ITEM 1. BUSINESS.
OVERVIEW
We are among the world's largest providers of low cost fuel for the generation of electricity and are also engaged in power trading and power and coal contract restructuring services. During this decade, we have transformed from a largely high sulfur, high-cost coal producer to a more broadly based energy company providing predominantly low sulfur, low-cost coal from operations in the United States and Australia, as well as a number of fuel/power products to the electricity market.
In fiscal 1999, we sold 176.0 million tons of coal worldwide. These products were used to generate more than 9 percent of the electricity produced in the United States and nearly 2.5 percent of the world's electricity. Through our Citizens Power unit, we ranked among the top ten United States power marketers in calendar 1998 and were the leader in restructuring electricity contracts with independent power producers. Our share of the United States coal market was approximately 16.0 percent in calendar 1998. We have approximately 10.3 billion tons of proven and probable coal reserves, which is the largest reserve base of any private sector coal producing company in the United States.
We currently own interests in more than 35 active mines in the United States and Australia, and also sell coal produced by third-party contractors and suppliers. In fiscal 1999, we produced approximately 71 percent of our coal in the Western United States, 25 percent from the eastern half of the United States and 4 percent from Australia. Peabody's coal production in the Western United States has grown from 37 million tons in 1990 to 119 million tons in fiscal 1999. Our highly productive western operations produce very low sulfur coal, which is attractive to utilities for purposes of complying with more stringent standards resulting from the Clean Air Act.
Our large and diverse customer base includes more than 150 electricity generating plants in the United States as well as steam and metallurgical customers in 15 other countries. In fiscal 1999, we supplied 93 percent of our United States production to United States electric utilities, 4 percent to the export market and 3 percent to the United States industrial sector.
COMPANY 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, and in 1977, it was sold to Peabody Holding Company, a holding company formed by a consortium consisting of Newmont Mining Corporation, The Williams Companies, Bechtel Investments, Inc., The Boeing Company, Fluor Corporation and The Equitable Life Assurance Society of the United States.
In July 1990, Hanson 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. The Energy Group was a publicly traded company in the United Kingdom. On May 19, 1997, The Energy Group, through Peabody, purchased Citizens Power, initiating its entry into the rapidly growing United States power marketing industry.
On May 19, 1998, Lehman Merchant Banking Partners II, an affiliate of Lehman Brothers, purchased Peabody Holding Company and its affiliates, Peabody Resources Limited ("Peabody Resources") and Citizens Power, now collectively called Peabody Group, in a transaction coinciding with the purchase by Texas Utilities of the remainder of The Energy Group.
ACQUISITIONS AND EXPANSION
During the 1980's, we 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 1986, 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, also in West Virginia.
From 1993 to 1999, we made twelve major acquisitions. In 1993, a major coal operation, including interests in three mines in New South Wales, Australia, was acquired from Costain Group in anticipation of the growing Pacific Rim market for coal. The properties included 100 percent ownership of the Ravensworth Mine, a 50 percent interest in the Narama Mine and a 37.5 percent interest in the Warkworth Mine, subsequently raised to 43.75 percent. We also subsequently developed a fourth mine, Bengalla, which began shipments in early 1999. Our stake in the Bengalla joint venture was raised to 37 percent in 1998.
In 1993, the Lee Ranch Mine in New Mexico was acquired. The following year, a one-third ownership in Black Beauty Coal Company ("Black Beauty"), Indiana's largest coal producer, was purchased. Our interest in Black Beauty was increased to 43.3 percent in February 1998 and to 81.7 percent in January 1999.
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 Basin increased from 31 million tons in 1993 to 98 million tons in fiscal 1999.
Since 1990, our coal sales volumes have grown from 93 million annual tons to 176 million annual tons, an increase of 89 percent. During this period, we transformed ourselves from a largely high sulfur, high cost coal producer to a more broadly based energy company providing predominantly low sulfur fuels and other products and services to the electricity industry.
OUR BUSINESSES
Through our interests in Peabody Resources in Australia, and Black Beauty, now operating in Indiana and Illinois, we have interests in joint ventures that expand the scope of our operations. Also, our ownership of Citizens Power and the development of coal and sulfur dioxide emission allowance trading have transformed us into a leading provider of low cost coal products and services, including power contract restructuring services, to the electricity industry.
Today, we are engaged in coal mining, marketing and transportation, electricity and coal contract restructuring, and coal, power and sulfur dioxide emission allowance trading. We also offer innovative fuel/power products and services to an electricity market that is in the process of being deregulated.
POWER MARKETING AND ELECTRICITY CONTRACT RESTRUCTURING
Our subsidiary, Citizens Power, headquartered in Boston, Massachusetts, is engaged in electricity contract restructuring and electricity, gas and oil trading. For purposes of our financing, Citizens Power and its subsidiaries are unrestricted subsidiaries.
Citizens Power obtained the first power trading license issued by the Federal Energy Regulatory Commission in 1989, and in calendar 1998, Citizens Power was among the top ten United States power marketing companies. Citizens Power is also a leader in electricity contract restructuring. During fiscal 1999, three such contract restructurings were completed. Typically, Citizens Power acts, through subsidiary companies, as a third party facilitator to obtain non-recourse financing, the proceeds of which are used to purchase, and then obtain lower cost replacement power, for long-term electricity supply contracts between independent power producers and electric utility companies.
MINING OPERATIONS
The following provides a description of the operating characteristics of the principal mines and reserves of each of our United States and Australian mining units.
U. S. OPERATIONS
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UNITED STATES
Within the United States, operations are divided into five operating regions: Powder River Basin; Southwest; Midwest; Southern Appalachia and Northern Appalachia. Our sales of coal in and from the United States are managed by our sales and marketing subsidiary, Peabody COALSALES, as well as Peabody COALTRADE. Together, United States coal sales totaled 168.6 million tons in fiscal 1999.
POWDER RIVER BASIN OPERATIONS
We own and manage three low sulfur, non-union surface mining complexes in Wyoming that sold approximately 97.5 million tons of coal in fiscal 1999, or approximately 55 percent of our total coal sales. The North Antelope/Rochelle and Caballo mines are serviced by the Burlington Northern/Santa Fe and Union Pacific railroads, while the Rawhide Mine is served by the Burlington Northern/Santa Fe. We control approximately 3.6 billion tons of coal reserves in the southern Powder River Basin, which enables us to increase or decrease production among our mines in that region to respond to market conditions. We recently suspended operations at the Rawhide Mine, shifting production under certain coal supply agreements to the Caballo Mine and the newly combined North Antelope/Rochelle Mine.
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 percent to 0.4 percent and the heat value ranges from 8,250 to 8,850 Btus per pound.
We also operate the Big Sky Mine in Montana in the northern Powder River Basin. Coal from this mine is shipped to customers in the upper Midwest and served by the Burlington Northern/Santa Fe railroad. Hourly workers at the Big Sky Mine are members of the United Mine Workers of America.
North Antelope/Rochelle
The North Antelope/Rochelle Mine is located 65 miles south of Gillette, Wyoming. Two mines were combined into a single mining complex in fiscal 1999 to achieve operational and administrative synergies. As separate mines, Rochelle and North Antelope were consistently ranked among the most productive in the United States. The combined North Antelope/Rochelle Mine now ranks as the largest coal mining operation in the United States, shipping 66.8 million tons during fiscal 1999.
The North Antelope/Rochelle Mine produces premium quality coal with a sulfur content averaging 0.22 percent and a heat value ranging from 8,500 to 8,800 Btus per pound. It produces the lowest sulfur coal in the United States. The mine uses a dragline along with five truck and shovel fleets to mine coal.
Caballo
The Caballo Mine is located 20 miles south of Gillette, Wyoming. In fiscal 1999, it sold approximately 27.3 million tons of 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. Dual loop tracks are in place connecting with the Burlington Northern/Santa Fe and Union Pacific railroads.
Rawhide
The Rawhide Mine is located ten miles north of Gillette, Wyoming and uses truck and shovel mining methods. In fiscal 1999, it sold approximately 3.4 million tons of low sulfur coal. Rawhide has four 11,000-ton silos and two 12,000-ton silos. Operations at the Rawhide Mine were suspended in 1999, pending improved market conditions for its lower-Btu coal.
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 3.3 million tons of low sulfur coal in fiscal 1999. The coal is shipped by rail to several major electric utility customers in the upper Midwestern United States. This mine is near the exhaustion of its economically recoverable reserves and may be closed in the next several years, depending upon market and mining conditions.
SOUTHWESTERN OPERATIONS
We own and manage two mines in Arizona and one each in Colorado and New Mexico. Each supply low sulfur coal under long-term coal supply agreements to electricity generating stations in the region. Together, these mines sold 18.4 million tons of coal in fiscal 1999.
Black Mesa
The Black Mesa Mine, which uses two draglines and is located on the Navajo and Hopi Indian reservations in Arizona, sold 4.5 million tons of steam coal in fiscal 1999. Its coal is crushed, mixed with water and then transported 273 miles through the underground Black Mesa Pipeline to Southern California Edison's Mohave Generating Station near Laughlin, Nevada. The mine and the pipeline were designed to deliver coal exclusively to the power plant, which has no other source of coal. The Mohave coal supply agreement extends until 2005. Hourly workers at this mine are members of the United Mine Workers of America.
Kayenta
The Kayenta Mine is adjacent to the Black Mesa Mine and uses three draglines in three mining areas. It sold approximately 7.5 million tons of steam coal in fiscal 1999. The coal is crushed, then carried 17 miles by conveyor belt to storage silos where it is loaded on to a private rail link 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 1.5 million tons of low sulfur steam coal in fiscal 1999, operating with two draglines in two separate mining areas. The Seneca Mine's coal is hauled by truck to the nearby Hayden Generating Station, operated by Public Service of Colorado, under a coal supply agreement that extends until 2011. Hourly workers at this mine are members of the United Mine Workers of America.
Lee Ranch Coal Company
The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 4.9 million tons of low sulfur coal in fiscal 1999. Lee Ranch shipped 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.
SOUTHERN APPALACHIA OPERATIONS
We own and manage three operating units and related facilities in southern West Virginia. In fiscal 1999, these operations sold approximately 13.3 million tons of low 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/Robin Hood Operating Unit
The Big Mountain/Robin Hood Operating Unit is based near Prenter, West Virginia. In fiscal 1999, the Big Mountain No. 16 and Robin Hood No. 9 mines sold approximately 1.8 million tons of steam coal. Both are underground mines using continuous mining equipment. Processed coal is loaded on the CSX railroad.
Pond Fork Operating Unit and Contract Mines
The Pond Fork Operating Unit consists of the Harris No. 1 Mine and the Rocklick preparation plant. Together, these units sold approximately 7.6 million tons of low sulfur steam and metallurgical coal in fiscal 1999. The Harris No. 1 Mine, near Bald Knob, West Virginia, sold approximately 3.6 million tons of low sulfur steam coal in fiscal 1999. This mine uses both longwall and continuous mining equipment. The Rocklick preparation plant, located near Wharton, West Virginia, processed coal produced by the Harris Mine and contract mining companies from coal reserves we own. This preparation plant shipped approximately 4.0 million tons of steam and metallurgical coal in fiscal 1999. Processed coal is loaded at the plant site on the CSX railroad or transferred via conveyor to the Kopperston loadout facility on the Norfolk Southern railroad.
Wells Operating Unit
The Wells Operating Unit, in Boone County, West Virginia, sold approximately 3.9 million tons of metallurgical and steam coal during fiscal 1999. The unit consists of the Lightfoot No. 1 and No. 2 mines and the Wells preparation plant, all located near Wharton, West Virginia. The mines use continuous miners to produce coal from reserves we own. The Lightfoot No. 1 mine closed on February 11, 1999 after depleting its mineable reserves. Processed coal is loaded on the CSX railroad.
NORTHERN APPALACHIA OPERATIONS
Federal No. 2 Mine
The Federal No. 2 Mine near Fairview, West Virginia, uses longwall- mining equipment and shipped approximately 4.7 million tons of steam coal in fiscal 1999. Coal shipped from the Federal No. 2 Mine has a sulfur content only slightly above that of low sulfur coal and, as a result, is more marketable than some other high sulfur coals. The mine is served jointly by the CSX and Norfolk Southern railroads, through which processed coal is sold to a variety of United States and Canadian utilities. Hourly workers at these operations are members of the United Mine Workers of America.
MIDWEST OPERATIONS
We own and operate eight mines in the Midwestern United States, which collectively sold 19.7 million tons of coal in fiscal 1999. Included are five underground and three surface mines, along with five preparation plants and four barge loading facilities, located in western Kentucky, southern Illinois and southwestern Indiana. Coal from these mines is primarily shipped to electric utilities in the Midwest, while some coal is sold to industrial customers that generate their own power. Approximately 51 percent of the high sulfur coal sold from these mining operations is shipped to electric generating stations equipped with desulfurization units. Most hourly workers are members of the United Mine Workers of America; Patriot Coal Company operates union-free.
We operate an additional 12 mines in the Midwestern United States through our 81.7 percent joint venture interest in Black Beauty.
Camp Operating Unit
The Camp Operating Unit, located near Morganfield, Kentucky, operates two underground mines and a large preparation and barge loading facility. Together, these operations sold 6.2 million tons of coal in fiscal 1999. The Camp No. 1 Mine uses continuous mining equipment with both continuous haulage systems and shuttle car haulage. The Camp No. 11 Mine uses both longwall and continuous mining equipment. Most of the production is sold to the Tennessee Valley Authority under a contract that expires in March 2000. Discussions for a follow-on contract are currently underway.
Hawthorn Operating Unit
The Hawthorn Operating Unit near Carlisle, Indiana uses three draglines and sold 3.0 million tons of steam coal in fiscal 1999. Processed coal is shipped to local utilities via the CSX railroad. Future production at this mine may be affected by the implementation of Phase II of the Clean Air Act Amendments since most of the coal is being sold to power plants that have not been retrofitted with scrubbers. We are examining the possibility of shipping coal to the Hawthorn Mine's principal customer from other facilities we own which are better able to meet the customer's future coal quality requirements.
Lynnville Operating Unit
The Lynnville Operating Unit, near Lynnville, Indiana, sold approximately 3.1 million tons of coal in fiscal 1999. The Lynnville Operating Unit uses three draglines and an electric shovel. Coal is processed at the Lynnville preparation plant and shipped via rail or barge to customers in Indiana and Kentucky.
Marissa Operating Unit
The Marissa Operating Unit, located near Marissa, Illinois, consists of the Marissa underground mine, the Randolph preparation plant and associated transportation facilities. The Marissa Operating Unit shipped 4.4 million tons of coal and uses six continuous miners. Most of the production is currently being shipped to Illinois Power Company, who announced its intention to begin using Powder River Basin coal in late 1999. This mine will close in fiscal 2000 unless we obtain new customers.
Midwest Operating Unit
The Midwest Operating Unit near Graham, Kentucky, sold 1.2 million tons of coal in fiscal 1999. The unit includes the Martwick underground mine, which uses continuous mining equipment, and several small surface mining operations. The unit is also responsible for closed or suspended mining operations throughout Peabody's North American operations. These properties are managed from bond release until final reclamation requirements are met. Future production may be affected by implementation of Phase II of the Clean Air Act Amendments.
Patriot Coal Company
Patriot Coal Company operates one surface mine and one underground mine in Henderson County, Kentucky, and sold approximately 1.8 million tons of coal in fiscal 1999. The underground mine uses continuous mining equipment, and the surface mine uses truck and shovel equipment. Patriot Coal Company also operates a preparation plant and a dock. The Big Run surface mine in Ohio County, Kentucky, closed in fiscal 1999 due to exhaustion of reserves.
BLACK BEAUTY COAL COMPANY
Peabody also owns 81.7 percent of Black Beauty, which operates nine mines in Indiana and also has interests in three mines in southern Illinois. Together these operations sold 17.0 million tons of low, medium and high sulfur steam coal in fiscal 1999. We purchased a one- third interest in Black Beauty in 1994, and added another 10 percent in 1998 and a 38.3 percent interest in early 1999. Black Beauty Resources, Inc., owned by certain members of Black Beauty's executive management team, owns the remaining interest.
Black Beauty's principal operating units include Air Quality No. 1 Mine, a low sulfur underground coal mine located near Monroe City, Indiana. In calendar 1998, Air Quality No. 1 Mine shipped 1.4 million tons of low sulfur coal. Among other mines in Indiana, Black Beauty also operates the Farmersburg Mine, a surface mine that produced 2.2 million tons of medium sulfur coal in calendar 1998, the Francisco Mine, a 2.1 million tons per year surface mine, and the Somerville Mine, a 1.3 million tons per year surface mine.
Black Beauty owns a 50 percent interest in Arclar Coal Company, which operates two underground mines in southern Illinois, and a 75 percent equity interest in Sugar Camp Coal, LLC, a 2 million tons per year surface mine also located in southern Illinois.
Black Beauty controls approximately 230 million tons of coal reserves, including the largest coal reserve in Indiana that will meet the Phase II Clean Air Act restrictions of 1.2 lbs. sulfur dioxide per million Btus required beginning after 1999.
AUSTRALIA
Peabody, through our subsidiary Peabody Resources which is headquartered in Sydney, Australia, own interests in coal mining operations and a mining services company in Australia. Peabody Resources manages and owns or holds joint venture interests in four operating surface coal mines in the Hunter Valley, New South Wales. All of these mines use draglines to uncover the coal seams. The mines sold 11.5 million short tons during fiscal 1999, of which Peabody Resources' entitlement was approximately 7.4 million tons. Approximately 70 percent of the coal is sold domestically via long-term contracts, and 30 percent is exported to Asia-Pacific markets.
AUSTRALIAN MINING OPERATIONS
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Ravensworth Mine
Located 12 miles northwest of Singleton, New South Wales, the Ravensworth Mine is 100 percent owned and managed by Peabody Resources under a long-term contract that runs to the year 2001 and requires the production of approximately 4.4 million tons per year from coal reserves owned by Macquarie Generation. The coal is trucked from the pit to a crushing plant and transported by overland conveyor to nearby Bayswater and Liddell power stations.
Narama Mine
The Narama Mine opened in January 1993 and is operated by Peabody Resources as an extension of the adjacent Ravensworth facility using similar mining techniques in the same coal seams. The Narama joint venture, of which Peabody Resources owns 50 percent, holds a 20 year contract extending through 2012 to supply approximately 2.3 million tons annually to Macquarie Generation.
Warkworth Mine
Located seven miles southwest of Singleton, the Warkworth Mine opened in 1981 and produces about 5.0 million tons per year of thermal and semi- soft coking coal each year, primarily for export. Peabody Resources manages the mine and owns 43.75 percent of the Warkworth Associates joint venture. The coal is processed at Warkworth Mine's preparation plant and blended to customer specifications before being transported by overland conveyor to the Mount Thorley rail loop and then by rail to the Port of Newcastle. Warkworth owns 13.9 percent of the Mount Thorley facility and 4.2 percent of the Port of Newcastle Coal Loading Terminal.
Bengalla Mine
The Bengalla Mine is located near Muswellbrook, New South Wales and is owned by the Bengalla joint venture, in which Peabody Resources holds a 37 percent interest. Construction of the first stage of a 6.1 million ton per year surface mine and facility is nearing completion, and production commenced in April 1999. The joint venture includes Taiwanese and Korean power utilities and a major trading house in Japan. Coal is removed by a system of loaders and conveyors and delivered to a modern coal preparation plant, then transported via rail to the Port of Newcastle for export.
Mining Services Division
Peabody Resource's Mining Services division is based in Brisbane, Queensland, and provides specialized tunneling and underground contract mining services to the mining and civil engineering industries. The Mining Services division has been involved in underground development work for a number of Australian mining companies and civil works projects, including BHP Minerals at Cannington, Western Mining Corporation at Olympic Dam, Placer Pacific at Osborne, and Plutonic Resources Limited at Darlot.
LONG-TERM COAL SUPPLY AGREEMENTS
United States
We have a large portfolio of coal supply agreements. For the year ended March 31, 1999, 87 percent of our sales volume was sold under coal supply agreements. We currently have coal supply agreements totaling approximately one billion tons of coal with terms ranging from one to 15 years and with an average volume-weighted remaining term of more than 4 years. This contract tonnage total does not include coal supply agreements of Black Beauty, which total approximately 120 million tons. In fiscal 1999, we sold coal to approximately 150 power plants in the United States and Canada and exported to 14 countries aboard.
Contract Terms
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 mines needed to supply such contracts. The terms of coal supply agreements result from bidding and extensive negotiations with customers. Consequently, the terms of such 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.
