December 31, 2001 from non-union mines. For the nine months ended December 31, 2001, 94% of our sales were to U.S. electricity generators, 4% were to the U.S. industrial sector and 2% were to customers outside the United States. Approximately 83% of our coal sales during the nine months ended December 31, 2001 were under long-term contracts. As of December 31, 2001, nearly one billion tons of our future coal production were committed under long-term contracts, with remaining terms ranging from one to 14 years and an average volume-weighted remaining term of approximately four years. As of March 1, 2002, we had approximately 6 million tons and 65 million tons of expected production available for sale at market-based prices in calendar year 2002 and 2003, respectively. In addition to our mining operations, we market and trade coal and emission allowances. Our total tons traded as part of these activities were 39.4 million for the nine months ended December 31, 2001. Finally, we are also expanding in related energy businesses that include coalbed methane production, transportation-related services, third-party coal contract restructuring and participation in the development of coal-based generating plants. HISTORY Peabody, Daniels and Co. was founded in 1883 as a retail coal supplier, entering the mining business in 1888 as Peabody & Co. with our first mine in Illinois. In 1926, Peabody Coal Company was listed on the Chicago Stock Exchange and, beginning in 1949, on the New York Stock Exchange. In 1955, Peabody Coal Company, primarily an underground mine operator, merged with Sinclair Coal Company, a major surface mining company. In 1968, Peabody Coal Company was acquired by Kennecott Copper Company. In 1977, it was sold to Peabody Holding Company, which was formed by a consortium of companies. In July 1990, Hanson, plc acquired Peabody Holding Company. In February 1997, Hanson spun off its energy-related businesses, including Eastern Group and Peabody Holding Company, into The Energy Group, plc. The Energy Group was a publicly traded company in the United Kingdom and its American Depository Receipts (ADR's) were publicly traded on the New York Stock Exchange. On May 19, 1997, The Energy Group, through Peabody, purchased Citizens Power LLC, a leading power marketer. On May 19, 1998, Lehman Brothers Merchant Banking Partners II L.P., an affiliate of Lehman Brothers Inc., purchased Peabody Holding Company and its affiliates, Peabody Resources Limited (Peabody Resources) and Citizens Power LLC. During the 1980s, Peabody grew through internal expansion and acquisition, opening the North Antelope Mine in Wyoming's coal-rich Powder River Basin in 1983 and the Rochelle Mine in 1985. In 1984, we acquired the West Virginia coal properties of ARMCO Steel and the following year purchased Coal Properties Corp. and Eastern Associated Coal Corp., which included seven operating mines and substantial low sulfur coal reserves in West Virginia. From 1993 to 2001, we made 16 major acquisitions. In 1993, interests in three mines in New South Wales, Australia, were acquired from Costain Group in anticipation of the growing Pacific Rim market for coal. The properties included 100% ownership of the Ravensworth Mine, a 50% interest in the Narama Mine and a 28.75% interest in the Warkworth Mine, 4 subsequently increased to 43.75%. We also subsequently developed a fourth mine, Bengalla, which began shipments in early 1999. Our interest in the Bengalla joint venture was increased from 35% to 37% in 1998 and to 40% in 2000. In 1993 we also acquired the Lee Ranch Mine in New Mexico. The following year, we purchased a one-third ownership in Black Beauty Coal Company (Black Beauty), Indiana's largest coal producer. We increased our interest in Black Beauty to 43.3% in February 1998 and to 81.7% in January 1999. Black Beauty acquired Catlin Coal Company in 1999 and acquired an additional 25% of Arclar Coal Company in 2000. In 1994, we acquired the Caballo and Rawhide mines in Wyoming's Powder River Basin from Exxon Coal USA Inc. This acquisition, along with the expansion of the North Antelope and Rochelle Mines, positioned Peabody as the leading producer in the Powder River Basin, the nation's largest and fastest growing coal region. Our sales volume from the Powder River Basin increased from 31 million tons in 1993 to 106.3 million tons in calendar 2001. In August 1999, we purchased a 55% interest in the Moura Mine in Queensland, Australia. The Moura Mine supplies a range of steam and metallurgical coals to Asia-Pacific customers and operates a coalbed methane extraction operation. We sold our Australian operations to a subsidiary of Rio Tinto Limited in January 2001. 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. On April 10, 2001, we changed our name from P&L Coal Holdings Corporation to Peabody Energy Corporation. On May 21, 2001, we completed an initial public offering of Common Stock and our shares began trading on the New York Stock Exchange under the symbol "BTU." MINING OPERATIONS 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. [UNITED STATES MINING OPERATIONS MAP] Within the United States, we conduct operations in the Powder River Basin, Southwest, Appalachia and Midwest regions. 5 POWDER RIVER BASIN OPERATIONS We control approximately 2.7 billion tons of coal reserves in the Southern Powder River Basin, the largest and fastest growing major U.S. coal-producing region. We own and manage two active low sulfur, non-union surface mining complexes in Wyoming that sold approximately 78.3 million tons of coal during the nine months ended December 31, 2001, 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 and the Union Pacific. In addition, we own the Rawhide Mine, which is located ten miles north of Gillette, Wyoming and uses truck-and-shovel mining methods. The Rawhide Mine is serviced by the Burlington Northern & Santa Fe railroad. Operations were suspended at the Rawhide mine in 1999, and the mine reopened in January 2002 as a result of favorable market conditions during 2001. 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 8,500 to 8,900 Btu per pound. We also operate 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 and most productive in the United States, selling 56.8 million tons during the nine months ended December 31, 2001. 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 expect to add a second dragline in 2002 to improve productivity. Caballo The Caballo Mine is located 20 miles south of Gillette, Wyoming. During the nine months ended December 31, 2001, it sold approximately 21.5 million tons of compliance coal. Caballo is a truck-and-shovel operation with a coal handling system that includes two 12,000-ton silos and two 11,000-ton silos. Big Sky The Big Sky Mine is located in the northern end of the Powder River Basin near Colstrip, Montana, and uses dragline mining equipment. The mine sold 2.0 million tons of medium sulfur coal during the nine months ended December 31, 2001. Coal is shipped by rail to several major electric 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 four mines in the western bituminous coal region - two in Arizona, and one in each of Colorado and New Mexico. The Colorado and Arizona mines supply primarily compliance coal and the New Mexico mine supplies medium sulfur coal under long-term coal supply agreements to electricity generating stations in the region. Together, these mines sold 16.0 million tons of coal during the nine months ended December 31, 2001. Black Mesa The Black Mesa Mine, which is located on the Navajo Nation and Hopi Tribe reservations in Arizona, uses two draglines and sold 3.6 million tons of coal during the nine months ended December 31, 2001. 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 2005, with the customer's option to extend the term up to an additional 15 years, subject to agreement on specified terms. Hourly workers at this mine are members of the United Mine Workers of America. 6 Kayenta The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines in three mining areas. It sold approximately 6.5 million tons of coal during the nine months ended December 31, 2001. 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. Seneca The Seneca Mine near Hayden, Colorado shipped 1.3 million tons of compliance coal during the nine months ended December 31, 2001, 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 Coal Company The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 4.6 million tons of medium sulfur coal during the nine months ended December 31, 2001. 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. Lee Ranch is currently expanding to annual production capacity of 6.7 million tons to meet the requirements of two new customers. APPALACHIA OPERATIONS We own and manage six operating units and related facilities in West Virginia. During the nine months ended December 31, 2001, these operations sold approximately 13.5 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. 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. In August 2000, we closed the Robin Hood No. 9 Mine after depleting its mineable reserves and the White's Branch Mine began production. White's Branch's operations are currently suspended due to geologic problems. During the nine months ended December 31, 2001, the Big Mountain No. 16 and White's Branch mines sold approximately 1.8 million tons of steam coal. Big Mountain No. 16 is an underground mine using continuous mining equipment. Processed coal is loaded on the CSX railroad. Harris Operating Unit The Harris Operating Unit consists of the Harris No. 1 Mine near Bald Knob, West Virginia, which sold approximately 2.8 million tons of compliance coal during the nine months ended December 31, 2001. 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 Mine and contract mining companies from coal reserves that we control. This preparation plant shipped approximately 5.4 million tons of steam and metallurgical coal during the nine months ended December 31, 2001, including 2.8 million tons related to the Harris Operating Unit. 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 2.4 million tons of metallurgical and steam coal during the nine months ended December 31, 2001. The unit consists of the Lightfoot No. 2 Mine, contract mines and the Wells preparation plant, located near Wharton, West Virginia. The mine uses continuous mining equipment to produce coal from reserves we own. Processed coal is loaded on the CSX railroad. 7 Federal No. 2 Mine The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining equipment and shipped approximately 3.7 million tons of steam coal during the nine months ended December 31, 2001. 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 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, utilizes 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. It is anticipated that this mine will produce approximately one million tons in 2002. Kanawha Eagle Coal Joint Venture We have a minority interest in Kanawha Eagle Coal, LLC, which owns a deep mine, a preparation plant and barge-and-rail loading facilities near Marmet, West Virginia. The union-free mine uses continuous mining equipment and shipped 1.7 million tons during the nine months ended December 31, 2001. MIDWEST OPERATIONS We own and operate five mines in the midwestern United States, which collectively sold 5.7 million tons of coal during the nine months ended December 31, 2001. Our midwest operations include three underground and two surface mines, along with five preparation plants and four 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 we sell some coal to industrial customers that generate their own power. In addition to the five wholly-owned mines in our Midwest operating region, we control 16 additional mines in the midwestern United States through our 81.7% joint venture interest in Black Beauty, as discussed below. Black Beauty Coal Company We own 81.7% of Black Beauty, the largest coal company in the Illinois Basin, which controls nine mines in Indiana, five mines in Illinois and one mine in western Kentucky. Together, these operations sold 19.1 million tons of compliance, medium sulfur and high sulfur steam coal during the nine months ended December 31, 2001. We purchased a one-third interest in Black Beauty in 1994, and increased our interest to 43.3% in 1998 and 81.7% in 1999. Black Beauty Resources, Inc., owned by certain members of Black Beauty's management team, owns the remaining interest. Black Beauty's principal Indiana mines include Air Quality No. 1, Farmersburg, Francisco and two mines in Somerville, Indiana. Air Quality No. 1 is an underground coal mine located near Monroe City, Indiana that shipped 1.4 million tons of compliance coal during the nine months ended December 31, 2001. Farmersburg is a surface mine situated in Vigo and Sullivan counties in Indiana that sold 2.9 million tons of medium sulfur coal during the nine months ended December 31, 2001. Francisco, a surface mine located in Gibson county, Indiana, sold 2.0 million tons during the nine months ended December 31, 2001, and the two Somerville mines, also located in Gibson county, shipped a total of 5.0 million tons in fiscal year 2001. All of Black Beauty's mines utilize non-union labor. Black Beauty owns a 75% equity interest in Arclar Company, LLC (formerly Sugar Camp Coal, LLC), which operates a large surface and underground mining complex in Gallatin and Saline counties in southern Illinois. During the nine months ended December 31, 2001, these facilities sold 4.1 million tons of coal, primarily shipped by barge to downriver utility plants. Black Beauty provides a contract workforce for the Arclar surface mines; the workforce at the underground operations is provided by a separate contractor which employs miners represented under non-UMWA labor agreements. 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 Discovery mines and as contract operator for Black Beauty at the Evansville River Terminal. Kentucky United, LLC, a small coal producer with operations in Daviess County, Kentucky, is a wholly-owned subsidiary of United Minerals. During 2001, Black Beauty and Arclar each installed new underground mining facilities. Black Beauty's Vermilion Grove portal, in east-central Illinois, began operations early in the first quarter of 2002 and, together with the existing Riola #1 portal, is 8 expected to produce approximately 2.7 million tons of coal per year. Arclar's new Willow Lake portal also began operations during the first quarter of 2002. Willow Lake will replace Arclar's existing operations at Eagle Valley and Big Ridge, which will both then be idled. Camp Operating Unit The Camp Operating Unit, located near Morganfield, Kentucky, currently operates the Camp No. 11 Mine, an underground mine, and a large preparation plant and barge loading facility. The Camp No. 1 Mine exhausted its economically recoverable reserves and ceased operations in October 2000. Camp No. 11 Mine sold 2.5 million tons of coal during the nine months ended December 31, 2001. The Camp No. 11 Mine uses both longwall and continuous mining equipment. We sell most of the production under contract to the Tennessee Valley Authority. The Camp No. 11 Mine is expected to exhaust its economically recoverable reserves in the fourth quarter of 2002, and its production will be replaced by the Highland Operating Unit. Highland Operating Unit The Highland Operating Unit, located near Waverly, Kentucky, has two new underground mines under development. The Highland No. 11 Mine will operate in the No. 11 coal seam and Highland No. 9 Mine will operate in the No. 9 coal seam. We expect both mines to begin production in 2002 utilizing continuous mining equipment, and it is anticipated that these mines will produce up to 1.8 million tons of coal during 2002. Midwest Operating Unit The Midwest Operating Unit near Graham, Kentucky sold 1.3 million tons of coal during the nine months ended December 31, 2001. The unit currently includes the Gibraltar surface mining operation, which uses truck-and-shovel equipment, and the Gibraltar Highwall Mine, which uses continuous mining equipment. The unit used to include the Martwick mine; however in November 2000, the Martwick Mine exhausted its economically recoverable reserves and ceased operations, and the Gibraltar Highwall mine began operations to replace the production. We sell coal from these mines under contract to the Tennessee Valley Authority. On March 4, 2002, a WARN Act notice was sent advising that the Gibraltar Highwall Mine would be closed in the near future, as the mine is reaching the end of its economically recoverable reserves. Patriot Coal Company Patriot Coal Company operates Patriot, a surface mine, and Freedom, an underground mine, in Henderson County, Kentucky, and sold approximately 1.9 million tons of coal during the nine months ended December 31, 2001. The underground mine uses continuous mining equipment, and 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. LONG-TERM COAL SUPPLY AGREEMENTS We currently have coal supply agreements to sell nearly one billion tons of coal, with remaining terms ranging from one to 14 years and an average volume-weighted remaining term of approximately four years. For the nine months ended December 31, 2001, we sold 83% of our sales volume under coal supply agreements. During the nine months ended December 31, 2001, we sold coal to more than 250 electric generating and industrial plants in eleven countries. 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. During 2001, prices for coal increased from prior year levels, particularly in the Powder River Basin and in Appalachia, primarily due to increased prices for competing fuels and increased demand for electricity. Late in 2001, coal prices began to decline from the high levels experienced earlier in 2001, due to a softer economy and milder than normal winter weather. During calendar 2001, we signed contracts for nearly 200 million tons of new business at higher prices than those realized in 2001. As of December 31, 2001 we had sales commitments for approximately 93% of our calendar 2002 production which, as of March 1, 2002, increased to 97% as a result of reduced production estimates for calendar 2002. Long-term contracts may be particularly attractive in regions where market prices are expected to remain stable, particularly in cases such as high sulfur coal that would otherwise not be in great demand or for sales under cost-plus arrangements serving captive electric 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. 9 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 bidding and extensive negotiations with customers. Consequently, the terms of these contracts typically vary significantly in many respects, including price adjustment features, price reopener terms, coal quality requirements, quantity parameters, flexibility and adjustment mechanics, permitted sources of supply, treatment of environmental constraints, extension options and force majeure, termination and assignment provisions. Each contract sets a base price. Base prices are sometimes adjusted at quarterly or annual intervals for changes due to inflation and/or changes in actual costs such as taxes, fees and royalties. The inflation 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 Department of Commerce. Price adjustment provisions are present in most of our long-term coal contracts greater than three years in duration. These provisions allow either party to commence a renegotiation of the contract price at various intervals. If the parties do not agree on a new price, the purchaser or seller often has an option to terminate the contract. Some agreements provide that if the parties fail to agree on a price adjustment caused by cost increases due to changes in applicable law and regulations, the purchaser may terminate the agreement, subject to the payment of liquidated damages. 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. Coal supply agreements typically stipulate procedures for quality control, sampling and weighing. 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. 