ITEM 1. BUSINESS.
OVERVIEW
We are the largest private-sector coal company in the world. Excluding our Australian operations that were sold in January 2001, we sold 181.6 million tons of coal in the year ended March 31, 2001, or more than 16% of all U.S. coal sales. During this period, we sold coal to more than 290 electric generating and industrial plants, fueling the generation of more than 9% of all electricity in the United States and 2.5% of all electricity in the world. At March 1, 2001, we had 9.3 billion tons of proven and probable coal reserves.
We own majority interests in 34 coal operations located throughout all major U.S. coal producing regions, with 66% of our fiscal year 2001 coal sales shipped from the western United States and the remaining 34% 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 increased from 37.0 million tons in fiscal year 1990 to 119.7 million tons in fiscal year 2001, representing a compounded annual growth rate of 11%. In the west, we own and operate mines in Arizona, Colorado, Montana, New Mexico and Wyoming. In the east, we own and operate mines in Illinois, Indiana, Kentucky and West Virginia. We produced 77% of our fiscal year 2001 sales volume from non-union mines.
For the year ended March 31, 2001, 93% of our sales were to U.S. electricity generators, 3% were to the U.S. industrial sector and 4% were to customers outside the United States. Approximately 85% of our fiscal year 2001 coal sales were under long-term contracts. As of March 31, 2001, nearly one billion tons of our future coal production were committed under long-term contracts, with remaining terms ranging from one to 16 years and an average volume-weighted remaining term of four years. As a result of recent significant improvements in coal prices, we have added long-term contracts to our portfolio at favorable prices. Additionally, our uncommitted future production positions us well to continue to enter into favorably priced contracts. As of March 31, 2001, we had approximately 50 million tons, 101 million tons and 129 million tons of expected production available for sale at market-based prices in calendar year 2002, 2003 and 2004, respectively.
We are also expanding in related energy businesses that include coal trading, 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 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, 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 101 million tons in fiscal year 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.
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 January 29, 2001, we sold our Australian operations to a subsidiary of Rio Tinto Limited.
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.
[MAP]
Within the United States, we conduct operations in four regions: Powder River Basin; Southwest; Appalachia; and Midwest.
POWDER RIVER BASIN OPERATIONS
We control approximately 3.0 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 99.2 million tons of coal during fiscal year 2001, or approximately 50% of our total coal sales. The North Antelope/Rochelle and Caballo mines are serviced by both major western railroads, the Burlington Northern & Santa Fe and the Union Pacific.
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 73.1 million tons during fiscal year 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 are adding a second dragline in 2002 to improve productivity.
Caballo
The Caballo Mine is located 20 miles south of Gillette, Wyoming. During fiscal year 2001, it sold approximately 26.1 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 1.7 million tons of medium sulfur coal during fiscal year 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 19.7 million tons of coal during fiscal year 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 4.8 million tons of coal during fiscal year 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, operated and partially owned by Southern California Edison. The mine and the 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.
Kayenta
The Kayenta Mine is adjacent to the Black Mesa Mine and uses three draglines in three mining areas. It sold approximately 8.0 million tons of coal during fiscal year 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 the 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 1.6 million tons of compliance coal during fiscal year 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 5.3 million tons of medium sulfur coal during fiscal year 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 its annual production capacity by approximately 2.0 million tons that we plan to sell under long-term agreements to two new customers.
APPALACHIA OPERATIONS
We own and manage five operating units and related facilities in West Virginia. During fiscal year 2001, these operations sold approximately 18.5 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/White's Branch Operating Unit
The Big Mountain/White's Branch Operating Unit is based near Prenter, West Virginia. In August 2000, we closed the Robin Hood No. 9 Mine after depleting its mineable reserves and the White's Branch Mine began production. During fiscal year 2001, the Big Mountain No. 16, Robin Hood No. 9 and White's Branch mines sold approximately 2.4 million tons of steam coal. Big Mountain No. 16 and White's Branch are underground mines 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 4.2 million tons of compliance coal during fiscal year 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 7.7 million tons of steam and metallurgical coal during fiscal year 2001, including 4.2 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 3.7 million tons of metallurgical and steam coal during fiscal year 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.
Federal No. 2 Mine
The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining equipment and shipped approximately 4.8 million tons of steam coal during fiscal year 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.
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 1.1 million tons during fiscal year 2001.
MIDWEST OPERATIONS
We own and operate five mines in the midwestern United States, which collectively sold 8.8 million tons of coal during fiscal year 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. Some of our hourly workers in this region are members of the United Mine Workers of America; however, some of our mines in this region operate union-free.
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 Midwest region, which operates ten mines in Indiana and also has interests in one mine in east-central Illinois, four mines in southern Illinois and one mine in western Kentucky. Together these operations sold 22.9 million tons of compliance, medium sulfur and high sulfur steam coal during fiscal year 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 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 1.7 million tons of compliance coal during fiscal year 2001. Farmersburg is a surface mine in Vigo and Sullivan counties in Indiana that sold 4.1 million tons of medium sulfur coal during fiscal year 2001. Francisco, located in Gibson county, Indiana, sold 2.2 million tons during fiscal year 2001 and the two Somerville mines, also located in Gibson county, shipped a total of 4.8 million tons in fiscal year 2001. All of Black Beauty's mines operate union-free.
Black Beauty owns a 75%-equity interest in Sugar Camp Coal, LLC, a 5.0 million-ton per year complex comprised of two surface mines, Wildcat Hills and Cottage Grove, and one underground mine, Eagle Valley, located in southern Illinois. Sugar Camp also owns Arclar Coal Company, which operates one underground mine, Big Ridge, in southern Illinois that currently sells 1.8 million tons per year. The contract work forces at Eagle Valley and Big Ridge are both represented under non-UMWA labor agreements.
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 and barge loading facility. The Camp No. 1 Mine exhausted its economically recoverable reserves and ceased operations in October 2000. Together, these operations sold 5.4 million tons of coal during fiscal year 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.
Midwest Operating Unit
The Midwest Operating Unit near Graham, Kentucky sold 1.3 million tons of coal during fiscal year 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.
Patriot Coal Company
Patriot Coal Company operates Patriot, a surface mine, and Freedom, an underground mine, in Henderson County, Kentucky, and sold approximately 2.1 million tons of coal during fiscal year 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. These mines operate union-free.
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 16 years and an average volume-weighted remaining term of four years. For fiscal year 2001, we sold 85% of our sales volume under coal supply agreements. During fiscal year 2001, we sold coal to more than 290 electric generators and industrial plants in 12 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 favorable prices. Long-term contracts may be particularly attractive in regions where market prices are expected to remain stable, with respect to high sulfur coal that would otherwise not be in great demand or for sales under cost-plus arrangements serving captive power plants. Prices for coal have recently risen, particularly in the Powder River Basin and in Appalachia, primarily due to increased prices for competing fuels and increased demand for electricity.
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 often 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. In addition, most of the contracts contain price adjustments for changes in the laws regulating the mining, production, sale or use of coal. In the majority of these contracts, the purchaser has the right to terminate the contract if the price increases beyond certain limits, although we can usually decrease the price in order to maintain the contract.
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 emissions 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 March 31, 2001, we had 67 employees in our sales and marketing operations, including personnel dedicated to performing market research, contract administration and risk management activities.
TRANSPORTATION
Coal consumed domestically is usually sold at the mine, and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, with purchasers paying ocean freight. Producers usually pay shipping costs from the mine to the port.
The majority of our sales volume is shipped by rail, but a portion of our production is shipped by other modes of transportation. For example, coal from our 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 two Southern Powder River Basin mines. 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 the 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 the mining process. This research and development effort is typically undertaken and funded by equipment manufacturers using our input and expertise. Our engineering staff and purchasing departments work with manufacturers to design and produce equipment that we believe will add value to the business. For example, we worked with a manufacturer to design larger trucks to haul overburden and coal at various mines throughout our company. In Wyoming, we were the first coal company to use the current, state-of-the-art 400-ton haul trucks. We have worked with our underground equipment suppliers to develop higher horsepower continuous mining machines, which mine the coal more effectively, and at a lower cost per ton. We have also assisted them in the development of a continuous haulage machine, which can be operated by one person as opposed to the standard four-person requirement. 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 use global positioning satellite technology extensively in our larger surface mining operations to ensure proper mine layout. As a result of these efforts, many of our mines have become among the most productive in the industry. 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.
A number of factors beyond our control affect the markets in which we sell our coal. Continued demand for our coal and the prices obtained by us depend primarily on the coal consumption patterns of the electricity industries in the United States, the availability, location, cost of transportation and price of competing coal and other electricity generation and fuel supply sources such as natural gas, oil, nuclear and hydroelectric. Coal consumption patterns are affected primarily by the demand for electricity, environmental and other governmental regulations and technological developments. We compete on the basis of coal quality, delivered price, customer service and support and reliability.
CERTAIN LIABILITIES
We have significant long-term liabilities for reclamation, work-related injuries and illnesses, pensions and retiree health care. In addition, labor contracts with the United Mine Workers of America and voluntary arrangements with non-union employees include long-term benefits, notably health care coverage for retired and future retirees and their dependents. We provide reserves
for a substantial portion of these obligations. 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 $451.3 million as of March 31, 2001, $3.6 million of which was a current liability. Expense for fiscal year 2001 was $4.1 million.
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 $244.3 million as of March 31, 2001, $33.6 million of which was a current liability. Expense for fiscal year 2001 was $41.4 million.
Pension-Related Provisions. Pension-related costs represent the actuarially-estimated cost of pension benefits. Annual contributions to the pension plans are determined by consulting actuaries based on the Employee Retirement Income Security Act minimum funding standards and an agreement with the Pension Benefit Guaranty Corporation. Pension-related liabilities totaled approximately $10.7 million as of March 31, 2001, $8.1 million of which was a current liability.
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 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 multiemployer fund provides health care benefits to a 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 $1,036.1 million as of March 31, 2001, $62.0 million of which was a current liability. Expense for fiscal year 2001 was $70.7 million. Obligations to the United Mine Workers of America Combined Fund totaled $57.8 million as of March 31, 2001, $5.6 million of which was a current liability. Income for fiscal year 2001 was $8.0 million.
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, 24 states and Washington, D.C. have enacted programs leading to the deregulation of the electricity market; 19 other states are considering similar programs. Due to the uncertainty around the timing and implementation of deregulation, it is difficult to predict the impact on individual electricity generators. This uncertainty has increased due to the recent energy crisis in California, where market inefficiencies and supply and demand imbalances have created electricity supply shortages. The crisis has slowed deregulation activity in other states and at the federal level.
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 March 31, 2001, we and our subsidiaries had approximately 6,100 employees. Approximately 37% of our employees are affiliated with organized labor unions, which accounted for approximately 23% of the tons we sold in the United States during fiscal year 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, which is effective through December 31, 2002.
REGULATORY MATTERS
Federal, state and local authorities regulate the U.S. coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, the reclamation and restoration of mining properties after mining has been completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects of mining on groundwater quality and availability. In addition, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous federal, state and local governmental permits and approvals are required for mining operations. We believe that we have obtained all permits currently required to conduct our present mining operations. We may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment. These requirements could prove costly and time-consuming, and could delay commencing or continuing exploration or production operations. Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, our activities may be more closely regulated. Such legislation and regulations, as well as future interpretations and more rigorous enforcement of existing laws, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.
We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, because of extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time in the industry. None of the violations to date or the monetary penalties assessed upon us has been material.
MINE SAFETY AND HEALTH
Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations.
Most of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. While regulation has a significant effect on our operating costs, our U.S. competitors are subject to the same degree of regulation.
Our goal is to achieve excellent safety and health performance. We measure our success in this area primarily through the use of accident frequency rates. We believe that a superior safety and health regime is inherently tied to achieving our productivity and financial goals. We seek to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in establishing safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence.
BLACK LUNG
Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to claimants who last worked in the coal industry prior to July 1, 1973. 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 issued a preliminary injunction staying the effectiveness of the new rules. A trial on the merits was held on June 5, 2001, and the Court has not issued its decision on the matter.
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 $5.1 million and $4.1 million, respectively, during fiscal years 2000 and 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. 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, our subsidiaries will be required to pay an additional premium to the Combined Fund of approximately $2.4 million.
ENVIRONMENTAL LAWS
We are subject to various federal, state and foreign environmental laws. These laws require approval of many aspects of 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 a recent federal court action invalidating these ownership and control regulations, the scope and potential impact of the "ownership and control" requirements on us are unclear. The Office of Surface Mining Reclamation and Enforcement has responded to the court action by promulgating interim regulations, which more narrowly apply the ownership and control standards to coal companies. Although the federal action could have, by analogy, a
precedential effect on state regulations dealing with "ownership and control," which are in many instances similar to the invalidated federal regulations, it is not certain what impact the federal court decision will have on these state regulations.
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 has filed an appeal of the decision with the U.S. Court of Appeals for the Fourth Circuit. On October 29, 1999, the District Court issued a stay of its decision pending a resolution of the appeal. In April 2001, the Fourth Circuit overturned the District Court decision regarding the intermittent and perennial stream issue.
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 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. The Court of Appeals for the District of Columbia issued an opinion in May 1999 limiting the manner in which the EPA can enforce these standards. After a request by the federal government for a rehearing by the Court of Appeals was denied, the Supreme Court agreed in January 2000 to review the case. On February 27, 2001, the Supreme Court found in favor of the EPA in material part and remanded the case to the Court of Appeals. Implementation of the fine particulate National Ambient Air Quality Standards will occur, if at all, after the Court of Appeals disposes of any preserved challenges to the standards and the EPA develops a new implementation policy. The effect of this decision on us and our customers is unknown at this time.
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 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 at this time. We believe that implementation of Phase II has resulted in a downward pressure on the price of higher sulfur coal, 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. A coalition of 40 electricity generators and power companies petitioned the U.S. Court of Appeals for the District of Columbia to review the EPA's decision to grant the four petitions. On May 15, 2001, the Court of Appeals substantially upheld the EPA's ruling, but remanded for reconsideration the EPA's decision to regulate certain cogeneration facilities and the EPA's use of certain projections regarding future growth in setting the nitrogen oxide emission limitations.
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. Three electricity generators have reached 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.
In addition, 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 a possibility 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.
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
RCRA imposes 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.
RCRA excludes certain large-volume wastes generated primarily from the combustion of coal from being regulated as a hazardous waste pending a report to Congress and a decision by the EPA either to regulate the coal combustion wastes as a hazardous waste under RCRA or deem the regulation as unwarranted. The EPA made its report to Congress in March 1999 and determined in May 2000 not to regulate coal waste as a hazardous substance under RCRA. Any requirement to regulate coal combustion waste as a hazardous waste could cause a switch to other lower ash fuels and reduce 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 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 affect the price and demand for coal. According to the Energy Information Administration's Emissions of Greenhouse Gases in the United States 1999, coal accounts for 30% 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.
PERMITTING
Mining companies must obtain numerous permits that impose strict regulations on various environmental and safety matters in connection with coal mining. These provisions include requirements for coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and revegetation.
We must obtain permits from applicable state regulatory authorities before we begin to mine reserves. The mining permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mine and reclamation plans by utilizing this geologic data and incorporating elements of the environmental data. The mine and reclamation plan incorporates the provisions of the Surface Mining Control and Reclamation Act, the state programs and the complementary environmental programs that impact coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way, and surface land and documents required of the Office of Surface Mining's Applicant Violator System.
Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review, technical review and public notice and comment period before it can be approved. Some Surface Mining Control and Reclamation Act mine permits can take over a year to prepare, depending on the size and complexity of the mine and often take six months to sometimes two years to receive approval. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public has rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.
We do not believe there are any substantial matters that pose a risk to maintaining our existing mining permits or hinder our ability to acquire future mining permits. It is our policy to ensure that our operations are in full compliance with the requirements of the Surface Mining Control and Reclamation Act and the state laws and regulations governing mine reclamation.
ADDITIONAL INFORMATION
We file annual, quarterly and current reports 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: Public Relations.
ITEM 2.
ITEM 2. PROPERTIES.