Price reopeners are present in most of the recently negotiated contracts greater than three years in duration and usually occur midway through a contract or every two to three years, depending upon the length of the contract. Price reopeners allow the contract price to be renegotiated in order to correspond with the market price prevailing at the time. If the parties do not agree on a new price, the purchaser or seller often has an option to terminate the contract.
Base prices are set at the start of a contract and are oftentimes 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 United States Department of Commerce.
Quality and volumes for the coal are stipulated in coal supply agreements, although buyers normally have the option to vary annual or monthly volumes by up to 10 percent, 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 (Btus), sulfur, ash, grindability and ash fusion temperature. Failure to meet these specifications can result in economic penalties or termination of the contracts.
Contract provisions in some cases set out how coal volumes will be temporarily reduced or delayed in the event of a force majeure, including such events 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 insert 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.
In certain contracts, we have a right of substitution, allowing us to provide coal from different mines as long as the replacement coal is within a certain specified quality and will be sold at the same delivered cost. Contracts usually contain specified sampling locations: in the Eastern United States, approximately 50 percent 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.
Contract Expirations
Our coal supply agreements have an average volume-weighted remaining term of more than 4 years. As our coal supply agreements expire, we intend to negotiate new contracts in order to maintain our high percentage of volume sold through coal supply agreements and low percentage of volume sold into the spot market. When contracts expire, a coal producer is exposed to the risk of selling coal into the spot market, which may be subject to lower and more volatile prices, or to closing the mine if follow-on business cannot be obtained.
The total sales commitments corresponding to the coal supply agreements currently total approximately one billion tons of coal, assuming all the contracts run through to their expiration date. Contracts for coal from the mines in the Powder River Basin comprise approximately 65 percent of this total commitment.
Australia
In fiscal 1999, approximately 70 percent of Peabody Resources' 7.4 million ton share of coal produced by Australian mines was sold under coal supply agreements to the New South Wales power utility, Macquarie Generation. The remainder was exported to Pacific Rim countries. Coal from the Ravensworth and the Narama mines is sold to Macquarie Generation under contracts which expire in 2001 and 2012, respectively. The contracts contain price adjustment provisions based on the qualities of coal delivered and changes in indices of mining costs.
All coal from the Warkworth mine is exported. Approximately 75 percent is sold under contracts, including contracts with the other joint venture partners in Warkworth, and the remaining 25 percent is sold on the spot market. Peabody Resources' export contracts normally provide for annual price renegotiations.
The new Bengalla Mine began selling coal in early 1999 under annual contracts and in the spot market. Some of Bengalla's sales will be directed to the mine's joint venture partners, including Taiwan Power and Korea Electric.
TRANSPORTATION
Coal for domestic consumption is generally sold at the mine and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, and coal producers are responsible for shipment to the export coal-loading facility and the buyer pays the ocean freight. Coal for electricity generation is purchased on the basis of its delivered cost per million Btus. Most utilities arrange long-term shipping contracts with rail or barge companies to assure stable delivered costs.
Transportation is often a large component of the buyer's cost. Although the cost of freight is absorbed by the customer, transportation cost is still important to coal mining companies because the customer may choose a supplier largely based on the cost of transportation. According to RDI Coaldat, in 1998 transportation costs represented 56 percent, 25 percent and 23 percent of the overall cost of coal produced in the Western, Eastern and Midwestern United States, respectively.
According to RDI Coaldat, in 1998 approximately 83 percent of all United States coal was shipped by rail or barge, making these modes the keys to domestic coal distribution. Trucks and overland conveyors are used to haul coal over shorter distances, while lake carriers and ocean colliers move coal to export markets, although some domestic coal is shipped over the Great Lakes. Railroads move more coal than any other commodity, and in 1997 coal accounted for 22 percent of total United States rail freight revenue and 44 percent of total freight tonnage. Most coal mines are served by a single rail company, but much of the Powder River Basin is served by two competing rail carriers, the Burlington Northern/Santa Fe and the Union Pacific. Rail competition in this major coal producing
region is important, since rail costs constitute up to 75 percent of the delivered cost of Powder River Basin coal in remote markets. Rail rates for the Powder River Basin are lower when evaluated on a ton-per-mile basis because the relatively flat and straight rail routes out of the region allow heavily loaded trains to operate with less manpower and locomotive power than rail routes in other regions.
SALES AND MARKETING
Our subsidiaries, Peabody COALSALES and Peabody COALTRADE, undertake the sales and marketing functions for our United States operating subsidiaries, including exports from the United States. Peabody COALSALES acts as an agent in the sale and marketing of the coal produced by each mining subsidiary, and it generates profits through its brokering and agency activities. Peabody COALTRADE buys and resells coal produced by a number of third parties, and trades coal options and sulfur dioxide emission allowances in the developing over-the-counter markets. As of March 31, 1999, they had 43 employees located at five sites. They annually prepare a marketing plan that sets out the sales targets for the next five years by region, coal type and markets. The strategic plan formulates and concentrates the ongoing work carried out by the sales and marketing teams to sell the mines' production through different sales and marketing initiatives.
COMPETITION
The markets in which we sell our coal are highly competitive. The top ten coal producers in the United States produce approximately 61 percent of total domestic coal, although there are approximately 900 coal producers in the United States. Our principal competitors in coal operations are other large coal producers. Our largest competitors are Arch Coal, Inc., Kennecott Energy Co., Cyprus Amax Coal Company (which is being sold to a United States unit of RAG AG), CONSOL Energy Inc., AEI Resources, Inc. and A.T. Massey Coal Company, which collectively produced approximately 46 percent of total United States coal production in 1998.
The markets in which we sell our coal are affected by a number of factors beyond our control. 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 and the Pacific Rim countries, the availability, location (and therefore the cost of transportation) and price of competing coal and alternative 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. In recent years, there has been excess coal production capacity due to increased development of large surface mining operations in the Western United States, more efficient mining equipment and techniques and reduced consumption of high sulfur coal. We compete on the basis of coal quality, delivered price, customer service and support and reliability.
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. Purchases of capital goods, materials and services are approximately $550 million per annum, which is approximately 25 percent of our annual revenue. The supplier base providing these goods has been relatively consistent in recent years as we have many long established relationships with our key suppliers.
Between 25 percent and 30 percent of goods and services are supplied by the top ten suppliers, and some 70 percent of goods and services are provided by the top 100 suppliers. We do not have any supply arrangements with related parties, and all transactions are carried out on an arm's length basis. We consider all suppliers of a particular category of supplies to be interchangeable and do not believe we are vulnerable to over-dependence on any one supplier.
REGULATORY MATTERS
Our operations are subject to extensive regulation in the United States and Australia regarding production, sale, distribution, health and safety and environmental matters.
United States
The United States coal mining industry is subject to regulation by federal, state and local authorities on 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 all permits currently required to conduct our present mining operations have been obtained. 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. Such 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 cannot be predicted.
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 have been material.
Mine Health and Safety
Stringent health and safety standards have been in effect since the Coal Mine Health and Safety Act of 1969 was adopted by Congress. The Federal Mine Health and Safety Act of 1977 significantly expanded the enforcement of health and safety standards and imposed health and safety standards on all aspects of mining operations.
Most of the states in which we operate have state programs for mine health and safety regulation and enforcement. In combination, federal and state health and safety 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 United States industry. While regulation has a significant effect on our operating costs, our United States competitors are subject to the same degree of regulation.
Our goal is to achieve excellent health and safety performance. We measure our success in this area primarily through the use of accident frequency rates. We believe that this goal 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 is required to 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 percent of the miners currently seeking federal black lung benefits are awarded such 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 percent of the sales price. This tax is passed on to the purchaser under many of our coal supply agreements.
Legislation on black lung reform has been introduced in this session of Congress. The legislation would restrict the evidence that can be offered by a mining company, establish a standard for evaluation of evidence that greatly favors black lung claimants, allow claimants who have been denied benefits at any time since 1981 to refile their claims for consideration under the new law, make surviving spouse benefits significantly easier to obtain and retroactively waive repayment of preliminarily awarded benefits that are later determined to have been improperly paid. If this or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase.
The United States Department of Labor has issued proposed amendments to the regulations implementing the federal black lung laws which, 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.
Coal Industry Retiree Health Benefit Act of 1992
The Coal Industry Retiree Health Benefit Act of 1992, also known as the Coal Act, was enacted to provide 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 $9.2 million in fiscal 1999.
In October 1998, the Combined Fund sent a premium notice to all assigned operators subject to the fund which included retroactive death benefit and health benefit premiums dating back to February 1, 1993. On November 13, 1998, ten employers (including two of our subsidiaries, Peabody Coal Company and Eastern Associated Coal Corp.) challenged the fund's retroactive rebilling in a lawsuit filed in the Northern District Court of Alabama. The ten employers have recently filed an amended complaint which adds another plaintiff and the United States Department of the Interior as a defendant. The case is still pending. Our subsidiaries' retroactive premium amounts to approximately $1.3 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 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, among other things, require that mined property be restored 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.
The Surface Mining Control and Reclamation Act also requires that comprehensive environmental protection and reclamation standards be met during the course of, and upon completion of, mining activities. For example, it requires us to restore a surface mine to the approximate original contour as contemporaneously as practicable with surface coal mining operations. 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. The estimated cost of reclamation, and the corresponding accrual on our financial statements, is adjusted annually.
All states in which our active mining operations are located 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, our 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.
The Clean Air Act
The Clean Air Act and the Clean Air Act Amendments, and 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 emissions control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 2.5 micrometers in diameter or smaller. In July 1997, the Environmental Protection Agency adopted new, more stringent National Ambient Air Quality Standards for 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. Because coal mining operations emit particulate matter, our mining operations and utility 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 ruled in May 1999 that the 10 micrometer particulate and eight hour standards were invalid. The Court also ordered a new briefing on the validity of the fine particulate standard. The effect of this decision on us and our customers is unknown at this time.
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-fueled utility power plants. 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 such facilities. Reductions in such emissions occurred in Phase I in 1995 and additional reductions will occur in Phase II in 2000 and will apply to all coal-fired power plants, including those subject to the 1995 restrictions. The affected utilities have been and may be 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 or trading sulfur dioxide emission allowances. Specific emission sources will receive these sulfur dioxide emission allowances, which utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. The effect of these provisions of the Clean Air Act Amendments on us cannot be completely ascertained at this time. We believe that implementation of Phase II will likely exert a downward pressure on the price of higher sulfur coal, as additional coal-burning utility power plants become subject to the restrictions of Title IV.
The Clean Air Act Amendments also require utilities that currently are major sources of nitrogen oxides in moderate or higher ozone nonattainment areas install reasonably available control technology for nitrogen oxides, which are precursors of ozone. In addition, the recently issued, stricter ozone standards, as discussed above, are expected to be implemented by the Environmental Protection Agency by 2003. The Ozone Transport Assessment Group, formed to make recommendations to the Environmental Protection Agency for addressing ozone problems in the Eastern United States, submitted its final recommendations to the Environmental Protection Agency in June 1997. Based on their recommendations, the Environmental Protection Agency recently announced the final rules that would require 22 Eastern states to make substantial reductions in nitrogen oxide emissions. Under this rule, the Environmental Protection Agency expects that states will achieve these reductions by requiring power plants to make substantial reductions in their nitrogen oxide emissions. Installation of reasonably available control technology and additional control measures required under the final rules will make it more costly to operate coal-fired utility power plants and, depending on the requirements of individual state attainment plans and the development of revised new source performance standards, could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. In a decision on May 1999, the Court of Appeals for the District of Columbia enjoined enforcement of the final rules pending a final court decision in a related lawsuit.
In accordance with Section 126 of the Clean Air Act, eight Northeastern states filed petitions requesting the Environmental Protection Agency 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 Environmental Protection Agency has proposed to grant the petitions of certain states that certain sources are contributing to ozone nonattainment in certain of the petitioning states and the Environmental Protection Agency has proposed levels of nitrogen oxide control for the named sources. Our customers are among the named sources and, if the petitions are granted, the requirement to install control equipment could impact the amount of coal supplied to those customers if they decide to switch to other sources of fuel which would result in lower emission of nitrogen oxides.
The Clean Air Act Amendments 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 impact the amount of coal supplied to those customers if they decide to switch to other sources of fuel which use would result in lower emission of sulfur oxides and nitrogen oxides.
In addition, the Clean Air Act Amendments require a study of utility power plant emissions of certain toxic substances, including mercury, and direct the Environmental Protection Agency to regulate these substances, if warranted. In a recent report, the Environmental Protection Agency indicated that although it plans to further study the issue, it does not plan to propose regulations in the near future. However, future federal or state regulatory or legislative activity may seek to reduce mercury emissions and such requirements, if enacted, could result in reduced use of coal if utilities 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
The Resource Conservation and Recovery Act, which was enacted in 1976, affects coal mining operations by imposing requirements for the treatment, storage and disposal of hazardous wastes. Coal mining operations covered by the Surface Mining Control and Reclamation Act permits are exempted from regulation under the Resource Conservation and Recovery Act by statute; however we cannot predict whether this exclusion will continue.
Federal and State Superfund Statutes
The Comprehensive Environmental Response Compensation and Liability Act, or 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 to 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 Global Climate Change which is intended to limit or capture emissions of greenhouse gases such as carbon dioxide. In December 1997 in Kyoto, Japan, the signatories to the convention established a binding set of emissions 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 percent 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, such 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 Annual Energy Outlook for 1998, coal accounts for 36 percent 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.
Australia
The Australian mining industry is regulated by Australian federal, state and local governments with respect to environmental issues such as land reclamation, water quality, air quality, dust control and noise, planning issues such as approvals to expand existing mines or to develop new mines, and health and safety issues. The Australian federal government retains control over the level of foreign investment and export approvals. Industrial relations are regulated under both federal and state laws. Australian state governments also require coal companies to post deposits or give other security against land which is being used for mining, with those deposits being returned or security released after satisfactory rehabilitation.
Mining and exploration in Australia is generally carried on under leases or licenses granted by state governments. Mining leases, which are typically for an initial term of up to 21 years (but which may be renewed), contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.
Environmental
Primary responsibility for environmental regulation in Australia is vested in the state, rather than the federal system. Each state and territory in Australia has its own environmental and planning regime for the development of mines. In addition, each state and territory also has a specific act dealing with mining in particular, regulating the granting of mining licenses and leases. The mining legislation in each state and territory operates concurrently with environmental and planning legislation. The mining legislation governs mining licenses and leases, including the restoration of land, following the completion of mining activities. Apart from the grant of the rights to mine itself (which are covered by the mining statutes), all licensing, permitting, consent and approval requirements are contained in the various state and territory environmental and planning statutes.
The particular provisions of the various state and territory environmental and planning statutes vary depending upon the jurisdiction. Despite the variation in particulars, each state and territory has a system involving at least two major phases: (1) obtaining the developmental application and, if that is granted, obtaining the detailed operational pollution control licenses (which authorize emissions up to a maximum level); and (2) pollution control approvals (which authorize the installation of pollution control equipment and devices). In the first regulatory phase, an application to a regulatory authority is filed. The relevant authority will either grant a conditional consent, an
unconditional consent, or deny the application based on the details of the application and on any submissions or objections lodged by members of the public. If the developmental application is granted, the detailed pollution control license may then be issued and such license may regulate: emissions to the atmosphere; emissions in waters; noise impacts, including impacts from blasting; dust impacts; the generation, handling, storage and transportation of waste; and requirements for rehabilitation and restoration of land.
Each state and territory in Australia also has either a specific statute or certain sections in other environmental and planning statutes relating to the contamination of land and vesting powers in the various regulatory authorities in respect of the remediation of contaminated land. Those statutes are based on varying policies - the primary difference between the statutes is, that in certain states and territories, liability for remediation is placed upon the occupier of land, regardless of the culpability of that occupier for the contamination. In other states and territories, primary liability for remediation is placed on the original polluter, whether or not the polluter still occupies the land. If the original polluter cannot itself carry out the remediation, then a number of the statutes contain provisions which enable recovery of the costs of remediation from the polluter as a debt.
Many of the environmental planning statutes across the states and territories contain "third party" appeal rights in relation, particularly, to the first regulatory phase. This means that any party has a right to take proceedings for a threatened or actual breach of the statute, without first having to establish that any particular interest of that person (other than as a member of the public) stands to be affected by the threatened or actual breach. As a result, this makes third party challenges to consents for the carrying out of development relatively common.
Accordingly, in most states and territories throughout Australia, mining activities involve a number of regulatory phases. Following exploratory investigations pursuant to a mining license, the activity proposed to be carried out must be the subject of an application for the activity or development. This phase of the regulatory process, as noted above, usually involves the preparation of extensive documents to constitute the application, addressing all of the environmental impacts of the proposed activity. It also generally involves extensive notification and consultation with other relevant statutory authorities and members of the public. Once a decision is made to allow a mine to be developed by the grant of a development consent, permit or other approval, then a formal mining lease can be obtained under the mining statute. In addition, operational licenses and approvals can then be applied for and obtained in relation to pollution control devices and emissions to the atmosphere, to waters and for noise. The obtaining of licenses and approvals, during the operational phase, generally does not involve any extensive notification or consultation with members of the public, as most of these issues are anticipated to be resolved in the first regulatory phase.
Occupational Health and Safety
The combined effect of various state and federal statutes requires an employer to ensure that persons employed in a mine are safe from injury risks by providing: a safe working environment and systems of work; safe machinery, equipment, plant and substances; and appropriate information, instruction, training and supervision.
In recognition of the specialized nature of mining and mining activities, specific occupational health and safety obligations have been mandated under state legislation that deals specifically with the coal mining industry. Mining employers, owners, directors and managers, persons in control of work places, mine managers, supervisors and employees are all subject to these duties.
It is mandatory for an employer to have insurance coverage in respect of the compensation of injured workers; similar schemes are in effect throughout Australia which are of a no fault nature and which provide for benefits up to a prescribed level. The specific benefits vary from jurisdiction to jurisdiction, but generally include the payment of weekly compensation to an incapacitated employee, together with payment of medical, hospital and related expenses. The injured employee has a right to sue his or her employer for further damages if a case of negligence can be established.
DEREGULATION OF THE ELECTRIC UTILITY INDUSTRY
In October 1992, the Energy Policy Act of 1992 was enacted. To stimulate competition in the electricity market, the Act gave wholesale suppliers access to the transmission lines of United States electric utility companies. 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. While the Federal Energy Regulatory Commission proceeds to open access to wholesale electric markets, individual states are proceeding with the opening of retail access.
The pace of change differs significantly from state to state. To date, 10 states have enacted programs leading to the deregulation of the retail electricity market; 39 other states are considering such programs. Due to the uncertainty around timing and implementation of deregulation in each state, it is difficult to predict the impact on individual electric utilities.
When ultimately implemented, full-scale deregulation of the power industry will 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 electric utilities 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 the deregulation is anticipated downward pressure on fuel prices. However, because coal-fired generation is competitive with most other forms of generation, a competitive electricity market may stimulate greater demand for coal to be burned in plants with currently unused capacity. In 1998, for example, the average cost of generating electricity in coal-based generating units was less than one half the average cost of generating electricity in gas-fired units, and coal-based generation accounted for 56.3 percent of all electricity produced in the United States last year. Because of our cost advantage and because some coal-based generating facilities are underutilized in the current regulated electricity market, we estimate that additional coal demand could arise if the electricity market were rationalized and the most efficient coal-fired power plants were used to their full capacity. Estimates of this additional demand for coal vary between 100 and more than 200 million tons annually for the coal industry as a whole.
In the early 1990's, the Australian Federal Government commenced deregulation of the electricity market as part of Australia's ongoing micro-economic reform.
The commencement of the National Electricity Market in 1998 was to introduce competition in the wholesale supply and purchase of electricity combined with an open access regime for the use of electricity networks across the Eastern states of Australia. Introduction of competition was to be achieved by: restructuring the supply industry into the separate elements of generation, transmission and distribution, and retail supply; privatization of generation and retail supply; and enhancement and extension of the Eastern states interconnection of power systems.
Some states, in particular Victoria, have privatized power generation, transmission and distribution, and retail supply as part of the ongoing deregulation of the industry. In New South Wales the market is dominated by incorporated government utilities.
CITIZENS POWER
Industry Overview
Electricity is the most prevalent commodity sold in the United States economy, with retail volume in 1998 exceeding $218 billion, according to the Energy Information Administration. While the independent power marketing industry is in a developmental stage, the volume of megawatt hours traded grows substantially year to year.