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. Contracts usually contain specified sampling locations: in the eastern United States, approximately 50% of customers require that the coal is sampled and weighed at the destination, whereas in the western United States, samples are usually taken at the shipping source. SALES AND MARKETING Our sales 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 third-party coal supply agreements by acquiring a customer's right to receive coal from another coal company under a coal supply agreement, reselling that coal, and supplying that customer with coal from our own operations. As of December 31, 2001, we had 62 employees in our sales, marketing and trading operations, including personnel dedicated to performing market research, contract administration and risk management activities. 10 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 Camp 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 electric generating plant. Other mines transport coal by rail and barge or by rail and lake carrier on the Great Lakes. All coal from our Powder River Basin mines is shipped by rail, and two competing railroads, the Burlington Northern & Santa Fe and the Union Pacific, serve our North Antelope/Rochelle and Caballo mines. The Rawhide Mine is serviced by the Burlington Northern & Santa Fe railroad. 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 also purchase coal from third parties to satisfy some of our customer contracts. The supplier base providing these goods has been relatively consistent in recent years and we have many long established relationships with our key suppliers. We do not believe that we are dependent on any of our individual suppliers. TECHNICAL INNOVATION We place great emphasis on the application of technical innovation to improve new and existing equipment's 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 is being upgraded with new motors and digital controllers that are expected to increase productivity by 10% to 15%. 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 electric generating plant using advanced emissions reduction technology funded primarily through the Department of Energy and operated by an affiliate of Southern Company. COMPETITION The markets in which we sell our coal are highly competitive. The top 10 coal producers in the United States produce approximately 64% of total domestic coal, although there are approximately 730 coal producers in the United States. Our principal competitors are other large coal producers, including Arch Coal, Inc., Kennecott Energy Co., a subsidiary of Rio Tinto, RAG AG, CONSOL Energy Inc., AEI Resources, Inc. and Massey Energy Company, which collectively accounted for approximately 41% of total U.S. coal production in 2000. 11 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. POWER PLANT DEVELOPMENT To best use our asset base and enhance long-term growth, we are also developing coal-fueled generating plants. We are currently engaged in permitting, engineering and economic analysis for the Thoroughbred Energy Campus. Thoroughbred represents a planned 1,500 megawatt electricity generating plant to be fueled by a 5 to 6 million ton-per-year coal mine on company-controlled property in Western Kentucky. Thoroughbred has received a draft air permit from Kentucky. The governor of Kentucky has issued an executive order which prohibits the issuance of any final power plant permits in the Commonwealth until July 16, 2002. We have also filed an air permit and transmission access documents for a sister project, the Prairie State Energy Campus. Prairie State is using the design, engineering and purchasing template from Thoroughbred to achieve economies of scale, and speed the plant development cycle. Prairie State would be built atop a six million ton-per-year coal mine planned on our property in Southwestern Illinois. Thoroughbred and Prairie State are modeled to be among the cleanest and lowest cost coal-fueled plants east of the Mississippi River. We plan to secure partners for the projects with complementary skills in generating plant construction, operation and power marketing. COALBED METHANE Our subsidiary, Peabody Natural Gas, LLC is evaluating the potential for coalbed methane development within our coal reserves. In addition, we purchased coalbed methane assets near our Caballo Mine in Wyoming in January 2001 for approximately $10 million. We are considering expansion of this business line through acquisitions and development of our own reserves. 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. We also record other related liabilities, such as water treatment and environmental costs. Our long-term reclamation costs, mine-closing and other related liabilities totaled approximately $444.5 million as of December 31, 2001, $5.9 million of which was a current liability. Expense for the nine months ended December 31, 2001 and the year ended March 31, 2001 was $9.6 million and $4.1 million, respectively. 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 $250.4 million as of December 31, 2001, $42.7 million of which was a current liability. Expense for the nine months ended December 31, 2001 and the year ended March 31, 2001 was $36.5 million and $41.4 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 current liabilities totaled approximately $16.1 million as of December 31, 2001. Retiree Health Care. Consistent with Statement of Financial Accounting Standards 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 provided 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 12 closed group of former employees who retired prior to 1976; no new retirees will be added to this group. The liability is subject to increases or decreases in per capita health care costs, offset by the mortality curve in this aging population of beneficiaries. Our retiree health care liabilities totaled approximately $1,032.5 million as of December 31, 2001, $70.4 million of which was a current liability. Expense for the nine months ended December 31, 2001 and the year ended March 31, 2001 was $49.8 million and $70.7 million, respectively. Obligations to the United Mine Workers of America Combined Fund totaled $57.1 million as of December 31, 2001, $7.4 million of which was a current liability. Expense for the nine months ended December 31, 2001 was $3.3 million. For the year ended March 31, 2001, income of $8.0 million was recorded, mainly due to the withdrawal by the Social Security Administration of certain beneficiaries previously assigned to us. DEREGULATION OF THE ELECTRICITY GENERATION INDUSTRY In October 1992, Congress enacted the Energy Policy Act of 1992. To stimulate competition in the electricity market, that legislation gave 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 concerning utility deregulation. Individual states are also proceeding with their own deregulation initiatives. The pace of deregulation differs significantly from state to state. To date, 16 states and Washington, D.C. have either enacted legislation leading to the deregulation of the electricity market or issued a regulatory order to implement retail access; seven states have either passed legislation or issued regulatory orders to delay implementing retail access; and 26 other states have not enacted legislation to restructure the electric power industry or implement retail access. In California, where market inefficiencies and supply and demand imbalances created electricity supply shortages, the California Public Utilities Commission has ordered suspension of retail access. If ultimately implemented, full-scale deregulation of the power industry is expected to enable both industrial and residential customers to shop for the lowest-cost supply of power and the best service available. This fundamental change in the power industry is expected to compel electricity generators to be more aggressive in developing and defending market share, to be more focused on their pricing and cost structures and to be more flexible in reacting to changes in the market. A possible consequence of deregulation is downward pressure on fuel prices. However, because of coal's cost advantage and because some coal-based 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-based power plants are operated at greater capacity. EMPLOYEES As of December 31, 2001, we and our subsidiaries had approximately 6,500 employees. Approximately 35% of our employees are affiliated with organized labor unions, which accounted for approximately 21% of sales volume during the nine months ended December 31, 2001. Relations with organized labor are important to our success and we believe our relations with 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 represented by the United Mine Workers of America and is subject to the National Bituminous Coal Wage Agreement. The current five-year labor agreement was ratified in December 2001 and is effective from January 1, 2002 through December 31, 2006. REGULATORY MATTERS Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been 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. 13 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. 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 significantly as will the amounts of those awards. The National Mining Association has filed a lawsuit challenging these regulations. The U.S. District Court of the District of Columbia upheld the regulations. The National Mining Association has filed an appeal with the U.S. Court of Appeals for the District of Columbia. 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 the Combined Fund. Annual payments made by certain of our subsidiaries under the Coal Act totaled $3.9 million and $4.1 million, respectively, during the nine months ended December 31, 2001 and year ended March 31, 2001. In October 1998, the Combined Fund sent a premium notice to all assigned operators subject to the fund that included retroactive death benefit and health benefit premiums dating back to February 1, 1993. On November 13, 1998, 10 employers, including two of our subsidiaries, Peabody Coal Company and Eastern Associated Coal Corp., challenged the fund's retroactive rebilling in a lawsuit filed in the Northern District Court of Alabama. The District Court ruled against us and the other employers and we and the employers filed an appeal with the U.S. Court of Appeals for the 11th Circuit. If we are successful in this litigation, we will be eligible for a $1.0 million credit as a reduction to future premiums. 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 calculation of the per-beneficiary premium 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. The Combined Fund has obtained an amended order and the intervenor coal companies have appealed the court's decision. If this decision is upheld on appeal and applied retroactively, our subsidiaries will be required to pay an additional premium to the Combined Fund of approximately $3.6 million. 14 Environmental Laws We are subject to various federal, state and foreign environmental laws. These laws, some of which are discussed below, place many requirements on our coal mining operations, and both federal and state inspectors regularly visit our mines and other facilities to ensure compliance. Surface Mining Control and Reclamation Act The Surface Mining Control and Reclamation Act, which is administered by the Office of Surface Mining Reclamation and Enforcement, establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. The Surface Mining Control and Reclamation Act and similar state statutes require, among other things, the restoration of mined property in accordance with specified standards and an approved reclamation plan. In addition, the Abandoned Mine Land Fund, which is part of the Surface Mining Control and Reclamation Act, imposes a fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. A mine operator must submit a bond or otherwise secure the performance of these reclamation obligations. Mine operators must receive permits and permit renewals for surface mining operations from the Office of Surface Mining Reclamation and Enforcement or, where state regulatory agencies have adopted federally approved state programs under the act, the appropriate state regulatory authority. We accrue for the liability associated with all end-of-mine reclamation on a ratable basis as the coal reserve is being mined. All states in which we have active mining operations have achieved primary control of enforcement through approved state programs. Although we do not anticipate significant permit issuance or renewal problems, we cannot assure you that our permits will be renewed or granted in the future or that permit issues will not adversely affect operations. Under previous regulations of the act, responsibility for any coal operator currently in violation of the act could be imputed to other companies deemed, according to regulations, to "own or control" the coal operator. Sanctions included being blocked from receiving new permits and rescission or suspension of existing permits. Because of federal court action invalidating these ownership and control regulations, the Office of Surface Mining Reclamation and Enforcement responded to the court action by promulgating interim regulations, which more narrowly apply the ownership and control standards to coal companies. West Virginia Mountaintop Mining On October 20, 1999, the U.S. District Court for the Southern District of West Virginia issued a permanent injunction against the West Virginia Department of Environmental Protection in a mountaintop-mining lawsuit. As interpreted by the Director of the Department of Environmental Protection, the injunction prohibits the Department from approving any new permits that would authorize the placement of excess soil in intermittent and perennial streams for the primary purpose of waste (overburden) disposal. The Department also interpreted the injunction to affect certain existing coal refuse ponds, sediment ponds and mountaintop-mining operations. The Department filed an appeal of the decision with the U.S. Court of Appeals for the Fourth Circuit. In April 2001, the Fourth Circuit overturned the District Court decision regarding the intermittent and perennial stream issue. The U.S. Supreme Court recently denied the petition for certiorari filed by certain environmental groups. We currently have no mountaintop mining operations or plans to develop mountaintop mining operations. The 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 ten micrometers in diameter or smaller. The Clean Air Act indirectly affects coal mining operations by extensively regulating the air emissions of sulfur dioxide and other compounds, including nitrogen oxides, emitted by coal-based 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 electric 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 15 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-based power plants. The affected electricity generators have been able to meet these requirements by, among other ways, switching to lower sulfur fuels, installing pollution control devices, such as flue gas desulfurization systems, which are known as "scrubbers," reducing electricity generating levels or purchasing sulfur dioxide emission allowances. Emission sources receive these sulfur dioxide emission allowances, which can be traded or sold to allow other units to emit higher levels of sulfur dioxide. We cannot ascertain 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-based electric 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 recently announced the final rules that would require 19 eastern states and Washington, D.C. to make substantial reductions in nitrogen oxide emissions. Installation of additional control measures required under the final rules will make it more costly to operate coal-based electric generating plants. In accordance with Section 126 of the Clean Air Act, eight northeastern states filed petitions requesting the EPA to make findings and require decreases in nitrogen oxide emissions from certain sources in certain upwind states that might contribute to ozone nonattainment in the petitioning states. The EPA has granted four of the eight petitions finding that certain sources are contributing to ozone non-attainment in certain of the petitioning states and the EPA has proposed levels of nitrogen oxide control for the named sources. Our customers are among the named sources and, implementation of the requirement to install control equipment could impact the amount of coal supplied to those customers if they decide to switch to other sources of fuel, which would result in lower emission of nitrogen oxides. 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. The Justice Department on behalf of the EPA filed a number of lawsuits since November 1999, alleging that ten electricity generators violated the new source review provisions of the Clean Air Act Amendments at power plants in the midwestern and southern United States. The EPA issued an administrative order alleging similar violations by the Tennessee Valley Authority, affecting seven plants and notices of violation for an additional eight plants owned by the affected electricity generators. Four electricity generators have announced settlements with the Justice Department requiring the installation of 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, 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. 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. Visibility in these areas is to be returned to natural conditions by 2064 through plans that must be developed by the states. 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 oxides and nitrogen oxides. The Clean Air Act Amendments require a study of electric 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 electric power generators. In February 2002, the President proposed to cut electric 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 is expected to be translated into a legislative proposal. In addition, similar emission reduction proposals have been 16 introduced in the current session of 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 oxides, nitrogen oxides, mercury and carbon dioxide. Clean Water Act The Clean Water Act of 1972 affects coal mining operations by imposing restrictions on effluent discharge into water. Regular monitoring, reporting requirements and performance standards are preconditions for the issuance and renewal of permits governing the discharge of pollutants into water. Resource Conservation and Recovery Act The Resource Conservation and Recovery Act (RCRA), which was enacted in 1976, affects coal mining operations by imposing requirements for the treatment, storage and disposal of hazardous wastes. Coal mining operations covered by the Surface Mining Control and Reclamation Act permits are exempted from regulation under RCRA by statute. We cannot, however, predict whether this exclusion will continue. Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the Environmental Protection Agency (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 large volume 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 minefill. The agency also concluded beneficial uses of these wastes, other than for minefilling, 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 electric 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 liability may be imposed on waste generators, site owners and 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 2000, 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 electric generators switch to lower carbon sources of fuel. In March 2001, President Bush reiterated his opposition to the Kyoto Protocol and further stated that he did not believe that the government should impose mandatory carbon dioxide emission reductions on power plants. In February 2002, President Bush announced a new approach to climate change, confirming the Administration's opposition to the Kyoto Protocol and proposing voluntary actions to reduce the greenhouse gas intensity of the United States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The President's climate change initiative calls for a reduction in greenhouse gas intensity over the next ten 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 17 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. ADDITIONAL INFORMATION We file annual, quarterly and current reports, proxy statements and other information with the 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. 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. 18 ITEM 2. PROPERTIES. Coal Reserves We had an estimated 9.1 billion tons of proven and probable coal reserves as of December 31, 2001, of which approximately 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 units.