Coal Reserves
We had an estimated 9.3 billion tons of proven and probable coal reserves as of March 1, 2001, of which approximately 41% is compliance coal and 59% is non-compliance coal. We own approximately 45% of these reserves and lease the remaining 55%. 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 emissions 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.
- -------------- (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 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 March 1, 2001, proven and probable reserves totaled 9.3 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 March 31, 2001, we leased or applied to lease 23,386 acres of federal land in Colorado, 11,252 acres in Montana, 30,167 acres in Wyoming for a total of 64,805 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 9.3 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.
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.
The following chart provides a summary, by mining complex, of production for fiscal years 1999, 2000 and 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)
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 MARCH 1, 2001
(Tons in millions)
- -------------- (1) Assigned reserves represent recoverable coal reserves that we have committed to mine at locations operating as of March 1, 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 Cedar Creek mine was closed in July 1998. (10) The Sugar Ridge mine opened in December 2000. (11) The Eel mine was closed in July 1998. (12) The Discovery mine was temporarily idled from April 2000 to July 2000. (13) The Somerville Central mine opened in March 2000. (14) The West Fork mine closed in August 2000. (15) The Lyons mine closed in September 1998. (16) The Rawhide mine operated at reduced production during fiscal year 1999 and suspended production in March 1999. (17) 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:
Resource Development
We hold approximately 9.3 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 actively pursuing opportunities in the area of coalbed methane extraction in the United States through a new 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.
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, with a complaint that had been filed in the U.S. District Court for the District of Columbia. Other defendants in the litigation are two customers, 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 Coal Company's two coal leases for the Kayenta and Black Mesa mines have terminated due to our 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.
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, reformation of its coal lease and a termination of the 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.
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 October 29, 2001.
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.
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 back to the Superior Court of Maricopa County, Arizona, where a trial has been set for September 11, 2001. 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. The court also ruled that the claim for the overcharges and for damages resulting from the September 2001 trial would be tried separately, following the resolution of the September 2001 trial.
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 adverse effect on our financial condition or results of operations. We had a receivable on our balance sheet at March 31, 2001 for the mine closing costs associated with the Salt River and Southern California Edison matters of $81.5 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 had improperly assigned, under the Coal Act, 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 rejected the Social Security Administration's appeal. Accordingly, we believe that the matter will be resolved without a material adverse effect on our financial condition or results of operations.
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, 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 or remediation at nine sites and is a defendant in litigation with private parties involving two additional 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.
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 $48.0 million as of March 31, 2001 for the environmental liabilities described above relating to Gold Fields that are included as part of the overall provision for reclamation and environmental liabilities in our consolidated financial statements. 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of security holders during the fourth quarter of fiscal year 2001.
PART II
ITEM 5.
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 $451.8 million. Our Common Stock is listed on the New York Stock Exchange, under the symbol "BTU."
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 51.9 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 common stock, par value $.01 per share, of which no shares are issued and outstanding. As of May 31, 2001, there were approximately 8,800 holders of our common stock.
DIVIDEND POLICY
We paid no dividends in fiscal years 2000 or 2001. We currently intend to declare and pay quarterly dividends of $0.10 per share in fiscal year 2002. 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 dividends of $25.0 million in fiscal year 2002 and annual dividends in subsequent fiscal years equal 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 equal to 6% of our net proceeds from the offering, plus additional amounts based on financial tests, although the actual amount of any dividends will be determined by our board of directors.
RECENT SALES OF UNREGISTERED SECURITIES
During the fiscal year ended March 31, 2001, 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 July 1, 2000, we issued 42,087 shares of common stock to three executives in consideration for their services.(2) Additionally, we issued 398,929 options to purchase common stock at an exercise price of $14.29(1) 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(1) 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(1) 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(1) per share to one of our executives.
Notes: (1) The exercise price of $14.29 per share reflects the 1.4-for-one stock split we effected on May 17, 2001.
(2) 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 $451.8 million after deducting total expenses of $31.2 million, comprised of the underwriters' discounts and commissions of $27.2 million and other fees and expenses of $4.0 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 of $38.0 million will be used for the repayment of debt and/or 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.
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 statements of operations, and our interest in Black Beauty's net assets within "Investments and other assets" in the balance sheets.
In anticipation of the sale of Citizens Power, which occurred in August 2000, we classified Citizens Power as a discontinued operation as of March 31, 2000, and recorded an estimated loss on the sale of $78.3 million, net of income taxes. We have adjusted our results of operations to reflect the classification of Citizens Power as a discontinued operation for all periods presented.
We have derived the selected historical financial data for our predecessor for the year ended and as of September 30, 1996, the six months ended and as of March 31, 1997, 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 and the years ended and as of March 31, 2000 and 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."
(Dollars in thousands, except per share data)
- -------------- (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 Year 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) Results of operations for the year ended September 30, 1996 included a one-time, non-cash charge of $890.8 million made pursuant to Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of." (5) 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.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
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 mining services in Brisbane, Australia. The sale price was $446.8 million in cash, plus the assumption of all liabilities including $119.4 million of debt. 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. We have changed the presentation of our historical results of operations and cash flows to reflect Citizens Power as a discontinued operation for all periods presented. The fair value of the net assets of Citizens Power is classified as a single line in the balance sheet entitled "Net assets of discontinued operations" in fiscal year 2000 only.
Fiscal Year 2000 vs. Fiscal Year 1999
Effective January 1, 2000, our 81.7%-owned subsidiary, Black Beauty, invested $6.6 million to obtain control of three of its midwestern coal mining affiliates: Sugar Camp Coal, LLC, Arclar Coal Company, LLC and United Minerals Company, LLC. Prior to fiscal year 2000, interests in these affiliates were accounted for under the equity method and effective January 1, 2000, we obtained decision-making control and began accounting for our 75% interest in the affiliates on a consolidated basis. We have elected to consolidate these affiliates as part of Black Beauty's results of operations effective April 1, 1999.
Fiscal year 2000 results also include the consolidated results of operations for Black Beauty for 12 months compared to only three months in fiscal year 1999. We increased our ownership interest in Black Beauty from 43.3% to 81.7% effective January 1, 1999. We accounted for our interest in Black Beauty under the equity method from April 1 to December 31, 1998. As a result, prior to January 1, 1999, our share of Black Beauty's results of operations was included as a component of "Other revenues" in the statements of operations, and our interest in Black Beauty's net assets was included within "Investments and other assets" in the balance sheets.
The results of operations and cash flows for the period ended March 31, 1999 reflect the combination of our results from April 1, 1998 to March 31, 1999 (we acquired our predecessor company effective May 20, 1998 and prior to that date had no prior operations) and the results of the predecessor company for April 1, 1998 to May 19, 1998. In addition, the results of operations and cash flows for the period ended March 31, 1999 may not be directly comparable to fiscal year 2000 as a result of the effects of restatement of assets and liabilities to their estimated fair market value in accordance with the application of purchase accounting under Accounting Principles Board Opinion No. 16.
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.
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 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 in fiscal year 2001 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 fiscal 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 the current year 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.
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.
FISCAL YEAR ENDED MARCH 31, 2000 COMPARED TO TOTAL FISCAL YEAR 1999
Sales. For fiscal year 2000, sales increased $361.1 million, or 16.0%, to $2.6 billion. Sales volume increased 8.1% over the prior year. The fiscal year 2000 results included an increase attributable to Black Beauty of $428.9 million, which was principally comprised of two amounts: the inclusion of Black Beauty's results for an entire year ($264.1 million) and the consolidation of Sugar Camp, Arclar and United Minerals on a retroactive basis ($164.8 million). The average sales price per ton increased 7.4% in 2000 due to this inclusion of sales of Black Beauty and its affiliates and higher prices in the Powder River Basin. Sales in Australia increased $75.5 million over total fiscal year 1999.
Powder River Basin sales increased $13.1 million, due mainly to a continuing improvement in pricing for the low sulfur coal in this region. Offsetting these increases were declines in the Midwest and Appalachia markets of $68.1 million and $53.8 million, respectively. Both regions were negatively impacted by mild winter weather that increased customer coal stockpiles, causing lower demand and pricing. Sales in the Midwest region declined primarily due to the closure and
suspension of three high sulfur mines in fiscal year 2000, while results in Appalachia were hampered by price reductions for coal utilized by the export metallurgical market, and operating difficulties related to longwall panel development delays and adverse geological conditions. Brokerage and trading revenues declined $33.5 million, mainly due to new contracts with lower prices than expiring contracts.
Other Revenues. Other revenues improved $1.9 million compared to fiscal year 1999. This increase was primarily due to a $13.0 million gain from a contract restructuring in which Black Beauty initiated the buyout of a customer's contract in order to provide additional production capacity to meet a new long-term coal supply agreement, and a $3.9 million gain on the settlement of a contract dispute in the fourth quarter of fiscal year 2000, partially offset by the exclusion of $7.5 million of equity income in affiliates subsequently consolidated by Black Beauty as discussed above.
Selling and Administrative Expenses. Selling and administrative expenses increased $6.4 million in fiscal year 2000 to $95.3 million. This increase was the result of the inclusion of a full year of Black Beauty's operations, compared to three months in fiscal year 1999 (an increase of $9.9 million) and full year consolidation of Black Beauty affiliates previously mentioned, partially offset by $13.1 million of compensation expense in fiscal year 1999 related to the grant of 992,276 shares of Class B common stock to management.
Operating Profit. Operating profit was $193.2 million for fiscal year 2000, an increase of $26.8 million, or 16.1%. The impact of Black Beauty on fiscal year 2000 results increased operating profit by $43.8 million, including a $13.0 million gain from the Black Beauty contract restructuring previously mentioned. We also had $12.8 million less stock compensation expense in fiscal year 2000 than in fiscal year 1999.
Other regions showing year-over-year improvement were the Midwest ($15.0 million), Powder River Basin ($13.2 million) and Australia ($12.8 million). The Midwest region improved over fiscal year 1999 as a result of lower reclamation costs occurring from a change in permitting requirements in fiscal year 2000 ($5.1 million), improved productivity and higher volume at the ongoing Midwestern operations, partially offset by lower volumes due to the closure/suspension of three mines in fiscal year 2000. Profit improved in the Powder River Basin based upon higher pricing and higher demand for coal from our lowest cost, most efficient operations. Our Australian operations also reported higher profit.
Offsetting these increases were decreases in Appalachia ($32.1 million) and the Southwest ($4.1 million). Profitability in Appalachia was directly impacted by soft market conditions and higher costs as a result of longwall panel development delays. The decline in the Southwest region was the result of higher operating expenses, primarily as a result of higher repair and maintenance expenses than in fiscal year 1999, offset partially by higher volumes and a gain of $3.9 million from the settlement of a customer contractual dispute. In addition, income from brokerage and trading activities decreased $19.8 million, mainly as a result of lower volumes that were directly related to contract expirations. Finally, we experienced higher costs for past mining obligations due to the fiscal year 2000 cost of mine closure and suspension in the Midwest region, and $14.0 million in higher administrative costs as a result of the inclusion of Black Beauty and its affiliates.
Interest Expense. Interest expense for fiscal year 2000 was $205.1 million, an increase of $24.8 million, or 13.8%. Fiscal year 1999 included acquisition-related indebtedness from the May 19, 1998 acquisition of our predecessor company forward. Also affecting fiscal year 2000 was the inclusion of $12.6 million of additional interest associated with the consolidation of Black Beauty.
Interest Income. Interest income decreased $15.8 million from fiscal year 1999 to $4.4 million. The decrease was primarily attributable to interest income from higher average cash balances held in fiscal year 1999 in anticipation of the acquisition of an additional ownership interest in Black Beauty that occurred late in fiscal year 1999.
Income Taxes. For fiscal year 2000, we recorded an income tax benefit of $141.5 million on a pretax loss from continuing operations of $7.4 million, compared to an income tax expense of $7.5 million on pretax income from continuing operations of $6.2 million in fiscal year 1999. The fiscal year 2000 amount reflected a $144.0 million income tax benefit associated with an election to treat Peabody Natural Resources Company, our subsidiary, as a corporation rather than as a partnership for federal income tax purposes. This election, which became available through a change in tax law that occurred in December 1999, resulted in an increase in the tax basis in the entity's assets and eliminated the necessity for a deferred tax liability that had reflected the excess of the book basis in that subsidiary over the tax basis.
Our effective book income tax rate was primarily impacted by two factors: the percentage depletion tax deduction used by us and our U.S. subsidiaries that creates an alternative minimum tax situation and the level of contribution by the Australian operations to the consolidated results of operations, which is taxed at a higher rate than in the United States.
Loss From Discontinued Operations. In fiscal year 2000, our discontinued operations reported a net loss of $12.1 million, compared to net income of $4.7 million in fiscal year 1999. The decrease was largely the result of a decline in the number of utility contract restructuring transactions completed in fiscal year 2000 compared to fiscal year 1999. In addition, fiscal year 2000 results included the estimated after-tax loss on disposal of Citizens Power of $78.3 million.
LONG-TERM COAL SUPPLY AGREEMENTS
As of March 31, 2001, nearly one billion tons of our future coal production were committed under long-term contracts. Our strategy is to selectively renew, or enter into new, long-term supply contracts when we can do so at favorable prices. Long-term contracts may be particularly attractive in regions where market prices are expected to remain stable, with respect to high sulfur coal that would otherwise not be in great demand or for sales under cost-plus arrangements serving captive electric generating plants. Prices for coal have recently risen, particularly in the Powder River Basin and in Appalachia, primarily due to increased prices for competing fuels and increased demand for electricity. 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. In the majority of these contracts, the purchaser has the right to terminate the contract if the price increases beyond certain limits, although we can usually decrease the price in order to maintain the contract.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by operating activities decreased by $110.9 million, to $152.0 million, for fiscal year 2001. The decrease in net cash provided by operating activities was primarily due to $60.0 million of lower proceeds from the sale of accounts receivable in fiscal year 2001, combined with lower operating cash flow from our Australian operations.
In March 2000, we established a five-year accounts receivable securitization program under which we sell, without recourse, on an ongoing basis, undivided interests in trade accounts receivable from our domestic subsidiaries other than Black Beauty to a multi-seller, asset-backed commercial paper conduit. The qualified pool of receivables included in the securitization program includes customers with good credit ratings and is reduced for certain items, including past due balances and specified concentration limits. The conduit's purchases are financed with the sale of highly-rated commercial paper, allowing us to lower our overall financing costs. The commercial paper is secured by high-quality current trade receivables. The qualified pool of accounts receivable subject to the program represented approximately 56% of our total accounts receivable at March 31, 2001. Outstanding undivided interests totaled $100.0 million at March 31, 2000 and $140.0 million at March 31, 2001.
Net cash provided by investing activities was $388.5 million for fiscal year 2001, an increase of $573.9 million compared to fiscal year 2000. In fiscal year 2001, we received $455.0 million in proceeds from the sale of our Australian operations and $102.5 million in net proceeds from the sale of Citizens Power, while fiscal year 2000 included higher expenditures for acquisitions, partially offset by $32.9 million in proceeds from contract restructurings.
Total capital expenditures for fiscal years 2001, 2000 and 1999 were $187.1 million, $178.8 million and $195.4 million, respectively. Of these capital expenditures, $35.7 million, $28.6 million and $71.2 million relate to our Australian operations. Our capital expenditures are primarily made to acquire additional reserves and mining equipment. We currently estimate that our capital expenditures for fiscal year 2002 will be $198.0 million and will primarily be used to acquire additional coal reserves, develop existing reserves, replace equipment and fund cost reduction initiatives. We had $94.4 million of future committed capital expenditures at March 31, 2001 that are primarily related to acquiring additional Powder River Basin coal reserves and mining equipment in fiscal year 2002. We anticipate funding these capital expenditures through available cash and credit facilities.
Net cash used in financing activities was $543.3 million for fiscal year 2001, compared to $205.2 million in fiscal year 2000. We used the net proceeds from the sales of Citizens Power and our Australian operations to repay $633.9 million of long-term debt during fiscal year 2001, an increase of $423.9 million in our debt repayments compared to fiscal year 2000.