The United States electricity market is highly fragmented, with more than 3,500 entities selling power on a wholesale and retail basis, including more than 240 investor-owned utilities, and nearly 3,000 federal, state and municipal power entities and rural co-operatives. Historically, these entities have been highly regulated, but with the onset of deregulation, we expect the role of power marketing companies to continue to grow. We believe that deregulation will create new market opportunities for power and fuel trading, energy contract restructuring and for new products, such as options, to facilitate the rationalization of the electricity market.
Citizens Power Overview
Citizens Power is a licensed power marketer that trades and markets electric power and other energy commodities. According to industry rankings, for the year ended December 31, 1998, Citizens Power was among the top ten of more than 400 Federal Energy Regulatory Commission- authorized power marketers as measured by the number of megawatt hours bought and sold as reported by Power Markets Week. Citizens Power also structures and trades electricity, and provides services related to the restructuring of long-term power contracts.
Citizens Power obtained the first power marketing authorization from the Federal Energy Regulatory Commission in 1989. Since that time, Citizens Power has continued to solidify our position as an innovator in the United States power marketing industry. At present, Citizens Power is an integrated energy company with business activities in three main areas: (1) power/energy sales and trading, (2) transaction/asset restructuring and (3) fuel/power integration.
Power/Energy Sales and Trading
Citizens Power executes short-term, intermediate-term and long-term trades of both physically and financially settled electricity and natural gas contracts. Citizens Power's extensive network of contracts provide the ability to purchase and sell electricity and obtain access to transmission throughout the United States, maximizing access to counterparties and increasing liquidity. Citizens Power uses their trading activities as a platform to develop higher margin structured products and to support prior contract restructurings. Citizens Power manages trading exposure with a value-at-risk measurement, limiting the exposure to certain defined limits.
Power Contract Restructuring
Power contract restructuring creates value by correcting inefficiencies in ownership, operation, dispatching, pricing, risk allocation and regulation of power supply assets and contractual relationships. The transactions enhance value by using financial leverage and tax-advantaged structures, managing and reducing the forward curve of power costs, reallocating transactional risks and arbitraging supply costs and discount rates.
There are approximately 35,000 megawatts of capacity operated by non- utility generators in the United States. This capacity is purchased through long-term contracts, some of which are priced significantly above the current market rates. Citizens Power uses their expertise to restructure these contracts, creating solutions for all participants. Each transaction is unique and requires an established trading infrastructure, strong industry-wide relationships and complex negotiations with multiple parties.
Fuel/Power Integration
Citizens Power combines its power trading, financing and structured products expertise with the significant strength and market position of Peabody, the world's largest producer of coal, under the Peabody Energy Solutions trademark to add value through the integration of fuel and power. Through the Peabody Energy Solutions initiative, Citizens Power offers a variety of innovative and customized fuel, transportation and power products and services to the evolving North American energy markets.
Information Technology
Citizens Power has made significant investments in an integrated information technology infrastructure. The Energy Trading System links the trading, scheduling and accounting functions providing for integrated market, credit and operational price risk management. The Energy Trading System was developed using the latest client-server technology, allowing for flexible in-house customization and expansion.
EMPLOYEES
As of March 31, 1999, we and our joint ventures had approximately 7,800 employees. Of these employees, approximately 6,900 worked in the United States and 900 worked in foreign countries.
Approximately 48 percent of our United States coal employees are affiliated with organized labor unions, which accounts for approximately 31 percent of our fiscal 1999 mining revenues in the United States. Relations with organized labor are important to our success. 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 1996 and is effective through August 31, 2000. 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.
The Australian coal mining industry is highly unionized and the majority of workers employed at Peabody Resources are members of trade unions. These employees are represented by three unions: the United Mine Workers, which represents the production employees; and two unions that represent the other staff. The miners at Warkworth Mine signed a three year labor agreement which expires in September 1999. Renegotiation of the agreement for a minimum two additional years is nearing completion, with no major issues outstanding. The miners at Ravensworth and Narama Mines have signed a further enterprise labor agreement for two years commencing May 1999.
The Australian Federal Government, as part of micro-economic reform, has a Workplace Relations Strategy that seeks structural reform to encourage enterprise focus and to facilitate enterprise agreements. Under the legislation Bengalla has commenced the employment of its workforce under individual workplace agreements with each employee. These agreements do not require ratification by a coal union.
ADDITIONAL INFORMATION
We file annual reports on Form 10-K, quarterly reports on Form 10-Q and other information with the Securities and Exchange Commission. You may request copies of the filings, at no cost, by telephone at (314) 342- 3400 or by mail at: P&L Coal Holdings Corporation, 701 Market Street, Suite 700, St. Louis, Missouri 63101, attention: Public Relations.
ITEM 2.
ITEM 2. PROPERTIES.
COAL RESERVES
We had an estimated 10.3 billion tons of proven and probable reserves as of April 1, 1999, of which approximately 52 percent were low sulfur coal. We own approximately 43 percent of these reserves and lease the remaining 57 percent.
Below is a table summarizing the locations and reserves of our major operating units.
Reserve estimates are based on geological data assembled and analyzed by our staff, which includes various geologists and engineers. The reserve estimates are periodically updated to reflect production of coal from the reserves and new drilling or other data received. Accordingly, reserve estimates will change from time to time reflecting mining activities, analysis of new engineering and geological data, changes in reserve holdings, modification of mining methods and other factors. 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, is maintained 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. Data from individual drill holes are compiled into 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 the 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 the 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 on October 1, 1996, includes a review of the procedures used by us to prepare our internal reserve estimates, verifying the accuracy of selected property reserve estimates and retabulating reserve groups according to standard classifications of reliability.
We have numerous federal coal leases that are administered by the United States Department of the Interior pursuant to 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 lease 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 life and at ten yearly 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 percent of the gross proceeds of coal mined and sold for surface mined coal and 8 percent for underground mined coal. 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 National and Hopi Indian reservations. We also lease coal from various state governments.
Private coal leases normally have terms of between 10 and 20 years, and usually give us the right to renew the lease for a stated period or to maintain the lease in force until the exhaustion of mineable and merchantable coal contained on the relevant site. These private leases provide for royalties to be paid to the lessor either as a fixed amount per ton or as a percentage of the sales price. Many leases also require payment of a lease bonus or minimum royalty, payable either at the time of execution of the lease or in periodic installments.
The terms of private leases are normally extended by active production on or near the end of the lease term. Leases containing undeveloped reserves may expire or such leases may be renewed periodically. With a portfolio of approximately 10.3 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 such time as we prepare to mine such reserves.
Mining and exploration in Australia is generally carried on under leases or licenses granted by state governments. Mining leases, which are typically for an initial term of up to 21 years (but which may be renewed), contain conditions relating to such matters as minimum annual expenditures, restoration and rehabilitation. Surface rights are typically acquired directly from landowners and, in the absence of agreement, there is an arbitration provision in the mining law.
Peabody Resources holds or has rights to coal mining leases at Warkworth, Bengalla, Narama and Ravensworth East. Ravensworth is mined under contract from coal reserves owned by Macquarie Generation. Warkworth's mining lease has been renewed until 2023 with Bengalla and Narama leases valid until 2017 and 2012, respectively. Ravensworth East's lease expires in 1999 and an application for renewal for a 21 year period has been made. Peabody Resources also holds an exploration license for Ravensworth West and has applied for a mining lease.
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 are adequately reserved for these liabilities and that there is no individual case pending that could have a material adverse effect on our financial condition or results of operations. Our significant legal proceedings are discussed below. Concurrent adverse resolution of such proceedings could have a material effect on the results of operations for a particular interim or annual period.
Eastern Enterprises
On November 1, 1993, Eastern Enterprises filed suit in the United States District Court for the District of Massachusetts against the Social Security Administration and the Combined Fund claiming that the Coal Act, as applied to Eastern Enterprises, violated the due process and taking clauses of the Fifth Amendment. In 1994, Eastern Enterprises filed a third party complaint against Peabody Holding Company, Eastern Associated and Eastern Associated's parent company, Coal Properties Corp., seeking indemnification or contribution with respect to any liability that Eastern Enterprises may have under the Coal Industry Retirees Health Benefit Act of 1992, or the Coal Act. Eastern Enterprises claimed that the amount of its Coal Act liabilities was approximately $100 million.
The District Court held in 1996 that the Coal Act was constitutional. Eastern Enterprises filed an appeal with the First Circuit Court of Appeals, which affirmed the district court's decision. The United States Supreme Court accepted Eastern Enterprises' petition for certiorari on the constitutional claims. In a plurality decision issued on June 26, 1998, the Supreme Court found that the Coal Act as applied to Eastern Enterprises violated the takings clause of the Fifth Amendment. The United Mine Workers of America beneficiaries that were assigned to Eastern Enterprises will continue to receive retiree health care benefits from the Combined Fund without cost to us.
Eastern Enterprises advised Peabody Holding Company that it was unwilling to dismiss the third-party complaint and intended to seek reimbursement for its attorneys fees and prejudgment interest. We settled the third party claim for an immaterial amount.
Salt River Project Agricultural Improvement and Power District
The Salt River Agricultural Improvement and Power District and the other owners of the Navajo Generating Station, or Salt River, 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 relating to life insurance and 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 partially granted by the trial court. 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 has filed an appeal of the order denying arbitration of the retiree health care costs with the Arizona Court of Appeals, which was denied by the Court. Peabody Western then filed an appeal with the Arizona Supreme Court, which was denied. Peabody Western and Salt River will arbitrate the mine decommissioning costs issue and will litigate the retiree health care costs issue.
If Salt River is successful in the arbitration and litigation, our financial condition and results of operations may be adversely affected. However, based on our preliminary evaluation of the issues and the potential impact on us, and while the outcome of litigation and arbitration is subject to uncertainties, we believe that the matter will be resolved without a material adverse affect 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 Coal Company ("Peabody Western"), Southern California Edison Company and the other owners of the Mohave Generating Station, or Edison, 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 will expire in 2005.
Peabody Western filed a Motion to Compel Arbitration, which was granted by the trial court. Edison appealed this order to the Arizona Court of Appeals, which denied its appeal. Edison 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 parties have agreed to a stay of the arbitration pending the resolution of the arbitrability of these issues under the coal supply agreement.
If Edison is successful in the matter, our financial condition and results of operations may be adversely affected. However, based on a preliminary evaluation of the issues and the potential impact on us, we believe that the matter will be resolved without a material adverse affect on our financial condition or results of operations.
Public Service Company of Colorado
In August 1996, Seneca Coal Company, a subsidiary of Peabody Western Coal Company, filed a demand for arbitration in accordance with the terms of an Amended Revised Coal Supply Agreement dated December 1, 1971 between Seneca and three electric utilities, Public Service Company of Colorado, Salt River Project Agricultural Improvement District and PacifiCorp, or the Hayden Participants. The Hayden Participants own the Hayden Electric Generating Station at Hayden, Colorado. The arbitration demand requested the entry of an award for Seneca and against the Hayden Participants for amounts attributable to final reclamation, mine decommissioning and environmental monitoring of the Seneca mine and life insurance and post-retirement health care.
In September 1996, the Hayden Participants filed a complaint for declaratory judgment in the District Court for the City and County of Denver seeking a judicial declaration that they were not responsible for post-mine closure costs as a matter of law. The Hayden Participants also requested declaratory and other relief with respect to other claims against Seneca Coal Company including a determination that the contract expires in approximately 2005.
The arbitration provision in the 1971 Agreement limits the jurisdiction of the arbitrators to resolution of disputed issues of fact but the arbitrators are to determine the arbitrability of any dispute in the first instance. Accordingly, Seneca Coal Company filed a motion to stay the judicial proceedings with respect to the issue of responsibility under the 1971 Agreement for post-mine closure costs pending the outcome of the arbitration. The District Court granted the motion in January 1997.
The arbitration hearing was held in March 1999. In June 1999, the arbitrators issued their Findings of Fact in favor of the interests of Seneca Coal Company. The Denver District Court must now apply legal principles to the Findings of the arbitrators. We continue to believe that the dispute will be resolved without a material adverse effect on our financial condition or results of operations.
Macquarie Generation
In September 1997, our subsidiary, Peabody Resources, filed a lawsuit against Macquarie Generation in the Supreme Court of New South Wales, Commercial Division, seeking damages for certain coal deliveries which were not paid by Macquarie Generation and for a declaratory judgment regarding the assignment to Macquarie Generation of two long-term coal supply agreements for the Ravensworth and Narama mines. The contracts expire in 2001 and 2012, respectively. Macquarie Generation later agreed that the two contracts were properly assigned to it. Macquarie Generation subsequently filed a cross-claim against Peabody Resources alleging that Peabody Resources breached the labor escalation provisions in the coal supply agreements, committed misrepresentations regarding the labor costs and violated the Australian trade practices and fair trading laws in relation to the Narama contract. Macquarie Generation sought to terminate or rescind the Narama coal supply agreement and has sought damages from Peabody Resources for alleged breaches of both contracts. Even though we continued to deliver coal, Macquarie Generation unilaterally reduced the price that it is paying for coal deliveries under the Narama contract. A trial regarding these issues began on September 7, 1998 and concluded on September 25, 1998. On September 22, 1998, Macquarie Generation withdrew its breach of contract claims.
The Supreme Court of New South Wales issued a decision on November 19, 1998 rejecting Macquarie Generation's claims to terminate the coal supply agreement for the Narama mine. The Court also rejected Macquarie Generation's claim for damages. The Court ordered Macquarie Generation to pay Peabody Resources the portion of the price that it had unilaterally withheld, with interest. Macquarie Generation has made that payment to Peabody Resources and is paying Peabody Resources for deliveries of coal at the contract prices. Macquarie Generation has filed an appeal of the decision. We continue to believe that the matter will be resolved without a material adverse effect on our financial condition or results of operations.
Minerals Management Service
The Minerals Management Service issued a preliminary administrative decision in August 1992, determining that our subsidiary, Powder River Coal Company, had underpaid royalties owed to the federal government. If the preliminary decision is ultimately determined to be correct, the total alleged royalty deficiency amounts to approximately $7.5 million without interest. Since that time, no further action has been taken by the agency to issue a final, appealable decision. Pending such decision, we plan to appeal. Criminal and civil investigations were begun by the federal government in 1993 and 1996, respectively, to examine Powder River's activities with respect to the transactions at issue in the administrative matter. Powder River has fully cooperated with these investigations by providing documents and witnesses for interview. To date, no civil or criminal charges have been brought against us. If such claims are made and a case is successfully argued against us, our financial condition and results of operations may be adversely affected. However, based on our preliminary evaluation of the issues and the potential impact on us, and while the outcome of any potential litigation is subject to uncertainties, we believe that the matter will be resolved without a material adverse affect on our financial condition or results of operations.
Saline Valley Conservancy District
Saline Valley Conservancy District filed a lawsuit against our subsidiary, Peabody Coal Company, on April 5, 1999 in the Circuit Court of Saline County, Illinois. Saline Valley alleges that Peabody Coal Company's coal refuse pits at the closed Eagle No. 2 mine in Saline County, Illinois constitute a public and private nuisance and a trespass, and that Peabody Coal Company engaged in various negligent acts at the coal refuse pits. Saline Valley is seeking up to $124 million of compensatory damages, $125 million of punitive damages and injunctive relief. Peabody Coal Company has removed the case to the United States District Court for the Southern District of Illinois. At a settlement meeting held in April 1999, the parties agreed to tentatively settle the matter. The parties are now negotiating the definitive settlement agreement. We do not believe this settlement will have a material adverse effect on our financial condition or results of operations.
In addition, the state of Illinois has filed an administrative complaint against Peabody Coal Company alleging that our coal refuse pits have violated state water pollution control laws and regulations. The state is seeking daily fines from Peabody Coal Company for these alleged violations. We believe this matter will be resolved without a material adverse effect on our financial condition or results of operations.
ENVIRONMENTAL
Federal and State Superfund Statutes
The Comprehensive Environmental Response, Compensation and Liability Act 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, its predecessors and its former parent company are or may become parties to environmental proceedings which 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 seven sites and is a defendant in litigation with private parties involving one site. Gold Fields settled in February 1999 a lawsuit filed by Asarco Incorporated involving sites at Columbus, Ohio and Hillsboro, Illinois. Under the settlement, Gold Fields paid $3.25 million in fiscal 1999 and agreed to pay $3.25 million in fiscal 2000 for past costs at the Columbus, Ohio and Hillsboro, Illinois sites. The settlement also resolved the apportionment of liability for future costs at both sites.
These 10 sites were formerly owned or operated by Gold Fields. The Environmental Protection Agency has placed three of these sites on the National Priorities List, promulgated pursuant to that legislation, and one of the sites is on a similar state priority list. There are a number of further 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 such 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 three sites (on which no remediation is currently taking place) are no longer owned by Gold Fields. We have provisions of $61.8 million as of March 31, 1999 for the above environmental liabilities relating to Gold Fields. 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 that legislation, some products used by coal companies in operations, such as chemicals, and the disposal of such 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 that legislation 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 the fiscal year covered by this report.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
Not applicable.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA.
P&L Coal Holdings Corporation purchased its operating subsidiaries on May 19, 1998, and prior to such date had no substantial operations. The period ended March 31, 1999 is therefore a full fiscal year, but includes results of operations only from May 20, 1998 forward. The prior years' results of operations of the operating subsidiaries acquired are defined as the "Predecessor Company" and are included for comparative purposes. The results of operations include the consolidated results of Black Beauty Coal Company, effective January 1, 1999. Prior to that date, our investment in Black Beauty Coal Company was accounted for under the equity method.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
For purposes of comparisons to the prior year operating results in the discussion below, the results of operations and cash flows for the period ended March 31, 1999 reflect our results from April 1, 1998 to March 31, 1999 and the results of our Predecessor Company for April 1 to May 19, 1998. P&L Coal Holdings Corporation acquired the Predecessor Company on May 19, 1998 and prior to such date had no separate operations. In addition, the results of operations and cash flows for the period ended March 31, 1999 may not be directly comparable to prior periods 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 pursuant to Accounting Principles Board Opinion No. 16.
TOTAL FISCAL 1999 COMPARED WITH FISCAL YEAR ENDED MARCH 31, 1998
Sales. For fiscal 1999, sales increased 9.8 percent, or $201.2 million, over the prior twelve-month period. Excluding Black Beauty's results, sales increased $120.5 million, or 5.9 percent. We experienced an increase of $114.4 million in broker transactions, and had sales improvements in the following United States mining operating regions - Powder River ($19.1 million), Southern Appalachia ($20.4 million) and the Southwest region ($8.2 million).
The increase in brokered coal activity relates primarily to higher export volumes, an increased emphasis on broker transactions, newly added capacity for brokered shipments and the realization of a full year of sales from agreements entered into late in fiscal 1998.
With respect to the United States mining operations, Powder River experienced a 5.0 percent increase in sales volume from continued growth in demand for coal from this region, while Southern Appalachia sales volumes improved 13.0 percent, primarily due to longwall productivity increases as a result of capital improvements. Sales increases in the Southwest region are due mainly to improved pricing. Finally, the Midwest region declined $21.9 million due to the depletion and closing of a surface mine late in the prior fiscal year, lower shipments in the current year caused by customer unit outages for maintenance, and higher prior year sales due to a customer settlement.
Sales in Australia declined $28.3 million versus the prior year, due to weaker demand, lower pricing and the effects of foreign currency translation.
Other Revenues. Other revenues declined $59.0 million to $136.7 million for fiscal 1999, due mainly to $44.0 million in lower revenues from coal contract restructurings and $29.1 million in lower mining services revenues from Australia, partially offset by an increase of $12.5 million in revenues from Citizens Power, due to a higher volume of power contract restructurings and improved trading revenues. We cannot assure you we will be able to realize similar gains from future coal contract restructurings.
Operating Profit. For fiscal 1999, operating profit declined $83.1 million to $186.1 million. Operating profit from the United States mining operations improved by $59.9 million during the period, mainly as a result of improved results at the Powder River, Southern Appalachia and Southwest operating regions discussed above, and the inclusion of Black Beauty as a consolidated entity beginning with the fourth quarter of fiscal 1999. However, operating profit from Australia declined $9.2 million due to lower demand and prices for coal, lower mining services revenues and the effect of foreign currency translation.