PROVEN AND PROBABLE RESERVES AS OF DECEMBER 31, 2001(1) ---------------------------- OWNED LEASED TOTAL OPERATING REGIONS LOCATIONS TONS TONS TONS ----------------- --------- ------- ------- ----- (Tons in millions) Powder River Basin Wyoming and Montana................................................... 190 2,868 3,058 Southwest Arizona, Colorado and New Mexico...................................... 718 584 1,302 Appalachia West Virginia......................................................... 256 447 703 Midwest Illinois, Indiana and Kentucky........................................ 2,993 1,056 4,049 ----- ----- ----- Total...................................................................................... 4,157 4,955 9,112 ===== ===== =====
---------- (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, areal 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 19 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 production through December 31, 2001, proven and probable reserves totaled 9.1 billion tons. We have numerous federal coal leases that are administered by the 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 $3.08 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, 2001, we leased or had applied to lease 26,249 acres of federal land in Colorado, 10,322 acres in Montana and 30,225 acres in Wyoming, for a total of 66,796 nationwide. Similar provisions govern three coal leases with the Navajo and Hopi Indian tribes. These leases cover coal contained in 65,000 acres of land in northern Arizona lying within the boundaries of the Navajo Nation and Hopi Indian reservations. We also lease coal-mining properties from various state governments. Private coal leases normally have terms of between ten 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. 20 The following chart provides a summary, by mining complex, of production for fiscal years ended March 31, 2000 and 2001 and the nine months ended December 31, 2001, tonnage of coal reserves that is assigned to our operating mines, our property interest in those reserves and other characteristics of the facilities. PRODUCTION AND ASSIGNED RESERVES (1) (Tons in millions)
Sulfur Content (2) Production --------------------------------- ---------------------------------------- less than more than Nine Months Year Year 1.2 lbs. 1.2 to 2.5 lbs. Ended Ended Ended sulfur dioxide sulfur dioxide Dec. 31, March 31, March 31, Type of per per Mining Complex 2001 2001 2000 Coal Million Btu Million Btu ------------------------------------------------------------------------------------------------------------------------------------ Northern Appalachia: Federal No. 2 3.6 4.7 4.2 Steam - - ---------------------------------------- --------------------------------- Northern Appalachia 3.6 4.7 4.2 - - Southern Appalachia: Big Mountain/White's Branch 1.6 2.0 2.1 Steam 4.7 16.6 Harris #1 2.7 3.9 3.2 Steam/Metallurgical 0.4 11.5 Rocklick 2.5 3.2 3.3 Steam/Metallurgical 31.3 11.2 Wells 1.2 1.6 2.0 Steam/Metallurgical 8.9 2.4 ---------------------------------------- --------------------------------- Southern Appalachia 7.9 10.7 10.5 45.3 41.7 Midwest: Camps (4) 2.4 5.4 6.4 Steam - - Hawthorn (5) - - 2.1 Steam - - Lynnville (6) - - 2.2 Steam - - Marissa (7) - - 2.3 Steam - - Midwest 1.3 1.2 1.2 Steam - - Patriot 1.8 2.0 1.9 Steam - - Black Beauty Air Quality No. 1 1.4 1.7 1.8 Steam 54.9 - Riola No 1 (8) 0.8 1.0 0.4 Steam - - Miller Creek / Sugar Ridge (9) 0.8 0.1 - Steam - - Francisco 2.0 2.2 2.8 Steam - - Columbia 0.5 0.8 0.7 Steam - - Discovery (10) 0.8 0.3 0.6 Steam - - Farmersburg 2.9 4.1 3.5 Steam - 26.8 Birdwell - 0.9 1.4 Steam - - Somerville Central (11) 2.4 2.0 - Steam - - Somerville North / West 2.3 2.8 2.0 Steam - - Viking / Corning 1.1 1.0 1.3 Steam - 2.3 Sugar Camp Coal 4.1 5.0 5.6 Steam - - West Fork (12) - 0.2 0.5 Steam - - Deanefield 0.1 0.8 0.4 Steam - - ---------------------------------------- --------------------------------- Midwest 24.7 31.5 37.0 54.9 29.1 Powder River Basin: Big Sky 2.0 1.7 2.4 Steam - 24.5 North Antelope/Rochelle 56.3 72.3 68.3 Steam 1,360.3 - Caballo 20.7 25.6 26.1 Steam 801.2 31.5 ---------------------------------------- --------------------------------- Powder River Basin 79.0 99.6 96.9 2,161.5 56.0 Southwest: Black Mesa 3.4 4.9 4.5 Steam 79.0 11.8 Kayenta 6.2 8.5 7.6 Steam 235.1 85.6 Lee Ranch 4.7 5.2 4.9 Steam - 161.8 Seneca 1.3 1.5 1.4 Steam 13.3 0.1 ---------------------------------------- --------------------------------- Southwest 15.6 20.1 18.5 327.4 259.3 ---------------------------------------- --------------------------------- Total 130.9 166.6 167.1 2,589.1 386.1 ======================================== =================================
Sulfur Content (2) ------------------ more than As As of December 31, 2001 2.5 lbs. Received -------------------------------------------------------------- sulfur dioxide Btu Assigned per per Proven and Under- Mining Complex Million Btu Pound (3) Probable Reserves Owned Leased Surface ground ------------------------------------------------------------------------------------------------------------------------------------ Northern Appalachia: Federal No. 2 41.4 13,335 41.4 41.4 - - 41.4 ----------- -------------------------------------------------------------- Northern Appalachia 41.4 41.4 41.4 - - 41.4 Southern Appalachia: Big Mountain/White's Branch - 12,538 21.3 - 21.3 - 21.3 Harris #1 - 13,473 11.9 - 11.9 - 11.9 Rocklick - 13,067 42.5 - 42.5 24.6 17.9 Wells - 13,692 11.3 - 11.3 - 11.3 ----------- -------------------------------------------------------------- Southern Appalachia - 87.0 - 87.0 24.6 62.4 Midwest: - Camps (4) 117.9 11,242 117.9 3.6 114.3 - 117.9 Hawthorn (5) - N/A N/A - - - - Lynnville (6) - N/A N/A - - - - Marissa (7) - N/A N/A - - - - Midwest 9.0 10,596 9.0 6.9 2.1 6.9 2.1 Patriot 53.6 10,922 53.6 0.2 53.4 5.8 47.8 Black Beauty Air Quality No. 1 - 11,040 54.9 0.5 54.4 - 54.9 Riola No 1 (8) 10.7 10,683 10.7 - 10.7 - 10.7 Miller Creek / Sugar Ridge (9) 2.2 11,504 2.2 0.7 1.5 2.2 - Francisco 14.7 11,187 14.7 3.6 11.1 14.7 - Columbia 0.3 11,502 0.3 - 0.3 0.3 - Discovery (10) 0.8 10,583 0.8 - 0.8 - 0.8 Farmersburg - 10,871 26.8 19.2 7.6 26.8 - Birdwell - N/A N/A - - - - Somerville Central (11) 16.7 11,066 16.7 12.4 4.3 16.7 - Somerville North / W est 12.7 11,038 12.7 10.0 2.7 12.7 - Viking / Corning 11.7 11,697 14.0 - 14.0 14.0 - Sugar Camp Coal 86.2 12,029 86.2 27.2 59.0 7.6 78.6 West Fork (12) - N/A N/A - - - - Deanefield 0.1 10,716 0.1 - 0.1 0.1 - ----------- -------------------------------------------------------------- Midwest 336.6 420.6 84.3 336.3 107.8 312.8 Powder River Basin: Big Sky 16.8 8,658 41.3 - 41.3 41.3 - North Antelope/Rochelle - 8,756 1,360.3 - 1,360.3 1,360.3 - Caballo 0.7 8,692 833.4 - 833.4 833.4 - ----------- -------------------------------------------------------------- Powder River Basin 17.5 2,235.0 - 2,235.0 2,235.0 - Southwest: Black Mesa - 10,792 90.8 - 90.8 90.8 - Kayenta 5.1 10,948 325.8 - 325.8 325.8 - Lee Ranch 8.7 10,054 170.5 165.1 5.4 170.5 - Seneca 0.6 10,426 14.0 1.1 12.9 14.0 - ----------- -------------------------------------------------------------- Southwest 14.4 601.1 166.2 434.9 601.1 - ----------- -------------------------------------------------------------- Total 409.9 3,385.1 291.9 3,093.2 2,968.5 416.6 =========== ==============================================================
21 The following chart provides a summary of the amount of our proven and probable coal reserves in each state, the predominant type of coal mined in the applicable state, our property interest in the reserves and other characteristics of the facilities. ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES(1) AS OF DECEMBER 31, 2001 (Tons in millions)
Total Tons Proven and ----------------------------- Probable Type of Location Assigned Unassigned Reserves Proven Probable Coal ------------------------------------------------------------------------------------------------------------------------------- Northern Appalachia: Ohio - 40.4 40.4 28.1 12.3 Steam West Virginia 41.4 219.2 260.6 94.5 166.1 Steam -------------------------------------------------------------- Northern Appalachia 41.4 259.6 301.0 122.6 178.4 Southern Appalachia: Steam/ West Virginia 87.0 314.9 401.9 279.5 122.4 Metallurgical -------------------------------------------------------------- Southern Appalachia 87.0 314.9 401.9 279.5 122.4 Midwest: Illinois - 2,233.9 2,233.9 1,039.7 1,194.2 Steam Indiana - 324.7 324.7 208.2 116.5 Steam Kentucky 180.5 879.0 1,059.5 633.5 426.0 Steam Black Beauty 240.1 177.2 417.3 384.6 32.7 Steam (Illinois, Indiana, Kentucky ) Missouri - 11.8 11.8 10.7 1.1 Steam Oklahoma - 1.4 1.4 1.4 - Steam -------------------------------------------------------------- Midwest 420.6 3,628.0 4,048.6 2,278.1 1,770.5 Powder River Basin: Montana 41.3 301.3 342.6 314.3 28.3 Steam Wyoming 2,193.7 521.4 2,715.1 2,604.9 110.2 Steam -------------------------------------------------------------- Powder River Basin 2,235.0 822.7 3,057.7 2,919.2 138.5 Southwest: Arizona 416.6 - 416.6 416.6 - Steam Colorado 14.0 152.9 166.9 136.5 30.4 Steam New Mexico 170.5 544.7 715.2 358.0 357.2 Steam Utah - 3.6 3.6 - 3.6 Steam -------------------------------------------------------------- Southwest 601.1 701.2 1,302.3 911.1 391.2 -------------------------------------------------------------- Total Proven and Probable 3,385.1 5,726.4 9,111.5 6,510.5 2,601.0 ==============================================================
Sulfur Content (2) ------------------------------------------------------------------- less than more than more than 1.2 lbs. 1.2 to 2.5 lbs 2.5 lbs. As sulfur dioxide sulfur dioxide sulfur dioxide Received per per per Btu Location Million Btu Million Btu Million Btu per pound (13) --------------------------------------------------------------------------------------------------------------- Northern Appalachia: Ohio - - 40.4 11,255 West Virginia - 116.6 144.0 12,723 --------------------------------------------- Northern Appalachia - 116.6 184.4 Southern Appalachia: West Virginia 216.9 149.7 35.3 13,202 --------------------------------------------- Southern Appalachia 216.9 149.7 35.3 Midwest: Illinois 4.9 65.9 2,163.1 10,290 Indiana 0.1 2.9 321.7 10,533 Kentucky 0.2 0.3 1,059.0 10,939 Black Beauty 54.9 30.4 332.0 11,414 (Illinois, Indiana, Kentucky ) Missouri - - 11.8 10,036 Oklahoma - - 1.4 N/A --------------------------------------------- Midwest 60.1 99.5 3,889.0 Powder River Basin: Montana 42.1 138.7 161.8 8,594 Wyoming 2,541.1 140.6 33.4 8,690 --------------------------------------------- Powder River Basin 2,583.2 279.3 195.2 Southwest: Arizona 314.1 97.5 5.0 10,914 Colorado 64.6 101.7 0.6 10,763 New Mexico 243.7 434.7 36.8 9,235 Utah 3.6 - - 10,444 --------------------------------------------- Southwest 626.0 633.9 42.4 --------------------------------------------- Total Proven and Probable 3,486.2 1,279.0 4,346.3 =============================================
Reserve Control Mining Method ----------------------------------------------- Location Owned Leased Surface Underground ------------------------------------------------------------------------------------------- Northern Appalachia: Ohio 39.7 0.7 - 40.4 West Virginia 205.1 55.5 - 260.6 ---------------------------------------------- Northern Appalachia 244.8 56.2 - 301.0 Southern Appalachia: West Virginia 11.6 390.3 43.0 358.9 ---------------------------------------------- Southern Appalachia 11.6 390.3 43.0 358.9 Midwest: Illinois 2,163.8 70.1 49.9 2,184.0 Indiana 271.8 52.9 92.6 232.1 Kentucky 397.9 661.6 121.8 937.7 Black Beauty 157.2 260.1 113.2 304.1 (Illinois, Indiana, Kentucky ) Missouri 1.1 10.7 11.8 - Oklahoma 1.4 - - 1.4 ---------------------------------------------- Midwest 2,993.2 1,055.4 389.3 3,659.3 Powder River Basin: Montana 189.2 153.4 342.6 - Wyoming 1.0 2,714.1 2,715.1 - ---------------------------------------------- Powder River Basin 190.2 2,867.5 3,057.7 - Southwest: Arizona - 416.6 416.6 - Colorado 4.6 162.3 14.6 152.3 New Mexico 709.8 5.4 682.9 32.3 Utah 3.6 - - 3.6 ---------------------------------------------- Southwest 718.0 584.3 1,114.1 188.2 ---------------------------------------------- Total Proven and Probable 4,157.8 4,953.7 4,604.1 4,507.4 ==============================================
22 -------------- (1) Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of December 31, 2001. Unassigned reserves represent coal at suspended locations and coal that has not been committed, and that would require new mine development, mining equipment or plant facilities before operations could begin on the property. (2) Compliance coal is defined by Phase II of the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less per million Btu. Non-compliance coal is defined as coal having sulfur dioxide content in excess of this standard. Electricity generators are able to use coal that exceeds these specifications by using emissions reduction technology, using emissions allowance credits or blending higher sulfur coal with lower sulfur coal. (3) As-received Btu per pound includes the weight of moisture in the coal on an as-sold basis. (4) The Camp No. 1 mine at the Camp operating unit was closed in October 2000. (5) Production at the Hawthorn mine has been suspended since December 1999. (6) Production at the Lynnville mine has been suspended since December 1999. (7) The Marissa mine was closed in October 1999. (8) The Riola No. 1 mine was acquired in October 1999. (9) The Sugar Ridge mine opened in December 2000. (10) The Discovery mine was temporarily idled from April 2000 to July 2000. (11) The Somerville Central mine opened in March 2000. (12) The West Fork mine closed in August 2000. (13) As-received Btu per pound includes the weight of moisture in the coal on an as sold basis. The following table reflects the average moisture content used in the determination of as-received Btu for the region: Northern Appalachia.......................................................................... 6.0% Southern Appalachia.......................................................................... 7.0% Midwest: Illinois................................................................................ 14.0% Indiana................................................................................. 15.0% Kentucky................................................................................ 12.5% Black Beauty Coal Company............................................................... 14.5% Missouri/Oklahoma....................................................................... 12.0% Powder River Basin: Montana................................................................................. 26.5% Wyoming................................................................................. 27.5% Southwest: Arizona................................................................................. 13.0% Colorado................................................................................ 14.0% New Mexico.............................................................................. 15.5% Utah.................................................................................... 15.5%