Effective May 20, 1998, we paid The Energy Group PLC $2,003.5 million in cash for P&L Coal Group. The acquisition was financed by a $480.0 million equity contribution by Lehman Brothers Merchant Banking and affiliates and borrowings of $1,523.5 million. We also entered into a $480.0 million Senior Credit Facility to provide for our working capital requirements following the acquisition, with no initial borrowings related to financing the acquisition.
As of March 31, 2001, we had total indebtedness outstanding of $1,405.6 million that consisted of:
The following table sets forth the mandatory repayments of our indebtedness outstanding as of March 31, 2001:
Our Senior Credit Facility includes a revolving credit facility that currently provides for aggregate borrowings of up to $200.0 million and letters of credit of up to $280.0 million. The revolving credit facility commitment matures in fiscal year 2005. As of March 31, 2001, we had no borrowings outstanding under the revolving credit facility. Revolving loans under the 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. As of March 31, 2001, we had $73.4 million of letters of credit outstanding under the revolving credit facility.
The revolving credit facility and related term loan facility also currently contain restrictions and limitations including, but not limited to, financial covenants that require us to maintain and achieve certain levels of financial performance and prohibit the payment of cash dividends and similar restricted payments.
The indentures governing the Senior Notes and Senior Subordinated Notes permit us and our restricted subsidiaries to incur additional indebtedness, including secured indebtedness, subject to certain limitations. In addition, the indentures limit our ability to:
- pay dividends or make other distributions;
- 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;
- restrict our subsidiaries' ability to make dividend payments;
- merge or consolidate with any other person or enter into transactions with affiliates; and
- repurchase junior securities or make specified types of investments.
As of March 31, 2001, Black Beauty maintained a $100.0 million revolving credit facility that matures on February 28, 2002. 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. Borrowings outstanding under the Black Beauty revolving credit agreement totaled $70.0 million at March 31, 2001. The revolving credit facility contains customary restrictive covenants, including limitations on additional debt, investments and dividends. In addition, Black Beauty's ability to pay dividends is subject to certain financial tests.
Black Beauty's senior unsecured notes include $31.4 million of Senior Notes and three series of notes with an aggregate principal amount of $60.0 million as of March 31, 2001. The Senior Notes bear interest at 9.2%, payable quarterly, and are prepayable in whole or in part at any time, subject to certain make-whole provisions. The 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 fiscal year 2008. The Series B notes bear interest at an annual rate of 7.4% and are due in fiscal year 2004. The Series C notes bear interest at an annual rate of 7.4% and are due in fiscal year 2003. The senior unsecured notes contain customary restrictive covenants, including limitations on additional debt, investments and dividends.
As of March 31, 2001, the revolving and working capital borrowing facilities referred to above totaled $300.0 million, and borrowings thereunder totaled $70.0 million. We were in compliance with the restrictive debt covenants of all of our debt agreements as of March 31, 2001.
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 $47.8 million as of March 31, 2001.
On January 29, 2001, we received $455.0 million in cash, prior to post-closing adjustments of $8.2 million, from the sale of our Australian operations. Using these proceeds, we repaid the remaining $110.0 million of the tranche A term loan and $345.0 million of the tranche B term loan outstanding under our Senior Credit Facility. After giving effect to those repayments, we had no tranche A term loans outstanding and $125.0 million of tranche B term loans outstanding.
On May 22, 2001, we completed an initial public offering of 17,250,000 shares of common stock. Net proceeds from the offering were $451.8 million. In connection with the offering, we repaid 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 proceeds from the offering 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 previously announced 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 proceeds from the initial public offering of $38.0 million will be used for the repayment of additional debt and/or for general corporate purposes.
Subsequent to March 31, 2001, we received the approval from a sufficient number of our lenders to amend our Senior Credit Facility. The amendment, which became effective at the time of the offering, permits the payment of cash dividends and other restricted payments subject to specified limitations, increases the amount available for borrowing under the revolving credit facility from $200.0 million to $350.0 million and permits 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. We paid an amendment fee of $1.4 million to a group of over 100 lenders who consented to the amendment. All other terms and conditions remained unchanged.
Black Beauty replaced its $100.0 million revolving credit facility with a new $120.0 million revolving credit facility on April 16, 2001. The new facility contains substantially similar restrictive covenants and matures on April 17, 2004. Borrowings outstanding under the $100.0 million revolving credit facility on April 16, 2001 were refinanced under the new $120.0 million revolving credit facility.
CERTAIN LIABILITIES
We have significant long-term liabilities relating to mine reclamation, work-related injuries and illnesses, pensions and retiree health care. Accruals for these liabilities reflect U.S. coal industry and generally accepted accounting principles. Our operations and the operations of our predecessor subject us to liability for the investigation and remediation of releases of hazardous substances into the environment and for damages to natural resources under Superfund and similar state laws. The
majority of our existing liabilities relate to our past operations, which had more mines and employees than we currently have. Our aggregate cash payments for these liabilities for fiscal year 2001 were $149.0 million.
In connection with the sale of Citizens Power, we have indemnified the buyer from certain losses resulting from specified power contracts and guarantees. No claims have been asserted against us under this indemnity.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities." Statement of Financial Accounting Standards No. 133 (as amended by Statement of Financial Accounting Standards Nos. 137 and 138) requires the recognition of all derivatives as assets or liabilities within the balance sheet and requires both the derivatives and the underlying exposure to be recorded at fair value. Any gain or loss resulting from changes in fair value will be recorded as part of the results of operations, or as a component of comprehensive income or loss, depending upon the intended use of the derivative. The effective date of Statement of Financial Accounting Standards No. 133 is for all fiscal quarters of fiscal years beginning after June 15, 2000 (effective April 1, 2001 for us). We do not anticipate that the adoption of Statement of Financial Accounting Standards No. 133 will have a material effect on our financial condition or results of operations, subject to new or revised implementation guidelines issued by the Derivatives Implementation Group.
INVESTMENT CONSIDERATIONS
Reliance on Long-Term Coal Supply Agreements
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 fiscal year 2001, 85% of our sales volume was sold under long-term coal supply agreements. At March 31, 2001, our coal supply agreements had remaining terms ranging from one to 16 years and an average volume-weighted remaining term of 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. Over the last few 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 have recently increased in most regions, we cannot predict whether the current 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, two of our coal supply agreements are the subject of ongoing litigation and arbitration.
Dependence on Major Customers
For fiscal year 2001, we derived 36% of our total coal revenues from sales to our five largest customers. At March 31, 2001, we had 18 coal supply agreements with these customers that expire at various times from 2001 to 2015. We are currently discussing the extension of existing agreements or entering into new long-term agreements with some of these customers, but these negotiations may not be 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.
Substantial Leverage
Our financial performance could be affected by our substantial indebtedness. As of March 31, 2001, we had total indebtedness of $1,405.6 million that subsequently was reduced by $415.0 million from proceeds of the initial public offering. In addition, after consummation of the offering we 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 to you, 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.
Transportation
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
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.
Government Regulation of the Mining Industry
Federal, state and local authorities regulate the coal mining industry with respect to matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence from underground mining and the effects that mining has on groundwater quality and availability. In addition, significant legislation mandating specified benefits for retired coal miners affects our industry. Numerous governmental permits and approvals are required for mining operations. We are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be costly and time-consuming and may delay commencement or continuation of exploration or production 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.
Kyoto Protocol
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 1999, coal accounts for 30% 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.
Postretirement Benefit and Pension Obligations
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 $1,036.1 million as of March 31, 2001, of which $62.0 million was a current liability. We have estimated these unfunded obligations based on assumptions described in Note 14 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.
Replacement and Recoverability of Reserves
Our recoverable reserves decline as we produce coal. We have not yet applied for the permits required or developed the mines necessary to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our future success depends upon our conducting successful exploration and development activities or acquiring properties containing economically recoverable reserves. Our current strategy includes increasing our reserve base through acquisitions of government and other leases and producing properties and continuing to use our existing properties. The federal government also leases natural gas and coalbed methane reserves in the west, including in the Powder River Basin. Some of these natural gas and coalbed methane reserves are located on, or adjacent to, some of our Powder River Basin reserves, potentially creating conflicting interests between us and lessees of those interests. Other lessees' rights relating to these mineral interests could prevent, delay or increase the cost of developing our coal reserves. These lessees may also seek damages from us based on claims that our coal mining operations impair their interests. Additionally, the federal government limits the amount of federal land that may be leased by any company to 150,000 acres nationwide. We currently lease or have applied to lease a total of 64,805 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 "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.
Coal Industry Capacity
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.
Labor Force
As of March 31, 2001, the United Mine Workers of America represented approximately 37% of our employees, who produced 23% of our coal sales volume in the United States during fiscal year 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, 2002. The United Mine Workers of America has indicated an interest in seeking early negotiations for a new contract, although none of the parties are required to do so. Peabody Western Coal Company operates under a union contract that is in effect through September 1, 2005.
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 and to satisfy other miscellaneous obligations. As of March 31, 2001, we had outstanding surety bonds with third parties for post-mining reclamation totaling $651.8 million. Furthermore, we have an additional $77.4 million of surety bonds in place for our federal and state workers' compensation obligations and other miscellaneous obligations. 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:
- lack of availability, higher expense or unfavorable market terms of new surety bonds;
- restrictions on the availability of collateral for current and future third-party surety bond issuers under the terms of our indentures or Senior Credit Facility; and
- the exercise by third-party surety bond issuers of their right to refuse to renew the surety.
Lehman Brothers Merchant Banking
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, 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 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.
Dependence on Key Personnel
We manage our business with a number of key personnel, in particular the executive officers discussed in "Item 10 - Directors and Executive Officers of the Registrant," the loss of a number of whom could have a material adverse effect on us. In addition, as our business develops and expands, we believe that our future success will depend greatly on our continued ability to attract and retain highly skilled and qualified personnel. We cannot assure you that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. We do not have "key person" life insurance to cover our executive officers. Failure to retain or attract key personnel could have a material adverse effect on us.
ITEM 7A.
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 attempt to control market risks to ensure compliance with management policies. 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 our consolidated financial statements.
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 approximately 85% of our sales volume under long-term coal supply agreements during fiscal year 2001. Over the next few years, we anticipate that an increasing portion of our coal sales will be made at then-current market prices rather than under long-term coal supply agreements. As a result, our revenues will be increasingly affected by fluctuations in the price of coal.
Some of the products used in our mining activities, such as diesel fuel, are subject to price volatility. We use forward contracts to manage the volatility related to this exposure.
We have exposure to changes in interest rates due to our existing level of indebtedness. As of March 31, 2001, we had $1,161.1 million of fixed-rate borrowings and approximately $244.5 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of approximately $2.4 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a 1% increase in interest rates would result in a $61.3 million decrease in the fair value of these borrowings.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT AUDITORS
Board of Directors Peabody Energy Corporation
We have audited the accompanying consolidated balance sheets of Peabody Energy Corporation (the Company), formerly P&L Coal Holdings Corporation, as of March 31, 2001 and 2000, and the related consolidated statements of operations, changes in stockholders' equity and cash flows of the Company for the years then ended and the period from May 20, 1998 to March 31, 1999. We have also audited the combined statements of operations, changes in invested capital and cash flows of P&L Coal Group (the Predecessor Company) for the period from April 1, 1998 to May 19, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Peabody Energy Corporation at March 31, 2001 and 2000, the consolidated results of operations and cash flows of the Company for the years ended March 31, 2001 and 2000 and the period from May 20, 1998 to March 31, 1999, and the combined results of operations and cash flows of the Predecessor Company for the period from April 1, 1998 to May 19, 1998 in conformity with accounting principles generally accepted in the United States.
ERNST & YOUNG LLP
St. Louis, Missouri April 20, 2001 except for the fourth paragraph of Note 1 as to which the date is May 17, 2001
PEABODY ENERGY CORPORATION
STATEMENTS OF OPERATIONS (DOLLARS IN THOUSANDS, EXCEPT SHARE DATA)
See accompanying notes to financial statements.
PEABODY ENERGY CORPORATION
BALANCE SHEETS (DOLLARS IN THOUSANDS, EXCEPT SHARE DATA)
See accompanying notes to financial statements.
PEABODY ENERGY CORPORATION
STATEMENTS OF CASH FLOWS (DOLLARS IN THOUSANDS)
(Continued on following page)
See accompanying notes to financial statements.
PEABODY ENERGY CORPORATION
STATEMENTS OF CASH FLOWS (CONTINUED) (DOLLARS IN THOUSANDS)
See accompanying notes to financial statements.
PEABODY ENERGY CORPORATION
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY/INVESTED CAPITAL (DOLLARS IN THOUSANDS, EXCEPT SHARE DATA)
See accompanying notes to financial statements.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS (DOLLARS IN THOUSANDS, EXCEPT WHERE NOTED AND PER SHARE DATA)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The consolidated financial statements include the consolidated balance sheets of Peabody Energy Corporation (the "Company" or "Peabody") as of March 31, 2001 and 2000, and the consolidated results of operations and cash flows for the years ended March 31, 2001 and 2000 and the period from May 20, 1998 to March 31, 1999 (hereafter referred to as the "period ended March 31, 1999"). These financial statements include the subsidiaries (collectively, known as the "Predecessor Company" or "P&L Coal Group") of Peabody Holding Company, Inc. ("Peabody Holding Company"), Gold Fields Mining Corporation ("Gold Fields") which owns Lee Ranch Coal Company ("Lee Ranch"), Citizens Power LLC ("Citizens Power") and Peabody Resources Limited ("Peabody Resources"), an Australian company. The combined financial statements include the combined results of operations and cash flows of the Predecessor Company from April 1, 1998 to May 19, 1998 (hereafter referred to as the "period ended May 19, 1998"). P&L Coal Holdings Corporation, a holding company that was formed by Lehman Brothers Merchant Banking Partners II L.P. ("Lehman Brothers Merchant Banking") on February 27, 1998, acquired P&L Coal Group from The Energy Group PLC effective May 20, 1998. Lehman Brothers Merchant Banking is an investment fund affiliated with Lehman Brothers Inc.
In May 2000, the Company signed a purchase and sale agreement with Edison Mission Energy to sell Citizens Power (see Note 4). Results of operations and cash flows for all periods presented reflect Citizens Power as a discontinued operation. In January 2001, the Company sold its Australian operations (see Note 3).
On April 10, 2001, the Company changed its name from P&L Coal Holdings Corporation to Peabody Energy Corporation.
Stock Split
On May 17, 2001, the Company effected a 1.4-for-one stock split of its preferred and common stock. All references to number of shares, per share amounts and stock option data have been restated to reflect the stock split.
Description of Business
The Company is principally engaged in the mining of coal for sale primarily to electric utilities. The Company also markets and trades coal and emission allowances.
New Pronouncements
Effective April 1, 1998, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income." SFAS No. 130 requires that noncash changes in stockholders' equity be combined with net income and reported in a new financial statement category entitled "accumulated other comprehensive income."
The Company also adopted SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information" and SFAS No. 132, "Employers' Disclosures About Pensions and Other Postretirement Benefits" effective April 1, 1998. SFAS No. 131 and SFAS No. 132, address the disclosures required for the Company's operating segments and employee benefit obligations, respectively.
The adoption of SFAS Nos. 130, 131 and 132 had no effect on the Company's financial condition or results of operations.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 (as amended by SFAS Nos. 137 and 138) requires the recognition of all derivatives as assets or liabilities within the balance sheet and requires both the derivatives and the underlying exposure to be recorded at fair value. Any gain or loss resulting from changes in fair value will be recorded as part of the results of operations, or as a component of comprehensive income or loss, depending upon the intended use of the derivative. The effective date of SFAS No. 133 is fiscal years beginning after June 15, 2000 (effective April 1, 2001 for the Company). The Company does not anticipate that the adoption of SFAS No. 133 will have a material effect on its financial condition or results of operations, subject to new or revised implementation guidelines issued by the Derivatives Implementation Group.
Joint Ventures
Joint ventures are accounted for using the equity method except for undivided interests in Australia, which, prior to its sale in January 2001, was reported using pro rata consolidation whereby the Company reported its proportionate share of assets, liabilities, income and expenses. All significant intercompany transactions have been eliminated in consolidation.