Additionally, the prior year results included $44.0 million of actuarial gains associated with certain employee-related liabilities that are non- recurring, $44.0 million in higher gains from coal supply contract restructurings mentioned above and $21.5 million in higher gains on the sale of property, plant and equipment. Current year results of operations include: $8.5 million of additional depletion and amortization associated with purchase accounting adjustments to write-up our net assets to fair value; $3.9 million of compensation expense associated with the grant of 554,125 shares of Class B common stock to certain members of management in conjunction with the May 19, 1998 acquisition of Peabody; $3.7 million in additional profit as a result of the successful resolution of billing disputes with a customer in Australia; changes in United States employee benefits that resulted in accrual reductions of $10.2 million; a reduction in cost from a multiemployer benefit plan refund of $2.6 million; a reduction in reclamation accruals of $2.7 million due to improved equipment efficiencies; and $3.9 million in additional income due to the monetization of a royalty stream in October 1998.
Interest Expense. Interest expense increased $146.7 million for fiscal 1999. This increase is the result of the borrowings necessary to fund the acquisition on May 19, 1998, and higher borrowings in Australia to fund the construction of the Bengalla Mine.
Income Taxes. Our effective book income tax rate for fiscal 1999 was 51.6 percent. The effective tax rate is primarily impacted by two factors - the percentage depletion tax deduction utilized by us and our United States subsidiaries that creates an alternative minimum tax situation, and the level of contribution by the Australian business to the consolidated results of operations, which is taxed at a higher rate than in the United States. The effective tax rate for fiscal 1999 reflects tax expense in Australia not completely offset by tax benefits in the United States.
FISCAL YEAR ENDED MARCH 31, 1998 COMPARED WITH TWELVE MONTHS ENDED MARCH 31, 1997 (NOT PRESENTED HEREIN)
For the year ended March 31, 1998, we had revenues of $2.2 billion and operating profit of $269.2 million. The 1998 revenues were $2.1 million higher and operating profit increased $932.0 million compared to the same period in the prior year. The lower earnings in 1997 primarily resulted from a one-time non-cash charge of $890.8 million due to the adoption of the valuation methodology of Statement of Financial Accounting Standards ("SFAS") No. 121, which related to the impairment of certain inactive and undeveloped coal reserves. Most of the impairment write-down resulted from reduced values for specific properties with indications of unfavorable market conditions primarily relating to various properties containing coal reserves with a sulfur content that does not meet the air emissions limitations under the Clean Air Act Amendments. Excluding the impact of this charge, operating income would have been $228.0 million for the twelve months ended March 31, 1997.
Coal sales of 167.5 million tons for the fiscal year ended March 31, 1998 approximated volume for the year ended March 31, 1997. Low sulfur coal sales represented 81 percent of total sales volume for the fiscal year ended March 31, 1998 and sales under coal supply agreements of one year or more represented 92 percent of sales volume for the same period. Management estimates we had a United States market share of approximately 14.4 percent during the period. Our mines in Australia had coal sales of 7.3 million tons for both the fiscal year ended March 31, 1998 and the twelve months ended March 31, 1997.
Revenues of $2.2 billion for the fiscal year ended March 31, 1998 increased $2.1 million compared to the prior year, primarily as a result of restructuring the Tucson Electric Power contract at our Lee Ranch operation ($49.3 million additional revenue in that period) partially offset by lower export pricing and softer markets in Australia and the Powder River Basin. We also realized $11.6 million in gains from a coal supply agreement restructuring for the twelve months ended March 31, 1997. The Tucson Electric Power contract restructuring consisted of up- front payments in exchange for terminating the existing coal supply agreement and the subsequent agreement to a new long-term contract. We were able to realize a gain on the restructuring of this coal supply agreement since the termination fee required no future performance. The new contract, containing provisions at prevailing market terms, met the customer's desire for a reduced price of coal in the future. We determined that this payment was adequate compensation after considering the risk-adjusted discounted net present values, the impact of relaxed quality standards on mining costs and the benefits of a new agreement with a longer term.
Operating profit of $269.2 million for the fiscal year ended March 31, 1998 was $41.2 million more than the prior year, excluding the $890.8 million SFAS No. 121 charge. The improved earnings were primarily due to recognizing a $49.3 million gain on the Tucson Electric Power contract restructuring combined with $8.4 million of operating profit contributed by Citizens Power from power trading activities during the period and increased gains on property sales. Operating difficulties at the Eastern Associated mines, lower export pricing and lower prices in the Powder River Basin adversely impacted operating income. Our productivity in the United States remained strong, with an average of almost 92 tons per manshift for the period, while the Australian operations increased productivity by approximately 7 percent over the prior year. This had the effect of increasing gross profit margins, excluding Citizens Power, to 14.5 percent of revenues for the fiscal year ended March 31, 1998 as compared to 13.3 percent for the prior year. Selling and administrative expenses were 3.7 percent of revenues in 1998 compared to 3.6 percent in the prior year. The net gain on property and equipment disposals was $15.8 million favorable to the prior year
primarily due to a $14.7 million gain on a sale of property. Our Australian operations contributed $44.8 million of operating profit for the fiscal year ended March 31, 1998 and $47.4 million in the prior year.
Effective January 1998, we purchased an additional 10 percent interest in Black Beauty for $37.7 million in cash and as a result, increased our ownership in the partnership to 43.3 percent.
SIX MONTHS ENDED MARCH 31, 1997 COMPARED WITH SIX MONTHS ENDED MARCH 31, 1996 (NOT PRESENTED HEREIN)
For the six months ended March 31, 1997, we had revenues of $1.1 billion and operating profit of $102.1 million. Revenues and operating profit were slightly lower ($5.8 million and $3.9 million, respectively) compared to the six months ended March 31, 1996. The impact of the increased sales volume of 4.4 million tons during the six months ended March 31, 1997 was more than offset by unfavorable pricing variances and lower gains from surplus property sales as compared to the prior period.
Coal sales of 81.4 million tons for the six months ended March 31, 1997 increased 6 percent from 77.0 million tons for the six months ended March 31, 1996. The higher volume was primarily from the Powder River operations, as volumes increased over 10 percent due to improved customer demand and the installation of a crusher conveyor system. Our mines in Australia had coal sales of 3.5 million tons for the six months ended March 31, 1997, an increase of 19 percent from the previous period, resulting from favorable customer demand. Low sulfur coal sales represented 81 percent of total sales volume for the six months ended March 31, 1997 and sales under coal supply agreements represented 89 percent of total sales volume in that period.
Revenues of $1.1 billion for the six months ended March 31, 1997 decreased slightly from the six months ended March 31, 1996. The positive impact of a 6 percent growth in sales volume was more than offset by a decline in pricing during the period. The decline in pricing was primarily at Powder River as expiring and repriced contracts and a soft spot market reduced the average price per ton. We also realized gains from coal supply agreement restructurings of $11.6 million and $22.0 million for the six month period ended March 31, 1997 and 1996, respectively.
Operating profit of $102.1 million was $3.9 million lower than for the six months ended March 31, 1996. Our cost reduction measures and productivity (i.e., tons per manshift) enhancements continued to have a positive impact on operating profit which was more than offset by a decline in coal prices and lower gains from surplus property sales. The success of the cost reduction initiative improved productivity approximately 13 percent, with our United States operating companies averaging 93 tons per employee per manshift for the six month period which represented a Peabody record. Our Australian productivity also showed significant improvement increasing more than 17 percent from the equivalent period in the previous year. This had the impact of improving gross profit margins to 13.1 percent of revenues for the six months ended March 31, 1997, as compared to 12.8 percent of revenues for the six months ended March 31, 1996. Selling and administrative expenses remained substantially stable at 3.9 percent and 3.7 percent of revenues for 1997 and 1996, respectively. Our Australian operations contributed $22.3 million of operating profit in the six months ended March 31, 1997, up from $16.1 million for the comparable period in 1996.
FISCAL YEAR ENDED SEPTEMBER 30, 1996 COMPARED WITH FISCAL YEAR ENDED SEPTEMBER 30, 1995
For the fiscal year ended September 30, 1996, we had revenues of $2.2 billion and an operating loss of $651.3 million. The 1996 revenues increased $17.8 million from 1995 levels, while operating profit decreased $896.9 million from 1995. The lower earnings in 1996 were primarily due to a one-time, non-cash charge of $890.8 million as a result of adopting the valuation methodology of SFAS No. 121, principally related to the impairment of certain inactive and undeveloped coal reserves, primarily high sulfur coal reserves, affected by the Clean Air Act Amendments. Excluding the impact of this charge, operating income would have been $239.5 million for the fiscal year ended September 30, 1996.
Coal sales of 163.0 million tons in the fiscal year ended September 30, 1996 increased 8 percent from 151.0 million tons in the fiscal year ended September 30, 1995. The higher volume was primarily attributable to an 18.5 percent increase in our Powder River Basin production volume including a full year's contribution from the Caballo and
Rawhide mines acquired in November 1994. Our Australian operations sold 6.7 million tons of coal in the fiscal year ended September 30, 1996, compared to 7.3 million tons in 1995. Our overall production reflected the impact of our continued investment aimed at improving productivity, in particular at Powder River. Low sulfur coal sales represented 82 percent of total sales volume in the year ended September 30, 1996, up from 80 percent in 1995. Sales under long-term contracts represented 88 percent of sales volume in 1996 and management estimates Peabody's market share in the United States rose from 14 percent in the fiscal year ended September 30, 1995 to 15 percent in the fiscal year ended September 30, 1996.
Revenues were $2.2 billion in the fiscal year ended September 30, 1996, which were $17.8 million higher than revenues for the fiscal year ended September 30, 1995. The positive impact of higher sales volumes in 1996 was offset by lower pricing of three high sulfur coal contracts at Peabody Coal Company (estimated at $25 to $30 million) as price per ton was 10 percent lower than the prior year. Revenues were also adversely affected by reduced demand at our western operations, as customers purchased lower priced hydroelectric generation that was available due to unusually high rain and snowfall in the Western United States. Stabilizing spot prices in the higher sulfur markets in the last six months of the year also favorably impacted profits. We also realized gains from coal supply agreement restructurings totaling $22.0 million and $23.9 million for the fiscal years ended September 30, 1996 and 1995, respectively.
Excluding the one-time, non-cash charge of $890.8 million arising from the implementation of SFAS No. 121, operating income of $239.5 million for the fiscal year ended September 30, 1996 decreased $6.1 million from $245.6 million for the fiscal year ended September 30, 1995. The 1996 operating results were affected by lower customer demand at our western operations, the re-pricing of certain high sulfur coal contracts, which management estimates accounted for a decrease in profit of $25 to $30 million, and operational difficulties at Peabody Coal Company and Eastern Associated during the first nine months of the year. Offsetting the above impacts was a reduction in costs due to measures implemented during 1996 as part of continuing efforts to reduce production costs. These included employee reductions, improvements in working practices permitted under new union contracts and the effects of investment in more efficient equipment. The success of our cost reduction initiatives was evidenced by an improvement in productivity, as tons per manshift improved 17 percent in absolute terms over 1995 and 3 percent on a weighted average mine by mine basis taking into account the shift in sources of production. Operating profit in 1996 also included the benefit of $23.3 million related to the reversal of an excess accrual of our liability for the United Mine Workers of America Combined Fund established under the Coal Industry Retiree Health Benefit Act of 1992. This reversal resulted from our successful appeal of United States government beneficiary assignments and our active participation in the administrative process with respect to this fund. The effect of these items was to reduce gross profit margins to 13.8 percent in 1996 from 14.4 percent of revenues for 1995. Selling and administrative costs were $5.6 million lower than in 1995 as we continued to streamline and consolidate support functions. As a percentage of revenues, selling and administrative expenses were 3.5 percent in 1996 and 3.7 percent in 1995.
Our Australian operating profits of $48.5 million for the fiscal year ended September 30, 1996 increased from $37.9 million for the fiscal year ended September 30, 1995. The improved earnings were primarily related to increased volume of mining services projects during 1996.
LIQUIDITY AND CAPITAL RESOURCES
Net cash provided by operating activities was $240.1 million, which is comprised mainly of a $135.9 million royalty prepayment that occurred during the second quarter of fiscal 1999 and cash from current operations, partially offset by working capital changes.
Net cash used in investing activities was $2,257.1 million, primarily consisting of $2,076.9 million for the acquisition of our Predecessor Company and a controlling interest in Black Beauty and $195.8 million of capital expenditures. We expect to spend approximately $200 million for fiscal 2000 capital expenditures. We had $139.4 million of committed capital expenditures (primarily related to coal reserves and mining machinery) at March 31, 1999. It is anticipated these capital expenditures will be funded through available cash and credit facilities.
Net cash provided by financing activities was $2,184.8 million, reflecting a $480 million capital contribution and $1,817.4 million in borrowings to fund the acquisition of our Predecessor Company. In addition, we have borrowed approximately $160 million to fund domestic capital expenditures, the construction of a new mine in Australia and working capital requirements. We repaid $100 million of long-term debt during the period, including $75 million in prepayments and $5 million in scheduled payments on acquisition debt.
As of March 31, 1999, we had total indebtedness of $2,542.4 million, consisting of the following:
(In millions)
Term loans under senior credit facilities $ 840.0 8.875% Senior Notes due 2008 398.9 9.625% Senior Subordinated Notes due 2008 498.6 5.000% Subordinated Note 190.6 Non-Recourse Debt 333.9 Other 280.4 -------- $2,542.4 ========
The senior credit facilities include a revolving credit facility that provides for aggregate borrowings of up to $150 million and letters of credit of up to $330 million. As of March 31, 1999, we had no borrowings outstanding under the revolving credit facility. 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 our option. On October 1, 1998, we entered into two interest rate swaps to fix the interest cost on $500 million of long-term debt outstanding under the term loan facility. We will pay a fixed rate of approximately 7.0 percent on $300 million of such long-term debt for a period of three years, and on $200 million of such long-term debt for two years. The revolving credit facility commitment matures in fiscal 2005.
During fiscal 1999, we made optional prepayments of $75 million on the senior credit facilities, which we applied against mandatory Term Loan A and B payments in order of maturity, and mandatory payments of $5 million on Term Loan A. The following table sets forth the amortization schedule for the senior credit facilities after giving effect to the payments:
(In millions) Term Loan A Term Loan B ----------- ----------- Fiscal Year: 1999 $ - $ - 2000 - - 2001 10.00 - 2002 42.50 - 2003 68.75 - 2004 93.75 - 2005 25.00 64.00 2006 - 408.25 2007 - 127.75 ------- ------- $240.00 $600.00 ======= =======
The indentures governing the senior notes and senior subordinated notes permit us and our Restricted Subsidiaries (which include all of our subsidiaries except Citizens Power and its subsidiaries) to incur additional indebtedness, including secured indebtedness, subject to certain limitations. In addition, among other customary restrictive covenants, the indentures prohibit us and our 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 us or any of our Restricted Subsidiaries (subject to certain exceptions).
The revolving credit facility and related term loan facility also contain certain restrictions and limitations including but not limited to financial covenants that will require us 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 us from allowing our 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. We were in compliance with all of the restrictive covenants of our loan agreements as of March 31, 1999.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133 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. Based upon a recent decision by the Financial Accounting Standards Board, SFAS No. 133 is now effective for all fiscal quarters of fiscal years beginning after June 15, 2000 (effective April 1, 2001 for Peabody). We are evaluating the requirements of this Statement and have not yet determined the impact of adoption on the financial statements.
IMPACT OF YEAR 2000 ISSUE
We are preparing for the impact of the arrival of the Year 2000 on our business, as well as on the businesses of our customers, suppliers and business partners. The "Year 2000 Issue" is a term used to describe the problems created by computer systems that are unable to accurately interpret dates after December 31, 1999. These problems are derived predominantly from the fact that many software programs have historically categorized the "year" in a two-digit format. The Year 2000 Issue creates potential risks in the Information Technology ("IT") and non-IT systems that we use in our business operations. We may also be exposed to risks from third parties with which we interact that fail to adequately address their own Year 2000 issues.
Our State of Readiness - In 1998, we organized a company-wide Year - ---------------------- 2000 compliance project, staffed with a diverse team of personnel representing all levels of the organization. We also retained an outside consulting firm to assist in the Year 2000 risk assessment and to help ensure an effective project structure to address the Year 2000 Issue. In addition, we assessed our software and identified portions that will have to be modified or replaced so that our computer systems will function properly with respect to dates in the Year 2000 and thereafter. With respect to IT systems, an assessment was completed and we are now in the remediation, testing and implementation phases of the project whereby it is updating or replacing existing impacted applications. These phases of the project began in calendar 1998 and will continue in calendar 1999.
Additionally, we are also assessing our non-IT technology which consists primarily of embedded technology at our mining facilities (e.g., security systems, mine monitoring systems, plant operating systems, coal loading and scale facilities, equipment, etc.). We are in the assessment and remediation phases and plan to have all of our sites Year 2000 compliant by October 1999.
Software modifications are estimated to be 82 percent complete, a measurement primarily based upon overall labor hours. The goal of management is to have all systems and equipment Year 2000 ready by October 1999. We believe that with modifications to existing software and conversion to new software, the Year 2000 Issue will not present significant operational problems for our computer systems.
Finally, we are assessing our Year 2000 exposures related to our suppliers. We have identified our key suppliers and have sent a request for information on their Year 2000 compliance status. We have dedicated resources to monitor these parties' progress as they address the Year 2000 Issue. Additional requests will be sent, responses will be tracked and contingency plans will be developed as required to address potential failures of these parties to be prepared for the Year 2000.
The Costs to Address Our Year 2000 Issues - The total cost of the - ----------------------------------------- project associated with the Year 2000 Issue is estimated at approximately $9.1 million, which includes $3.0 million for the purchase of new software and hardware that will be capitalized and $6.1 million that will be expensed as incurred. To date, we have incurred approximately $2.8 million primarily for assessment of the Year 2000 Issue, development of a modification plan, and updating noncompliant programs. We believe that the total costs associated with modifying our current systems will not have a material adverse effect on our financial position, results of operations or liquidity.
The Risks of Our Year 2000 Issues - We cannot assure you that we will - --------------------------------- be completely successful in our efforts to address Year 2000 issues. If some of our systems are not Year 2000 compliant, we could suffer a disruption of operations (including delivery of coal pursuant to sales contracts) or other negative consequences, including, but not limited to, diversion of resources, damage to our reputation and increased litigation, any of which could materially adversely affect our financial position, results of operations or liquidity.
We are also dependent on third parties such as our customers, suppliers, service providers and other business partners. If these or other third parties with which we conduct business fail to adequately address Year 2000 issues, we could experience a negative impact on our financial position, results of operations or liquidity. For example, the failure of transportation providers, power generators and/or telecommunications companies to have Year 2000 compliant internal systems could impact our production and/or shipment of coal.
Contingency Plans - We are in the process of developing a - ----------------- comprehensive contingency plan to address situations that may result if we or any of the third parties upon which we are dependent is unable to achieve Year 2000 readiness. This effort is ongoing and will continue to be evaluated as new information becomes available.
Year 2000 Cautionary Statement - Year 2000 issues are widespread and - ------------------------------ complex. The costs of the project and the date on which we believe we will complete the appropriate modifications to deal with the Year 2000 Issue are based on management's best estimates, which were derived utilizing numerous assumptions of future events. However, we cannot assure you that these estimates will be achieved.
FORWARD LOOKING STATEMENTS
This document, the annual report and certain press releases and statements we make from time to time include statements of our and management's expectations, intentions, plans and beliefs that constitute "forward looking statements" within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act and are intended to come within the safe harbor protection provided by those sections. Forward looking statements involve risks and uncertainties, and a variety of factors could cause actual results to differ materially from our current expectations, including but not limited to: coal and power market conditions and fluctuations in the demand for coal as an energy source; weather conditions; the continued availability of long- term coal supply contracts; railroad performance; foreign currency translation; changes in the government regulation of the mining and power generation industries; risks inherent to mining; changes in our leverage position; the ability to successfully implement operating strategies; and the impact of Year 2000 compliance by us or those entities with which we do business.
RISK FACTORS
POSSIBILITY OF TERMINATION OF LONG-TERM COAL SUPPLY AGREEMENTS
A substantial portion of our sales are made pursuant to 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. Peabody has a large portfolio of coal supply agreements. In fiscal 1999, 87 percent of our sales volume was sold under coal supply agreements. At March 31, 1999, our coal supply agreements had terms ranging from one to 15 years and had an average volume-weighted remaining term of more than 4 years.
Many of our coal supply agreements contain price reopener provisions that provide for the contract price to be adjusted upward or downward at specified times. Failure of the parties to agree on a price pursuant to such reopener provisions may lead to early termination of the contracts. Over the last few years, several of our coal supply agreements have been renegotiated, bringing the contract prices closer to the then current market prices, thus leading to a reduction in the revenues from such contracts. A similar reduction in contract prices has also been experienced in relation to the replacement of expiring contracts. The coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during the duration of certain events beyond the control of the affected party. Most coal supply agreements contain provisions requiring us to deliver coal within certain ranges for specific coal characteristics such as Btus, sulfur, ash, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties or termination of the contracts.