23 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. The Resource Development group is also pursuing opportunities in the area of coalbed methane extraction in the United States through a subsidiary, Peabody Natural Gas, LLC. In January 2001, we purchased the coalbed methane assets of JN Exploration & Production Limited Partnership for approximately $10 million. ITEM 3. LEGAL PROCEEDINGS. From time to time, we are involved in legal proceedings arising in the ordinary course of business. We believe we have recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on our financial condition 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 ("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%. All defendants have filed motions to dismiss the complaint. On March 15, 2001, the court denied the Peabody defendants' motions to dismiss. Discovery for this litigation has commenced. In March 2000, the Hopi Tribe filed a motion to intervene in this lawsuit. The Hopi Tribe has alleged seven claims, including fraud. The Hopi Tribe is seeking various remedies, including unspecified actual and punitive damages, and reformation of its coal lease. On March 15, 2001, the court granted the Hopi Tribe's motion. On April 17, 2001, we filed a motion to dismiss the Hopi complaint. On October 31, 2001, the court denied our motion to dismiss the Hopi complaint. 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. The complaint was filed under seal because it describes material that is the subject of an arbitration confidentiality agreement. 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. Our subsidiaries sought leave to file the counterclaim under seal because it describes material that is the subject of the same arbitration confidentiality agreement. 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. 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. Salt River Project Agricultural Improvement and Power District--Price Review 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 panel has been selected and the hearing is scheduled to start on April 8, 2002. 24 On February 12, 2001 in a related action, Salt River, again acting for all owners of the Navajo Generating Station, filed a lawsuit against Peabody Western in the Superior Court in Maricopa County in Arizona. This lawsuit seeks to compel arbitration of issues that Peabody Western does not believe are subject to arbitration, namely, (1) the effective date of any price change resulting from the resolution of the price review arbitration discussed above and (2) the validity of Salt River's $50.5 million claim for alleged overcharges by Peabody Western for the period from 1992 through 1996 (the five-year period that was the subject of the price review). If the court declines to compel arbitration of these issues, the lawsuit alternatively requests that the court find in favor of Salt River on these issues. We have removed this matter to the U.S. District Court for the District of Arizona. On October 3, 2001, the U.S. District Court issued an order compelling arbitration with respect to the effective date of any price change and conditionally compelling arbitration with respect to the validity of Salt River's $50.5 million claim. We have filed an appeal of this decision with the U.S. Ninth Circuit Court of Appeals. While the outcome of arbitration and litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe that the matter will be resolved without a material adverse effect on our financial condition or results of operations. 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. Peabody Western appealed and the Arizona Court of Appeals affirmed the trial court's order. Peabody Western filed a petition for review with the Arizona Supreme Court. That petition was denied on September 24, 1998. 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. Southern California Edison Company In response to a demand for arbitration by one of our subsidiaries, Peabody Western, Southern California Edison 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. The contract expires in 2005. Peabody Western filed a motion to compel arbitration which 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, where a trial has been set for May 20, 2002. 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. The court denied Peabody Western's supplemental motion for summary judgment in an order filed on February 6, 2002. While the outcome of litigation 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 25 adverse effect on our financial condition or results of operations. We had a receivable on our balance sheet at December 31, 2001 for the mine closing costs associated with the Salt River and Southern California Edison matters of $83.8 million. Social Security Administration In 1999, Eastern Associated Coal Corp. and Peabody Coal Company filed a lawsuit in the U.S. District Court for the Western District of Kentucky against the Social Security Administration asserting that the Social Security Administration, under the Coal Act, had improperly assigned certain beneficiaries to us. Subsequently, Peabody Coal and Eastern Associated moved for summary judgment on this claim. Summary judgment was granted and in 2000, the Social Security Administration filed an appeal of the district court's decision with the U.S. Court of Appeals for the Sixth Circuit. On June 21, 2001, the Sixth Circuit Court denied the Social Security Administration's appeal. The U.S. Supreme Court granted the federal government's petition for certiorari in January 2002 and the case will be argued in the term commencing October 2002. We believe that the matter will be resolved without a material adverse effect on our financial condition or results of operations. 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 $8.35 per ton offer submitted by our subsidiaries. Our subsidiaries are seeking specific performance of the agreement, injunctive relief, declaratory judgment, 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. We have filed an appeal of that ruling. Since the court did not grant our motion for a preliminary injunction, we are not 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. Department of Justice During 2001, along with other coal producers in the Powder River Basin in Wyoming, we received a request for information from the U.S. Department of Justice regarding an alleged agreement to restrict production of coal from this region. We have responded to that request. Environmental Federal and State Superfund Statutes. Superfund and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under that legislation and many state Superfund statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. Our subsidiary, Gold Fields Mining Corporation ("Gold Fields"), 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 is currently involved in environmental investigation, litigation or remediation at ten sites. These ten sites were formerly owned or operated by Gold Fields. The Environmental Protection Agency has placed four 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. 26 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 2000. We have accrued liabilities of $46.6 million as of December 31, 2001 for the environmental liabilities described above relating to Gold Fields that are included as part of accrued reclamation and other environmental 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. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. No matters were submitted to a vote of security holders during the quarter ended December 31, 2001. ITEM 4A. EXECUTIVE OFFICERS OF THE COMPANY Set forth below are the names, ages as of March 15, 2002 and current positions of our executive officers. Executive officers are appointed by, and hold office at, the discretion of the Company's Board of Directors.
NAME AGE POSITION ---- --- -------- Irl F. Engelhardt 55 Chairman, Chief Executive Officer and Director Richard M. Whiting 47 President, Chief Operating Officer and Director Roger B. Walcott, Jr. 45 Executive Vice President-Corporate Development Richard A. Navarre 41 Executive Vice President and Chief Financial Officer Fredrick D. Palmer 57 Executive Vice President-Legal and External Affairs and Secretary Paul H. Vining 47 Executive Vice President-Sales and Trading Jeffery L. Klinger 55 Vice President-Legal Services and Assistant Secretary Sharon D. Fiehler 45 Vice President-Human Resources
Irl F. Engelhardt has been a director of the Company since 1998. He is Chairman and Chief Executive Officer of the Company, a position he has held since 1998. He served as Chief Executive Officer of a predecessor of the Company from 1990 to 1998. He also served as Chairman of a predecessor of the Company from 1993 to 1998 and as President from 1990 to 1995. Since joining a predecessor of the Company in 1979, he has held various officer level positions in the executive, sales, business development and administrative areas, including serving as Chairman of Peabody Resources Ltd. (Australia) and Chairman of Citizens Power LLC. Mr. Engelhardt also served as Co-Chief Executive Officer and executive director of The Energy Group from February 1997 to May 1998, Chairman of Cornerstone Construction & Materials, Inc. from September 1994 to May 1995 and Chairman of Suburban Propane Company from May 1995 to February 1996. He also served as a director and Group Vice President of Hanson Industries from 1995 to 1996. Mr. Engelhardt is Co-Chairman of the Coal Utilization Research Council, Co-Chairman of the Coal Based Generators Stakeholders Group and past 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. Whiting has been a director of the Company since 1998. He is also President and Chief Operating Officer of the Company, a position he has held since 1998. Previously, Mr. Whiting served as President of Peabody COALSALES Company from 1992 to 1998. He joined a predecessor of the Company in 1976 and has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. Mr. Whiting is currently Chairman of the Bituminous Coal Operators' Association, Chairman of the National Mining Association's Safety and Health Committee and a member of the National Coal Council. 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 1981 to 1998, he was a Senior Vice President and a 27 director with The Boston Consulting Group where he served a variety of clients in strategy and operational assignments. He was also Chairman of The Boston Consulting Group's Human Resource Capabilities Committee. Mr. Walcott holds an MBA with high distinction from the Harvard Business School. Richard A. Navarre became 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. Prior to that, 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 is a member of the Trade and International Affairs Committee and the Transportation Committee of the National Mining Association. He is also a member of the NYMEX Coal Advisory Council. He also serves on the Board of Advisors to the College of Business for Southern Illinois University. Fredrick D. Palmer became Executive Vice President-Legal and External Affairs of our company in February 2001. He is responsible for our legal affairs, state and federal government affairs, public relations and investor relations. Prior to joining Peabody, he served for 15 years as chief executive officer of Western Fuels Association, Inc. He most recently was of counsel in the Washington, D.C. office of Shook Hardy & Bacon, a Kansas City-based law firm. He received a BA and a JD from the University of Arizona. Paul H. Vining became Executive Vice President-Sales and Trading of our company in February 2001. Prior to that, he was President of Peabody COALSALES Company from October 1999 to January 2001, and President of Peabody COALTRADE, Inc. from March 1997 to October 1999, and Senior Vice President of Peabody COALSALES Company from August 1995 to February 1997. Mr. Vining is a member of the board of directors of the Coal Exporters Association. Jeffery L. Klinger was 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. Fiehler has been Vice President of Human Resources of our company since 1991, with executive responsibility for employee development, benefits, compensation, employee relations and affirmative action programs. She joined Peabody in 1981 as Manager-Salary Administration and has held a series of employee relations, compensation and salaried benefits positions. Prior to joining Peabody, Ms. Fiehler, who earned degrees in social work and psychology and an MBA, was a personnel representative for Ford Motor Company. Ms. Fiehler is a member of the National Mining Association's Human Resource Committee. 28 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. In May 2001 we completed an initial public offering of our common stock and sold 17.25 million shares to the public at an offering price of $28 per share. Our net proceeds from the offering totaled $449.8 million. Our common stock is listed on the New York Stock Exchange, under the symbol "BTU." The table below sets forth the range of quarterly high and low sales prices for our common stock on the New York Stock Exchange during the calendar quarters indicated.