The financial statements include the following asset and operating amounts for Australian entities utilizing pro rata consolidation (dollars in thousands):
Accounting for Coal and Emission Allowance Trading
The Company engages in risk management activities for both trading and non-trading purposes. Activities for trading purposes, generally consisting of coal and emission allowance trading, are accounted for using the fair value method. Under such method, the derivative commodity instruments (forwards, options and swaps) with third parties are reflected at market value and are included in "Assets and liabilities from coal and emission allowance trading activities" in the consolidated balance sheets. In the absence of quoted values, financial commodity instruments are valued at fair value, considering the net present value of the underlying sales and purchase obligations, volatility of the underlying commodity, appropriate reserves for market and credit risks and other factors, as determined by management. Subsequent changes in market value are recognized as gains or losses in "Other revenues" in the period of change.
As a writer of options, the Company receives a premium when the option is written and then bears the risk of unfavorable changes in the price of the financial instruments underlying the option. Forwards, swaps and over-the-counter options are traded in unregulated markets.
Over-the-counter forwards, options and swaps are either liquidated with the same counterparty or held to settlement date. For these financial instruments, the unrealized gains or losses on financial settlements, rather than the contract amounts, represent the approximate future cash requirements. Realized gains and losses on trading activities are recorded as part of "Other revenues" as they occur. Physical settlements are recorded on a gross basis within "Sales" and "Operating costs and expenses."
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
Derivative Financial Instruments
A portion of the Company's long-term indebtedness bears interest at rates that fluctuate based upon certain indices. The Company utilizes financial instruments, such as interest rate swap agreements, to mitigate the impact of changes in interest rates on a portion of its floating rate debt. Gains or losses on interest rate swap agreements are recognized as they occur and are included as a component of interest expense.
Prior to the sale in January 2001, the Company's Australian operations used forward currency contracts to manage their exposure against foreign currency fluctuations on sales denominated in U.S. dollars. These financial instruments were accounted for using the deferral method. Changes in the market value of these transactions were deferred until the gain or loss on the underlying hedged item was recognized as part of the related transaction. If the future sale was no longer anticipated, the changes in market value of the forward currency contracts were recognized as an adjustment to revenue in the period of change.
Revenue Recognition
The Company incurs certain "add-on" taxes and fees on coal sales. Coal sales are reported including taxes and fees charged by various federal and state governmental bodies. The Company recognizes revenue from coal sales when title passes to the customer.
Other Revenues
Other revenues include royalties related to coal lease agreements, earnings and losses from joint ventures, management fees, farm income, contract restructuring payments, coalbed methane extraction, coal and emission allowance trading activities and revenues from contract mining services. Royalty income generally results from the lease or sub-lease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced. Certain agreements require minimum annual lease payments regardless of the extent to which minerals are produced from the leasehold. The terms of these agreements generally range from specified periods of five to 20 years, or can be for an unspecified period until all reserves are depleted.
Revenues from coal trading activities are recognized for the differences between contract and market prices.
Cash and Cash Equivalents
Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with original maturities of three months or less.
Inventories
Materials and supplies and coal inventory are valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs, operating overhead and other related costs.
Property, Plant, Equipment and Mine Development
Property, plant, equipment and mine development are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period, including $0.3 million and $1.8 million for the years ended March 31, 2001 and 2000, respectively, and $3.0 million and $0.2 million for the periods ended March 31, 1999 and May 19, 1998, respectively.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
Expenditures which extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs are charged to operating costs as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Costs incurred to maintain current production capacity at a mine and exploration expenditures are charged to operating costs as incurred. Certain costs to acquire computer hardware and the development and/or purchase of software for internal use are capitalized and depreciated over the estimated useful lives.
The fair value of coal reserves was established by an independent third party review and evaluation at the time of the Company's acquisition in May 1998. Reserves acquired subsequent to that date are recorded at cost. At March 31, 2001, the net book value of coal reserves totaled $3.5 billion. This amount includes $1.3 billion attributable to properties where the Company is not currently engaged in mining operations or leasing to third parties and, therefore, the coal reserves are not currently being depleted.
Depletion of coal interests is computed using the units-of-production method utilizing only proven and probable reserves in the depletion base. Mine development costs are principally amortized over the estimated lives of the mines using the straight-line method. Depreciation of plant and equipment (excluding life of mine assets) is computed using the straight-line method over the estimated useful lives as follows:
In addition, certain plant and equipment assets associated with mining are depreciated using the straight-line method over the estimated life of the mine, which varies from three to 24 years.
Accrued Reclamation and Other Environmental Liabilities
The Company records a liability for the estimated costs to reclaim land as the acreage is disturbed during the ongoing surface mining process. The estimated costs to reclaim support acreage and to perform other related functions at both surface and underground mines are recorded ratably over the lives of the mines. As of March 31, 2001, the Company had $651.8 million in surety bonds outstanding to secure reclamation obligations or activities. The amount of reclamation self-bonding in certain states in which the Company qualifies was $216.5 million as of March 31, 2001.
Accruals for other environmental matters are recorded in operating expenses when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Accrued liabilities are exclusive of claims against third parties and are not discounted. In general, costs related to environmental remediation are charged to expense.
Income Taxes
Income taxes are accounted for using a balance sheet approach known as the liability method. The liability method accounts for deferred income taxes by applying statutory tax rates in effect at the date of the balance sheet to differences between the book and tax basis of assets and liabilities.
Postemployment Benefits
The Company provides postemployment benefits to qualifying employees, former employees and dependents under the provisions of various benefit plans or as required by state or federal law. The Company accounts for workers' compensation obligations and other Company-provided postemployment benefits on the accrual basis of accounting.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
Earnings Per Share
The Company has two classes of common stock and, as such, applies the "two-class method" of computing earnings per share as prescribed in SFAS No. 128, "Earnings Per Share." In accordance with SFAS No. 128, income or loss is allocated to preferred stock, Class A common stock and Class B common stock on a pro-rata basis.
Basic earnings (loss) per share is calculated by dividing income (loss) from continuing operations, income (loss) from discontinued operations, extraordinary loss from early extinguishment of debt and net income, respectively, that is attributed to the Company's Class A and Class B common shares by the weighted average number of common shares outstanding for each class of common stock for each respective period. Diluted earnings (loss) per share is calculated by dividing income from continuing operations, income (loss) from discontinued operations, extraordinary loss from early extinguishment of debt and net income, respectively, that is attributed to the Company's Class A and Class B common shares by the weighted average number of common and common equivalent shares outstanding for each class of common stock for each respective period. Any potential difference between basic and diluted earnings (loss) per share is solely attributable to stock options. For the years ended March 31, 2001 and 2000 and the period ended March 31, 1999 all options (for 5.2 million shares, 5.2 million shares and 5.3 million shares, respectively) were excluded from the diluted earnings per share calculations for the Company's Class A and Class B common stock because they were anti-dilutive. A reconciliation of income (loss) from continuing operations, income (loss) from discontinued operations, extraordinary loss from early extinguishment of debt and net income follows:
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
Concentration of Credit Risk and Market Risk
The Company's power, coal and emission allowance trading and risk management activities give rise to market risk, which represents the potential loss caused by a change in the market value of a particular commitment. Market risks are actively monitored to ensure compliance with the risk management policies of the Company. Policies are in place that limit the Company's total net exposure at any point in time. Procedures exist which allow for monitoring of all commitments and positions, with daily reporting to senior management.
The Company's concentration of credit risk is substantially with energy producers and marketers and electric utilities. The Company's policy is to independently evaluate each customer's creditworthiness prior to entering into transactions and to constantly monitor the credit extended. In the event that the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company will protect its position by requiring the counterparty to provide appropriate credit enhancement. Counterparty risk with respect to interest rate swap transactions is not considered to be significant based upon the creditworthiness of the participating financial institutions.
Approximately 37% of the Company's U.S. coal employees are affiliated with organized labor unions, which accounts for approximately 23% of sales volume in the U.S. during fiscal year 2001. Hourly workers at the Company's mines in Arizona, Colorado and Montana are represented by the United Mine Workers' of America under the Western Surface Agreement, which was ratified in 2000 and is effective through September 1, 2005. Union labor east of the Mississippi is also represented by the United Mine Workers of America but is subject to the National Bituminous Coal Wage Agreement. On December 16, 1997, this five-year labor agreement effective from January 1, 1998 to December 31, 2002, was ratified by the United Mine Workers of America.
Use of Estimates in the Preparation of the Financial Statements
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Impairment of Long-Lived Assets
The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets under various assumptions are less than the carrying amounts of those assets. Impairment losses are measured by comparing the estimated fair value of the assets to their carrying amount.
Foreign Currency Translation
Assets and liabilities of foreign affiliates are generally translated at current exchange rates, and related translation adjustments are reported as a component of comprehensive income. Income statement accounts are translated at an average rate for each period. The Company sold its Australian mining operations in January 2001.
Reclassifications
Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended March 31, 2001, with no effect on previously reported net income or stockholders' equity.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(2) BUSINESS COMBINATIONS
Black Beauty Coal Company
Effective January 1, 1999, the Company purchased an additional 38.3% interest in Black Beauty Coal Company ("Black Beauty"), raising its ownership percentage to 81.7%. Total consideration paid for the additional interest was $150.7 million. The acquisition was accounted for as a purchase and, accordingly, the operating results of Black Beauty have been included in the Company's financial statements since the effective date of acquisition. Prior to the acquisition, the Company accounted for its ownership using the equity method of accounting.
Effective January 1, 2000, Black Beauty invested $6.6 million to increase its ownership interest and obtain control of three of its Midwestern coal mining affiliates--Sugar Camp Coal, LLC, Arclar Coal Company, LLC and United Minerals Company, LLC. Prior to fiscal year 2000, interests in these affiliates were accounted for under the equity method, and effective January 1, 2000, the Company obtained decision-making control and began accounting for its 75% interest in the affiliates on a consolidated basis. The Company has elected to consolidate these affiliates as part of Black Beauty's results of operations effective April 1, 1999.
Peabody Resources
Effective August 20, 1999, Peabody Resources purchased a 55% interest in the Moura Mine in Queensland, Australia for $30.2 million. The acquisition was accounted for as a purchase and the operating results were included in the Company's financial statements since the date of acquisition using pro rata consolidation. The Moura Mine was included in the sale of the Australian operations in January 2001.
P&L Coal Group
Effective May 20, 1998, the Company paid The Energy Group PLC $2,003.5 million in cash for P&L Coal Group. The acquisition was financed by a $480.0 million equity contribution by Lehman Brothers Merchant Banking and affiliates and borrowings of $1,523.5 million.
The acquisition has been accounted for under the purchase method of accounting. Historical assets received of $6,406.6 million were increased to a fair value of $7,252.4 million. Historical liabilities assumed of $4,909.2 million were increased to a fair value of $5,248.9 million. Fair value adjustments to liabilities consist primarily of recognition of restructuring liabilities that are discussed in Note 15, an increase in the fair value of long-term debt assumed, the elimination of actuarial gains, losses and deferrals, adjustments to conform foreign entities to U.S. generally accepted accounting principles and the deferred income tax effects of purchase accounting. The fair value of liabilities assumed included an estimated $75.0 million of transaction fees.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
Below are the balance sheet of Peabody Energy Corporation (including the effect of acquisition financing), the Company's historical balance sheet at May 19, 1998, purchase accounting adjustments and the opening balance sheet.
The Company finalized its purchase price allocation at March 31, 1999 based upon the receipt of all the information it had arranged to obtain in order to complete its estimates. This included independent appraisals on property, plant, equipment and mine development (including land and coal interests) and actuarial valuations supporting final adjustments to its employee-related liabilities. In addition, agreement on the final purchase price was reached with The Energy Group PLC.
The following unaudited pro forma results of operations assumed the acquisitions had occurred as of April 1, 1998:
(3) SALE OF AUSTRALIAN OPERATIONS
On January 29, 2001, the Company sold its 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. The selling price represents the $455.0 million original contract price at January 29, 2001 less an $8.2 million purchase price adjustment. The Company used the proceeds from the sale to repay long-term debt.
The pretax gain on sale of $171.7 million is included in the statement of operations for the year ended March 31, 2001. The gain on sale was $124.2 million on an after-tax basis.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(4) DISCONTINUED OPERATIONS
On March 13, 2000 the Board of Directors authorized management to sell Citizens Power, its wholly-owned subsidiary that engaged in power trading and power contract restructuring transactions. Subsequent to March 31, 2000, the Company signed an agreement to sell Citizens Power to Edison Mission Energy. As of March 31, 2000, the Company estimated its loss on disposal of the entity to be $109.5 million on a pretax basis ($78.3 million after-tax), which included an $8.0 million pretax provision for expected operating losses through the expected disposal date. The Company completed the sale of operations and the monetization of non-trading assets held by Citizens Power in March 2001, resulting in an after-tax decrease to the loss on disposal of $12.9 million.
As a result of the estimated loss on the disposal of the entity, the results of operations of Citizens Power were reported separately as a discontinued operation in the statements of operations for all periods presented, and are summarized as follows (dollars in thousands):
The fair value of net assets related to the discontinued operation were segregated in the March 31, 2000 consolidated balance sheet and include the following (dollars in thousands):
(5) ACCOUNTS RECEIVABLE SECURITIZATION
In March 2000, the Company and its wholly-owned, bankruptcy-remote subsidiary ("Seller") established a five-year accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been contributed to the Seller are sold, without recourse, to a multi-seller, asset backed commercial paper conduit ("Conduit"). Purchases by the Conduit are financed with the sale of highly rated commercial paper. The Company utilized proceeds from the sale of its accounts receivable to repay long-term debt, effectively reducing its overall borrowing costs. The funding cost of the securitization program for fiscal year 2001 was $8.7 million.
Under the provisions of 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 and $100.0 million at March 31, 2001 and March 31, 2000, respectively.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
The Seller is a separate legal entity from the Company. The Seller's assets are available first and foremost to satisfy the claims of its creditors. Eligible receivables, as defined in the securitization agreement, consist of trade receivables from our domestic subsidiaries, excluding Black Beauty, reduced for certain items, including past due balances and concentration limits. Of the eligible pool of receivables contributed to the Seller, undivided interests in only a portion of the pool are sold to the Conduit. The portion of eligible receivables not sold to the Conduit remain an asset of the Seller ($50.9 million as of March 31, 2001). The Seller's interest in these receivables is subordinate to the Conduit's interest in the event of default under the securitization agreement.
(6) COAL INVENTORY
Coal inventory consisted of the following as of March 31:
Raw coal represents coal stockpiles that may be sold in current condition or may be further processed prior to shipment to a customer. Work in process consists of the costs to remove overburden above an unmined coal seam as part of the surface mining process. These costs include labor, supplies, equipment costs and operating overhead, and are charged to operations as coal from the seam is sold.
(7) LEASES
The Company leases equipment and facilities under various noncancelable lease agreements. Certain lease agreements require the maintenance of specified ratios and contain restrictive covenants which limit indebtedness, subsidiary dividends, investments, asset sales and other Company actions. Rental expense under operating leases was $60.4 million and $55.7 million for the years ended March 31, 2001 and 2000, respectively, and $34.6 million and $5.4 million for the periods ended March 31, 1999 and May 19, 1998, respectively. The net book value of property, plant, equipment and mine development assets under capital leases was $2.2 million and $24.9 million at March 31, 2001 and 2000, respectively.
The Company also leases coal reserves under agreements that require royalties to be paid as the coal is mined. Certain agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year. Total royalty expense was $163.9 million and $164.2 million for the years ended March 31, 2001 and 2000, respectively and $123.2 million and $17.3 million for the periods ended March 31, 1999 and May 19, 1998, respectively.
A substantial amount of the coal mined by the Company is produced from reserves leased from the owner of the coal. One of the major lessors is the U.S. government, from which the Company leases substantially all of the coal it mines in Wyoming, Montana and Colorado under terms set by Congress and administered by the U.S. Bureau of Land Management. The terms of these leases are generally for an initial term of ten years but may be extended by diligent development and mining of the reserve until all economically recoverable reserves are depleted. The Company has met the diligent development requirements for substantially all of these federal leases either directly through production or by including the lease as a part of a logical mining unit with other leases upon which development has occurred. Annual production on these federal leases must total at least 1% of the original amount of coal in the entire logical mining unit. Royalties are payable monthly at a rate of 12.5% of the gross realization from the sale of the coal mined using surface mining methods and at a rate of 8.0% of the gross realization for coal produced using underground mining methods. The Company also leases the coal production at its Arizona mines from The Navajo Nation and the Hopi Tribe under leases that are administered by the U.S. Department of the Interior. These leases expire once mining activities cease. The royalty rates are also generally based upon a percentage of the gross realization from the sale of coal. These rates are subject to redetermination every ten years under the terms of the leases. The remainder of the leased coal is
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
generally leased from state governments, land holding companies and various individuals. The duration of these leases varies greatly. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal.