We restructure coal supply agreements in the normal course of business. In connection with such restructurings, we recognized a gain of $5.3 million in fiscal 1999 and $49.3 million in fiscal 1998. We cannot assure you that we will be able to realize such gains in connection with future coal supply agreement restructurings.
The operating profit margins realized by Peabody under coal supply agreements depend on a variety of factors. In addition, price adjustment, price reopener and other provisions may reduce the insulation from any short-term coal price volatility provided by such 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. Because the price of coal has declined in recent years, many of our coal supply agreements are for prices above current spot market prices. We cannot assure you that we will be able to replace these contracts at the same prices or with similar profit margins when they expire. In addition, certain coal supply agreements are the subject of ongoing litigation and arbitration.
DEPENDENCE ON MAJOR CUSTOMERS
In fiscal 1999, we derived 31 percent of our total coal revenues from sales to our 5 largest customers, under 14 coal supply agreements that expire in various years from 1999 to 2014. We are currently engaged in discussions with several customers to either extend or enter into new long-term agreements upon expiration of existing agreements. We cannot assure you these customers either will extend or enter into new long- term agreements or, in the absence of long-term agreements, that they will continue to purchase the same amount of coal as they have in the past or on terms, including pricing terms, as favorable to us as under existing agreements. The concurrent loss of several coal supply agreements, reductions in the amounts of coal that all five of these customers purchase under those agreements, or the terms under which they buy could have a material adverse effect on our financial condition and results of operations.
TRANSPORTATION RISKS
Coal producers depend upon rail, barge, trucking, overland conveyor and other systems to provide access to markets. While 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 system accessing that region.
Transportation costs represent a significant portion of the total cost of coal, and as a result, the cost of delivery 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 certain of our operations less competitive than other sources of coal. Such increases could have a material adverse effect on our ability to compete and on our financial condition and results of operations.
In Australia, we transport coal using the Hunter River Valley Railroad and the coal loading terminal at the Port of Newcastle. The Port of Newcastle has had problems with ship congestion in the past. Such congestion could delay shipments from Peabody Resources' Warkworth and Bengalla mines.
RISKS INHERENT TO MINING
Our mining operations are subject to conditions beyond our control which can 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 geological and other conditions.
RESTRUCTURING OF AUSTRALIAN COAL INDUSTRY
The coal mining industry in Australia is going through a process of restructuring in an effort to improve the industry's international competitiveness. This restructuring is directed at improving workforce flexibility through training workers to perform multiple tasks and eliminating existing inflexibilities in work practices. Certain major coal mining companies, including Peabody Resources, have also attempted to employ non-union labor under individual contracts of employment. While to date these changes have been accomplished without major industrial disruption, we cannot assure you that this state of affairs will continue or that further restructuring will not cause major work stoppages in the future.
GOVERNMENT REGULATION OF THE MINING INDUSTRY
General. The coal mining industry is subject to regulation by federal, state and local authorities on 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, the industry is affected by significant legislation mandating certain benefits for current and retired coal miners. Numerous governmental permits and approvals are required for mining operations. We may be 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. All requirements imposed by any such authority 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 which may materially adversely affect our mining operations, our cost structure and/or our customers' ability to use coal. New legislation, including proposals related to the protection of the environment which would further regulate and tax the coal industry, may also require us or our customers to change their operations significantly or incur increased costs. Such factors and legislation, if enacted, could have a material adverse effect on our financial condition and results of operations.
Reclamation and Mine Closure Accruals. The Federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan and require that we obtain and periodically renew permits for mining operations. We accrue for the costs of final mine closure over the estimated useful mining life of the property and expense current mine disturbance as part of the ongoing mining process. The establishment of the final mine closure reclamation liability and the current disturbance is based upon permit requirements and requires various estimates and assumptions, principally associated with costs and production levels. Annually, we review our entire environmental liability under the Surface Mining Control and Reclamation Act of 1977 and makes necessary adjustments, including mine reclamation plan and permit changes and revisions to costs and production levels to optimize mining and reclamation efficiency. The economic impact of such adjustments is recorded to the cost of coal sales. Although we believe we are making adequate provisions for all expected reclamation and other costs associated with mine closures, future operating results would be adversely affected if such accruals were later determined to be insufficient.
Impact of Clean Air Act Amendments on Coal Consumption. The Clean Air Act and the Clean Air Act Amendments, and 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 emissions control requirements relating to particulate matter, such as fugitive dust, including future regulation of fine particulate matter measuring 2.5 micrometers in diameter or smaller. In July 1997, the United States Environmental Protection Agency adopted new, more stringent National Ambient Air Quality Standards for 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. Because coal mining operations emit particulate matter, our mining operations are likely to be affected directly 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 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-fueled utility power plants. 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 such facilities. Reductions in such emissions under Title IV of the Clean Air Act Amendments will occur in two phases: (1) Phase I began in 1995 and applies only to certain identified facilities; and (2) Phase II is scheduled to begin in 2000 and will apply to all coal-fired power plants, including those subject to the 1995 restrictions. The affected utilities have been and may be able to meet these requirements by, among other methods, switching to lower sulfur coal or other low sulfur fuels, installing pollution control devices such as scrubbers, reducing electricity generating levels or purchasing excess sulfur dioxide emission allowances from other facilities. The effect of these provisions of the Clean Air Act Amendments on us cannot be fully determined at this time. We believe that implementation of Phase II will likely exert a downward pressure on the price of higher sulfur coal, as additional coal-burning utility power plants become subject to the restrictions of Title IV. This price effect is expected to result after the large surplus of sulfur dioxide emission allowances which has accumulated in connection with Phase I has been reduced, and before utilities electing to comply with Phase II by installing sulfur-reduction technologies are able to implement such a compliance strategy. The extent to which this expected price decrease will materially adversely affect us will depend upon a number of factors, including our ability to secure coal supply agreements for our coal reserves with higher sulfur content.
The Clean Air Act Amendments also indirectly affect coal mining operations by requiring utilities that currently are major sources of nitrogen oxides in moderate or higher ozone nonattainment areas to install reasonably available control technology for nitrogen oxides, which are precursors of ozone. In addition, the recently issued, stricter ozone air quality standards, as discussed above, are expected to be implemented by the Environmental Protection Agency by 2003. On September 24, 1998, the Environmental Protection Agency announced the final rules governing nitrogen oxide emissions intended to reduce ozone concentrations in Northeastern cities. The new rules require additional nitrogen oxide reductions in 22 states, including reductions in nitrogen oxide emissions from coal-fueled power plants located in Midwestern and Southern states, sources purported to impact ozone in urban areas in the Northeast. Installation of reasonably available control technology and additional control measures required under the final rules will make it more costly to operate coal-fired plants and, depending on the requirements of individual state attainment plans and the development of revised new source performance standards, could make coal a less attractive fuel alternative in the planning and building of utility power plants in the future. On September 16, 1998, the Environmental Protection Agency issued a new rule governing nitrogen oxide emissions from new sources. The rule, which is likely to face legal challenge, would limit nitrogen oxide emissions from new, significantly modified or reconstructed boilers to amounts per megawatt-hour of gross electric output. The new rule would require expensive nitrogen oxide emission control technology for such coal-fired boilers, which could affect the competitiveness of coal as a fuel for electricity generation in the future. Any reduction in coal's share of the capacity for power generation could have a material adverse effect on our business, financial condition and results of operations. The effect such regulations or other requirements that may be imposed in the future could have on the coal industry in general and on us in particular cannot be predicted with certainty. We cannot assure you that the implementation of the Clean Air Act Amendments, the new air quality standards or any other future regulatory provisions will not materially adversely affect us.
Impact of the Framework Convention on Global Climate Change on the Coal Industry. The United States, Australia and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change which is intended to limit or capture emissions of greenhouse gases, such as carbon dioxide. In December 1997 in Kyoto, Japan, the signatories to the Convention established a binding set of emissions targets for developed nations. Although the specific limits vary from country to country, the United States would be required to reduce emissions to 93 percent 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, efforts to control greenhouse gas emissions could result in reduced use of coal if electric power generators switch to lower carbon sources of fuel. It is unclear what impact, if any, greenhouse gas restrictions may have on our operations. There is no guarantee, however, that such restrictions, if established through regulation or legislation, will not have a material adverse effect on our financial condition and results of operations.
Impact of Federal and State Superfund Statutes on Coal Mining Operations and Past Hard Rock Mining Operations. Risks of environmental liability are inherent with respect to both current and past coal mining and hard rock mining activities. The Comprehensive Environmental Response, Compensation and Liability Act, or Superfund, and similar state laws create liability for investigation and remediation in response to releases of substances hazardous to the environment and for damages to natural resources. Under the Comprehensive Environmental Response, Compensation and Liability Act and many state Superfund statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault.
We assumed environmental obligations associated with certain former non- coal mining operations of our subsidiary, Gold Fields, and our former parent company. Gold Fields, its predecessors and its former parent company are or may become parties to environmental proceedings which 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 Field's former parent company for any environmental claims resulting from any activities, operations or conditions that occurred prior to the sale of Gold Fields to Peabody. Gold Fields is currently involved in environmental investigation or remediation at seven sites and is a defendant in litigation with private parties involving one other site. These sites were formerly owned or operated by Gold Fields. The Environmental Protection Agency has placed three of these sites on the National Priorities List, promulgated pursuant to the Comprehensive Environmental Response, Compensation and Liability Act, and one of the sites is on a similar state priority list. There are a number of other sites in the United States which were previously owned or operated by such companies and which could give rise to environmental proceedings in which Gold Fields could incur liabilities.
Where such 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 three sites (on which no remediation is currently taking place) are no longer owned by Gold Fields. We have provisions of $61.8 million as of March 31, 1999 for the above environmental liabilities relating to Gold Fields. 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 the Comprehensive Environmental Response, Compensation and Liability Act, some products used by coal companies in operations, such as chemicals, and the disposal of such products are governed by the statute. Thus, coal mines currently or previously owned or operated by us, and sites to which we sent waste materials, may be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act and similar state laws. In addition to the Gold Fields liabilities associated with the Comprehensive Environmental Response, Compensation and Liability Act and similar state laws, our current and former coal mining operations presently incur, and will continue to incur, expenditures associated with the investigation and remediation of environmental matters, including acid mine drainage, land subsidence, underground storage tanks, solid and hazardous waste disposal and other matters.
While we believe that we have identified costs likely to be incurred for these environmental matters, and that those costs are not likely to have a material adverse effect upon our financial condition or results of operations, we cannot assure you that total costs and liabilities for these environmental matters will not increase in the future. The magnitude of such additional liabilities and the costs of complying with these environmental laws cannot be predicted with certainty due to the lack of specific information available with respect to many sites, the potential for new or changed laws and regulations and for the development of new remediation technologies and the uncertainty regarding the timing of work with respect to particular sites. As a result, we cannot assure you that material liabilities or costs related to environmental matters will not be incurred in the future or that our liquidity will not be adversely impacted by such environmental liabilities or costs.
Black Lung and Workers' Compensation Obligations. 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 is required to 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 percent of the miners currently seeking federal black lung benefits are awarded such 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 percent of the per ton sales price. This tax is passed on to the purchaser under many of our coal supply agreements.
Legislation on black lung reform has been introduced in this session of Congress. The legislation would restrict the evidence that can be offered by a mining company, establish a standard for evaluation of evidence that greatly favors black lung claimants, allow claimants who have been denied benefits at any time since 1981 to refile their claims for consideration under the new law, make surviving spouse benefits significantly easier to obtain and retroactively waive repayment of preliminarily awarded benefits that are later determined to have been improperly paid. If this or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase. We cannot assure you that such legislation or other proposed changes in black lung legislation will not have an adverse effect on us.
The United States Department of Labor has issued proposed amendments to the regulations implementing the federal black lung laws which, 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. If adopted, the amendments could have an adverse impact on us, the extent of which cannot be accurately predicted.
REPLACEMENT AND RECOVERABILITY OF RESERVES
Our future success depends upon our ability to find, develop or acquire additional coal reserves that are economically recoverable. Our recoverable reserves will generally decline as reserves are depleted, except to the extent that we conduct successful exploration and development activities or acquire properties containing recoverable reserves. To increase reserves and production, we must continue our development, exploration and acquisition activities or undertake other replacement activities. Our current strategy includes increasing our reserve base through acquisitions of government leases and other leases and producing properties and continuing to exploit our existing properties. The federal government continually leases coal reserves through a competitive bidding process. Companies such as Peabody may nominate specific areas to be leased by the government by application. Companies that have operations adjacent to these nominated lease areas have advantages in the bid process since their mining infrastructure is in place and they could avoid the cost of developing a new mine. Through this process, in June 1998, we acquired an additional 532 million tons of low sulfur coal reserves in a lease auction in the Powder River Basin adjacent to our Rochelle Mine. We cannot assure you that we will be able to continue successfully leasing additional reserves from the government. Additionally, we cannot assure you that our planned development and exploration projects and acquisition activities will result in significant additional reserves or that we will 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 certain of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, we cannot assure you that we can successfully negotiate new leases from the government or private parties or 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.
PRICE FLUCTUATIONS AND MARKETS
Our results of operations are highly dependent upon the prices received for our coal. Although in fiscal 1999, 87 percent of our sales were made pursuant to coal supply agreements, many of our coal supply agreements contain price reopener provisions which provide for the contract price to be adjusted upward or downward at specified times. Any significant decline in prices for coal could have a material adverse effect on our financial condition and results of operations, and quantities of reserves recoverable on an economic basis. Should the industry experience significant price declines from current levels or other adverse market conditions, we may not be able to generate sufficient cash flow from operations to meet our obligations and make planned capital expenditures.
The availability of a ready market for our coal production also depends on a number of factors, including the demand and supply of low sulfur coal and the availability of sulfur dioxide emission allowances.
COMPETITION
The coal industry is highly competitive, with numerous producers in all coal producing regions. We compete with other large producers and hundreds of small producers in the United States and abroad. Many of our customers are also customers of our competitors. The markets in which we sell our coal are highly competitive and affected by factors beyond our control. Continued demand for our coal and the prices that we will be able to obtain will depend primarily on coal consumption patterns of the domestic electric utility industry, which in turn are affected by the demand for electricity, coal transportation costs, environmental and other governmental regulations and orders, technological developments and the availability and price of competing alternative energy sources such as oil, natural gas, nuclear energy and hydroelectric energy. In addition, during the mid-1970s and early 1980s, a growing coal market and increased demand for coal attracted new investors to the coal industry and spurred the development of new mines and added production capacity throughout the industry. Although demand for coal has grown over the recent past, the industry has since been faced with overcapacity, which in turn has increased competition and lowered prevailing coal prices. Moreover, because of greater competition for electricity and increased pressure from customers and regulators to lower electricity prices, public utilities are lowering fuel costs and requiring competitive prices on their purchases of coal.
UNIONIZATION OF LABOR FORCE
Approximately 48 percent of Peabody's and our joint venture's United States coal employees, who accounted for 31 percent of Peabody's United States coal sales in fiscal 1999, are represented by the United Mine Workers of America. The Australian coal mining industry is highly unionized and the majority of workers employed at Peabody Resources are members of trade unions. Certain of our competitors have non-union work forces. Because of the increased risk of strikes and other work-related stoppages in addition to higher labor costs which 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 the Company's 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 long United Mine Workers of America strike in 1993 had a material adverse effect on us. Our subsidiaries, Peabody Coal Company and Eastern Associated Coal Corp., operate under a union contract which is in effect through December 31, 2002 and our Peabody Western Coal Company subsidiary operates under a union contract which is in effect through August 31, 2000. Peabody Resources' Warkworth Mine operates under a labor agreement that expires in September 1999. Peabody Resources,' Ravensworth and Narama mines entered into two-year labor agreements in May 1999. We cannot assure you that our unionized labor will not go on strike upon expiration of existing contracts.
SURETY BONDS
Federal and state laws require bonds to secure our obligations to reclaim lands disturbed for mining, to pay federal and state workers' compensation and to satisfy other miscellaneous obligations. As of March 31, 1999, we had outstanding surety bonds with third parties for post- mining reclamation totaling $534.9 million, with an additional $240.5 million in self-bonding obligations. Furthermore, surety bonds valued at an additional $80.5 million are in
place for federal and state workers' compensation obligations and other miscellaneous obligations. These bonds are typically renewable on a yearly basis. We cannot assure you that the surety bond holders will continue to renew the bonds or refrain from demanding additional collateral upon such renewals. Furthermore, as a result of the acquisition financings, we are highly leveraged, making it questionable whether we will be able to continue our self-bonding program and thus requiring us to obtain additional third-party surety bonds. The failure to maintain or the inability to acquire sufficient surety bonds, as required by state and federal law, would have a material adverse effect on us. Such failure could result from a variety of factors including the following: (1) lack of availability, higher expense or unreasonable terms of new surety bonds; (2) restrictions on the demand for collateral by current and future third-party surety bond holders due to the terms of the indentures or the senior credit facilities; and (3) the exercise by third-party surety bond holders of their right to refuse to renew the surety.
SUBSTANTIAL LEVERAGE
We are highly leveraged and, at March 31, 1999, had total indebtedness of $2,542.4 million, including $333.9 million of Citizens Power non- recourse debt, of which (1) $840.0 million consisted of indebtedness under the senior credit facilities, (2) $398.8 million consisted of the senior notes, (3) $498.6 million consisted of the senior subordinated notes and (4) the balance primarily consisted of the 5 percent subordinated note. In addition, we had available borrowings of up to $150.0 million under the revolving credit facility. Peabody and our Restricted Subsidiaries are permitted to incur additional indebtedness in the future.
Our ability to pay principal and interest on each series of the notes and to satisfy our other debt service obligations will depend upon the future operating performance of our subsidiaries, which will be affected by prevailing economic conditions in the markets they serve and other factors, certain of which are beyond their control. Based upon the current level of operations, management believes that cash flow from operations and available cash, together with available borrowings under the senior credit facilities, will be adequate to meet our future liquidity needs for at least the next several years. We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available under the senior credit facilities in an amount sufficient to enable us to service our indebtedness, including each series of the notes, or to fund our other liquidity needs. We may need to refinance all or a portion of the principal of each series of the notes on or prior to maturity. We cannot assure you that we will be able to effect any such refinancing on commercially reasonable terms or at all.
The degree to which we are leveraged could have important consequences to holders of each series of the notes, including, but not limited to: (1) making it more difficult for us to satisfy our obligations with respect to each series of the notes; (2) increasing our vulnerability to general adverse economic and industry conditions; (3) limiting our ability to obtain additional financing to fund future working capital, capital expenditures, research and development or other general corporate requirements; (4) 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 such cash flow to fund working capital, capital expenditures, research and development or other general corporate purposes; (5) limiting our flexibility in planning for, or reacting to, changes in our business and the industries in which we compete; and (6) placing us at a competitive disadvantage compared to less leveraged competitors. In addition, the indentures and the senior credit facilities contain financial and other restrictive covenants that limit our ability to, among other things, borrow additional funds. Failure by us to comply with such covenants could result in an event of default which, if not cured or waived, could have a material adverse effect on us. In addition, the degree to which we are leveraged could prevent us from repurchasing all of the notes tendered to us upon the occurrence of a change of control.
DEPENDENCE ON KEY PERSONNEL
Our business is managed by a number of key personnel, the loss of which 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 currently have not obtained key person life insurance to cover our executive officers. Failure by us to retain or attract such 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 electric power and energy-related commodities and provide services to the electric power industry through our subsidiary, Citizens Power. 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. Market risks are actively measured, monitored and controlled to ensure compliance with management policies. Polices are in place that limit the amount of total exposure we may enter into at any point in time. In addition, we have implemented procedures that allow us to measure, monitor and control all commitments and positions, with daily reporting to management.
These activities are accounted for using the fair value method, whereby financial instruments with third parties (such as forwards, futures, options and swaps) are reflected at market value in the consolidated financial statements.
NON-TRADING
Commodity price risk
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. Approximately 87 percent of our sales volume was sold under long-term coal supply agreements in fiscal 1999.
Certain products used in our mining activities are subject to price volatility. We use forward contracts to manage the volatility related to this exposure. Commodity price risk associated with these products used in our mining activities is not material to our consolidated financial position, results of operations or liquidity.