2001 HIGH LOW ---- --- Second Quarter (from May 22, 2001) $38.05 $26.00 Third Quarter 32.00 22.20 Fourth Quarter 31.90 23.35
After completion of the offering, our authorized capital stock consisted of (1) 150.0 million shares of common stock, par value $0.01 per share, of which 52.0 million shares of common stock are issued and outstanding, (2) 10.0 million shares of preferred stock, par value $.01 per share, of which no shares are issued and outstanding and (3) 40.0 million shares of series common stock, par value $.01 per share, of which no shares are issued and outstanding. As of February 15, 2002, there were approximately 243 holders of our common stock. Dividend Policy We paid dividends of $0.20 per share during the nine months ended December 31, 2001. The declaration and payment of dividends and the amount of dividends will depend on our results of operations, financial condition, cash requirements, future prospects, any limitations imposed by our debt instruments and other factors deemed relevant by our board of directors. Our Senior Credit Facility, as amended, allows us to pay annual dividends of up to the greater of $25.0 million or 10% of consolidated EBITDA as defined in the facility. The indentures governing our Senior Notes and Senior Subordinated Notes 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. However, the actual amount of any dividends will be determined by our board of directors. Recent Sales of Unregistered Securities We sold shares of and issued options for common stock and preferred stock in the amounts, at the times, and for the aggregate amounts of consideration listed below without registration under the Securities Act of 1933. Exemption from registration under the Securities Act for each of the following sales is claimed under Section 4(2) of the Securities Act because each of the transactions were by the issuer and did not involve a public offering: On March 31, 1999, we issued 72,164 shares of common stock to one of our executives and 144,334 shares of common stock to eight executives of our Citizens Power subsidiary in consideration for their services. Additionally, we issued 826,986 options to purchase common stock at an exercise price of $14.29 per share to our executives and other employees. On July 1, 1999, we issued 52,675 options to purchase common stock at an exercise price of $14.29 per share to our employees. On January 1, 2000, we issued 6,300 shares of common stock to two executives of our Citizens Power subsidiary in consideration for their services. Additionally, we issued 320,461 options to purchase common stock at an exercise price of $14.29 per share to our executives and to other employees. On July 1, 2000, we issued 42,087 shares of common stock to three executives in consideration for their services.(1) Additionally, we issued 398,929 options to purchase common stock at an exercise price of $14.29 per share to our executives and other employees. On October 1, 2000, we issued 49,350 shares of common stock at an exercise price of $14.29 per share to our executives. On December 29, 2000, we issued 83,255 shares of common stock to nine executives in consideration for their services in exchange for other shares previously issued to them. On January 1, 2001, we issued 945,263 options to purchase common stock at an exercise price of $14.29 per share to executives and to other employees. On February 1, 2001, we issued 205,304 shares of common stock for an aggregate consideration of $1,096,912 to 20 of our executives. On February 12, 2001, we issued 63,000 options to purchase common stock at an exercise price of $14.29 per share to one of our executives. On April 9, 2001, we issued 11,466 shares of common stock for an aggregate consideration of $61,261 to one of our executives. -------- Notes: (1) These shares had been acquired by us from terminated employees. Use of Proceeds In connection with our initial public offering, the Securities and Exchange Commission declared our Registration Statement on Form S-1 (File No. 333-55412) relating to our common stock, $0.01 par value per share, effective on May 21, 2001. Lehman Brothers, Bear, Stearns & Co. Inc., Merrill Lynch & Co., Morgan Stanley Dean Witter, UBS Warburg and A.G. Edwards & Sons, Inc. acted as representatives of the underwriters for our initial public offering. We completed the sale of all 17,250,000 shares of common stock registered under the offering on May 22, 2001 and raised net proceeds of $449.8 million after deducting total expenses of $33.2 million, comprised of the underwriters' discounts and commissions of $27.2 million and other fees and expenses of $6.0 million. We did not make any direct or indirect payments to any of our directors, officers or their associates under the offering; however, usual and customary underwriting discounts and commissions were paid to Lehman Brothers Inc. and Lehman Brothers International (Europe), each an affiliate of Lehman Brothers Merchant Banking which beneficially owns 57% of our common stock. We used the net proceeds from the offering to repay the remaining tranche B term loan outstanding under the Senior Credit Facility of $125.0 million and used $100.0 million to repay borrowings under our revolving credit facility that were used to repay a portion of our 5% subordinated note. We also used $173.0 million of net proceeds to repurchase $80.0 million in principal amount of our Senior Notes and $80.0 million in principal amount of our Senior Subordinated Notes pursuant to a tender offer. In addition, we used $3.1 million and $12.7 million of proceeds to repurchase $2.9 million in principal amount of our Senior Notes and $11.7 million in principal amount of our Senior Subordinated Notes, respectively, in a private transaction. The remaining net proceeds were used for the repayment of debt and for general corporate purposes. Except as described above, none of the net proceeds from our initial public offering was used to make direct or indirect payments to (1) any of our directors, officers or their associates, (2) any person owning 10% or more of our equity securities, (3) any of our affiliates or (4) any others. ITEM 6. SELECTED FINANCIAL DATA. The following table presents selected financial and other data about us and our predecessor. We purchased our operating subsidiaries on May 19, 1998, and prior to that date we had no substantial operations. The period ended March 31, 1999 is thus a full fiscal year, but includes results of operations only from May 20, 1998. For periods prior to May 19, 1998, the results of operations are for the operating subsidiaries acquired, which we refer to as our "predecessor company" and which we include for comparative purposes. In early 1999, we increased our equity interest in Black Beauty Coal Company 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 consolidated statements of operations, and our interest in Black Beauty's net assets within "Investments and other assets" in the consolidated 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. On May 22, 2001, concurrent with our initial public offering, we converted our Class A common stock and Class B common stock into a single class of common stock, all on a one-for-one basis. We have derived the selected historical financial data for our predecessor for the year ended and as of March 31, 1998 and 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 and the nine months ended and as of December 31, 2001 from our predecessor company's and our audited financial statements. You should read the following table in conjunction with the financial statements, the related notes to those financial statements, and "Management's Discussion and Analysis of Financial Condition and Results of Operations." 29 (Dollars in thousands, except share data)
Nine Months Period From Ended Year Ended Year Ended May 20, 1998 December 31, March 31, March 31, Total Fiscal to 2001 2001 (1) 2000 (2) 1999 (3) March 31, 1999 ------------ ----------- ------------ ------------- --------------- RESULTS OF OPERATIONS DATA Revenues Sales $ 1,963,273 $ 2,579,104 $ 2,610,991 $ 2,249,887 $ 1,970,957 Other revenues 63,497 90,588 99,509 97,603 85,875 ----------- ----------- ----------- ------------ ------------ Total revenues 2,026,770 2,669,692 2,710,500 2,347,490 2,056,832 Costs and expenses Operating costs and expenses 1,677,426 2,165,090 2,178,664 1,887,846 1,643,718 Depreciation, depletion and amortization 174,587 240,968 249,782 204,698 179,182 Selling and administrative expenses 73,553 99,267 95,256 88,905 76,888 Gain on sale of Australian operations -- (171,735) -- -- -- Net gain on property and equipment disposals (14,327) (5,737) (6,439) (328) -- ----------- ----------- ----------- ------------ ------------ Operating profit 115,531 341,839 193,237 166,369 157,044 Interest expense 88,686 197,686 205,056 180,327 176,105 Interest income (2,155) (8,741) (4,421) (20,194) (18,527) ----------- ----------- ----------- ------------ ------------ Income (loss) before income taxes and minority interests 29,000 152,894 (7,398) 6,236 (534) Income tax provision (benefit) 2,465 42,690 (141,522) 7,542 3,012 Minority interests 7,248 7,524 15,554 1,887 1,887 ----------- ----------- ----------- ------------ ------------ Income (loss) from continuing operations 19,287 102,680 118,570 (3,193) (5,433) Income (loss) from discontinued operations -- 12,925 (90,360) 4,678 6,442 ----------- ----------- ----------- ------------ ------------ Income (loss) before extraordinary item 19,287 115,605 28,210 1,485 1,009 Extraordinary loss from early extinguishment of debt (28,970) (8,545) -- -- -- ----------- ----------- ----------- ------------ ------------ Net income (loss) $ (9,683) $ 107,060 $ 28,210 $ 1,485 $ 1,009 =========== =========== =========== ============ ============ Basic earnings per share from continuing operations $ 0.40 Diluted earnings per share from continuing operations $ 0.38 Basic and diluted earnings (loss) per Class A/B share from continuing operations $ 2.97 $ 3.43 $ (0.16) Weighted average shares used in calculating basic earnings (loss) per share 48,746,444 27,524,626 27,586,370 26,823,383 Weighted average shares used in calculating diluted earnings (loss) per share 50,524,978 27,524,626 27,586,370 26,823,383 Dividends declared per share $ 0.20 -- -- -- OTHER DATA Tons sold (in millions) 146.5 192.4 190.3 176.0 154.3 Adjusted EBITDA (4) $ 290,118 $ 582,807 $ 443,019 $ 371,067 $ 336,226 Net cash provided by (used in): Operating activities 115,798 151,980 262,911 253,865 282,022 Investing activities (172,989) 388,462 (185,384) (2,270,886) (2,249,336) Financing activities 33,090 (543,337) (205,181) 2,184,818 2,161,281 Depreciation, depletion and amortization 174,587 240,968 249,782 204,698 179,182 Capital expenditures 194,246 151,358 178,754 195,394 174,520 BALANCE SHEET DATA (AT PERIOD END) Total assets $ 5,150,902 $ 5,209,487 $ 5,826,849 $ 7,023,931 $ 7,023,931 Total debt 1,031,067 1,405,621 2,076,166 2,542,379 2,542,379 Total stockholders' equity/invested capital 1,035,472 631,238 508,426 495,230 495,230
PREDECESSOR COMPANY --------------------------- Period From April 1, 1998 Year Ended to March 31, May 19, 1998 1998 ------------- ----------- RESULTS OF OPERATIONS DATA Revenues Sales $ 278,930 $2,048,694 Other revenues 11,728 169,328 ---------- ---------- Total revenues 290,658 2,218,022 Costs and expenses Operating costs and expenses 244,128 1,695,216 Depreciation, depletion and amortization 25,516 200,169 Selling and administrative expenses 12,017 83,640 Gain on sale of Australian operations -- -- Net gain on property and equipment disposals (328) (21,815) ---------- ---------- Operating profit 9,325 260,812 Interest expense 4,222 33,410 Interest income (1,667) (14,543) ---------- ---------- Income (loss) before income taxes and minority interests 6,770 241,945 Income tax provision (benefit) 4,530 83,050 Minority interests -- -- ---------- ---------- Income (loss) from continuing operations 2,240 158,895 Income (loss) from discontinued operations (1,764) 1,441 ---------- ---------- Income (loss) before extraordinary item 476 160,336 Extraordinary loss from early extinguishment of debt -- -- ---------- ---------- Net income (loss) $ 476 $ 160,336 ========== ========== Basic earnings (loss) per share from continuing operations Diluted earnings (loss) per share from continuing operations Basic and diluted earnings (loss) per Class A/B share from continuing operations Weighted average shares used in calculating basic earnings (loss) per share Weighted average shares used in calculating diluted earnings (loss) per share Dividends declared per share OTHER DATA Tons sold (in millions) 21.7 167.5 Adjusted EBITDA (4) $ 34,841 $ 460,981 Net cash provided by (used in): Operating activities (28,157) 187,852 Investing activities (21,550) (136,033) Financing activities 23,537 (235,389) Depreciation, depletion and amortization 25,516 200,169 Capital expenditures 20,874 165,514 BALANCE SHEET DATA (AT PERIOD END) Total assets $6,406,587 $6,343,009 Total debt 633,562 602,276 Total stockholders' equity/invested capital 1,497,374 1,687,842
30 -------------- (1) Results of operations for the year ended March 31, 2001 included a $171.7 million pretax gain on the sale of our Australian operations. (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) 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. (4) Adjusted EBITDA is defined as income from continuing operations before deducting net interest expense, income taxes, minority interests and depreciation, depletion and amortization. Adjusted EBITDA is not a substitute for operating income, net income and cash flow from operating activities as determined in accordance with generally accepted accounting principles as a measure of profitability or liquidity. Adjusted EBITDA is presented as additional information because management believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. 31 ITEM 7. 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. References to "fiscal year 2001" and "fiscal year 2000" refer to the twelve months ended March 31, 2001 and March 31, 2000, respectively. FACTORS AFFECTING COMPARABILITY Sale of Australian Operations In December 2000, we signed a share purchase agreement for the transfer of the stock in two U.K. holding companies which, in turn, owned our Australian subsidiaries, to a subsidiary of Rio Tinto Limited. Our Australian operations consisted of interests in six coal mines, as well as a mining services operation in Brisbane, Australia. The sale price was $446.8 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. 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 the U.S. operations (represents all of our operations, except for Australian operations sold in January 2001) increased $219.1 million, to $1,963.3 million, a 12.6% increase from the prior 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 nine-month period, led the increase. Additionally, sales from trading and brokerage activities increased as a result of improved market liquidity and higher prices in the current nine-month period. Sales volume for the U.S. operations was 146.5 million tons for the current nine months, compared to 133.7 million tons for the prior nine-month period, an increase of 9.6%. Higher sales volume at our Powder River Basin, Southwest and Midwest operations led 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 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 current nine months compared to the prior nine-month period. Total sales for the nine months ended December 31, 2001 increased $44.9 million, or 2.3%, from the prior nine-month period. Sales from Australian operations included in the prior nine-month period were $174.2 million, 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 current nine-month period, 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. Finally, sales from brokerage and trading activities increased $64.1 million, as sales volume increased as a result of improved market liquidity and higher prices in the current year. 32 Other Revenues. Other revenues for the nine months ended December 31, 2001 for U.S. operations increased $40.9 million over the prior 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 current year. Other revenues from Australian operations included in the prior year 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 nine-month period. Higher production volume in the current year, 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 Australian operations. Selling and Administrative Expenses. Selling and administrative expenses of $73.6 million increased $6.6 million compared to the nine months ended December 31, 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 current nine-month period. 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 nine-month period, which included $49.0 million of operating profit from 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 over the prior nine-month period 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 compared to the prior nine-month period, 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 current nine-month period. Operating costs related to past mining activities were $9.8 million higher in the current nine-month period, 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. Current period 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 of our liability for environmental cleanup-related costs. Operating profit from trading and brokerage operations increased $16.4 million over the prior nine-month period, 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. 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 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 33 our initial public offering in May 2001, we reduced long-term debt by $835 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. 