In fiscal years 2001 and 2000, the Company sold certain assets for $28.8 million and $34.2 million, respectively, and those assets were leased back under operating lease agreements from the purchasers over a period of seven to 13 years. No gains were recognized on these transactions. Each lease agreement contains renewal options at lease termination and purchase options at amounts approximating fair market value during the lease and at lease termination.
Future minimum lease and royalty payments as of March 31, 2001 are as follows:
(8) ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses consisted of the following as of March 31:
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(9) INCOME TAXES
Pretax income (loss) from continuing operations consisted of the following (dollars in thousands):
Total income tax provision (benefit) from continuing operations consisted of the following (dollars in thousands):
The deferred tax benefit for the year ended March 31, 2000 includes the effect of a change in tax regulations and statutes in that current period which allowed the Company to make a tax election to treat a wholly-owned partnership as a corporation. The election eliminated a $144.0 million deferred tax liability previously recognized pursuant to the provisions of SFAS No. 109 on the "outside tax basis," which represents the tax effected difference between the book value and the tax basis of the investment in the partnership interest. The election allowed the Company to treat the partnership as a corporation and look to the "inside tax basis," which represents the tax effected difference between the book value of the assets and liabilities recorded on the balance sheet of the partnership and the tax basis of the individual assets and liabilities. The Company recognized a deferred tax benefit of $144.0 million in the year ended March 31, 2000 related to this election.
The non U.S. deferred tax provision for the year ended March 31, 2000 included a benefit of $3.2 million due to changes in the Australian tax rate from 36% to 34% effective April 1, 2000.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
The income tax rate on income (loss) from continuing operations differed from the U.S. federal statutory rate as follows (dollars in thousands):
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and liabilities consisted of the following as of March 31:
The Company's deferred tax assets include alternative minimum tax ("AMT") credits of $50.6 million and net operating loss ("NOL") carryforwards of $207.2 million at March 31, 2001. The AMT credits have no expiration date and the NOL carryforwards expire beginning in the year 2019. The AMT credits and NOL carryforwards are offset by a valuation allowance of $177.5 million.
The Company made U.S. federal tax payments totaling $0.2 million and $0.3 million for the years ended March 31, 2001 and 2000, respectively. No payments for U.S. federal taxes were made for the periods ended March 31, 1999 or May 19, 1998. The Company paid state and local income taxes totaling $0.1 million and $0.6 million for the years ended March 31, 2001 and 2000, respectively, and $0.7 million for the period ended March 31, 1999. The Company made no state or local income tax payments were made for the period ended May 19, 1998.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
Non U.S. tax payments were $19.1 million and $8.8 million for the years ended March 31, 2001 and 2000, respectively and $11.9 million and $0.3 million for the periods ended March 31, 1999 and May 19, 1998, respectively.
(10) SHORT-TERM BORROWINGS
The Company was not obligated for any short-term borrowings at March 31, 2001. Short-term borrowings were $9.9 million at March 31, 2000.
The Company maintains a Revolving Credit Facility that provides for aggregate borrowings of up to $200.0 million and letters of credit of up to $280.0 million. Interest rates on the revolving loans under the Revolving Credit Facility are based on the Base Rate (as defined in the Senior Credit Facilities) or LIBOR (as defined in the Senior Credit Facilities) at the Company's option. The applicable rate was 6.3% at March 31, 2001. The Revolving Credit Facility commitment matures in fiscal year 2005. As of March 31, 2001, the Company had $73.4 million of letters of credit outstanding under the Revolving Credit Facility.
Interest paid was $1.4 million and $2.1 million for the years ended March 31, 2001 and 2000, respectively and $1.4 million and $0.2 million for the periods ended March 31, 1999 and May 19, 1998, respectively. As of March 31, 2001 and 2000, Lehman Commercial Paper Inc. had committed to provide $18.9 million and $23.3 million of the Company's total available borrowing capacity under the Revolving Credit Facility.
(11) LONG-TERM DEBT
Long-term debt consisted of the following as of March 31:
The Senior Credit Facilities are secured by a first priority lien on certain assets of the Company and its domestic subsidiaries. During fiscal year 2001, the Company made optional prepayments of $565.0 million on the Senior Credit Facilities, which it applied against mandatory Term Loan A and B payments in order of maturity. As a result of the prepayments, the Company recorded an extraordinary loss on debt extinguishment of $8.5 million, net of income taxes. As of March 31, 2001 and 2000, Lehman Brothers Inc.'s and its affiliates' share of the Company's term loans outstanding under the Senior Credit Facilities was $1.8 million and $1.9 million, respectively.
During fiscal year 2001, the Company terminated its interest rate swap agreements and realized a net gain of approximately $5.1 million which has been included as a component of interest expense for the year ended March 31, 2001. In fiscal years 2000 and 1999, the Company maintained interest rate swap agreements to fix the interest cost on $500 million of long-term debt outstanding under the Term Loan Facility.
The Senior Subordinated Notes are general unsecured obligations of the Company and are subordinate in right of payment to all existing and future senior debt (as defined), including borrowings under the Senior Credit Facilities and the Senior Notes. The
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
Senior Notes are general unsecured obligations of the Company, rank senior in right of payment to all subordinated indebtedness (as defined) and rank equally in right of payment with all current and future unsecured indebtedness of the Company. As of March 31, 2001 and 2000, Lehman Brothers Inc.'s and its affiliates' share of the Company's Senior Notes outstanding was $1.1 million and $3.9 million, respectively. As of March 31, 2001 and 2000, Lehman Brothers Inc.'s and its affiliates' share of the Company's Senior Subordinated Notes outstanding was $8.9 million and $12.4 million, respectively.
The indentures governing the Senior Notes and Senior Subordinated Notes permit the Company and its Restricted Subsidiaries to incur additional indebtedness, including secured indebtedness, subject to certain limitations. In addition, among other customary restrictive covenants, the indentures prohibit the Company and its Restricted Subsidiaries from creating or otherwise causing any encumbrance or restriction on the ability of any Restricted Subsidiary that is not a Guarantor to pay dividends or to make certain other upstream payments to the Company or any of its Restricted Subsidiaries (subject to certain exceptions). The Revolving Credit Facility and related term loans also contain certain restrictions and limitations including, but not limited to, financial covenants that will require the Company to maintain and achieve certain levels of financial performance and limit the payment of cash dividends and similar restricted payments. In addition, the Senior Credit Facilities prohibit the Company from allowing its Restricted Subsidiaries (which include all Guarantors) to create or otherwise cause any encumbrance or restriction on the ability of any such Restricted Subsidiary to pay any dividends or make certain other upstream payments subject to certain exceptions. At March 31, 2001, restricted net assets of the Company's consolidated subsidiaries was $500.0 million.
The 5.0% Subordinated Note, which had an original face value of $400.0 million, is recorded net of discount at an effective annual interest rate of approximately 12.0%. Interest and principal are payable each March 1 and scheduled principal payments of $20.0 million per year are due from 2002 through 2006 with any unpaid amounts due March 1, 2007. The 5.0% Subordinated Note is expressly subordinated in right of payment to all prior indebtedness (as defined), including borrowings under the Senior Credit Facilities and the Senior Notes.
The senior unsecured notes represent obligations of Black Beauty and include $31.4 million of Senior Notes and three series of notes with an aggregate principal amount of $60.0 million. The Senior Notes bear interest at 9.2%, payable quarterly, and are prepayable in whole or in part at any time, subject to certain make-whole provisions. The 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 fiscal year 2008. The Series B Notes bear interest at an annual rate of 7.4% and are due in fiscal year 2004. The Series C Notes bear interest at an annual rate of 7.4% and are due in fiscal year 2003.
At March 31, 2001, Black Beauty maintained a $100.0 million revolving credit facility with several banks that matures on February 28, 2002. Black Beauty may elect one or a combination of interest rates on its borrowings; the effective annual interest rate was 8.0% at March 31, 2001. Borrowings outstanding at March 31, 2001 were $70.0 million. Quarterly commitment fees are paid on the unused portion of the facility at a 0.16% rate.
Other long-term debt at March 31, 2000 included a project finance facility and capital lease obligations totaling $98.9 million related to the Company's Australian operations. Other, principally notes payable at March 31, 2001, is due in installments through 2006 with a weighted average effective interest rate of 7.6%.
The aggregate amounts of long-term debt maturities subsequent to March 31, 2001 are as follows (dollars in thousands):
The amount of interest paid was $184.6 million and $196.9 million for the years ended March 31, 2001 and 2000, respectively and $138.8 million and $0.5 million for the periods ended March 31, 1999 and May 19, 1998, respectively.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(12) WORKERS' COMPENSATION OBLIGATIONS
The workers' compensation obligations consisted of the following as of March 31:
Workers' compensation obligations consist of amounts accrued for loss sensitive insurance premiums, uninsured claims, and related taxes and assessments under traumatic injury and occupational disease workers' compensation programs. As of March 31, 2001, the Company had $77.4 million in surety bonds outstanding to secure workers' compensation obligations.
Certain subsidiaries of the Company are subject to the Federal Coal Mine Health & Safety Act of 1969, and the related workers' compensation laws in the states in which they operate. These laws require the subsidiaries to pay benefits for occupational disease resulting from coal workers' pneumoconiosis ("CWP"). The provision for CWP claims (including projected claims costs and interest discount accruals) was a charge of $11.9 million and a charge of $12.0 million for the years ended March 31, 2001 and 2000, respectively, a charge of $11.1 million for the period ended March 31, 1999 and a benefit of $0.4 million for the period ended May 19, 1998.
The Company provides income replacement and medical treatment for work related traumatic injury claims as required by the applicable state law. The provision for traumatic injury claims (including projected claims costs and interest discount accruals) was a charge of $15.7 million and a charge of $16.7 million for the years ended March 31, 2001 and 2000, respectively, a charge of $16.0 million for the period ended March 31, 1999 and a charge of $2.4 million for the period ended May 19, 1998.
Certain subsidiaries are required to contribute to state workers' compensation funds for second injury and other costs incurred by the state fund based on a payroll based assessment by the applicable state. The provision for state assessments was a charge of $13.7 million and a charge of $14.0 million for the years ended March 31, 2001 and 2000, respectively, a charge of $8.8 million for the period ended March 31, 1999 and a charge of $1.3 million for the period ended May 19, 1998.
The liability for occupational disease claims represents the present value of known claims and an actuarially-determined estimate of future claims that will be awarded to current and former employees. The projections at March 31, 2001 were based on a 8.1% per annum interest discount rate and a 3.5% estimate for the annual rate of inflation. The projections at March 31, 2000 were based on a 7.125% per annum interest discount rate and a 3.5% estimate for the annual rate of inflation. Traumatic injury workers' compensation obligations are estimated from both case reserves and actuarial determinations of historical trends, discounted at 8.1% and 7.125% per annum at March 31, 2001 and 2000, respectively.
Federal Black Lung Excise Tax Refund Claims
In addition to the obligations discussed above, certain subsidiaries of the Company are required to pay Black Lung excise taxes to the Federal Black Lung Trust Fund. The trust fund pays CWP benefits to entitled former miners who worked prior to July 1, 1973. Excise taxes are based on the selling price of the coal, up to a maximum per ton amount.
Pursuant to a Federal District Court ruling, which the Internal Revenue Service did not appeal, the Black Lung excise tax was declared unconstitutional for export coal sales. As a result, the Company recorded income of $13.7 million and $5.0 million during fiscal years 2001 and 2000, respectively, related to refund claims filed with the Internal Revenue Service. In addition, related interest income of $3.6 million was recorded during fiscal year 2001.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(13) PENSION AND SAVINGS PLANS
Peabody Holding Company sponsors a defined benefit pension plan covering substantially all salaried U.S. employees (the "Peabody Plan"). A Peabody Holding Company subsidiary also has a defined benefit pension plan covering eligible employees who are represented by the United Mine Workers of America under the Western Surface Agreement of 1996 (the "Western Plan"). Peabody Holding Company and Gold Fields sponsor separate unfunded supplemental retirement plans to provide senior management with benefits in excess of limits under the federal tax law and increased benefits to reflect a service adjustment factor. Powder River Coal Company, a wholly-owned subsidiary, sponsored a defined benefit pension plan for its salaried employees that was merged into the Peabody Plan effective January 1, 1999. Pension benefits were not affected by the merger. Lee Ranch sponsors two defined benefit pension plans, one which covers substantially all Lee Ranch hourly employees (the "Lee Ranch Hourly Plan") and one which covers substantially all Lee Ranch salaried employees (the "Lee Ranch Salaried Plan").
Benefits under the Peabody Plan and the Lee Ranch Salaried Plan are computed based on the number of years of service and compensation during certain years. Benefits under the Western Plan are computed based on the number of years of service with the subsidiary or other specified employers. Benefits under the Lee Ranch Hourly Plan are computed based on job classification and years of service.
Annual contributions to the plans are made as determined by consulting actuaries based upon the Employee Retirement Income Security Act of 1974 minimum funding standard. As a result of the acquisition of the Predecessor Company, the Company entered into an agreement with the Pension Benefit Guaranty Corporation which requires the Company to maintain minimum funding requirements. Assets of the plans are primarily invested in various marketable securities, including U.S. government bonds, corporate obligations and listed stocks. The funds are part of a master trust arrangement managed by the Company.
Net periodic pension costs included the following components (dollars in thousands):
During the period ended March 31, 1999, the Company made an amendment to phase out the Peabody Plan beginning January 1, 2000 that resulted in a curtailment gain of $7.1 million. Effective January 1, 2001, certain employees no longer accrue future service under the plan and certain employees accrue reduced service under the plan based on their age and years of service at December 31, 2000. For plan benefit calculation purposes, employee earnings are also frozen at December 31, 2000. The Company has adopted an enhanced savings plan contribution structure in lieu of benefits formerly accrued under the defined benefit pension plan.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
The following summarizes the change in benefit obligation, change in plan assets and funded status of the Company's plans:
The projected benefit obligation applicable to pension plans with accumulated benefit obligations in excess of plan assets was $72.9 million and $13.2 million at March 31, 2001 and 2000, respectively. The accumulated benefit obligation related to these plans was $71.3 million and $13.0 million at March 31, 2001 and 2000, respectively. The fair value of plan assets related to these plans was $48.6 million at March 31, 2001 and zero at March 31, 2000.
At March 31, 2001, the projected benefit obligation exceeded plan assets for all plans. The projected benefit obligation applicable to pension plans with projected benefit obligations in excess of plan assets was $15.0 million at March 31, 2000. The plan assets related to these plans was $1.5 million at March 31, 2000.
The provisions of SFAS No. 87, "Employers' Accounting for Pensions," require the recognition of an additional minimum liability and related intangible asset to the extent that accumulated benefits exceed plan assets. As of March 31, 2001, the Company recorded an adjustment of $1.5 million which was required to reflect the Company's minimum liability.
The assumptions used to determine the above projected benefit obligation at the end of each fiscal period were as follows:
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
Certain subsidiaries make contributions to multiemployer pension plans, which provide defined benefits to substantially all hourly coal production workers represented by the United Mine Workers of America other than those covered by the Western Plan. Benefits under the United Mine Workers of America plans are computed based on service with the subsidiaries or other signatory employers. The amounts contributed to the plans and included in operating costs were $0.1 million and $0.3 million for the years ended March 31, 2001 and 2000, respectively, and $1.1 million and $0.6 million for the periods ended March 31, 1999 and May 19, 1998, respectively.