Interest rate risk
We have exposure to changes in interest rates due to our existing level of indebtedness. As of March 31, 1999, we had $2.2 billion of fixed-rate borrowings and approximately $397 million of variable-rate borrowings outstanding. To minimize our exposure to changes in interest rates, we entered into two interest rate swaps during fiscal 1999 with a total notional amount of $500 million for a 2-3 year term.
Foreign currency risk
Our Australian subsidiary, Peabody Resources, utilizes the Australian dollar as its functional currency. Peabody Resources exports coal to the Asian market under United States dollar-denominated supply agreements, creating exposure to fluctuations in exchange rates upon subsequent translation of such export sales to United States dollars in the consolidated financial statements. Peabody Resources utilizes a combination of forward currency and option contracts to hedge the impact of these exchange rate fluctuations.
Sensitivity analysis of market risks: - ------------------------------------
Foreign currency risk
The net amount of our derivative financial instruments and foreign currency transaction exposure of approximately $200 million, after considering $217 million of existing foreign exchange contracts, has been subjected to an assumed 10 percent appreciation and 10 percent depreciation in the value of the Australian dollar versus the United States dollar over a period not exceeding the average expected maturity of the related foreign exchange contract.
Assuming the United States dollar appreciates 10 percent against the Australian dollar, the resulting foreign exchange gain would be approximately $24 million. If the United States dollar were to decline 10 percent against the Australia dollar, the resulting foreign exchange loss would be approximately $24 million.
Interest rate risk
After taking into account the interest rate swap transactions discussed above, a one percentage point increase in interest rates would result in an annualized increase to interest expense of approximately $4 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one percentage point increase in interest rates would result in a $55 million decrease in the fair value of such borrowings.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Report of Independent Auditors
Board of Directors P&L Coal Holdings Corporation
We have audited the accompanying consolidated balance sheet of P&L Coal Holdings Corporation (the Company) as of March 31, 1999 and the related consolidated statements of operations, changes in stockholders' equity and cash flows of the Company for the period then ended. We have also audited the accompanying combined balance sheet of P&L Coal Group (the Predecessor Company) as of March 31, 1998, and the related combined statements of operations, changes in invested capital and cash flows of the Predecessor Company for the period ended May 19, 1998, the year ended March 31, 1998, the six months ended March 31, 1997 and the year ended September 30, 1996. 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 generally accepted auditing standards. 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 P&L Coal Holdings Corporation at March 31, 1999, the combined financial position of P&L Coal Group at March 31, 1998, the consolidated results of operations and cash flows of the Company for the period ended March 31 1999, and the combined results of operations and cash flows of the Predecessor Company for the period ended May 19, 1998, the year ended March 31, 1998, the six months ended March 31, 1997 and the year ended September 30, 1996 in conformity with generally accepted accounting principles.
As discussed in Note 1 to the financial statements, in 1996 the Predecessor Company changed its method of accounting for the impairment of long-lived assets and for long-lived assets to be disposed of.
Ernst & Young LLP
April 30, 1999 St. Louis, Missouri
P&L COAL HOLDINGS 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 results of operations and balance sheet of P&L Coal Holdings Corporation (the "Company"), also known as Peabody Group. These financial statements include the subsidiaries 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 (collectively, the "Predecessor Company"). The combined financial statements include the combined results of operations of the Predecessor Company from April 1, 1998 to May 19, 1998, the fiscal year ended March 31, 1998, the six months ended March 31, 1997 and the fiscal year ended September 30, 1996.
Until May 19, 1998, the Predecessor Company was a wholly owned indirect subsidiary of The Energy Group, PLC ("The Energy Group"). Effective May 20, 1998, the Predecessor Company was acquired by the Company, which at the time was wholly owned by Lehman Merchant Banking Partners II and its affiliates ("Lehman Merchant Banking"), an investment fund affiliated with Lehman Brothers Inc. The transaction was part of the sale of The Energy Group to Texas Utilities Company. P&L Coal Holdings Corporation, a holding company with no direct operations and nominal assets other than its investment in its subsidiaries, was formed by Lehman Merchant Banking on February 27, 1998 for the purpose of acquiring the Predecessor Company and had no significant activity until the acquisition.
Prior to March 7, 1997, the Company was a wholly owned indirect subsidiary of Hanson PLC (collectively referred to as "Hanson"). During 1996 and 1997, Hanson demerged its operations into four separate companies. As part of this tax-free distribution plan ("spin-off"), on February 24, 1997 Hanson demerged The Energy Group to hold the energy businesses of Hanson. In addition, on March 7, 1997, a subsidiary of Hanson sold the outstanding common stock of Peabody Holding Company to a subsidiary of The Energy Group and combined it with other Hanson energy companies to form The Energy Group.
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 electric power and energy-related commodity price risk management products.
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 results of operations.
JOINT VENTURES
Joint ventures are accounted for using the equity method except for undivided interests in Australia, which are reported using pro rata consolidation whereby the Company reports its proportionate share of assets, liabilities, income and expenses. All significant intercompany transactions have been eliminated in consolidation.
NOTES (continued)
The financial statements include the following asset and operating amounts for Australian entities utilizing pro rata consolidation:
ACCOUNTING FOR POWER TRADING
The Company engages in price risk management activities for both trading and non-trading purposes. Activities for trading purposes, generally consisting of services provided to the power sector through Citizens Power's operations, are accounted for using the fair value method. Under such method, the derivative commodity instruments (forwards, futures, options and swaps) with third parties are reflected at market value and are included in "Assets and liabilities from power trading activities" in the balance sheets. In the absence of quoted value, 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 the Company's management. Subsequent changes in market value are recognized as gains or losses in "Other revenues" in the period of change.
DERIVATIVE FINANCIAL INSTRUMENTS
The Company utilizes derivative financial instruments to hedge the impact of exchange rate fluctuations on anticipated future sales as well as to hedge the impact of interest rate movements on floating rate debt. The Company uses forward currency contracts to manage its exposure against foreign currency fluctuations on sales denominated in U.S. dollars. These financial instruments are accounted for using hedge accounting. Changes in the market value of these transactions are deferred until the gain or loss on the hedged item is recognized. If the future sale is no longer anticipated, the changes in market value of the forward currency contracts would be recognized as a gain or loss in the period of change.
SALES
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 in joint ventures, management fees, farm income, contract restructuring payments, trading activities and revenues from contract mining services. Royalty income generally results from the lease or sub-lease of mineral rights to third parties. These agreements generally provide for 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 5 to 20 years, or can be for an unspecified period until all reserves are depleted. Revenues from trading activities are recognized for the differences between contract and market prices. Revenues from price risk management activities are recognized by discounting the estimated net cash flows from the underlying long-term sales and purchase agreements after providing for appropriate reserves for credit, market risk and other future costs.
NOTES (continued)
CASH AND CASH EQUIVALENTS
Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with an original maturity 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 $3.0 million and $0.2 million for the periods ended March 31, 1999 and May 19, 1998, respectively, $1.5 million for the year ended March 31, 1998 and $0.1 million for the six months ended March 31, 1997. No interest was capitalized for the year ended September 30, 1996.
Expenditures which extend the useful lives of existing plant and equipment are capitalized. Maintenance and repairs are charged to operating costs and expenses as incurred. Costs incurred to develop coal mines or to expand the capacity of operating mines are capitalized. Development costs incurred to maintain current production capacity at a mine and exploration expenditures are charged to expense 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.
Depletion of coal lands is computed using the units-of-production method utilizing only proven and probable reserves in the depletion base. Mine development costs are principally amortized over the estimated lives of the mines using the straight-line method. Depreciation of plant and equipment (excluding life of mine assets) is computed using the straight-line method over the estimated useful lives as follows:
Years ----- Building and improvements 10 to 20 Machinery and equipment 2 to 30 Leasehold improvements Life of Lease
In addition, certain plant and equipment assets associated with mining are depreciated using the straight-line method over the estimated life of the mine, which varies from 3 to 49 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, 1999, the Company had $534.9 million in surety bonds outstanding related to reclamation. The amount of reclamation self-bonding in certain states in which the Company qualifies approximated $240.5 million at March 31, 1999.
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. Environmental costs are capitalized only to the extent the capitalization criteria of Emerging Issues Task Force 90-8 "Capitalization of Costs to Treat Environmental Contamination" are met (see note 17).
NOTES (continued)
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, federal or Australian law. The Company accounts for workers' compensation obligations and other Company provided postemployment benefits on the accrual basis of accounting.
CONCENTRATION OF CREDIT RISK AND MARKET RISK
The Company's power trading and price 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 price risk management policies of the Company. Policies are in place that limit the amount of total net exposure the Company may enter into at any point in time. Procedures exist which allow for monitoring of all commitments and positions with daily reporting to senior management.
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 its floating rate debt.
The Company's concentration of credit risk is substantially with electricity 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.
As a writer of options, the Company receives a premium at the outset 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.
Futures and exchange-traded options are typically liquidated by entering into offsetting contracts. Over-the-counter forwards, options and swaps are either liquidated with the same counterparty or held to settlement date. For the financial instruments, except for price risk management contracts, the unrealized gain or loss, rather than the contract amounts, represent the approximate future cash requirements.
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
During fiscal 1996, the Company elected early adoption of the provisions of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS No. 121 requires impairment losses to be recognized on long- lived assets used in operations when indicators of impairment are present and the undiscounted cash flows estimated to be generated under various assumptions by those assets are less than the assets' carrying amount. Impairment losses under SFAS No. 121 are measured by comparing the estimated fair value of the assets to their carrying amount.
NOTES (continued)
In fiscal 1996, a noncash charge of $890.8 million ($525.7 million after income taxes) was recorded as a result of adopting the evaluation methodology of SFAS No. 121, principally related to the impairment of certain inactive and undeveloped coal reserves.
Prior to the adoption of this pronouncement, asset impairment was evaluated at an operating company level based on the contribution of operating profits and undiscounted cash flows being generated from those operations. Under the Company's previous policy, assets used in operations were evaluated for impairment based on gross margins and cash flows generated by each separate operating company in a given business cycle.
SFAS No. 121 requires the impairment review to be performed at the lowest level of asset grouping for which there are identifiable cash flows, a change from the higher level at which the Company's previous accounting policy measured impairment. The Company's economic grouping of assets was based on the markets in which the operations compete and consisted of both active and inactive mines, as well as undeveloped properties. Evaluation of assets at the lower grouping level indicated an impairment of certain of those assets. A significant factor contributing to the estimated impairment was a decline in certain coal markets caused by weak demand and lower prices. Coal market conditions have also been adversely impacted by the effects of the Clean Air Act Amendments of 1990.
GOODWILL
Goodwill of $96.8 million and $78.4 million at March 31, 1999 and 1998, respectively, included in "Investments and other assets" represents the excess of the cost over the net tangible and identifiable intangible assets of the acquisition of Citizens Power (see note 2), and is stated at cost. The Company assesses the recoverability of goodwill based upon several factors, including management's intention with respect to the operations to which the goodwill relates and those operations' projected future income and undiscounted cash flows. Write-downs of goodwill are recognized when it is determined that the value of such asset has been impaired. Amortization expense was $4.6 million for the period ended March 31, 1999, $0.6 million for the period ended May 19, 1998 and $2.2 million for the year ended March 31, 1998.
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 the average rates during the period.
RECLASSIFICATIONS
Certain amounts in prior periods have been reclassified to conform with the report classifications of the period ended March 31, 1999, with no effect on previously reported net income, stockholders' equity or invested capital.
(2) BUSINESS COMBINATIONS
Black Beauty Coal Company
Effective January 1, 1999, the Company purchased an additional 38.3 percent interest in Black Beauty Coal Company ("Black Beauty"), raising its ownership percentage to 81.7 percent. 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. The Company has made a preliminary allocation of the cost of the acquisition to the assets acquired and liabilities assumed based upon estimated fair value. The preliminary fair values were determined based upon management's estimates.
The Predecessor Company purchased an additional 10.0 percent interest in Black Beauty for $37.7 million in cash, and as a result, increased its ownership in the partnership to 43.3 percent, effective January 1, 1998.
NOTES (continued)
P&L Coal Group
The acquisition of P&L Coal Group by the Company was funded through borrowings by the Company pursuant to a $920.0 million Senior Secured Term Facility, the offerings of $400.0 million aggregate principal amount of Senior Notes and $500.0 million aggregate principal amount of Senior Subordinated Notes, an equity contribution to the Company by Lehman Merchant Banking of $400.0 million, and an equity contribution of $80.0 million from other parties, including Lehman Brothers Holdings Inc. Such amounts were used to pay $2,003.6 million for the equity of the Company, repay debt, increase cash balances and pay transaction fees and expenses incurred with the acquisition. The Company also entered into a $480.0 million senior revolving credit facility to provide for the Company's working capital requirements following the acquisition.
The acquisition has been accounted for under the purchase method of accounting. Accordingly, the cost to acquire the Company has been allocated to the assets acquired and liabilities assumed according to their respective estimated fair values.
Below are the Company's historical balance sheet at May 19, 1998, the purchase accounting adjustments and the opening balance sheet. The historical balance sheet has been adjusted to include the effects of the financing transactions described above.
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 Texas Utilities Company.
Various assets and liabilities were adjusted to reflect their estimated fair value. The purchase accounting adjustments resulted in a net increase in total assets of $768.4 million. The majority of the excess purchase price is reflected as adjustments to the fair value assigned to various land and coal interests.
The purchase accounting adjustments include a $39.4 million liability for estimated costs associated with a restructuring plan resulting from the business combination. The estimate is comprised of costs associated with exiting certain activities ("exit plan") and consolidating and restructuring certain management and administrative functions ("restructuring plan") and includes costs resulting from a plan to involuntarily terminate or relocate employees. As of
NOTES (continued)
March 31, 1999, the Company has finalized its involuntary termination and employee relocation plan as well as its plans to exit certain business activities. Costs associated with the restructuring and exit plans are being charged against the liability as incurred. The net cash outlays and non-cash costs charged against the liability through March 31, 1999 are as follows:
The liability was reduced by $0.6 million from the original $40.0 million estimate in conjunction with the finalization of the purchase price allocation. This amount was recorded as an adjustment of the cost of the acquisition. The Company expects to utilize the majority of the $10.6 million remaining liability ($5.7 million related to the restructuring plan and $4.9 million related to the exit plan) during the first half of fiscal 2000. If the ultimate amount of cost expended is less than the amount recorded as a liability, the excess will further reduce the cost of the acquisition. Any amount of cost exceeding the amount recorded as a liability will be included as a charge to earnings in the period in which the adjustment is determined.
The following unaudited pro forma results of operations assumed the acquisitions had occurred as of April 1, 1998:
Total revenues $2,642,251 Operating profit 196,753 Loss before income taxes 3,858 Net loss (6,343)
Guarantor 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 debt associated with the purchase 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 investors. The following condensed historical financial statement information is provided for such Guarantor/Non-guarantor Subsidiaries.
NOTES (continued)
Unaudited Supplemental Condensed Statements of Consolidated Operations For the Period Ended March 31, 1999
Unaudited Supplemental Condensed Statements of Combined Operations For the Period Ended May 19, 1998
NOTES (continued)
Unaudited Supplemental Condensed Statements of Combined Operations For the Year Ended March 31, 1998
Unaudited Supplemental Condensed Statements of Combined Operations For the Six Months Ended March 31, 1997
NOTES (continued)
Unaudited Supplemental Condensed Statements of Combined Operations For the Year Ended September 30, 1996
NOTES (continued)
Unaudited Supplemental Condensed Consolidated Balance Sheets As of March 31, 1999
NOTES (continued)
Unaudited Supplemental Condensed Combined Balance Sheets As of March 31, 1998
NOTES (continued)
Unaudited Supplemental Condensed Statements of Consolidated Cash Flows Period Ended March 31, 1999
NOTES (continued)
Unaudited Supplemental Condensed Statements of Combined Cash Flows Period Ended May 19, 1998
Unaudited Supplemental Condensed Statements of Combined Cash Flows Year Ended March 31, 1998
NOTES (continued)
Unaudited Supplemental Condensed Statements of Combined Cash Flows Six Months Ended March 31, 1997
Unaudited Supplemental Condensed Statements of Combined Cash Flows Year Ended September 30, 1996
Citizens Power
In May 1997, the Company acquired all of the ownership interests in Citizens Lehman Power L.L.C. ("Citizens Power") and its subsidiaries for $120 million. Citizens Power, located in Boston, Massachusetts, markets and trades electric power and energy- related commodity price risk management products. Citizens Power also provides services and price risk management capabilities to the electric power industry (see note 1).
NOTES (continued)
The acquisition was accounted for as a purchase and accordingly, the operating results of Citizens Power have been included in the Company's combined financial statements since the date of acquisition. The excess of the aggregate purchase price over the fair market value of net assets acquired of approximately $80.6 million is being amortized on a straight-line basis over 20 years.
(3) 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 average cost to remove overburden above an unmined coal seam as part of the surface mining process.
(4) 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, sales of assets and other actions of the Company. Rental expense under operating leases was $35.5 million and $5.6 million for the periods ended March 31, 1999 and May 19, 1998, respectively, $40.6 million for the year ended March 31, 1998, $17.1 million for the six months ended March 31, 1997 and $36.5 million for the year ended September 30, 1996. The cost of property, plant, equipment and mine development assets acquired under capital leases was $34.8 million and $56.0 million at March 31, 1999 and 1998, respectively. The related accumulated amortization was $2.2 million and $27.1 million at March 31, 1999 and 1998, respectively. Amortization of capital leases is included in "Depreciation, depletion and amortization" in the Statements of Operations.
The Company also leases coal reserves under agreements that require royalties to be paid as the coal is mined. Total royalty expense was $123.2 million and $17.3 million for the periods ended March 31, 1999 and May 19, 1998, respectively, $132.9 million for the year ended March 31, 1998, $64.2 million for the six months ended March 31, 1997 and $136.2 million for the year ended September 30, 1996. Certain agreements also require minimum annual royalties to be paid regardless of the amount of coal mined during the year.
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 mined 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 10 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 had occurred. Annual production on these federal leases must total at least 1 percent of the original amount of coal in the entire logical mining unit. Royalties are payable monthly at a rate of 12.5 percent of the gross realization from the sale of the coal mined using surface mining methods and at the rate of 8.0 percent of the gross realization for coal produced using underground mining methods. The Company also leases the coal production at its Arizona mines from The Navajo Nation and the
Hopi Tribe under leases that are administered by the U.S. Department of the Interior. These leases expire once mining activities cease. The royalty rates are also generally based upon a percentage of the gross realization from the sale of coal. These rates are subject to redetermination every ten years under the terms of the leases. The remainder of the leased coal is generally leased from state governments, land holding companies and various individuals. The duration of these leases varies greatly. Typically, the lease terms are automatically extended as long as active mining continues. Royalty payments are generally based upon a specified rate per ton or a percentage of the gross realization from the sale of the coal. Many of these leases require the Company to pay minimum annual royalty payments.
Future minimum lease and royalty payments as of March 31, 1999 are as follows:
(5) ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses consisted of the following as of March 31:
NOTES (continued)
(6) INCOME TAXES
Pre-tax income (loss) consisted of:
Total income tax provision (benefit) consisted of:
NOTES (continued)
The income tax rate on income (loss) differed from the U.S. federal statutory rate as follows:
Beginning March 7, 1997, Peabody Investments, Inc. ("PII"), parent of Gold Fields, filed a consolidated U.S. federal income tax return with its subsidiaries. At March 31, 1997, U.S. federal and state income taxes were determined on that basis. Prior to March 7, 1997 there were two separate U.S. federal consolidated groups, Peabody Holding Company and PII.
For the year ended September 30, 1996, Peabody Holding Company was included in a consolidated federal income tax return with other Hanson affiliates. Peabody Holding Company had a tax sharing arrangement with Hanson whereby federal income taxes were computed as part of a consolidated group of companies. For purposes of these financial statements, Peabody Holding Company determined its federal tax provision (benefit) based on its expected allocated share of the consolidated group tax position. State taxes were determined on a separate return basis. Under the tax sharing arrangement, Hanson allocated the consolidated federal income tax liability to the members of the consolidated group by applying a ratio of each member's separate taxable income to the sum of the separate taxable incomes of all members having taxable income for the years. If the consolidated group had taxable income, a member having a taxable loss did not receive a benefit for that loss. If the consolidated group had a taxable loss, only members having a taxable loss received a benefit for that loss. PII was the common parent of a separate consolidated tax group. The group included its interest in the operations of HNRC, a partnership, which historically included the operations of Lee Ranch, Cavenham Timber and Western Rock Quarries. For purposes of these statements, PII determined its federal and state tax provision as if Lee Ranch was the only operation included for the year ended September 30, 1996.