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 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 nine-month period. Excluding the effect of Australian operating results included in the prior 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. Our consolidated tax position is impacted by the percentage depletion tax deduction that creates an alternative minimum tax situation. The current year tax situation reflects 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. FISCAL YEAR ENDED MARCH 31, 2001 COMPARED TO FISCAL YEAR ENDED MARCH 31, 2000 Sales. Sales decreased $31.9 million, or 1.2%, to $2,579.1 million for the fiscal year 2001. Sales volume increased 2.1 million tons, or 1.1%, to 192.4 million tons in fiscal year 2001. The majority of the decline was the result of $24.6 million of lower sales in Australia, due to the sale of our Australian operations in January 2001. During the first nine months of fiscal year 2001, average prices were 2.7% lower than the prior year's first nine months, primarily due to a change in sales mix as higher-priced Midwest region volume decreased in fiscal year 2001. However, this decrease was somewhat mitigated by higher coal prices in the fourth quarter in nearly all operating regions, which reduced the full year decline in average prices to only 1.0% compared to the prior year. Sales from our U.S. operations decreased $7.3 million in fiscal year 2001, due to lower volumes in the Midwest region offset partially by slightly higher volume in Appalachia, the Southwest region and at Black Beauty, and improved pricing and volume in the Powder River Basin. Sales in the Powder River region increased $44.9 million in fiscal year 2001, due to improved pricing and increased volume as a result of strong demand for Powder River Basin coal. Sales in Appalachia improved by $42.3 million due to higher volume from improved performance at our longwall operations in that region. Black Beauty's sales increased $23.6 million due to the higher volumes on contracts transitioned from our other mines, while sales in the Southwest region improved $4.9 million due to slightly higher sales volume. Sales from broker and trading activities increased $41.4 million, reflecting an increase in volume over fiscal year 2000. These sales increases were more than offset by the sales decrease in the Midwest region of $164.5 million from the closure and suspension of three mines during fiscal year 2000 and the closure of another mine early in the third quarter of fiscal year 2001. Other Revenues. Other revenues decreased $8.9 million compared to the prior year, to $90.6 million. Lower contract restructuring revenues and coal royalty income in fiscal year 2001 were only partially offset by an increase in revenues from engineering services for underground mining projects in Australia. Our contract restructuring revenues typically arise from the negotiated termination of our or a third party's existing coal supply agreement in exchange for a cash payment. 34 Depreciation, Depletion and Amortization. Fiscal year 2001 depreciation, depletion and amortization expense was $241.0 million, a decrease of $8.8 million compared to fiscal year 2000. The decrease was primarily due to $6.0 million of additional depletion associated with a new coal royalty agreement entered into in fiscal year 2000. Selling and Administrative Expenses. Selling and administrative expenses increased $4.0 million in fiscal year 2001 to $99.3 million. This increase was primarily related to $3.7 million of increased stock compensation expense in fiscal year 2001 related to the grant of Class B common stock to management. Gain on Sale of Australian Operations. On January 29, 2001, we sold our Australian operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto Limited. The selling price was $446.8 million, plus the assumption of all liabilities, including $119.4 million of debt. We recorded a pretax gain of $171.7 million on the sale. Operating Profit. Fiscal year 2001 operating profit was $341.8 million, an increase of $148.6 million compared to fiscal year 2000. Excluding the gain on the sale of our Australian operations, operating profit was $170.1 million, a decrease of $23.1 million from fiscal year 2000. Operating margin excluding the gain on the sale of our Australian operations was 6.6% in fiscal year 2001, a decrease from 7.4% in fiscal year 2000. A 41% increase in fuel prices decreased operating margin by 1.0% and operating profit by $24.1 million in fiscal year 2001. At our U.S. mining operations, operating profit, excluding fuel cost variances, remained stable in fiscal year 2001. Operating profit in the Powder River Basin region increased $20.5 million primarily due to higher pricing in fiscal year 2001, combined with slightly improved sales volume. In the Southwest region, we realized increased operating profit of $12.1 million as a result of improved productivity and higher sales volume in fiscal year 2001. Offsetting these increases was a $40.0 million decrease in the Midwest region associated with the closure and suspension of three mines in fiscal year 2000 and the closure of another mine early in the third quarter of fiscal year 2001. Black Beauty's operating profit decreased $18.5 million due to lower contract restructuring revenues in fiscal year 2001, higher operating costs caused by adverse geologic conditions encountered during the first nine months of the year as we transitioned to new mining areas and unfavorable weather conditions, which delayed production and transportation of coal. Appalachia's operating profit decreased $6.5 million due to poor mining conditions at certain underground operations and lower average pricing in the first nine months of fiscal year 2001 due to contract expirations, partially offset by improved performance at the region's longwall operations. Fiscal year 2001 results also included a decrease in operating costs for an $8.0 million reduction in our liabilities for environmental cleanup-related costs based upon favorable experience and lower costs of $9.1 million related to Black Lung excise tax refund credits on export shipments. Beginning in 1997, we filed for a refund of these taxes on the basis that the tax was unconstitutional. In May 2000, the Internal Revenue Service issued guidelines for the refund of these taxes. We have filed a claim and expect to receive a refund in the first half of calendar year 2002. Operating costs also decreased $11.4 million in fiscal year 2001 due to the reduction in our liability associated with the United Mine Workers of America Combined Fund. The Coal Industry Retiree Health Benefit Act of 1992 established the Combined Fund to provide for the funding of specified health benefits for covered United Mine Workers of America retirees. Two of our subsidiaries filed a lawsuit against the Social Security Administration asserting that it improperly assigned certain beneficiaries to them. A federal District Court ruled in our favor. Effective October 1, 2000, the Social Security Administration withdrew the assignment to our subsidiaries of a specified number of beneficiaries, resulting in a $11.4 million reduction in our liability. Additionally, our Australian operations' operating profit increased $5.0 million in fiscal year 2001. Interest Expense. Interest expense decreased $7.4 million to $197.7 million in fiscal year 2001. The decrease was primarily due to a $7.7 million decrease in interest expense in the fourth quarter resulting from the repayment of $455.0 million of term loans under our senior credit facilities during the quarter, and the removal of $119.4 million of debt from our balance sheet as a result of the sale of our Australian operations. Interest Income. Interest income increased $4.3 million to $8.7 million in fiscal year 2001, primarily as a result of the interest income recorded in fiscal year 2001 associated with the Black Lung excise tax refunds. Income Taxes. Fiscal year 2001 income tax expense was $42.7 million on pretax income of $152.9 million, compared to an income tax benefit of $141.5 million on a pretax loss of $7.4 million in fiscal year 2000. Additionally, in fiscal year 2000 we recorded 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. 35 Our consolidated tax position is impacted by the percentage depletion tax deduction utilized by us and our U.S. subsidiaries that creates an alternative minimum tax situation, and the positive contribution of our Australian operations, which are taxed at a higher rate than our U.S. operations. Additionally, in fiscal year 2001 we recorded a $47.5 million tax provision related to the gain on sale of our Australian operations. Excluding the tax provision related to the sale of our Australian operations, the income tax benefit recorded on U.S. pretax losses exceeded the Australian income tax expense in fiscal year 2001 by $4.8 million. Minority Interests. In fiscal year 2001, minority interest expense decreased $8.0 million to $7.5 million, due to lower fiscal year 2001 results at our 81.7%-owned Black Beauty operations. As discussed above, Black Beauty's results were affected by a contract restructuring gain in fiscal year 2000, combined with higher mining costs due to poor geologic conditions and higher fuel costs in fiscal year 2001. Loss from Discontinued Operations. In fiscal year 2000, Citizens Power incurred a loss from operations of $12.1 million. Citizens Power was classified as a discontinued operation in March 2000. Gain from Disposal of Discontinued Operations. During fiscal year 2001, we reduced our estimated net loss from the sale of Citizens Power by $12.9 million, net of income taxes. This 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 during the first quarter ($8.8 million) and higher estimated proceeds from the monetization of power contracts as part of the wind-up of our ownership of Citizens Powers' operations ($4.1 million). We completed the sale of Citizens Power in fiscal year 2001. Extraordinary Loss from the Early Extinguishment of Debt. In the fourth quarter of fiscal year 2001, we made optional prepayments of term loans under our senior credit facilities. These prepayments were primarily funded with the proceeds from the sale of our Australian operations. The prepayments resulted in an extraordinary loss of $8.5 million, net of income taxes, due to the write-off of costs related to the issuance of the debt repaid. LONG-TERM COAL 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. During 2001, prices for coal increased from prior year levels, particularly in the Powder River Basin and in Appalachia, primarily due to increased prices for competing fuels and increased demand for electricity. Late in 2001, coal prices began to decline from the levels experienced earlier in 2001, due to a softer economy and milder than normal winter weather. During calendar 2001, we signed contracts for nearly 200 million tons of new business at higher prices than those realized in calendar 2001. As of December 31, 2001 we had sales commitments for approximately 93% of our calendar 2002 production which, as of March 1, 2002, increased to 97% as a result of reduced production estimates for calendar 2002. As of March 1, 2002, nearly 1 billion tons of our future coal production was committed under long-term contracts. Long-term contracts may be particularly attractive in regions where market prices are expected to remain stable, particularly in cases such as high sulfur coal that would otherwise not be in great demand or for sales under cost-plus arrangements serving captive electricity 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. Most of the contracts contain price adjustments for inflation and changes in the laws regulating the mining, production, sale or use of coal. LIQUIDITY AND CAPITAL RESOURCES Cash provided by operating activities was $115.8 million in the nine months ended December 31, 2001, an increase of $15.2 million over the prior nine-month period. Cash flow in the prior year benefited from $25.0 million of proceeds received related to our accounts receivable securitization program, while the current nine-month period benefited from a $22.7 million federal income tax refund. Cash from operations improved as a result of lower borrowing costs, which overcame increased working capital cash uses in the current year. Cash provided by operating activities was $152.0 million in the year ended March 31, 2001. Net cash used in investing activities was $173.0 million for the nine months ended December 31, 2001, compared to cash used in investing activities in the prior nine month period of $31.7 million. The prior year period included $85.6 million of proceeds related to the sale of Citizens Power and $34.7 million of cash used related to our Australian operations. Capital expenditures increased $84.9 million, to $194.2 million, in the current nine-month period. This increase was primarily due to higher investments in the Powder River Basin and at our Black Beauty operations. Powder River Basin capital was used to incrementally expand the operations, add new equipment, and reopen the Rawhide mine. At our Black 36 Beauty operations, additional capital was used in the current year to complete the addition of new mines to service long-term contracts and to purchase a dragline to lower overburden removal costs. For the year ended March 31, 2001, net cash provided by investing activities was $388.5 million. This included $455.0 million from the sale of our Australian operations and $102.6 million from discontinued operations. Net cash provided by financing activities was $33.1 million for the nine months ended December 31, 2001, an increase of $133.2 million over the prior year period. We made debt payments of $458.8 million during the nine-month period, principally from proceeds received from our initial public offering. The prior year period reflects $132.3 million in debt repayments, principally made using proceeds from our sale of Citizens Power. Finally, we paid $10.4 million of dividends in the current nine-month period. Cash used in financing activities was $543.3 million in the year ended March 31, 2001. This included net debt payments of $568.6 million, sourced from the sale of our Australian operations and Citizens Power. The following table reflects our total indebtedness as of December 31, 2001 (in thousands):
December 31, 2001 ----------------- 9.625% Senior Subordinated Notes ("Senior Subordinated Notes") due 2008 $ 391,390 8.875% Senior Notes ("Senior Notes") due 2008 316,413 5.0% Subordinated Note 90,026 Senior unsecured notes under various agreements 83,571 Unsecured revolving credit agreement 96,790 Other 52,877 ---------- Total debt $1,031,067 ==========
As of December 31, 2001, our revolving credit and letter of credit borrowing facilities include the $480.0 million Revolving Credit Facility under our Senior Credit Facility and Black Beauty's $120.0 million revolving credit facility. These facilities total $600.0 million, and have a total of $470.0 million available for borrowing. Outstanding borrowings under Black Beauty's revolving credit facility totaled $96.8 million. We were in compliance with the restrictive covenants of all of our and our subsidiaries' debt agreements as of December 31, 2001. We have a $480.0 million Revolving Credit Facility that includes a borrowing sub-limit of $350.0 million and a letter of credit sub-limit of $330.0 million. Our borrowing capacity increased from $200.0 million as a result of an amendment to our Senior Credit Facility. The amendment, which became effective at the time of the initial public offering, permits: the payment of annual cash dividends up to the greater of $25.0 million or 10% of consolidated EBITDA, as defined in the facility; other restricted payments subject to specified limitations; and additional joint venture investments. In connection with the amendment, we agreed to reduce the maximum permitted debt to EBITDA ratio and increase the minimum required interest coverage ratio. All other terms and conditions remained unchanged. As of December 31, 2001, we had no borrowings outstanding under our Revolving Credit Facility. Revolving loans under our Revolving Credit Facility bear interest based on the Base Rate (as defined in the Senior Credit Facility), or LIBOR (as defined in the Senior Credit Facility) at our option. The applicable rate was 3.4% at December 31, 2001. 37 The following is a summary of commercial commitments available to us as of December 31, 2001 (in thousands):
Expiration Per Year ---------------------------------------------------- Total Amounts Less than Committed 1 Year 1 - 3 Years 4 - 5 Years Over 5 Years ------------- --------- ----------- ----------- ------------ Lines of Credit $470,000 - $470,000 - - Standby Letters of Credit $330,000 - $330,000 - -