The Company sponsors an employee retirement account for eligible salaried U.S. employees. The Company matches between 50.0% and 75.0% of voluntary contributions up to a maximum matching contribution between 3.0% and 6.0% of a participant's salary. Beginning with fiscal year 2000, a performance contribution feature was added to the Employee Retirement Account to allow for contributions up to a maximum of 4% of a participants salary based upon meeting specified company performance targets. Effective January 1, 2001, the Company increased the matching contribution to a maximum of 6.0% of a participant's salary. The expense for these plans was $6.4 million and $6.1 million for the years ended March 31, 2001 and 2000, respectively, and $4.1 million and $0.6 million for the periods ended March 31, 1999 and May 19, 1998, respectively.
The Company utilizes an alternative method for amortization of actuarial gains and losses. The method is a 5% corridor and an amortization period of five years.
(14) POSTRETIREMENT HEALTH CARE AND LIFE INSURANCE BENEFITS
The Company currently provides health care and life insurance benefits to qualifying salaried and hourly retirees and their dependents from defined benefit plans established by the Company. Employees of Gold Fields are only eligible for life insurance benefits as provided by the Company. Plan coverage for the health and life insurance benefits is provided to future hourly retirees in accordance with the applicable labor agreement. The Company accounts for postretirement benefits using the accrual method.
Net periodic postretirement benefits costs included the following components (dollars in thousands):
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
The following table sets forth the plans' combined funded status reconciled with the amounts shown in the balance sheets:
The assumptions used to determine the accumulated postretirement benefit obligation at the end of each fiscal years were as follows:
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend would have the following effects:
In October 1999, Powder River announced changes in its medical plan for active employees and retirees. Employees who retired prior to December 31, 1999 were not affected by these changes. The changes included: 90/10 coinsurance, maximum out-of-pocket limits, copay for prescription drugs and mandatory generic drug usage. The effect of the change on the salaried retiree health care liability is $1.1 million. Powder River is recognizing the effect of the plan amendment over nine years. The effect for the years ended March 31, 2001 and 2000 was $0.1 million.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
In January 1999, the Company adopted reductions to the salaried employee medical coverage levels for employees retiring before January 1, 2003. For employees retiring on or after January 1, 2003, the current medical plan is replaced with a medical premium reimbursement plan. This plan change does not apply to Powder River or Lee Ranch salaried employees. The change in the retiree health care plan resulted in a $22.4 million reduction to the salaried retiree health care liability. The Company is recognizing the effect of the plan amendment over nine years beginning January 1, 1999. Therefore, the effect was $2.5 million for each of the years ended March 31, 2001 and 2000, and for the three months ended March 31, 1999 was $0.6 million.
The Company utilizes an alternative method for amortization of actuarial gains and losses. The method is a 5% corridor and an amortization period of three years.
Multi-Employer Pension and Benefit Plans
Retirees formerly employed by certain subsidiaries and their predecessors, who were members of the United Mine Workers of America, last worked before January 1, 1976 and were receiving health benefits on July 20, 1992, receive health benefits provided by the Combined Fund, a fund created by the Coal Industry Retiree Health Benefit Act of 1992 (the "Coal Act"). The Coal Act requires former employers (including certain subsidiaries of the Company) and their affiliates to contribute to the Combined Fund according to a formula. In addition, certain Federal Abandoned Mine Lands funds will be used to pay benefits to orphaned retirees through 2004.
The Company has recorded an actuarially determined liability representing the amounts anticipated to be due for the Combined Fund. The "Obligation to industry fund" reflected in the balance sheets at March 31, 2001 and 2000 was $52.2 million and $64.7 million, respectively. The current portion related to this obligation reflected in "Accounts payable and accrued expenses" in the balance sheets at March 31, 2001 and 2000 was $5.6 million and $5.1 million, respectively.
A benefit of $8.0 million was recognized for the period ended March 31, 2001, which includes interest discount of $4.6 million, net amortization of an actuarial gain of $1.1 million and a gain of $11.5 million related to beneficiaries formerly assigned to the Company by the Social Security Administration and withdrawn in the current year. Expense of $2.6 million was recognized for the period ended March 31, 2000 which includes interest discount of $4.8 million, net of the amortization of an actuarial gain of $2.2 million. Expense of $4.5 million was recognized for the period ended March 31, 1999 due to the interest discount accrual. A benefit of $0.9 million was recognized for the period ended May 19, 1998 which included amortization of an actuarial gain of $1.7 million, net of the interest discount accrual of $0.8 million.
The Coal Act also established a multiemployer benefit plan ("1992 Plan") which will provide medical and death benefits to persons who are not eligible for the Combined Fund, whose employer and any affiliates are no longer in business and who retired prior to October 1, 1994. A prior labor agreement established the 1993 United Mine Workers of America Benefit Trust ("1993 Plan") to provide health benefits for retired miners not covered by the Coal Act. The 1992 Plan and the 1993 Plan qualify under SFAS No. 106 as multiemployer benefit plans, which allows the Company to recognize expense as contributions are made. The amounts related to these funds were $1.9 million and $1.7 million for the years ended March 31, 2001 and 2000, respectively, and $0.7 million and $0.2 million for the periods ended March 31, 1999 and May 19, 1998, respectively.
Pursuant to the provisions of the Coal Act and the 1992 Plan, the Company is required to provide security in an amount equal to three times the cost of providing health care benefits for one year for all individuals receiving benefits from the 1992 Plan who are attributable to the Company, plus all individuals receiving benefits from an individual employer plan maintained by the Company who are entitled to receive such benefits. In accordance with the Coal Act and the 1992 Plan, the Company has outstanding surety bonds at March 31, 2001 of $109.3 million. The surety bonds represent security for the postretirement liability included on the balance sheets.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(15) RESTRUCTURING LIABILITY
In conjunction with the acquisition of the Predecessor Company, the Company established a $39.4 million liability for estimated costs associated with a restructuring plan resulting from the business combination. The estimate was comprised of costs associated with restructuring certain management and administrative functions ("restructuring plan") and exiting certain activities ("exit plan"). The primary actions of the restructuring plan were to eliminate or significantly downsize administrative functions for operating locations, and consolidate and relocate administrative functions to the corporate headquarters. The restructuring activities were substantially complete by September 1998, resulting in the involuntary termination of 118 employees and the relocation of 102 employees. Costs included severance pay, relocation costs, office closure costs (primarily non-cancelable leases) and payments due to employees resulting from the change in ownership. The costs associated with the exit plan relate to the decision at the date of the acquisition to suspend the operations of the Rawhide Mine in Wyoming. Exit activities included stabilizing the coal face, covering the coal pit, sloping the highwall and idling equipment and facilities, which were necessary to obtain the required approval from state and federal regulatory agencies to suspend operations. Costs associated with the restructuring and exit plans have been charged against the liability as incurred. The total costs charged against the liability were $6.4 million and $28.8 million for the period ended March 31, 2000 and the year ended March 31, 1999, respectively.
The exit plan was completed in the third quarter of fiscal year 2000 and the liability was reduced by $3.8 million at that time to reflect the most recent cost estimates. This amount was recorded as an adjustment to the cost of the acquisition. The majority of the adjustment related to lower exit plan costs than originally estimated. The $0.3 million remaining liability as of March 31, 2000 was recorded as an adjustment to the cost of the acquisition during the year ended March 31, 2001.
The following table displays a rollforward of the restructuring liability from the acquisition date to March 31, 2001:
(16) STOCKHOLDERS' EQUITY
Preferred Stock
The Company has 14,000,000 authorized shares of $0.01 par value preferred stock. The Board of Directors is authorized to issue any or all of the preferred stock. Shares of preferred stock are exchangeable on a one-for-one basis into shares of Class A common stock upon resolution by the Board of Directors.
Common Stock
The Company has 42,000,000 authorized shares of $0.01 par value Class A common stock, and 4,200,000 authorized shares of $0.01 par value Class B common stock. Holders of the Class A and Class B common stock are entitled to one vote for each share held on all matters submitted to a vote of the stockholders. Shares of Class B common stock are convertible into shares of Class A common stock on a one-for-one basis upon a resolution by the Board of Directors, a change of control, an initial public offering, a recapitalization that does not result in a change of control or the passing of nine years after the issuance.
Subject to the rights of the holders of the preferred stock, holders of Class A and Class B common stock are entitled to ratably receive such dividends as may be declared by the Board of Directors. In the event of liquidation, dissolution or winding up of the Company, holders of the Class A common stock are entitled to share ratably in the distribution of all assets remaining after payment of liabilities, subject to the rights of the preferred stockholders. Holders of Class B common stock have a junior liquidation right to the holders of Class A common stock.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
The Company recognized compensation cost related to grants of Class B common stock to management of $3.9 million, $0.3 million and $13.1 million during the years ended March 31, 2001 and 2000 and the period ended March 31, 1999, respectively.
Stock Option Plan
Effective May 19, 1998, the Company adopted the "1998 Stock Purchase and Option Plan for Key Employees of P&L Coal Holdings Corporation" (the "Plan"), making 5,638,920 shares of the Company's common stock available for grant. The Board of Directors may provide such grants in the form of stock, non-qualified options or incentive stock options.
A portion of the options vest solely on the passage of time ("time options") to the extent permitted under the Internal Revenue Code. Additionally, a portion of the options vest at the end of nine and one-half years, whether or not the applicable performance targets are achieved, but become exercisable earlier with the achievement of performance goals determined by the Board of Directors ("performance options"). Time options become fully vested early upon death, disability, a change in control or a recapitalization event, as defined. Performance options become fully vested early upon a change on control, a recapitalization event or an initial public offering, as defined.
During the year ended March 31, 2001, the Company granted 1,456,542 options to purchase Class A common stock, 371,934 of which are time options and 1,084,608 of which are performance options. During the year ended March 31, 2000, the Company granted 282,275 options to purchase Class A common stock, 81,414 of which are time options and 200,861 of which are performance options. During the period ended March 31, 1999, the Company granted 5,314,222 options to purchase Class A common stock, 1,304,639 of which are time options and 4,009,583 of which are performance options. All options have an exercise price of $14.29 per share, and expire 10 years after date of grant.
A summary of outstanding option activity is as follows:
The Company applies APB Opinion No. 25 and related interpretations in accounting for the Plan. The Company recorded $0.1 million of compensation expense for stock options granted during the year ended March 31, 2001. The Company deferred $2.0 million of compensation related to stock option grants as of that date, $0.8 million of which is expected to be recognized as expense upon completion of an initial public offering, and $1.2 million of which will be recognized in subsequent periods as the stock options become exercisable. The Company recorded no compensation expense for stock options granted during the period ended March 31, 1999 or the year ended March 31, 2000. The following table reflects pro forma net income (loss) and earnings (loss) per share had compensation cost been determined for the Company's non-qualified and incentive stock options based on the fair value at the grant dates consistent with the minimum value method set forth under SFAS No. 123, "Accounting for Stock-Based Compensation:"
These pro forma amounts may not be representative of future disclosures since the estimated fair value of stock options is amortized to expense over the vesting period, and additional options may be granted in future years.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
The weighted average fair values of the Company's stock options and the assumptions used in applying the minimum value method were as follows:
The weighted average remaining contractual life of stock options outstanding as of March 31, 2001 was 7.8 years.
(17) COMPREHENSIVE INCOME
The after-tax components of accumulated other comprehensive income (loss) are as follows:
In conjunction with the sale of the Australian operations as discussed in Note 3, the Company recorded a reduction of the foreign currency translation adjustment of the Company's Australian operations.
(18) RELATED PARTY TRANSACTIONS
On May 19, 1997, the Predecessor Company, which at the time was owned by The Energy Group PLC, purchased Citizens Lehman Power, a joint venture formed in 1994 by Lehman Brothers Holdings and a subsidiary of Citizens Energy Corporation, from Lehman Brothers Holdings, which owned a 50% interest in Citizens Lehman Power, and from the other owners of Citizens Lehman Power for a maximum purchase price of $120.0 million, which included (1) an up-front payment of $20.0 million and (2) up to $100.0 million of future cash payments based on a formula taking into account the net asset value of Citizens Lehman Power as of the date of its sale to The Energy Group PLC and any future increase in net asset value over the period ending on the last day of fiscal year 2002. That payment obligation was subject to acceleration, under certain circumstances, in the event of a change of control of The Energy Group PLC. Citizens Lehman Power was renamed Citizens Power after the 1997 purchase. As a result of the May 19, 1998 acquisition of the Predecessor Company by Lehman Brothers Merchant Banking, the change of control payment acceleration provisions became effective, and the Company paid the former owners of Citizens Lehman Power an aggregate of approximately $93.0 million in full settlement of the deferred purchase price obligations, with approximately $73.0 million, including $1.0 million of interest, of that payment made on May 19, 1998 and $21.0 million, including $1.0
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
million of interest, paid on April 3, 2000. Amounts paid in settlement of the deferred purchase price obligations, excluding interest, were included in the cost of the acquisition of Citizens Lehman Power.
Lehman Brothers provided other financial advisory services to the Predecessor Company in April 1998, for which the Company paid a fee of $0.1 million.
Lehman Brothers Merchant Banking formed the company to acquire the Predecessor Company and various of its subsidiaries, including Citizens Power, from The Energy Group PLC on May 19, 1998. In connection with the acquisition, the Company paid the $73.0 million of obligations of Citizens Power referred to above. Lehman Brothers advised Lehman Brothers Merchant Banking in connection with that acquisition. In addition, Lehman Brothers was the initial purchaser in connection with the sale of the Company's Senior Notes and our Senior Subordinated Notes. Furthermore, Lehman Commercial Paper Inc. arranged the Company's Senior Credit Facility and is one of the Company's lenders. Lehman Brothers and Lehman Commercial Paper Inc. collectively received fees of approximately $85 million for those services.
As part of the acquisition, Lehman Brothers Holdings Inc. provided a 364-day guarantee facility to trading counterparties of Citizens Power Sales, the trading subsidiary of Citizens Power, for trades initiated after the acquisition. Lehman Brothers Holdings received a fee of $0.5 million, plus reimbursement of expenses, for providing this guarantee facility, which expired in accordance with its terms in November 1998. There are no further guarantee obligations outstanding under this facility.
Lehman Brothers served as the placement agent in a financing completed in January 1999 by a subsidiary of Citizens Power relating to a utility power contract restructuring, and the Company paid Lehman Brothers a fee of approximately $0.8 million, plus reimbursement of expenses, for those services.
Lehman Brothers served as the placement agent in a financing completed in October 1999 by a subsidiary of Citizens Power relating to a utility power contract restructuring, and the Company paid Lehman Brothers a fee of approximately $0.8 million, plus reimbursement of expenses, for those services.
Lehman Brothers served as the Company's financial advisor in connection with the Company's acquisition of an additional 38.3% interest in Black Beauty. The Company paid Lehman Brothers a fee of approximately $1.3 million, plus reimbursement of expenses, for those services.
Lehman Brothers served as the Company's financial advisor in connection with the sale of Citizens Power, which was completed in fiscal year 2001. The Company paid Lehman Brothers a fee of approximately $1.5 million, plus reimbursement of expenses, for those services.
Lehman Brothers served as one of the Company's financial advisors in connection with the sale of the Company's Australian operations, which was completed on January 29, 2001. The Company paid Lehman Brothers a fee of $2.7 million, plus reimbursement of expenses, for those services.
(19) CONTRACT RESTRUCTURINGS
The Company has periodically agreed to terminate coal supply agreements in return for payments by the customer. There were no gains related to coal supply agreement terminations for the year ended March 31, 2001 or the period ended May 19, 1998. The amounts included in "Other revenues" were $13.0 million for the year ended March 31, 2000 and $5.3 million for the period ended March 31, 1999.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(20) FINANCIAL INSTRUMENTS WITH OFF-BALANCE-SHEET RISK
The Company owns a 30.0% interest in a partnership that leases a coal export terminal from the Peninsula Ports Authority of Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority, and which are supported by letters of credit from a commercial bank. The Company's reimbursement obligation to the commercial bank is in turn supported by a letter of credit totaling $42.8 million.