NOTES (continued)
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:
Deferred taxes 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 $34.3 million at March 31, 1999. The AMT credits have no expiration date and the NOL carryforwards expire in the year 2019. The AMT credits and NOL carryforwards are offset by a valuation allowance of $68.9 million.
The Company made no U.S. federal tax payments for the periods ended March 31, 1999 and May 19, 1998, and $0.1 million for the year ended March 31, 1998. The Company paid state and local income taxes totaling $0.7 million for the period ended March 31, 1999, $0.8 million for the year ended March 31, 1998, $3.3 million for the six months ended March 31, 1997 and $2.7 million for the year ended September 30, 1996. No state or local income tax payments were made for the period ended May 19, 1998.
NOTES (continued)
Foreign tax payments were $11.9 million and $0.3 million for the periods ended March 31, 1999 and May 19, 1998, respectively, $18.3 million for the year ended March 31, 1998, $13.4 million for the six months ended March 31, 1997 and $27.5 million for the year ended September 30, 1996.
(7) SHORT-TERM BORROWINGS
Short-term borrowings consisted of the following as of March 31:
At March 31, 1999, Peabody Resources maintained four, 365-day corporate debt facilities with several banks totaling $110.0 million Australian dollars (approximately $70.0 million U.S. dollars). The interest rate is determined at the time of borrowing based on the Bank Bill Swap Rate plus a margin. At March 31, 1999, the effective annual interest rate was 5.9 percent.
The amount of interest paid was $1.4 million and $0.2 million for the periods ended March 31, 1999 and May 19, 1998, respectively, $1.8 million for the year ended March 31, 1998, $6.6 million for the six months ended March 31, 1997 and $12.8 million for the year ended September 30, 1996.
(8) LONG-TERM DEBT
Long-term debt consisted of the following as of March 31:
NOTES (continued)
The Senior Credit facilities, which are secured by a first priority lien on certain assets of the Company and its domestic subsidiaries, include a Revolving Credit Facility that provides for aggregate borrowings of up to $150.0 million and letters of credit of up to $330.0 million. During the period from May 20, 1998 to March 31, 1999, the Company had no borrowings outstanding under the Revolving Credit Facility. 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 9.0 percent at March 31, 1999. The Revolving Credit Facility commitment matures in fiscal 2005. During fiscal 1999, the Company made optional prepayments of $75.0 million on the Senior Credit Facilities, which it applied against mandatory Term Loan A and B payments in order of maturity, and mandatory payments of $5.0 million on Term Loan A. Scheduled payments resume in fiscal 2001 ($10.0 million); the majority of the remaining payments occur in fiscal 2006 (48.6 percent) and fiscal 2007 (15.2 percent).
The Senior Subordinated Notes are general unsecured obligations of the Company and are subordinate in right of payment to all existing and future senior debt (as defined), including borrowings under the Senior Credit Facilities and the Senior Notes. The Senior Notes are general unsecured obligations of the Company, rank senior in right of payment to all subordinated indebtedness (as defined) and rank equally in right of payment with all current and future unsecured indebtedness of the Company.
On October 1, 1998, the Company entered into two interest rate swap agreements to fix the interest cost on $500.0 million of long-term debt outstanding under the Term Loan Facility. The Company will pay a fixed rate of approximately 7.0 percent on $300.0 million of such long-term debt for a period of three years, and on $200.0 million of such long-term debt for two years.
The indentures governing the Senior Notes and Senior Subordinated Notes permit the Company and its Restricted Subsidiaries (which include all subsidiaries of the Company except Citizens Power and its 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.
Non-recourse debt is payable in installments through fiscal 2017. The weighted average interest rate is 7.6 percent.
The 5.0 percent 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 percent. Interest and principal are payable each March 1 and scheduled principal payments of $20.0 million per year are due from 2000 through 2006 with any unpaid amounts due March 1, 2007. The 5.0 percent Subordinated Note is expressly subordinated in right of payment to all prior indebtedness (as defined), including borrowings under the Senior Credit Facility and the Senior Notes.
The senior unsecured notes represent obligations of Black Beauty and include $47.1 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 percent, 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 percent and are due in fiscal 2008. The Series B Notes bear interest at an annual rate of 7.4 percent and are due in fiscal 2004. The Series C Notes bear interest at an annual rate of 7.4 percent and are due in fiscal 2003.
Peabody Resources entered into a project finance facility in 1998 to finance the construction of its 37.0 percent interest in the Bengalla mine. The facility, which is denominated in U.S. dollars, expires in 2010 and the maximum drawdown is $88.3 million. In accordance with the facility agreement, the loan will be repaid from the net proceeds derived from coal sales from the Bengalla Mine. There were borrowings against the facility of $48.8 million and $3.2 million for the periods ended March 31, 1999 and May 19, 1998, respectively, with an effective annual interest rate of approximately
NOTES (continued)
6.75 percent for both periods. In fiscal 1998, there were borrowings of $14.6 million against the facility with an effective annual interest rate of approximately 7.0 percent.
Capital lease obligations are payable in installments through 2009 with a weighted average effective interest rate of 4.4 percent. Other, principally notes payable, are due in installments through 2002 with a weighted average effective interest rate of 4.4 percent.
The aggregate amounts of long-term debt maturities subsequent to March 31, 1999 are as follows:
2000 $ 62,883 2001 62,093 2002 141,304 2003 144,411 2004 210,413 2005 and thereafter 1,911,754 ---------- $2,532,858 ==========
The amount of interest paid was $138.8 million and $0.5 million for the periods ended March 31, 1999 and May 19, 1998, respectively, $44.6 million for the year ended March 31, 1998, $18.0 million for the six months ended March 31, 1997 and $20.8 million for the year ended September 30, 1996.
(9) 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, 1999, the Company had $22.2 million in letters of credit and $80.5 million in surety bonds outstanding to secure workers' compensation obligations.
In Australia, workers' compensation funds are either separately administered industry funds or externally insured. Premiums are paid as a percentage of salary and labor costs. The administration of claims and the liability for payment of workers' compensation is the responsibility of the industry fund or the insurance company.
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 $11.1 million for the period ended March 31, 1999 and a benefit of $0.4 million for the period ended May 19, 1998, a benefit of $9.4 million for the year ended March 31,
NOTES (continued)
1998, a benefit of $3.8 million for the six months ended March 31, 1997 and a benefit of $10.3 million for the year ended September 30, 1996. The benefits recorded in prior years were primarily attributable to favorable loss experience factors and changes in certain actuarial assumptions.
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, 1999 were based on a 7.25 percent per annum interest discount rate and a 3.5 percent estimate for the annual rate of inflation, and the projections at March 31, 1998 were based on a 7.5 percent per annum interest discount rate and a 4.0 percent 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 approximately 7.25 and 7.5 percent per annum at March 31, 1999 and 1998, respectively.
(10) 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"). Peabody Resources participates in a number of superannuation funds and contributes on various percentages of employee compensation. Members of the funds may voluntarily contribute additional amounts to their accounts. Fund members are variously entitled to benefits on retirement, withdrawal, disability or death.
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:
During the period ended March 31, 1999, the Company made an amendment to phase out the Peabody Plan beginning January 1, 2000. This plan amendment resulted in a curtailment gain of $7.1 million. During fiscal years 1998 and 1996, early retirement and reduction in force programs were offered to certain employees as part of company-wide restructuring and cost reduction efforts. As a result of the special termination benefits offered, charges of $0.6 million and $15.3 million were recognized during fiscal years 1998 and 1996, respectively, in accordance with SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits."
NOTES (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, accumulated benefit obligation and fair value of plan assets for the pension plans with accumulated benefit obligations in excess of plan assets were $57.0 million, $56.9 million, and $43.1 million, respectively, as of March 31, 1999 and $50.6 million, $48.6 million, and $31.1 million, respectively, as of March 31, 1998.
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. At March 31, 1999 and 1998, the Company recorded adjustments of $3.0 million and $8.2 million, respectively, which were required to reflect the Company's minimum liability.
NOTES (continued)
The assumptions used to determine the above projected benefit obligation at the end of each fiscal period were as follows:
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 $1.1 million and $0.6 million for the periods ended March 31, 1999 and May 19, 1998, $4.9 million for the year ended March 31, 1998, $2.4 million for the six months ended March 31, 1997 and $5.0 million for the year ended September 30, 1996.
The Company sponsors savings and long-term investment plans for eligible salaried U.S. employees. The Company matches 50 percent of voluntary contributions up to a maximum matching contribution between 3 and 4 percent of a participant's salary. Effective January 1, 2001, the Company will increase the matching contribution to a maximum of 6 percent of a participant's salary. The expense for these plans was $4.1 million and $0.6 million for the periods ended March 31, 1999 and May 19, 1998, respectively, $4.2 million for the year ended March 31, 1998, $2.1 million for the six months ended March 31, 1997 and $4.7 million for the year ended September 30, 1996.
The amount contributed and expensed by Peabody Resources to superannuation funds was $0.9 million and $0.4 million for the periods ended March 31, 1999 and May 19, 1998, respectively, $2.9 million for the year ended March 31, 1998, $1.5 million for the six months ended March 31, 1997 and $2.8 million for the year ended September 30, 1996.
(11) 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.
Retirees of Peabody Resources are provided similar benefits by plans sponsored by the Australian government. As a result, no liability is recorded for this plan.
NOTES (continued)
Net periodic postretirement benefits costs for the period ended March 31 included the following components:
The following table sets forth the plans' combined funded status reconciled with the amounts shown in the balance sheets:
NOTES (continued)
The assumptions used to determine the accumulated postretirement benefit obligation as of March 31 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:
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 United Mine Workers of America Combined Fund. The "Obligation to industry fund" reflected in the balance sheets at March 31, 1999 and 1998 was $63.1 million and $97.0 million, respectively. The current portion related to this obligation reflected in "Accounts payable and accrued expenses" in the balance sheets at March 31, 1999 and 1998 was $9.2 million and $8.8 million, respectively.
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. A benefit of $15.9 million was recognized for the year ended March 31, 1998 which included amortization of an actuarial gain of $21.4 million, net of the interest discount accrual of $5.5 million. A benefit of $8.7 million was recognized for the six months ended March 31,1997 which included amortization of an actuarial gain of $11.7 million, net of the interest discount accrual of $3.0 million. A benefit of $15.4 million was recognized for the year ended September 30, 1996 which included amortization of an actuarial gain of $23.3 million, net of the interest discount accrual of $7.9 million.
NOTES (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 for the three months ended March 31, 1999 was $0.6 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 continue to recognize expense as contributions are made. The amounts expensed related to these funds were $0.7 million and $0.2 million for the periods ended March 31, 1999 and May 19, 1998, $4.5 million for the year ended March 31, 1998, $3.7 million for the six months ended March 31, 1997 and $1.5 million for the year ended September 30, 1996.
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, 1999 of $77.4 million and outstanding letters of credit at March 31, 1998 of $91.2 million. The surety bonds represent security for a portion of the postretirement liability included on the balance sheets.
(12) STOCKHOLDERS' EQUITY
PREFERRED STOCK
The Company has 10,000,000 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 into shares of Class A common stock upon resolution by the Board of Directors.
COMMON STOCK
The Company has 30,000,000 authorized shares of $0.01 par value Class A common stock, and 3,000,000 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.
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.
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 4,027,800 shares of the Company's common stock available for grant. The Board of Directors may provide such grants in the form of either non- qualified or incentive stock options.
During the period ended March 31, 1999, the Company granted 3,795,873 options to purchase Class A common stock, 931,885 of which are incentive stock options that vest at a rate of 20 percent per year for five years, and 2,863,988 of non-qualified stock options that vest in full or in part at a rate of 20 percent per year based upon the attainment of performance goals determined by the Board of Directors.
NOTES (continued)
A summary of the outstanding options as of March 31, 1999 is as follows:
The Company applies APB Opinion No. 25 and related Interpretations in accounting for the Plan. Accordingly, no compensation cost has been recognized for non-qualified or incentive stock options granted under the Plan. Had compensation cost been determined for the Company's non-qualified or incentive stock options based on the fair value at the grant dates consistent with the alternative method set forth under SFAS No. 123, "Accounting for Stock-Based Compensation," the Company's net income would have decreased by approximately $3.3 million for the period ended March 31, 1999.
(13) RELATED PARTY TRANSACTIONS
The "Receivables from affiliates, net" reflected in the balance sheet at March 31, 1998 represents amounts due to/from The Energy Group and other affiliates. No interest is earned by the Company on the balance with The Energy Group.
In fiscal 1998, the Company paid a $65.1 million dividend and provided a $141.0 million loan to a subsidiary of The Energy Group with a five year term at a 5.0 percent interest rate.
During the six months ended March 31, 1997, the Company received a capital contribution of $269.2 million from The Energy Group.
In August 1990, the Company borrowed $284.0 million from Hanson. The funds were used to prepay certain senior indebtedness. The note payable to Hanson carried interest at the rate of 10.0 percent per annum through September 1994 and 8.5 percent per annum through September 2000. This intercompany note was contributed by Hanson to capital during 1996. The amount of interest paid on the note was $18.1 million for the year ended September 30, 1996.
(14) CONTRACT RESTRUCTURINGS
The Company has periodically agreed to terminate coal supply agreements in return for payments by the customer. The amounts included in "Other revenues" were $5.3 million for the period ended March 31, 1999, $49.3 million for the year ended March 31, 1998, $11.6 million for the six months ended March 31, 1997 and $22.0 million for the year ended September 30, 1996. There were no gains related to coal supply agreement terminations for the period ended May 19, 1998.
(15) FINANCIAL INSTRUMENTS WITH OFF-BALANCE-SHEET RISK
The Company owns a 30 percent 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
NOTES (continued)
from a commercial bank. The Company's reimbursement obligation to the commercial bank is in turn supported by a letter of credit totaling $45.8 million.
Peabody Resources uses 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 are recognized in the same period as the hedged transactions. The Company had unrealized gains and (losses) recorded of $16.2 million and $33.6 million for the periods ended March 31, 1999 and May 19, 1998, respectively, ($17.3 million) for the year ended March 31, 1998, $11.7 million for the six months ended March 31, 1997 and $14.2 million for the year ended September 30, 1996, related to the forward currency contracts. The Company had forward currency contracts outstanding at March 31, 1999 and 1998 of $217.1 million and $244.0 million, respectively.
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.
(16) 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, receivables from affiliates, 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.
Notes payable fair value estimates are based on estimated borrowing rates to discount the cash flows to their present value. The 5.0 percent 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 notes payable.
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.
NOTES (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 power trading activities as of March 31, 1999, which include energy commodities, and average fair value of those instruments held are set forth below:
The approximate gross contract or notional amounts of financial instruments are as follows:
The net gain arising from trading and price risk management activities was $36.9 million and $1.7 million for the periods ended March 31, 1999 and May 19, 1998, respectively, and $26.4 million for the year ended March 31, 1998. The change in unrealized gain from power trading activities for the period ended March 31, 1999 was $10.1 million.
(17) 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.
NOTES (continued)
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 in the balance sheets at March 31, 1999 and 1998 were $61.8 million and $68.6 million, respectively. This amount represents those costs that the Company believes are probable and reasonably estimable.
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, 1999, purchase commitments for capital expenditures were approximately $139.4 million.
NOTES (continued)
(18) SEGMENT INFORMATION
The Company operates primarily in the coal industry. "Other" data represents an aggregation of the remainder of the Company's business including Citizens Power and the Company's other non- mining entities. The Company's industry and geographic data for continuing operations are as follows:
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, 1999 and current positions with us and our subsidiaries of our executive officers and Directors. The terms of our Directors will expire upon the election and qualification of successors at the annual meeting of stockholders.
Irl F. Engelhardt served as President and Chief Executive Officer of Peabody from 1990 to 1995 and Chairman and Chief Executive Officer of Peabody since 1993, and has been a Director of Peabody since June 1998. Since joining Peabody 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 an 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 past chairman of the National Mining Association, Chairman of the Coal Industry Advisory Board of the International Energy Agency, Chairman of the Center for Energy and Economic Development and a director of Mercantile Bank of St. Louis, N.A.
Richard M. Whiting was promoted to President and Chief Operating Officer of Peabody in January 1998 and has been a Director of Peabody and a member of the Management Committee since June 1998. He served as President of Peabody COALSALES Company from June 1992 to January 1998. Since joining Peabody 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 and Chairman of the National Mining Association's Safety and Health Committee.
W. Howard Carson was named Chief Commercial Officer and a member of Peabody's Management Committee in June 1998. Prior to that, he had been President of Peabody Western since 1993. Previously, he has served as Vice President of Finance and Administration for PCC from 1991 to 1993. He joined Peabody in 1979 from Arthur Andersen and has held numerous financial positions including Vice President of Accounting and Vice President of Corporate Planning for Peabody. Mr. Carson holds an MBA from Saint Louis University.
Roger B. Walcott, Jr. joined Peabody in June 1998 as Executive Vice President and a member of Peabody's Management Committee. From 1981 to 1998, he was a Senior Vice President & 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.
Mark Maisto was named Chief Executive Officer of Citizens Power in September 1998. He was also named a member of Peabody's Management Committee at that time. He has been President of Citizens Power since February 1998. He joined Peabody in 1997 as Executive Vice President of Citizens Power. Prior to joining Citizens Power he was a Senior Vice President at Lehman Brothers. At Lehman Brothers, he specialized in corporate and project finance working with electric utility companies. Prior to joining Lehman Brothers in 1987, Mr. Maisto was employed at GE Capital, where he was Director-Utility Finance. Mr. Maisto holds an MBA from New York University.
Christopher G. Farrand has been Vice President of Corporate Affairs of Peabody since June 1992. From April 1991 to June 1992, he served as President of Peabody Development Company. Between 1981 and 1992 he worked as Vice President of Government Relations for both Peabody Coal Company and Peabody Holding Company. Mr. Farrand joined Peabody as Director of Corporate Planning for Peabody Coal Company in 1978. Prior to working for Peabody, Mr. Farrand held several positions in the United States Department of Interior, including Deputy Under Secretary in 1977 and 1978 and Deputy Assistant Secretary from 1974 to 1976. He currently serves on the board of directors of the National Coal Association.
Larry H. Fox was named Vice President-Powder River Basin Operations in June 1998. Prior to that, he was President of Powder River Coal Company since 1989. Mr. Fox previously served as Vice President of Powder River Coal Company and General Manager of North Antelope Coal Company. Prior to that he also held several mine operations positions within Peabody, including Mine Superintendent at the Big Sky mine in Montana and Director of Operations for the Rocky Mountain Division. He joined Peabody in 1962. Mr. Fox currently serves as President of the Wyoming Mining Association and is a member of the Wyoming Coal Operators Committee.
George J. Holway was appointed to his current position as Vice President and Chief Financial Officer in June 1998. Prior to that, he had been Vice President of Corporate Development with responsibilities for our mining business development and land functions. After first joining Peabody in 1980, Mr. Holway served in several financial positions at Peabody Holding Company including Vice President and Controller from 1990 to 1992. In 1992, he left Peabody to become Chief Financial Officer of Zeigler Coal Holding Company, a position he held until he rejoined Peabody in November 1996. Prior to joining the Peabody in 1980, Mr. Holway was employed by Arthur Andersen & Co. Mr. Holway is a CPA and holds an MBA from Saint Louis University.
Robert D. Humphris has been Managing Director-Australia and a member of Peabody's Management Committee since May 1998. Prior to that, he had been Managing Director of Peabody Resources since April 1993. He has held management positions at various mining companies in the United Kingdom and Australia, including Managing Director of mining operations for Costain Australia Limited, which was subsequently acquired by Hanson. He was actively involved in Costain's real estate and construction activities in Australia. Mr. Humphris is Chairman of the New South Wales Minerals Council and past Chairman of the Australian Coal Association and the Newcastle Coal Shippers. He is a member of the Coal Industry Advisory Board of the International Energy Agency and the State Minerals Advisory Council.
Jeffery L. Klinger was named Vice President of Legal Services and Secretary in May 1998. Prior to that, he had been 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 and member of the Executive Committee of the Eastern Mineral Law Foundation.
Richard A. Navarre was named Vice President of Sales & Marketing in May 1998, and has also been President of Peabody COALSALES Company since January of 1998. He previously served as President of Peabody Energy Solutions, Inc. from 1996 to 1997, he was Vice President of Finance and prior to that served as Vice President and Controller of Peabody. He joined Peabody in 1993 as Director of Financial Planning. Prior to joining Peabody, Mr. Navarre was 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.