The indentures governing our Senior Notes and Senior Subordinated Notes permit us and our Restricted Subsidiaries (as defined in the indentures) to incur additional indebtedness, including secured indebtedness, subject to certain limitations. In addition, the indentures limit our and our Restricted Subsidiaries' ability to: lease, convey or otherwise dispose of all or substantially all of our assets; issue specified types of capital stock; enter into guarantees of indebtedness; incur liens; merge or consolidate with any other person or enter into transactions with affiliates; and repurchase junior securities or make specified types of investments. 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. We expressly reserve the right, at our sole discretion, from time to time, to purchase any notes, in the open market or through privately negotiated transactions. Black Beauty has a $120.0 million revolving credit facility which matures on April 17, 2004. Black Beauty may elect one or a combination of interest rates based on LIBOR or the corporate base rate plus a margin, which fluctuates based on specified leverage ratios. The effective annual interest rate was 3.9% as of December 31, 2001. Borrowings outstanding under the Black Beauty revolving credit facility totaled $96.8 million at December 31, 2001. The revolving credit facility contains customary restrictive covenants including limitations on additional debt, investments and dividends. Black Beauty's senior unsecured notes include $23.6 million of senior notes and three series of notes with an aggregate principal amount of $60.0 million as of December 31, 2001. The senior notes bear interest at 9.2%, payable quarterly, and are pre-payable in whole or in part at any time, subject to certain make-whole provisions. The three series of notes include Series A, B and C notes, totaling $45.0 million, $5.0 million and $10.0 million, respectively. The Series A notes bear interest at an annual rate of 7.5% and are due in November 2007. The Series B notes bear interest at an annual rate of 7.4% and are due in November 2003. The Series C notes bear interest at an annual rate of 7.4% and are due in November 2002. The senior unsecured notes contain customary restrictive covenants including limitations on additional debt, investments and dividends. Subsidiaries of Black Beauty maintain borrowing facilities with banks and other lenders with customary restrictive covenants. The aggregate amount of outstanding indebtedness under those facilities totaled $52.9 million as of December 31, 2001. The effective annual interest rate of this debt was 3.9% as of December 31, 2001. 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 seven years ending May 15, 2008. The applicable rate was 6.03% as of December 31, 2001. The Company realized interest savings of $0.6 million from the inception of the swaps on October 26, 2001 through December 31, 2001. During calendar 2001, we repaid $835 million in debt. In January 2001, we sold our Australian operations for $446.8 million. On May 22, 2001, we completed an initial public offering of 17,250,000 shares of common stock. Net proceeds from the offering were $449.8 million. We used substantially all of the proceeds from the sale of our Australian operations and the initial public offering to repay debt. Since March 31, 1999, we have reduced our total debt by over $1.5 billion. During the nine months ended December 31, 2001, Moody's, Standard & Poor's and Fitch reviewed our various debt ratings. Moody's upgraded our senior implied rating to Ba2 from Ba3, our senior secured revolving credit facility to Ba1 from Ba2, and our 9.625% Senior Subordinated Notes to B1 from B2. Standard & Poor's upgraded our corporate credit 38 rating to BB from BB-, our 8.875% Senior Notes to BB from B+ and our 9.625% Senior Subordinated Notes to B+ from B. Fitch upgraded our senior secured revolving credit facility to BB+ from BB-, our 8.875% Senior Notes to BB from B+ and our 9.625% Senior Subordinated Notes to B+ from B-. In March 2000, we established an accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been contributed to the Seller are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit ("Conduit"). Purchases by the Conduit are financed with the sale of highly rated commercial paper. The Company used 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 $4.5 million and $8.7 million for the nine months ended December 31, 2001 and the year ended March 31, 2001, respectively. The securitization program is currently scheduled to expire in 2007. Under the provisions of Statement of Financial Accounting Standards ("SFAS") No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," (as amended by SFAS No. 140) 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 were $140.0 million as of December 31, 2001 and March 31, 2001. The following is a summary of our significant contractual obligations as of December 31, 2001 (in thousands):
Payments Due by Year --------------------------------------------------------- After 5 Less than 1 Year 1-3 Years 4-5 Years Years ---------------- --------- --------- -------- Long-term debt $ 46,499 $198,613 $ 35,549 $750,406 Capital lease obligations 895 869 579 53 Operating leases 65,511 113,821 80,964 72,610 Unconditional purchase obligations 136,688 - - - Coal reserve obligations 36,725 26,118 24,818 32,454 -------- -------- -------- -------- Total contractual cash obligations $286,318 $339,421 $141,910 $855,523 ======== ======== ======== ========
Additionally, we have long-term liabilities relating to retiree health care, 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, 2001 (in thousands):
Payments Due by Year ------------------------------------------- Less than 1 Year 1-3 Years 4-5 Years ---------------- --------- --------- $190,600 $413,200 $373,300
We had $136.7 million of committed capital expenditures at December 31, 2001, that are primarily related to acquiring additional coal reserves and mining equipment in 2002. Total capital expenditures for calendar year 2002 are expected to range from $165 million to $195 million, and have been and will be primarily used to acquire additional low sulfur coal reserves, develop existing reserves, replace or add equipment and fund cost reduction initiatives. We anticipate funding these capital expenditures through operating cash flow. In addition, cash requirements to fund employee related and reclamation liabilities included above are expected to be funded from operating cash flow, along with obligations related to long-term debt, capital and operating leases and coal reserves. We believe the risk of generating lower than anticipated operating cash flow in 2002 is reduced by our high level of sales commitments (97% of 2002 planned production) and lower expected borrowing costs as a result of our significant debt reductions. CRITICAL ACCOUNTING POLICIES Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. Employee Related Liabilities We have significant long-term liabilities relating to retiree health care, work-related injuries and illnesses and defined pension plans. Detailed information related to these liabilities is included in the notes to our consolidated financial statements. Retiree health care and work-related injuries are not funded. Pension obligations are funded in accordance with the provisions of federal law. 39 Each of these liabilities are actuarially determined and we use various actuarial assumptions, including the discount rate and future cost trends, to estimate the costs and obligations for these items. Our discount rate is based on a hypothetical portfolio of currently available, high-quality debt instruments ("AA" or better rating under either Moody's or Standard & Poor's) whose maturity dates match the expected payments. We assumed a discount rate of 7.4% and 7.85% to determine the obligations at December 31, 2001 and March 31, 2001, respectively. 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 be materially different than currently estimated. Moreover, regulatory changes could increase our obligation to satisfy these or additional obligations. Payments related to these liabilities totaled $100.5 million for the nine months ended December 31, 2001. Reclamation We 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. Payments related to reclamation liabilities totaled $20.7 million for the nine months ended December 31, 2001. Trading Activities We engage in the buying and selling of coal and emission allowances in over-the-counter markets. Purchases and sales of commodities on a forward basis are marked-to-market and carried at fair value in the consolidated financial statements, with changes in that fair value recorded in earnings in the period they occur. For transactions that take place in over-the-counter markets, we use bid/ask price quotations obtained from multiple, independent third party brokers to value coal and emission allowance positions. Prices from these sources are then averaged to obtain trading position values. We would experience difficulty in valuing our market positions if the number of third party brokers should decrease or market liquidity is reduced. Seventy-six percent of the contracts in our trading portfolio as of December 31, 2001 were valued utilizing prices from over-the-counter market sources. The remaining 24% 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 December 31, 2001, the timing of trading portfolio contract expirations are as follows:
Year of Expiration Percentage of Portfolio ------------------ ----------------------- 2002 75% 2003 3% 2004 18% 2005 3% 2006 1% --- 100% ===
40 At December 31, 2001, 89% of our credit exposure related to coal and emission allowance trading activities is with counterparties that are investment grade. RECENT ACCOUNTING PRONOUNCEMENTS In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 addresses accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This statement is effective for fiscal years beginning after June 15, 2002 (effective January 1, 2003 for the Company). The Company is currently assessing the impact of this new standard. In July 2001, the FASB issued SFAS No. 144, "Impairment or Disposal of Long-Lived Assets," which is effective for fiscal years beginning after December 15, 2001 (effective January 1, 2002 for the Company). The provisions of this statement provide a single accounting model for impairment of long-lived assets. We do not anticipate the adoption of SFAS No. 144 will have a material effect on our financial condition or results of operations. RISK FACTORS IF A SUBSTANTIAL PORTION OF OUR LONG-TERM COAL SUPPLY AGREEMENTS TERMINATE, OUR REVENUES AND OPERATING PROFITS COULD SUFFER IF WE WERE UNABLE TO FIND ALTERNATE BUYERS WILLING TO PURCHASE OUR COAL ON COMPARABLE TERMS TO THOSE IN OUR CONTRACTS. A substantial portion of our sales are made under coal supply agreements, which are important to the stability and profitability of our operations. The execution of a satisfactory coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract. For the nine months ended December 31, 2001, 83% of our sales volume was sold under long-term coal supply agreements. At December 31, 2001, our coal supply agreements had remaining terms ranging from one to 14 years and an average volume-weighted remaining term of approximately four 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 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. Failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. In past years, several of our coal supply agreements have been renegotiated, resulting in the contract prices being closer to the then-current market prices, thus leading to a reduction in the revenues from those contracts. We have also experienced a similar 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, a majority 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, we cannot predict whether the strength in the coal market will continue. As a result, we 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, three 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 nine months ended December 31, 2001, we derived 33% of our total coal revenues from sales to our five largest customers. At December 31, 2001, we had 20 coal supply agreements with these customers that expire at various times from 2002 to 2015. We are currently discussing the extension of existing agreements or entering into new long-term agreements 41 with some of these customers, but these negotiations may not be successful and those customers may not continue to purchase coal from us under long-term coal supply agreements. If a number of these customers were to significantly reduce their purchases of coal from us, or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our financial condition and results of operations could suffer materially. OUR FINANCIAL PERFORMANCE COULD BE ADVERSELY AFFECTED BY OUR SUBSTANTIAL DEBT. Our financial performance could be affected by our substantial indebtedness. As of December 31, 2001, we had total indebtedness of $1,031.1 million. We currently have total borrowing capacity under our and Black Beauty's revolving credit facilities of $470.0 million. We may also incur additional indebtedness in the future. Our ability to pay principal and interest on our debt depends upon the operating performance of our subsidiaries, which will be affected by, among other things, prevailing economic conditions in the markets they serve, some of which are beyond our control. Our business may not generate sufficient cash flow from operations and future borrowings may not be available under our revolving credit facilities or otherwise in an amount sufficient to enable us to service our indebtedness or to fund our other liquidity needs. The degree to which we are leveraged could have important consequences, including, but not limited to: (1) making it more difficult for us to pay dividends and satisfy our debt obligations; (2) increasing our vulnerability to general adverse economic and industry conditions; (3) 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; (4) limiting our ability to obtain additional financing to fund future working capital, capital expenditures, research and development or other general corporate requirements; (5) limiting our flexibility in planning for, or reacting to, changes in our business; and (6) placing us at a competitive disadvantage compared to less leveraged competitors. In addition, our indebtedness subjects us to financial and other restrictive covenants. Failure by us to comply with these covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us. Furthermore, substantially all of our assets secure our indebtedness under our Senior Credit Facility. 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 Southern 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, 42 state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production 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 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 and demand for coal. According to the Energy Information Administration's Emissions of Greenhouse Gases in the United States 2000, 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 the Kyoto Protocol 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 $1,032.5 million as of December 31, 2001, $70.4 million of which was a current liability. We have estimated these unfunded obligations based on assumptions described in Note 18 to our audited 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 three 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 gives 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. 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 43 nationwide. As of December 31, 2001, we leased or have applied to lease a total of 66,796 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, as discussed in Part I, Item 1 of this report under "Regulatory Matters." 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. Recent increases in coal prices could similarly 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, 2001, the United Mine Workers of America represented approximately 35% of our employees, who produced 21% of our coal sales volume in the United States during the nine months ended December 31, 2001. 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 ten-month United Mine Workers of America strike in 1993 had a material adverse effect on us. Two of our subsidiaries, Peabody Coal Company and Eastern Associated Coal Corp., operate under a union contract that is in 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, 2001, we had outstanding surety bonds with third parties for post-mining reclamation totaling $684.9 million. Furthermore, we have an additional $223.7 million of surety bonds in place for workers' compensation and retiree health care obligations and $111.6 million of surety bonds securing coal leases. These bonds are typically renewable on a yearly basis. Surety bond issuers and holders may not continue to renew the bonds or refrain from demanding 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: o lack of availability, higher expense or unfavorable market terms of new surety bonds; o restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures or Senior Credit Facility; and o the exercise by third-party surety bond issuers of their right to refuse to renew the surety. LEHMAN BROTHERS MERCHANT BANKING CONTROLS US AND MAY HAVE CONFLICTS OF INTEREST WITH OTHER STOCKHOLDERS IN THE FUTURE. Lehman Brothers Merchant Banking owns 57% of our common stock. Lehman Brothers Merchant Banking will continue to be able to control 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. The interests of Lehman Brothers Merchant Banking may not coincide with the interests of other holders of our common stock. We have retained 44 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, in particular the executive officers discussed previously in Part I, Item 4A. The loss of a number of key personnel 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. Recent terrorist attacks in the United States, as well as future events occurring in response to, or in connection with, the attacks, including future terrorist attacks against United States targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers, may materially adversely affect our operations. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extension of time for payment of accounts receivable from our customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could have a material adverse effect on our business, financial condition and results of operations. OUR ABILITY TO COLLECT PAYMENTS FROM OUR CUSTOMERS COULD BE IMPAIRED IF THEIR CREDITWORTHINESS DETERIORATES. Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties. These new power plant owners may have credit ratings that are below investment grade. One of our customers, Southern California Edison Company, had its credit rating downgraded to non- investment grade as a result of the electricity crisis in California in 2001. Southern California Edison, which owns 56% of the Mohave Generating Station, and the other owners of the Mohave Generating Station have a coal supply agreement that expires in 2005. For fiscal year 2001 and the nine months ended December 31, 2001, we sold 4.8 million and 3.6 million tons of coal, respectively, to the Mohave Generating Station. The owners of the Mohave Generating Station created a trust account in early 2001 to fund the payment of coal under the coal supply agreement and have advised us of their obligation, subject to certain conditions, to cure any defaults of another owner. Our ability to continue to receive payment from the Mohave Generating Station depends, in part, on the creditworthiness of Southern California Edison. Failure to receive payment for Southern California Edison's share of the Mohave Generating Station deliveries could adversely affect our financial condition and results of operations. If the creditworthiness of California utilities causes a general deterioration of the creditworthiness of other utilities, our accounts receivable securitization program could be adversely affected. On April 6, 2001, Pacific Gas and Electric Company filed for Chapter 11 reorganization. We do not have any coal supply agreements with that utility. One of our trading counterparties, Enron North America, filed for bankruptcy in December 2001. At December 31, 2001, we recorded a $6.6 million pre-tax charge for trades with Enron North America. Subsequent to Enron's bankruptcy, the creditworthiness of other trading counterparties has deteriorated. If deterioration of the creditworthiness of other counterparties continues, we could be adversely affected. 