In December 1999, the Company entered into a 49.0% interest in a joint venture to develop and rehabilitate an underground mine and prep plant facility. The partners have severally agreed to guarantee a $32.3 million financing agreement provided by two commercial banks of which 49.0% ($15.8 million) is guaranteed by the Company. Principal payments are due beginning April 1, 2001 at $0.3 million per month for 24 months, then increase to $0.4 million per month for 20 months beginning April 1, 2003. A final principal payment of $17.1 million is due December 31, 2004. Interest payments are due monthly and accrue at prime, which was 8.0% at March 31, 2001.
Prior to the sale of the Company's Australian operations, as discussed in Note 3, Peabody Resources used forward currency contracts to manage its exposure against foreign currency fluctuations on sales denominated in U.S. dollars. Realized gains and losses on these contracts were recognized in the same period as the hedged transactions. The Company had deferred unrealized gains and (losses) of ($13.9 million) as of March 31, 2000 and $16.2 million as of March 31, 1999.
In the normal course of business, the Company is a party to financial instruments with off-balance-sheet risk, such as bank letters of credit, performance bonds and other guarantees, which are not reflected in the accompanying balance sheets. Such financial instruments are to be valued based on the amount of exposure under the instrument and the likelihood of performance being required. In the Company's past experience, virtually no claims have been made against these financial instruments. Management does not expect any material losses to result from these off-balance-sheet instruments and, therefore, is of the opinion that the fair value of these instruments is zero.
(21) FAIR VALUE OF FINANCIAL INSTRUMENTS
SFAS No. 107, "Disclosures About Fair Value of Financial Instruments," defines the fair value of a financial instrument as the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced or liquidation sale.
The following methods and assumptions were used by the Company in estimating its fair value disclosures for financial instruments:
Cash and cash equivalents, accounts receivable and accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the financial nature of these instruments.
Long-term debt fair value estimates are based on estimated borrowing rates to discount the cash flows to their present value. The 5.0% Subordinated Note carrying amount is net of unamortized note discount.
Other noncurrent liabilities include a deferred purchase obligation related to the prior purchase of a mine facility. The fair value estimate is based on the same assumption as long-term debt.
Investments and other assets include certain notes receivable with customers at various interest rates. Notes receivable fair value estimates are based on estimated borrowing rates to discount the cash flows to their present values.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
The carrying amounts and estimated fair values of the Company's financial instruments are summarized as follows:
The fair value of the financial instruments related to coal and emission allowance trading activities as of March 31, 2001, and the average fair value during the year ended March 31, 2001, which include energy commodities, are set forth below:
The approximate gross contract or notional amounts of financial instruments are as follows:
The change in unrealized gain from coal trading activities for the year ended March 31, 2001 was $4.3 million. The net gain arising from coal and emission allowance trading activities was $7.8 million and $1.3 million for the years ended March 31, 2001 and 2000, respectively, and $0.5 million for the period ended March 31, 1999. There was no net gain or loss from coal and emission allowance trading activities for the period ended May 19, 1998.
(22) COMMITMENTS AND CONTINGENCIES
Environmental claims have been asserted against a subsidiary of the Company at 18 sites in the United States. Some of these claims are based on the Comprehensive Environmental Response Compensation and Liability Act of 1980, as amended, and on similar state statutes. The majority of these sites are related to activities of former subsidiaries of the Company.
The Company's policy is to accrue environmental cleanup-related costs of a noncapital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures requires an assessment of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. For certain sites, the Company also assesses the financial capability of other potentially responsible parties and, where allegations are based on tentative findings, the reasonableness of the Company's apportionment. The Company has not anticipated any recoveries from insurance carriers or other potentially responsible third parties in its balance sheets. The undiscounted liabilities for environmental cleanup-related costs recorded as part of "Other noncurrent liabilities" at March 31, 2001 and 2000 were $48.0 million and $57.7 million, respectively. This amount represents those costs that the Company believes are probable and reasonably estimable.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
On June 18, 1999, The Navajo Nation served our subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company, with a complaint that had been filed in the U.S. District Court for the District of Columbia. Other defendants in the litigation are two customers, 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 Coal Company's two coal leases for the Kayenta and Black Mesa mines have terminated due a 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.
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, reformation of its coal lease and a termination of the coal lease. On March 15, 2001, the court granted the Hopi Tribe's motion. On April 17, 2001, the Company filed a motion to dismiss the Hopi complaint.
The Company believes this matter will be resolved without a material adverse effect on the financial condition or results of operations.
In addition, the Company at times becomes a party to claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. Management believes that the ultimate resolution of pending or threatened proceedings will not have a material effect on the financial position, results of operations or liquidity of the Company.
At March 31, 2001, purchase commitments for capital expenditures were approximately $94.4 million.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(23) SUMMARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
The following is a summary of the unaudited quarterly results of operations for fiscal years 2001 and 2000 (dollars in thousands, except share data):
Results of operations for the first quarter, second quarter and fourth quarter of fiscal year 2001 included reductions to the after-tax estimated loss on disposal of Citizens Power of $8.8 million, $3.0 million and $1.1 million, respectively. Results of operations for the fourth quarter of fiscal year 2001 included an after-tax gain of $124.2 million on the sale of the Company's Australian operations, and an after-tax extraordinary loss of $8.5 million related to the early extinguishment of debt. Additionally, results of operations for the fourth quarter of fiscal year 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, and a $78.3 million estimated loss from the disposal of Citizens Power that was classified as a discontinued operation in March 2000.
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(24) SEGMENT INFORMATION
The Company operates primarily in the coal industry. "Other" data represents an aggregation of the Company's other non-mining entities including Gold Fields. The Company's material operations outside the U.S. related to its operations in Australia that were sold in January 2001. The Company's industry and geographic data for continuing operations were as follows (dollars in thousands):
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(25) SUPPLEMENTAL GUARANTOR/NON-GUARANTOR FINANCIAL INFORMATION
In accordance with the indentures governing the Senior Notes and Senior Subordinated Notes, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed the Senior Notes and Senior Subordinated Notes on a joint and several basis. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to holders of the Senior Notes and the Senior Subordinated Notes. The following condensed historical financial statement information is provided for such Guarantor/Non-Guarantor Subsidiaries.
SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS YEAR ENDED MARCH 31, 2001
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS YEAR ENDED MARCH 31, 2000
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS MAY 20, 1998 TO MARCH 31, 1999
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED COMBINED STATEMENTS OF OPERATIONS APRIL 1, 1998 TO MAY 19, 1998
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS AS OF MARCH 31, 2001
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS AS OF MARCH 31, 2000
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS YEAR ENDED MARCH 31, 2001
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS YEAR ENDED MARCH 31, 2000
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS MAY 20, 1998 TO MARCH 31, 1999
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
SUPPLEMENTAL CONDENSED COMBINED STATEMENTS OF CASH FLOWS APRIL 1, 1998 TO MAY 19, 1998
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Set forth below are the names, ages as of March 31, 2001 and current positions with us and our subsidiaries of our executive officers and directors. Directors are elected at the annual meeting of stockholders. Executive officers are appointed by, and hold office at, the discretion of the directors.
Irl F. Engelhardt served as our President and Chief Executive Officer from 1990 to 1995 and our Chairman and Chief Executive Officer since 1993, and has been a director since June 1998. Since joining our company in 1979, he has held various officer level positions in the executive, sales, business development and administrative areas, including serving as Chairman of Peabody Resources Ltd. (Australia) and Chairman of Citizens Power. 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 Firstar Bank, N.A. (formerly Mercantile Bank of St. Louis, N.A.).
Richard M. Whiting has been President and Chief Operating Officer of our company since January 1998 and has been a director since June 1998. He served as President of Peabody COALSALES Company from June 1992 to January 1998. Since joining our company in 1976, Mr. Whiting has held a number of operations, sales and engineering positions both at the corporate offices and at field locations. From 1989 to 1990, Mr. Whiting served as Vice President of Engineering and Operations Support. 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. has been Executive Vice President-Corporate Development of our company since 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 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 has been Executive Vice President and Chief Financial Officer of our company since 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 our 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 has been Executive Vice President-Legal and External Affairs of our company since 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 has been Executive Vice President-Sales and Trading of our company since 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 has been Vice President-Legal Services of our company since May 1998. Prior to that, he had been our Vice President, Secretary and Chief Legal Officer since October 1990. From 1986 to October 1990, he served as Eastern Regional Counsel for Peabody Holding Company and from 1982 to 1986 as Director of Legal and Public Affairs, Eastern Division of Peabody Coal Company and joined Peabody as Director of Legal and Public Affairs, Indiana Division of Peabody Coal Company from 1978 to 1982. 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 their 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.
Roger H. Goodspeed became a director of our company in May 1998. He is also a Managing Director of Lehman Brothers. He joined Lehman Brothers in 1974 and became a Managing Director in 1984. During his tenure at Lehman Brothers, he has served in management positions for several different groups. In 1994, he became the original Chairman of Citizens Lehman Power, an electric power marketing joint venture 50%-owned by Lehman Brothers, and continued in that role until the joint venture was sold to The Energy Group in 1997 and changed its name to Citizens Power. Mr. Goodspeed received an MBA from the Anderson School at the University of California, Los Angeles.
Henry E. Lentz became a director of our company in February 1998. He is also a Managing Director of Lehman Brothers and a principal of the firm's Merchant Banking Group. Mr. Lentz joined Lehman Brothers in 1971 and became a Managing Director in 1976. In 1988, Mr. Lentz left Lehman Brothers to serve as Vice Chairman of Wasserstein Perella Group, Inc. In 1993, he returned to Lehman Brothers as a Managing Director and, prior to joining the Merchant Banking Group, served as head of the firm's worldwide energy practice. Mr. Lentz is currently a director of Rowan Companies, Inc. and Consort Holdings plc. Mr. Lentz holds an MBA, with honors, from the Wharton School of the University of Pennsylvania.
Alan H. Washkowitz became a director of our company in May 1998. He is also a Managing Director of Lehman Brothers and the head of the firm's Merchant Banking Group, responsible for the oversight of Lehman Brothers Merchant Banking Partners II L.P. Mr. Washkowitz joined Kuhn Loeb & Co. in 1968 and became a general partner of Lehman Brothers in 1978 when it acquired Kuhn Loeb & Co. Prior to joining the Merchant Banking Group, Mr. Washkowitz headed Lehman Brothers' Financial Restructuring Group. He is currently a director of CP Kelco ApS, L-3 Communications Corporation, K&F Industries, Inc. and McBride plc. Mr. Washkowitz holds an MBA from Harvard University and a JD from Columbia University.
Our board of directors is currently comprised of five directors, and we expect to add two independent members to our board of directors within three months and a third independent member to our board of directors within 12 months after May 2001, when our initial public offering was completed. In addition, we expect that as long as Lehman Brothers Merchant Banking controls us, they will add additional members to our board of directors so that Lehman Brothers Merchant Banking will continue to control a majority of our board of directors. In accordance with the terms of our certificate of incorporation, the board of directors will be divided into three classes, each serving staggered three-year terms: Class I, whose initial term will expire at the annual meeting of stockholders held in 2002; Class II, whose initial term will expire at the annual meeting of stockholders in 2003; and Class III,
whose initial term will expire at the annual meeting of stockholders in 2004. As a result, only one class of directors will be elected at each annual meeting of our stockholders, with the other classes continuing for the remainder of their respective terms. Roger Goodspeed has been designated as a Class I director; Messrs. Whiting and Lentz have been designated as Class II directors; and Messrs. Engelhardt and Washkowitz have been designated as Class III directors. In addition, our certificate of incorporation and by-laws provide that directors may be removed only for cause and only upon the affirmative vote of holders of at least 75% of the voting power of all the outstanding shares of stock entitled to vote generally in the election of directors, voting together as a single class. There are no family relationships among any of our directors and executive officers.
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires our executive officers, directors and persons who own beneficially more than 10% of our common stock to file with the SEC initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. These persons are required by SEC regulation to furnish us with copies of all Section 16(a) reports they file with the SEC.
Based solely on our review of copies of such reports furnished to us, we believe our executive officers, directors, and greater than 10% beneficial owners complied with all Section 16(a) filing requirements since our initial public offering on May 22, 2001. Prior to our initial public offering, these persons were not subject to the Section 16(a) filing requirements.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
The following table sets forth the annual compensation for our chief executive officer and the four most highly compensated executive officers (the named executive officers, other than the chief executive officer) for their services to our company during fiscal years 2001, 2000 and 1999.
SUMMARY COMPENSATION TABLE
- -------------- (1) Represents number of shares of common stock granted to executives as of May 19, 1998. In addition, shares purchased by Mr. Walcott on May 19, 1998 were converted to granted shares during the year ended March 31, 2000. (2) Represents number of shares of common stock underlying options. (3) Represents certain long-term incentive payments earned during the fiscal year that relate to our predecessor company's compensation plans. (4) Represents annual matching contributions and performance contributions to qualified and non-qualified savings and investment plans and group term life insurance.
OPTION/SAR GRANTS IN FISCAL YEAR 2001
The following table sets forth the number and value of securities underlying unexercised options held by each of our executive officers listed on the Summary Compensation Table above as of March 31, 2001. None of our executive officers exercised any options in fiscal year 2001, and we do not have any stock appreciation rights.
AGGREGATED OPTION/SAR EXERCISES IN FISCAL YEAR 2001 AND OPTIONS/SAR VALUES AS OF MARCH 31, 2001
PENSION BENEFITS
Our Salaried Employees Retirement Plan, or pension plan, is a "defined benefit" plan. The pension plan provides a monthly annuity to salaried employees when they retire. A salaried employee must have at least five years of service to be vested in the pension plan. A full benefit is available to a retiree at age 62. A retiree can begin receiving a benefit as early as age 55; however, a 4% reduction factor applies for each year a retiree receives a benefit prior to age 62.
An individual's retirement benefit under the pension plan is equal to the sum of (1) 1.112% of the highest average monthly earnings over 60 consecutive months up to the "covered compensation limit" multiplied by the employee's years of service, not to exceed 35 years, and (2) 1.5% of the average monthly earnings over 60 consecutive months over the "covered compensation limit" multiplied by the employee's years of service, not to exceed 35 years.
We announced in February 1999 that the pension plan would be phased out beginning January 1, 2001. Certain transition benefits were introduced based on the age and/or service of the employee at December 31, 2000: (1) employees age 50 or older will continue to accrue service at 100%; (2) employees between the ages of 45 and 49 or under age 45 with 20 years or more of service will accrue service at the rate of 50% for each year of service worked after December 31, 2000; and (3) employees under age 45 with less than 20 years of service will have their pension benefits frozen. In all cases, final average earnings for retirement plan purposes will be capped at December 31, 2000 levels.
The estimated annual pension benefits payable upon retirement at age 62, the normal retirement age, for the Chief Executive Officer and the named executive officers are as follows:
We have two supplemental defined benefit retirement plans that provide retirement benefits to executives whose pay exceeds legislative limits for qualified defined benefit plans.
OTHER BENEFIT PLANS
In addition to the pension plan, we maintain various other benefit plans covering employees and retirees, including medical insurance plans and the Employee Retirement Account, a defined contribution plan. We announced in February 1999 that we were restructuring several of these plans over the succeeding four years. The benefits associated with the medical insurance plan and the Employee Retirement Account will be affected most significantly.
The changes to the medical insurance plan include the following as of January 1, 2000: (1) a decrease in employee and retiree contributions from 15% to 10% of actual plan costs; (2) an increase in medical contributions for dependents from 15% to 30% of actual plan costs; (3) a decrease in medical coverage from 100% to 80% for specified expenses; (4) additional medical plan options; and (5) changes to dependent eligibility rules for retirees. In addition, the medical insurance plan was restructured so that employees leaving us after January 1, 2003 (at age 55 or older with ten years of service) will be covered under a medical premium reimbursement plan instead of the current medical insurance plan.
Beginning with fiscal year 2000, a performance contribution feature was added to the Employee Retirement Account to allow for our contributions of up to a maximum of 4% of employees' salaries based upon meeting specified company performance targets. Effective January 1, 2001, we increased our matching contributions for the Employee Retirement Accounts to 100% of the first 3% of base pay and 75% of the next 4% of base pay contributed by employee participants. With the completion of the initial public offering in May 2001, employees are now able to purchase shares of our stock through the Employee Retirement Account. We have one defined contribution supplemental plan, which provides benefits to executives whose pay exceeds legislative limits for qualified defined contribution plans.
EMPLOYEE STOCK PURCHASE PLAN
In connection with the completion of the Company's initial public offering, we adopted an employee stock purchase plan. One million five hundred thousand shares of common stock will be available for purchase. Eligible full-time and part-time employees will be able to contribute up to 15% of their base compensation into this plan subject to a limit of $25,000 per year. These employees will be able to purchase the shares at a 15% discount to the lower of the fair market values of the initial and ending dates of each offering period. There will be two offering periods each year, one commencing on April 1 (except that the first offering period will commence on the effective date of the plan) and the other commencing on October 1. Participating employees will be restricted from selling their shares for 18 months from the purchase date, except upon the death of a participant or a change in control of our company.
MANAGEMENT ANNUAL INCENTIVE COMPENSATION PLAN
We have an annual incentive compensation plan that provides a cash bonus to selected employees based on the participant's base salary, target level and the attainment of certain company and individual targets. The company targets are established each year by the compensation committee of our board of directors or the board of directors based on performance criteria that may include total shareholder return, various return measures, earnings per share, EBITDA, cash flow or other appropriate organizational and individual measures. The annual incentive awards are designed to be exempt from the $1 million limit on deductible compensation under section 162(m) of the Internal Revenue Code.
EMPLOYMENT AGREEMENTS
We have entered into employment agreements with Mr. Engelhardt, our Chairman and Chief Executive Officer, or CEO, and Messrs. Whiting, Walcott, Navarre, Vining and other key executive officers. The CEO's employment agreement provides for a three-year term that extends day-to-day so that there is at all times a remaining term of three years, and other executives' employment agreements have a one-year term or a two-year term, each of which extends day-to-day so that there is at all times a remaining term of one or two years, respectively. Following a termination without cause or resignation for good reason, the CEO is entitled to a lump sum payment equal to three years' base salary and three times the higher of his (A) target annual bonus or (B) average of the actual annual bonuses paid in the three prior years. The CEO is also entitled to a one-time prorated bonus for the year of termination (based on our actual performance multiplied by a fraction, the numerator of which is the number of business days the CEO was employed during the year of termination, and the denominator of which is the total number of business days during that year), payable when bonuses, if any, are paid to our other executives. He will also receive qualified and nonqualified pension, life insurance, medical and other benefits for three years. The other key executives are entitled to the following benefits, payable in equal installments over one or two years: (1) one or two times base salary and (2) one or two times the higher of (A) the target annual bonus or (B) the average of the actual annual bonuses paid in the three prior years. In addition, the other executives are entitled to (1) a one-time prorated bonus for the year of termination (based on our actual performance multiplied by a fraction, the numerator of which is the number of business days the executive was employed during the year of termination and the denominator of which is the total number of business days during that year), payable when bonuses, if any, are paid to our other executives; and (2) qualified and nonqualified pension, life insurance, medical and other benefits for the one or two-year period, as applicable, following termination. However, we are not obligated to provide any benefits under tax qualified plans that are not permitted by the terms of each plan or by applicable law or that could jeopardize the plan's tax status. Continuing benefit coverage will terminate to the extent an executive (including the CEO) is offered or obtains comparable coverage from any other employer. The employment agreements provide for confidentiality during and following employment, and include a noncompetition and
nonsolicitation agreement that is effective during and for one year following employment. If an executive (including the CEO) breaches any of his or her confidentiality, noncompetition or nonsolicitation agreements, the executive will forfeit any unpaid amounts or benefits. To the extent that excise taxes are incurred by an executive (including the CEO) as a result of "excess parachute payments," we will pay additional amounts up to $10 million, in the aggregate so that executives would be in the same financial condition as if the excise taxes were not incurred.
STOCK PURCHASE AND OPTION PLAN
We adopted our 1998 Stock Purchase and Option Plan for Key Employees. Pursuant to that plan, the executive officers and 17 other employees acquired, in the aggregate, approximately 3% of our initial fully-diluted equity, which was issued as Class B common stock in connection with our acquisition on May 19, 1998. With respect to these shares, we provided a full recourse loan for the amount of the tax liability to each executive, with a five-year principal balloon payment that accelerates six months following any termination of employment or disposition of the stock, with interest payable throughout the term of the loan at the applicable federal rate. Executives who received Class B common stock and some other employees were eligible to receive options under the plan exercisable for common stock to purchase an aggregate of 7% of our initial fully-diluted equity, or 2,819,460 shares. As of March 31, 2001, options to purchase 1,296,950 shares were outstanding as "time options" in the form of Incentive Stock Options (as defined in Section 422 of the Internal Revenue Code) to the extent permitted under the Internal Revenue Code, and in the form of non-qualified stock options for the remainder, and 1,301,290 options to purchase shares were outstanding in the form of nonqualified stock options as "performance options." Time options become exercisable with respect to 20% of the shares subject to those options on each of the first five anniversaries of May 19 of the fiscal year during which the options were granted if the executive's employment continues through and includes that date. Time options will become fully exercisable early upon death, disability, a change of control or a recapitalization event. Performance options became exercisable early upon our initial public offering. "Change of control," for the purposes of this plan, means an acquisition of all or substantially all of our direct and indirect assets by merger, consolidation, recapitalization event, stock or asset sale or otherwise, immediately following which (a) Lehman Brothers and its affiliates own, in the aggregate, less than 50% of our outstanding voting securities that Lehman Brothers and its affiliates owned after May 19, 1998, excluding the sale of $80 million of their original investment, which occurred after May 19, 1998, or (b) any person individually owns more of our then-outstanding voting securities than Lehman Brothers and its affiliates. "Recapitalization event," for purposes of this plan, means a recapitalization, reorganization, stock dividend or other special corporate restructuring which results in an extraordinary distribution to the stockholders of cash and/or securities through the use of leveraging or otherwise but that does not result in a change of control. "Initial public offering," for purposes of this plan, means the first sale of shares of our stock to the public pursuant to an effective registration statement filed under the Securities Act that results in the listing on a national exchange or the NASDAQ National Market of the lesser of 25% of our outstanding common stock and an aggregate value of outstanding securities equal to $250.0 million.
The plan also provides for the grant of additional performance-based options as "superperformance options" exercisable for common stock to purchase an aggregate of another 7% of our initial fully-diluted equity, or 2,819,460 shares. As of March 31, 2001, options to purchase 2,627,269 shares were outstanding as "superperformance options." Approximately 36% of these options became exercisable upon our initial public offering and the remainder of these options will vest in accordance with the achievement of specified financial performance targets.
All options have an exercise price of $14.29 per share of our common stock.
All options under the plan have a ten-year term. Exercisable options expire earlier, as follows: (1) upon termination for cause or a resignation without good reason, immediately upon termination, (2) upon termination without cause, resignation for good reason, death, disability or retirement, one year after termination of employment or (3) if the option exercise price is higher than the fair market value of our shares upon any termination of employment, immediately upon termination. Unexercisable options terminate earlier upon any termination of employment unless acceleration in connection with the termination, subject to specified exceptions. Upon a change of control, the board of directors may terminate the options so long as the executives are cashed out at the change of control price or are permitted to exercise their options prior to the change of control, except as otherwise provided.
LONG-TERM EQUITY INCENTIVE PLAN
In connection with the completion of the Company's initial public offering, we adopted the Long-Term Equity Incentive Plan. Under that plan, selected executive officers, key employees and other service providers will be eligible to receive grants of stock options, shares of our common stock or monetary payments based on the value of our stock or based upon the achievement of specified performance goals. This plan is intended to provide an incentive for employees to contribute to our success and align the interests of key employees with the interests of our shareholders. Two million five hundred thousand shares of our outstanding
common stock will be available for issuing awards with a grant of up to one-third of the total in fiscal year 2002. Awards may include stock appreciation rights, restricted stock, performance awards, incentive stock options, nonqualified stock options and stock units. Performance criteria for the vesting of performance awards may include total shareholder return, various return measures, earnings per share, EBITDA, cash flow or other appropriate measures. The compensation committee of our board of directors or the board of directors will determine performance goals and levels of rewards to be granted upon the achievement of these goals. If we change the number of issued shares of our common stock without new consideration, the total number of shares reserved for issuance under this plan and the number of shares covered by each outstanding award will be adjusted so that the aggregate consideration payable to us, if any, and the value of each award will not be changed. Awards are designed to be exempt from the $1 million limit on deductible compensation under section 162(m) of the Internal Revenue Code.
EQUITY INCENTIVE PLAN FOR NON-EMPLOYEE DIRECTORS
In connection with the completion of the Company's initial public offering, we adopted the Equity Incentive Plan for Non-Employee Directors. Under that plan, members of our board of directors who are not employees of our company or one of our affiliates will be eligible to receive grants of restricted stock and options to purchase our stock at a price equal to the fair market value per share of the stock on the date the option is granted. Restricted stock will be granted to a director upon election or appointment to the board of directors, and will vest upon the third anniversary of the date of grant. Options to purchase stock will be granted to eligible directors each year at the annual meeting of the board of directors, and will vest ratably over three years. All options granted under the plan will expire after ten years from the date of the grant, subject to earlier termination in connection with a director's termination of service. Options to purchase stock granted under the plan will become fully exercisable and restricted stock will become fully vested upon a change of control, or upon the director's involuntary termination other than for cause, voluntary termination with the board of director's consent, or permanent disability. Options will remain exercisable for a period ending upon the earlier to occur of five years after the director's involuntary termination without cause or voluntary termination with the board of director's consent, or ten years from the date of grant. In the event of a director's death while serving on the board of directors, each of the outstanding options of the option holder shall become exercisable immediately and may be exercised within a period of five years after death, but no later than the expiration date of the option term. If an option holder dies or becomes permanently disabled within five years following termination of service on the board of directors, the option will be exercisable for the longer of two years after the holder's death or five years after termination of service on the board of directors, or until the earlier expiration of the term of the option. Shares of restricted stock and options will be forfeited upon the director's voluntary termination without consent of the board of directors or termination for cause.
COMPENSATION OF DIRECTORS
Currently, members of our board of directors are not compensated for their services; however, they are reimbursed for expenses.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
None of our executive officers has served as a director or member of the compensation committee, or other committee serving an equivalent function, of any entity of which an executive officer is expected to serve as a member of our compensation committee.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The following table sets forth information concerning ownership of our capital stock as of May 31, 2001 by persons who beneficially own more than 5% of the outstanding shares of capital stock, each person who is a director of our company, each person who is a named executive officer, and all directors and executive officers as a group. As of May 31, 2001, there were 51,892,456 shares of common stock outstanding.
- -------------- (1) Beneficial ownership is determined in accordance with the rules of the SEC and includes voting and investment power with respect to shares. Unless otherwise indicated, the persons named in the table have sole voting and sole investment control with respect to all shares beneficially owned. (2) Includes options exercisable within 60 days after May 31, 2001. (3) Messrs. Goodspeed, Lentz and Washkowitz are Managing Directors of Lehman Brothers. Mr. Washkowitz is the head of Lehman Brothers Merchant Banking and Mr. Lentz is a principal of Lehman Brothers Merchant Banking. Messrs. Goodspeed, Lentz and Washkowitz disclaim beneficial ownership of the shares held or controlled by these entities or their affiliates.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
TRANSACTIONS WITH AFFILIATES OF LEHMAN BROTHERS
Lehman Brothers served as our financial advisor in connection with the sale of Citizens Power, which we completed in fiscal year 2001. We paid Lehman Brothers a fee of approximately $1.5 million, plus reimbursement of expenses, for those services.
Lehman Brothers served as one of our financial advisors in connection with the sale of our Australian operations, which we completed on January 29, 2001. We paid Lehman Brothers a fee of $2.7 million, plus reimbursement of expenses, for those services.
After completion of the Company's initial public offering, Lehman Brothers Merchant Banking Partners II L.P. and its affiliates (collectively, the "Lehman Brothers Merchant Banking Fund") owns 57% of our common stock. Messrs. Goodspeed, Lentz and Washkowitz, each one of our directors, are investors in the Lehman Brothers Merchant Banking Fund and employees of Lehman Brothers.
TRANSACTIONS WITH MANAGEMENT
During fiscal years 1999, 2000 and 2001 some of our executive officers and 18 other employees purchased or were granted shares of our Class B common stock under the 1998 Stock Purchase and Option Plan for Key Employees. In connection with these purchases and grants, we, affiliates of Lehman Brothers Holdings and the executives who received our Class B common stock entered into stockholders agreements providing for certain rights of the investors relating to the registration of their shares with respect to certain sales of our capital stock by affiliates of Lehman Brothers Holdings. The stockholders agreements provide the investors with the right to register and sell their unregistered stock in the event that we conduct certain types of registered offerings.
In conjunction with the purchases and grants of our Class B common stock, the executive officers and employees executed term notes. The term notes related to these grants are due on May 19, 2003 and the term notes executed for purchases are due on February 1, 2006. All of the term notes bear annual interest at an applicable U.S. federal rate used by the Internal Revenue Service for loans to employees. The maturity of the promissory notes will accelerate upon the occurrence of certain events, including six months following any termination of employment or disposition of the stock.
The following table indicates the amounts due under the term notes for our executive officers with aggregate indebtedness in excess of $60,000 during the year ended March 31, 2001:
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Documents filed as part of this Report
(1) Financial Statements.
The following financial statements of Peabody Energy Corporation are included in Item 8 at the page indicated:
(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 Valuation and Qualifying Accounts
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 March 31, 2001.
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
IRL F. ENGELHARDT ------------------------------------ Irl F. Engelhardt Chairman and Chief Executive Officer
Date: June 27, 2001
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.
*By: RICHARD A. NAVARRE ------------------------------- Richard A. Navarre Attorney-In-Fact
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).
Exhibit No. Description of Exhibit ------- ----------------------
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 10.7 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 Receivables Sale Agreement dated as of March 31, 2000, by and among Originators and the Registrant (Incorporated by reference to Exhibit 10.16 of the Registrant's Form 10-K for the year ended March 31, 2000). 10.16 Receivables Contribution Agreement dated as of March 31, 2000, by and between the Registrant and P&L Receivables Company, LLC ("Seller") (Incorporated by reference to Exhibit 10.17 of the Registrant's Form 10-K for the year ended March 31, 2000). 10.17 Receivables Purchase Agreement as of March 31, 2000, by and among Seller, the Registrant, International Securitization Corporation, Bank One, NA, as Agent ("Agent") and the Financial Institutions named therein (Incorporated by reference to Exhibit 10.18 of the Registrant's Form 10-K for the year ended March 31, 2000). 10.18* 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). 10.19 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).
Exhibit No. Description of Exhibit ------- ----------------------
10.20* 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). 10.21* 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). 10.22* 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). 10.23* 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). 10.24* 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). 10.25* Form of First Amendment to Stockholders' Agreement dated as of May 19, 1998. 10.26* Long-Term Equity Incentive Plan. 10.27* 2001 Employee Stock Purchase Plan. 10.28* Equity Incentive Plan for Non-Employee Directors. 10.29* Form of Amendment to the Non-Qualified Stock Option Agreement. 21 List of Subsidiaries. 23 Consent of Ernst & Young LLP, Independent Auditors. 24 Power of Attorney.
* 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.
REPORT OF INDEPENDENT AUDITORS
Board of Directors Peabody Energy Corporation
We have audited the consolidated financial statements of Peabody Energy Corporation (the Company), formerly P&L Coal Holdings Corporation, as of March 31, 2001 and 2000, and for the years then ended and the period from May 20, 1998 to March 31, 1999, and the combined financial statements of P&L Coal Group (the Predecessor Company) for the period from April 1, 1998 to May 19, 1998 and have issued our report thereon dated April 20, 2001. Our audits also included the financial statement schedule listed in Item 14(a). This schedule is the responsibility of 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 April 20, 2001
PEABODY ENERGY CORPORATION SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(1) Reserves utilized, unless otherwise indicated. (2) Balances transferred from other accounts. (3) Balances recorded as part of May 19, 1998 purchase accounting adjustments. (4) Balances acquired as part of the controlling interest in Black Beauty Coal Company purchased January 1, 1999. (5) Balances transferred as part of asset contribution to joint venture.