45 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Trading Activities We market and trade coal and emission allowances. These activities give rise to market 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 market risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure we may assume at any point in time. We account for coal and emission allowance trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, futures, options and swaps, at market value in the consolidated financial statements. We perform a value at risk analysis of our trading portfolio, which includes over-the-counter and brokerage trading of coal and emission allowances. 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 fifteen-day holding period and a 95% confidence interval. The use of value at risk allows management to aggregate market 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 nine months ended December 31, 2001, the low, high and average values at risk for our coal trading portfolio were $0.7 million, $5.0 million and $1.8 million, respectively. Our emission allowance value at risk averaged $0.1 million during the nine months ended December 31, 2001, and did not exceed $0.6 million during that period. Seventy-five percent of our trading positions will settle in calendar 2002. The Company also monitors other types of risk associated with its coal and emission allowance trading activities, including market liquidity, counterparty nonperformance and position valuation. Non-trading Activities We manage our commodity price risk for non-trading purposes through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 83% of our sales volume under long-term coal supply agreements during the nine months ended December 31, 2001. We have sales commitments for 97% of our calendar 2002 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 December 31, 2001, after taking into consideration the effects of interest rate swaps, we had $729.0 million of fixed-rate borrowings and $302.1 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $3.0 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 $41.0 million decrease in the fair value of these borrowings. 46 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. See Part IV, Item 14 of this report for the information required by this Item. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. The information required by Item 401 of Regulation S-K is included under the caption "Election of Directors" in the Company's 2002 Proxy Statement and in Part I, Item 4A of this report under the caption "Executive Officers of the Company." Such information is incorporated herein by reference. The information required by Item 405 of Regulation S-K is included under the caption "Section 16(a) Beneficial Ownership Reporting Compliance" in the Company's 2002 Proxy Statement and is incorporated herein by reference. ITEM 11. EXECUTIVE COMPENSATION. The information required by Item 402 of Regulation S-K is included under the caption "Executive Compensation" in the Company's 2002 Proxy Statement and is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT. The information required by Item 403 of Regulation S-K is included under the caption "Ownership of Company Securities" in the Company's 2002 Proxy Statement and is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The information required by Item 404 of Regulation S-K is included under the caption "Related Party Transactions" in the Company's 2002 Proxy Statement and is incorporated herein by reference. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K. (a) Financial Statements (1) The following consolidated financial statements of Peabody Energy Corporation included in the Company's December 31, 2001 Annual Report to Stockholders are incorporated by reference: Report of Independent Auditors Consolidated Statements of Operations--Nine Months Ended December 31, 2001, and the years ended March 31, 2001 and March 31, 2000 Consolidated Balance Sheets--December 31, 2001 and March 31, 2001 Consolidated Statements of Changes in Stockholders' Equity--Nine Months Ended December 31, 2001, and the years ended March 31, 2001 and March 31, 2000 Consolidated Statements of Cash Flows--Nine Months Ended December 31, 2001, and the years ended March 31, 2001 and March 31, 2000 Notes to Consolidated Financial Statements (2) Financial Statement Schedule. The following financial statement schedule of Peabody Energy Corporation is included in Item 14, along with the report of independent auditors thereon, at the pages indicated:
Page ---- Report of Independent Auditors on Financial Statement Schedule F-1 Valuation and Qualifying Accounts F-2
47 All other schedules for which provision is made in the applicable accounting regulation of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted. (3) Exhibits. See Exhibit Index hereto. (b) Reports on Form 8-K. We filed no reports on Form 8-K during the quarter ended December 31, 2001. 48 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. PEABODY ENERGY CORPORATION /s/ Irl F. Engelhardt ------------------------------------ Irl F. Engelhardt Chairman and Chief Executive Officer Date: March 12, 2002 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons, on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- /s/ Irl F. Engelhardt ------------------------------------------- Irl F. Engelhardt Chairman, Chief Executive Officer and Director March 12, 2002 (principal executive officer) /s/ Richard M. Whiting ------------------------------------------- Richard M. Whiting President, Chief Operating Officer and Director March 12, 2002 /s/ Richard A. Navarre ------------------------------------------- Richard A. Navarre Executive Vice President and Chief Financial Officer March 12, 2002 (principal financial and accounting officer) /s/ Henry E. Lentz ------------------------------------------- Henry E. Lentz Vice President, Assistant Secretary and Director March 12, 2002 /s/ Bernard J. Duroc-Danner ------------------------------------------- Bernard J. Duroc-Danner Director March 12, 2002 /s/ Roger H. Goodspeed ------------------------------------------- Roger H. Goodspeed Director March 12, 2002 /s/ Felix P. Herlihy ------------------------------------------- Felix P. Herlihy Director March 12, 2002 /s/ William E. James ------------------------------------------- William E. James Director March 12, 2002 /s/ William C. Rusnack ------------------------------------------- William C. Rusnack Director March 12, 2002 /s/ James R. Schlesinger ------------------------------------------- James R. Schlesinger Director March 12, 2002 /s/ Blanche M. Touhill ------------------------------------------- Blanche M. Touhill Director March 12, 2002 /s/ Alan H. Washkowitz ------------------------------------------- Alan H. Washkowitz Director March 12, 2002
49 REPORT OF INDEPENDENT AUDITORS Board of Directors Peabody Energy Corporation We have audited the consolidated financial statements of Peabody Energy Corporation (the Company) as of December 31, 2001 and March 31, 2001, and for the nine months ended December 31, 2001 and the years ended March 31, 2001 and 2000, and have issued our report thereon dated January 19, 2002. Our audits also included the financial statement schedule listed in Item 14(a). This schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. /s/ Ernst & Young LLP St. Louis, Missouri January 19, 2002 F-1 PEABODY ENERGY CORPORATION SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(In thousands) Balance at Charged to Balance Beginning Costs and at End Description of Period Expenses Deductions(1) Other of Period ----------- ---------- ---------- ------------- -------- ---------- NINE MONTHS ENDED DECEMBER 31, 2001 Reserves deducted from asset accounts: Land and coal interests $ 13,184 $ (275) $ - $ (73) $ 12,836 Reserve for materials and supplies 11,562 - (1,689) 20 9,893 Allowance for doubtful accounts 1,213 283 - - 1,496 YEAR ENDED MARCH 31, 2001 Reserves deducted from asset accounts: Land and coal interests $ 13,199 $ 605 $ - $ (620)(2) $ 13,184 Reserve for materials and supplies 12,400 - (2,672) 1,834 (2) 11,562 Allowance for doubtful accounts 1,233 - (20) - 1,213 YEAR ENDED MARCH 31, 2000 Reserves deducted from asset accounts: Land and coal interests $ 54,277 $ 2,179 $(40,541) $ (2,716)(2)(3) $ 13,199 Reserve for materials and supplies 16,558 - (4,748) 590 (2) 12,400 Allowance for doubtful accounts 177 1,213 (157) - 1,233
(1) Reserves utilized, unless otherwise indicated. (2) Balances transferred from other accounts. (3) Balances transferred as part of asset contribution to joint venture. F-2 EXHIBIT INDEX The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.
Exhibit No. Description of Exhibit --- ---------------------- 3.1 Third Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant's Form S-1 Registration Statement No. 333-55412). 3.2 Amended and restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.2 of the Company's Form S-1 Registration Statement No. 333-55412). 4.1 Senior Note Indenture dated as of May 18, 1998 between the Registrant and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.1 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.2 Senior Subordinated Note Indenture dated as of May 18, 1998 between the Registrant and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.2 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.3 First Supplemental Senior Note Indenture dated as of May 19, 1998 among the Guaranteeing Subsidiary (as defined therein), the Registrant the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.3 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.4 First Supplemental Senior Subordinated Note Indenture dated as of May 19, 1998 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.4 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.5 Notation of Senior Subsidiary Guarantee dated as of May 19, 1998 among the Senior Note Guarantors (as defined in the Senior Note Indenture) (Incorporated by reference to Exhibit 4.5 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.6 Notation of Subordinated Subsidiary Guarantee dated as of May 19, 1998 among the Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) (Incorporated by reference to Exhibit 4.6 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.7 Senior Note Registration Rights Agreement dated as of May 18, 1998 between the Registrant and Lehman Brothers Inc. (Incorporated by reference to Exhibit 4.7 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.8 Senior Subordinated Note Registration Rights Agreement dated as of May 18, 1998 between the Registrant and Lehman Brothers Inc. (Incorporated by reference to Exhibit 4.8 of the Registrant's Form S-4 Registration Statement No. 333-59073). 4.9 Second Supplemental Senior Note Indenture dated as of December 31, 1998 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.9 of the Registrant's Form 10-Q for the quarter ended December 31, 1999). 4.10 Second Supplemental Senior Subordinated Note Indenture dated as of December 31, 1998 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.10 of the Registrant's Form 10-Q for the quarter ended December 31, 1999). 4.11 Third Supplemental Senior Note Indenture dated as of June 30, 1999 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.11 of the Registrant's Form 10-Q for the quarter ended December 31, 1999). 4.12 Third Supplemental Senior Subordinated Note Indenture dated as of June 30, 1999 among the Guaranteeing Subsidiary (as defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.12 of the Registrant's Form 10-Q for the quarter ended December 31, 1999).
1
Exhibit No. Description of Exhibit --- ---------------------- 4.13 Specimen of stock certificate representing the Registrant's common stock, $.01 par value. (Incorporated by reference to Exhibit 4.13 of the Registrant's Form S-1 Registration Statement No. 333-55412). 4.14 Stockholders' Agreement dated as of May 19, 1998 among the Registrant, Lehman Brothers Merchant Banking Partners II L.P., Lehman Brothers Offshore Investment Partners II L.P., LB I Group Inc., Lehman Brothers Capital Partners III, L.P., Lehman Brothers Capital Partners IV, L.P., Lehman Brothers MBG Partners 1998 (A) L.P. and certain members of the Registrant's management. (Incorporated by reference to Exhibit 4.14 of the Registrant's Form S-1 Registration Statement No. 333-55412). 4.15 Stockholders' Agreement dated as of July 23, 1998 among the Registrant, Lehman Brothers Merchant Banking Partners II L.P., Lehman Brothers Offshore Investment Partners II L.P., LB I Group Inc., Lehman Brothers Capital Partners III, L.P., Lehman Brothers Capital Partners IV, L.P., Lehman Brothers MBG Partners 1998 (A) L.P., Co-Investment Partners, L.P., The Mutual Life Insurance Company of New York and Finlayson Investments Pte Ltd. (Incorporated by reference to Exhibit 4.15 of the Registrant's Form S-1 Registration Statement No. 333-55412). 4.16 Registration Rights Agreement, dated as of December 2001, among the Registrant, Lehman Brothers Merchant Banking Partners II L.P., Lehman Brothers Offshore Investment Partners II L.P., LB I Group, Inc., Lehman Brothers Capital Partners III L.P., Lehman Brothers Capital Partners IV L.P., Lehman Brothers MBG Partners (A) L.P., Lehman Brothers MBG Partners (B) L.P. and Lehman MBG Partners (C) L.P. 10.1 Amended and Restated Credit Agreement dated as of June 9, 1998 among the Registrant, as Borrower, Lehman Brothers Inc., as Arranger, Lehman Commercial Paper Inc., as Syndication Agent, Documentation Agent, and Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.2 Guarantee and Collateral Agreement dated as of May 14, 1997 made by the Guarantors, in favor of Lehman Commercial Paper, Inc., as Administrative Agent for the banks and other financial institutions (Incorporated by reference to Exhibit 10.2 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.3 Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.4 Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.5 Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.6 Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.7 Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.8 Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 of the Registrant's Form S-4 Registration Statement No. 333-59073). 10.9 Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy Company, dated September 30, 1998 (Incorporated by reference to Exhibit 10.9 of the Registrant's Form 10-Q for the second quarter ended September 30, 1998). 10.10* 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.10 of the Registrant's Form 10-Q for the third quarter ended December 1998). 10.11* Employment Agreement between Irl F. Engelhardt and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.11 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.12* Employment Agreement between Richard M. Whiting and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.12 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.13* Employment Agreement between Richard A. Navarre and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.13 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.14* Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit 10.14 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.15* Employment Agreement between Paul H. Vining and the Registrant dated July 1, 2000 (Incorporated by reference to Exhibit 10.19 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.16 Amendment No. 1 to Credit Agreement dated as of April 30, 2001 among the Registrant, as Borrower, Lehman Brothers Inc., as Arranger, Lehman Commercial Paper Inc., as Syndication Agent, Bank of America National Trust & Savings Association and The Fuji Bank, Limited, as Documentation Agents, Bank One, NA, as Administrative Agent, and the lenders party thereto (Incorporated by reference to Exhibit 10.20 of the Registrant's Form S-1 Registration Statement No. 333-55412).
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Exhibit No. Description of Exhibit --- ---------------------- 10.17* First Amendment to the Employment Agreement between Irl F. Engelhardt and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.21 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.18* First Amendment to the Employment Agreement between Richard M. Whiting and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.22 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.19* First Amendment to the Employment Agreement between Richard A. Navarre and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.23 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.20* First Amendment to the Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.24 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.21* First Amendment to the Employment Agreement between Paul H. Vining and the Registrant dated as of May 10, 2001 (Incorporated by reference to Exhibit 10.25 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.22* Form of First Amendment to Stockholders' Agreement dated as of May 19, 1998 (Incorporated by reference to Exhibit 10.26 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.23* Form of Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.27 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.24* Form of 2001 Employee Stock Purchase Plan (Incorporated by reference to Exhibit 10.28 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.25* Form of Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.29 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.26* Form of Amendment to the Non-Qualified Stock Option Agreement (Incorporated by reference to Exhibit 10.30 of the Registrant's Form S-1 Registration Statement No. 333-55412). 10.27* Peabody Energy Corporation Deferred Compensation Plan (Incorporated by reference to Exhibit 10.30 of the Registrant's Form 10-Q for the quarter ended September 30, 2001). 10.28 Receivables Purchase Agreement as of February 20, 2002, by and among Seller, the Registrant, Market Street Funding Corporation, and PNC Bank, National Association, as Administrator. 13 Portions of the Company's Annual Report to Stockholders for the nine months ended December 31, 2001. 21 List of Subsidiaries. 23 Consent of Ernst & Young LLP, Independent Auditors.
* These exhibits constitute all management contracts, compensatory plans and arrangements required to be filed as an exhibit to this form pursuant to Item 14(c) of this report. 3