Sharon K. Schergen has been Vice President-Human Resources 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. Schergen, who earned degrees in social work and psychology and an MBA, was a personnel representative for Ford Motor Company. Ms. Schergen is a member of the National Mining Association's Human Resource Committee.
Roger H. Goodspeed became a Director 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 Chairman of Citizens Lehman Power, an electric power marketing joint venture 50 percent owned by Lehman Brothers until the joint venture was sold to The Energy Group in 1997. Mr. Goodspeed remains a director of the ongoing entity, Citizens Power. Mr. Goodspeed received an MBA from the University of California, Los Angeles.
Henry E. Lentz became a Director 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 Imperial Sugar Company. Mr. Lentz holds an MBA, with honors, from the Wharton School of the University of Pennsylvania.
Alan H. Washkowitz became a Director 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 Portfolio Partnership L.P. Mr. Washkowitz joined Kuhn Loeb & Co. in 1968 and became a general partner of Lehman Brothers in 1978 when Kuhn Loeb & Co. was acquired. Prior to joining the Merchant Banking Group, Mr. Washkowitz headed Lehman Brothers' Financial Restructuring Group. He is currently a director of Illinois Central Corporation, 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.
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 Peabody during fiscal 1999 and 1998.
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 percent 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 percent of the 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 percent 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 percent; (2) employees between the ages of 45 and 49 or with 20 years or more of service will accrue service at the rate of 50 percent 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 benefit frozen. In all cases, final average earnings for retirement plan purposes will be capped at December 31, 2000 levels.
We have three supplemental retirement plans, which provide pension benefits to executives whose pay exceeds legislative limits for qualified pension plans.
The estimated annual benefits payable upon retirement at age 62, the normal retirement age, for the CEO and named executive officers are as follows:
Irl F. Engelhardt $411,686 Richard M. Whiting 203,861 W. Howard Carson 172,113 Roger B. Walcott, Jr. 12,911
Mr. Maisto is not eligible for the pension plan.
Other Benefit Plans
In addition to the pension plan, we maintain various other benefit plans covering employees and retirees. We announced in February 1999 that we were restructuring several of these plans over the next four years. The benefits associated with the medical plan and savings and long term investment plan will be most significantly impacted.
The changes to the medical plan include the following as of January 1, 2000: (1) a decrease in employee/retiree contributions; (2) an increase in medical contributions for dependents; (3) a decrease in medical coverage for certain expenses; (4) additional medical plan options; and (5) changes to dependent eligibility rules for retirees. In addition, the medical plan was restructured so that employees leaving Peabody on or after January 1, 2003 (age 55 or older with ten years of service) will be covered under a medical premium reimbursement plan instead of the current medical plan.
Effective January 1, 2001, we will increase the company match for the savings and long-term investment plan, and beginning with fiscal 2000, we will also add a new performance contribution feature.
Management Incentive Compensation Plans
We have established an incentive compensation plan that provides a bonus to selected employees based on the participant's base salary, target level, and the attainment of certain organizational and individual targets. The organizational targets are a ratio of net debt (long-term debt minus cash) divided by earnings before interest, income taxes and depreciation, depletion and amortization expense, or EBITDA.
Employment Agreements
We have entered into employment agreements with Mr. Engelhardt, the Chairman and Chief Executive Officer, or CEO, and Messrs. Whiting, Carson, Walcott, Maisto and eight other key executive officers. The CEO's employment agreement provides for an initial term of three years and the other executives' employment agreements provide for initial terms of two years, each of which extend thereafter on a day-to-day basis such that the CEO's employment agreement continually has a three year term and the other executives, subsequent to their initial one year of employment, continually have a one-year term. Upon a termination without cause or resignation for good reason, the executive is entitled to the following benefits during the continuation period, described below: (1) base salary; (2) bonus actually paid in the year prior to such termination, except that, instead of such actual bonus amount, the CEO shall receive an amount equal to 100 percent of his final base salary in each of the three years following such termination; (3) a one-time prorated bonus for the year of termination (based on actual performance multiplied by a fraction, the numerator of which is the number of business days such executive was employed during the year of termination and the denominator of which is the total number of business days during such year); and (4) continuation of qualified and nonqualified pension, life insurance, medical, hospitalization and other benefits; provided, however, that we shall not be obligated to provide any benefits under tax qualified plans which are not permitted by the terms of each such plan or by applicable law or could jeopardize the plan's tax status; provided, further, that any such coverage shall terminate to the extent that executive is offered or obtains comparable coverage from any other employer. The "continuation period" is three years for the CEO and for the other executives, the balance of the initial two-year term if termination occurs during the first year of the initial term, or for a period of one year after. The employment agreements provide for confidentiality during employment and at all times thereafter, and include a noncompetition and nonsolicitation agreement that is effective during the employment term and for one year thereafter.
Equity Agreements
The executives and 20 other employees acquired, in the aggregate, approximately 3 percent of our initial fully-diluted equity, issued as Class B common stock in connection with our acquisition on May 19, 1998. With respect to these Class B shares, we provided a full recourse loan for the amount of the tax liability to each executive, and to certain of these executives, an additional full recourse loan for the amount of the value of the stock, with a five-year principal balloon payment which accelerates to the date which is 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.
Stock Option Plan
We adopted the 1998 Stock Purchase and Option Plan for Key Employees, under which we granted options to certain employees to purchase shares of our common stock. We granted the executives who received Class B common stock and other employees our options exercisable for common stock to purchase an aggregate of 7 percent of our initial fully- diluted equity; 50 percent of the options were granted as "time options" in the form of Incentive Stock Options (as defined in Section 422 of the Internal Revenue Code), to the extent permitted, and 50 percent of the options were granted in the form of nonqualified stock options as "performance options." Time options become exercisable with respect to 20 percent of the shares subject to such options on each of the first five anniversaries of the date of the closing of the transaction if the executive's employment continues through and including such date, subject to acceleration upon (1) death, (2) disability (3) a change of control or (4) a recapitalization event. Performance options become exercisable at the end of nine and one-half years, whether or not the applicable performance targets are achieved, but become exercisable earlier with respect to up to 20 percent of the shares subject to the performance options, on each of the first five anniversaries of the date of May 19, 1998, to the extent certain performance targets, as determined by the Board of Directors and based on net debt and EBITDA, are met or exceeded. Performance options accelerate upon (1) a change of control, (2) a recapitalization event or (3) an initial public offering. "Change of control," for the purposes of this section, 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, whereby immediately following any such transaction (1) Lehman Merchant Banking owns less than 8.1 million of our outstanding voting securities or (2) any person individually owns more of our then outstanding voting securities entitled to vote generally than Lehman Merchant Banking. "Recapitalization event" 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 which does not result in a change of control.
We granted these executives performance-based options exercisable for common stock to purchase an aggregate of 7 percent of our initial fully-diluted equity. Options vest upon the earlier of (1) achievement of certain financial performance targets and the earliest of completion of (x) an initial public offering, (y) a change of control or (z) a recapitalization event; and (2) nine and one-half years from the date of grant. Vesting of options accelerate: (1) upon completion of an initial public offering during our first 36 months following the closing of our acquisition, at least 2.5 percent of these options shall vest and the balance shall vest in accordance with the achievement of certain financial performance targets; or (2) upon a change of control or a recapitalization event during the first 36 months following the closing of our acquisition, at least 5 percent of these options shall vest.
The options have an exercise price of $20.00 per share of the Class A common stock.
The options have a 10-year term; provided, however, that exercisable non-performance based options expire earlier upon termination of employment as follows: (1) upon termination for cause or a resignation without good reason, immediately upon such termination; or (2) upon termination without cause, resignation for good reason, death, disability or retirement, one year after termination of employment. Unexercisable options terminate upon termination of employment, unless acceleration in connection with such termination is explicitly provided for.
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.
Stock options granted to the CEO and the named executive officers during 1999, and the number of exercisable and unexercisable stock options as of March 31, 1999 are as follows:
Stockholders Agreements
We have entered into stockholders agreements with the executives who received our Class B common stock and will enter into shareholder agreements with employees who have options to purchase shares of common stock when such options have vested and are exercised. Such stockholders agreements contain, among other things, puts/calls, drag- along, tag-along, voting, corporate governance and registration rights provisions.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The following table sets forth certain information concerning ownership of the capital stock as of March 31, 1999: (1) persons who beneficially own more than 5 percent of the outstanding shares of capital stock; (2) each person who is a director of Peabody; (3) each person who is a Named Executive Officer; and (4) all directors and executive officers as a group. Our capital stock consists of our Class A common stock, our Class B common stock and our Non-Convertible, Exchangeable Preferred Stock. Class B common stock has voting rights and other attributes similar to Class A common stock (except that Class A common stock will have a liquidation preference) and will convert to Class A common stock upon consummation of a change of control, an initial public offering or a recapitalization event or, in any event, after nine years. Of the $480 million equity contribution made in connection with our acquisition on May 19, 1998, $100 million was in the form of preferred stock. The preferred stock bears the same voting powers, dividend rights and other rights as, and votes as a single class with, the common stock, except for the following: (1) upon the occurrence of any merger, consolidation, sale of all or substantially all assets, liquidation, dissolution or winding up of Peabody, the holders of the preferred stock will receive a preferential distribution of available assets equal to the cost per share before the holders of the common stock receive any distributions (following which the holders of common stock will receive a similar preferential distribution of any remaining available assets equal to the same cost per share, and thereafter the shares of Common Stock and Preferred Stock will receive equal distributions per share of any remaining available assets); (2) we may, at any time at our discretion, exchange all or part of the shares of preferred stock for an equal number of shares of common stock; and (3) we may, at our discretion and only for the first six months after the issuance of shares of the preferred stock, redeem all or part of the shares of preferred stock for an amount equal to the cost per share.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Affiliates of Lehman Brothers Holdings Inc.
Lehman Brothers Merchant Banking Partners II L.P. and other affiliates of Lehman Brothers Holdings Inc. (collectively, the "Lehman Merchant Banking Fund") own a substantial majority of our outstanding shares of capital stock. Messrs. Washkowitz, Lentz and Goodspeed, each directors of Peabody, are investors in the Lehman Merchant Banking Fund and employees of an affiliate of LBHI.
During fiscal year ended March 31, 1999, affiliates of Lehman Brothers Holdings Inc. received approximately $90 million in cash for advising on the acquisition of certain of our subsidiaries from The Energy Group plc, including Citizens Power LLC, on May 19, 1998 and arranging the financing for the acquisition. In addition, during the fiscal year ended March 31, 1999, we have paid affiliates of Lehman Brothers Holdings Inc. $0.1 million for other management, consulting and financial services, as well as reimbursements for expenses. Affiliates of Lehman Brothers Holdings Inc. also received customary fees from Texas Utilities Company in connection with advising on and arranging financing for the purchase of The Energy Group plc by Texas Utilities Company.
On May 19, 1997, The Energy Group plc purchased Citizens Power through Peabody from Lehman Brothers Holdings Inc. (which owned 50 percent of Citizens Power), certain employees of Citizens Power (who owned 20 percent of Citizens Power) and certain other parties (collectively, the "Selling Shareholders") for $120 million, which included (1) an up- front cash payment of $20 million and (2) up to $100 million of future cash payments (the "Citizens Power Obligation"). The Citizens Power Obligation was comprised of (1) a payment based upon the net asset value of Citizens Power as of the date of the sale to The Energy Group plc (subject to certain adjustments based upon events occurring between the date of sale and June 30, 1997) up to a maximum of $30 million and (2) net asset value increase payments for the fiscal years ending on March 31 or 2000, 2001 and 2002, which combined with the amount of the initial net asset value payment would be no greater than $100 million. The agreement for the purchase of Citizens Power included a provision that protected the Selling Shareholders in the event of material changes that would adversely affect the ability of Citizens Power to attain expected net asset value increases, including a change of control. Due to the change of control of Citizens Power in our acquisition, we agreed to pay the Selling Shareholders $72.96 million on May 19, 1998 and $20.0 million plus interest on April 3, 2000 in full consideration for the Citizens Power Obligation. Lehman Brothers Holdings Inc. has guaranteed payment of this obligation. Mr. Goodspeed, who is a director of Peabody and an employee of an affiliate of Lehman Brothers Holdings Inc. and Mr. Maisto, a named executive officer and an employee of Citizens Power, received a portion of the proceeds received by Lehman Brothers Holdings Inc.
In connection with our acquisition, Lehman Brothers Holdings Inc. agreed to provide a guarantee facility to trading counterparties of Citizens Power Sales, the trading subsidiary of Citizens Power LLC, for trades initiated after the acquisition. The guaranty facility initially was to be available for 364 days after the date of the acquisition. For establishing the guaranty facility, Lehman Brothers Holdings Inc. was paid a minimum fee of $0.5 million and reimbursed for the associated legal and out-of-pocket costs. The guaranty facility was allowed to terminate according to its terms in November 1998 with respect to all subsequent transactions of Citizens Power Sales.
OTHER TRANSACTIONS WITH AFFILIATES
Peabody COALSALES, a subsidiary of ours, purchased 0.3 million tons of coal from Black Beauty for $5.5 million during the fiscal year ended March 31, 1999 and may continue to purchase coal from Black Beauty in the ordinary course of business. The terms of these transactions are comparable to those negotiated with independent third parties. Executive officers of Peabody, which is a general partner of Black Beauty, serve on the partnership committee of Black Beauty. The members of the Black Beauty partnership committee do not receive a fee for their services.
TRANSACTIONS WITH MANAGEMENT
During the fiscal year ended March 31, 1999, our executive officers, were granted, or allowed to purchase shares of our capital stock pursuant to the 1998 Stock Purchase and Option Plan for Key Employees. In connection with these grants and sales, we, affiliates of Lehman Brothers Holdings Inc. and the executives who received our Class B common stock entered into a stockholders agreement providing for piggy- back registration rights and drag-along and tag-along rights with respect to certain sales of our capital stock by affiliates of Lehman Brothers Holdings Inc.
In conjunction with the grant or sale of our capital stock, the executive officers executed term notes as of December 31, 1998. The term notes for executive officers receiving grants of capital stock are generally due on March 31, 2003 and bear annual interest at an applicable United States federal rate utilized by the Internal Revenue Service for loans to employees. The term notes for executive officers who purchased capital stock are payable in equal amounts on March 31 of 1999 through 2003 and have a 5 percent annual interest rate. Either form of promissory note will accelerate upon the occurrence of certain events.
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 fiscal year ended March 31, 1999:
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 P&L Coal Holdings Corporation are included in Item 8 at the page indicated:
Page ---- Report of Independent Auditors 46 Audited Financial Statements: Statements of Operations - Periods ended March 31, 1999 and May 19, 1998, Year ended March 31, 1998, Six Months ended March 31, 1997 and Year ended September 30, 1996 47 Balance Sheets - March 31, 1999 and 1998 48 Statements of Cash Flows - Periods ended March 31, 1999 and May 19, 1998, Year ended March 31, 1998, Six Months ended March 31, 1997 and Year ended September 30, 1996 49 Statements of Changes in Stockholders' Equity / Invested Capital - Periods ended March 31, 1999 and May 19, 1998 50 Notes to Financial Statements 51
(2) Financial Statement Schedule.
The following financial statement schedule of P&L Coal Holdings 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.
The following exhibits are filed as part of this Report:
(b) Reports on Form 8-K.
No reports were filed on Form 8-K for the period ended March 31, 1999.
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.
P&L COAL HOLDINGS CORPORATION
June 18, 1999 IRL F. ENGELHARDT ____________________________________
Irl F. Engelhardt Chairman and Chief Executive Officer
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.
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 Second Amended and Restated Certificate of Incorporation of P&L Coal Holdings Corporation (Incorporated by reference to Exhibit 3.1 of the Company's Form 10-Q for the third quarter ended December 31, 1998). 3.2 By-Laws of P&L Coal Holdings Corporation (Incorporated by reference to Exhibit 3.2 of the Company's Form S-4 Registration Statement No. 333-59073). 3.3 Certificate of Incorporation of Affinity Mining Company (Incorporated by reference to Exhibit 3.3 of the Company's Form S-4 Registration Statement No. 333-59073). 3.4 By-Laws of Affinity Mining Company (Incorporated by reference to Exhibit 3.4 of the Company's Form S-4 Registration Statement No. 333-59073). 3.5 Certificate of Incorporation of Arid Operations Inc (Incorporated by reference to Exhibit 3.5 of the Company's Form S-4 Registration Statement No. 333-59073). 3.6 By-Laws of Arid Operations Inc (Incorporated by reference to Exhibit 3.6 of the Company's Form S-4 Registration Statement No. 333-59073). 3.7 Certificate of Incorporation of Big Sky Coal Company (Incorporated by reference to Exhibit 3.7 of the Company's Form S-4 Registration Statement No. 333-59073). 3.8 By-Laws of Big Sky Coal Company (Incorporated by reference to Exhibit 3.8 of the Company's Form S-4 Registration Statement No. 333-59073). 3.9 Articles of Incorporation of Blackrock First Capital Corporation (Incorporated by reference to Exhibit 3.9 of the Company's Form S-4 Registration Statement No. 333-59073). 3.10 By-Laws of Blackrock First Capital Corporation (Incorporated by reference to Exhibit 3.10 of the Company's Form S-4 Registration Statement No. 333-59073). 3.11 Certificate of Incorporation of Bluegrass Coal Company (Incorporated by reference to Exhibit 3.11 of the Company's Form S-4 Registration Statement No. 333-59073). 3.12 By-Laws of Bluegrass Coal Company (Incorporated by reference to Exhibit 3.12 of the Company's Form S-4 Registration Statement No. 333-59073). 3.13 Certificate of Incorporation of Caballo Coal Company (Incorporated by reference to Exhibit 3.13 of the Company's Form S-4 Registration Statement No. 333-59073). 3.14 By-Laws of Caballo Coal Company (Incorporated by reference to Exhibit 3.14 of the Company's Form S-4 Registration Statement No. 333-59073). 3.15 Certificate of Incorporation of Charles Coal Company (Incorporated by reference to Exhibit 3.15 of the Company's Form S-4 Registration Statement No. 333-59073). 3.16 By-Laws of Charles Coal Company (Incorporated by reference to Exhibit 3.16 of the Company's Form S-4 Registration Statement No. 333-59073). 3.17 Certificate of Incorporation of Coal Properties Corp (Incorporated by reference to Exhibit 3.17 of the Company's Form S-4 Registration Statement No. 333-59073). 3.18 By-Laws of Coal Properties Corp (Incorporated by reference to Exhibit 3.18 of the Company's Form S-4 Registration Statement No. 333-59073). 3.19 Exhibit Intentionally Omitted 3.20 Amended and Restated Venture Agreement of Colony Bay Coal Company (Incorporated by reference to Exhibit 3.20 of the Company's Form S-4 Registration Statement No. 333-59073). 3.21 Certificate of Incorporation of Cook Mountain Coal Company (Incorporated by reference to Exhibit 3.21 of the Company's Form S-4 Registration Statement No. 333-59073). 3.22 By-Laws of Cook Mountain Coal Company (Incorporated by reference to Exhibit 3.22 of the Company's Form S-4 Registration Statement No. 333-59073). 3.23 Certificate of Incorporation of Cottonwood Land Company (Incorporated by reference to Exhibit 3.23 of the Company's Form S-4 Registration Statement No. 333-59073). 3.24 By-Laws of Cottonwood Land Company (Incorporated by reference to Exhibit 3.24 of the Company's Form S-4 Registration Statement No. 333-59073).
Exhibit No. Description of Exhibit - ------- ----------------------
3.25 Certificate of Incorporation of Orion Mines, Inc. (now known as Darius Gold Mine Inc.) (Incorporated by reference to Exhibit 3.25 of the Company's Form S-4 Registration Statement No. 333-59073). 3.26 By-Laws of Darius Gold Mine Inc. (Incorporated by reference to Exhibit 3.26 of the Company's Form S-4 Registration Statement No. 333-59073). 3.27 Certificate of Incorporation of Koppers Recreation Camps (now known as EACC Camps, Inc.) (Incorporated by reference to Exhibit 3.27 of the Company's Form S-4 Registration Statement No. 333-59073). 3.28 By-Laws of Koppers Recreation Camps, Inc. (now known as EACC Camps, Inc.) (Incorporated by reference to Exhibit 3.28 of the Company's Form S-4 Registration Statement No. 333-59073). 3.29 Certificate of Incorporation of Eastern Associated Coal Corp. (Incorporated by reference to Exhibit 3.29 of the Company's Form S-4 Registration Statement No. 333-59073). 3.30 By-Laws of Eastern Associated Coal Corp. (Incorporated by reference to Exhibit 3.30 of the Company's Form S-4 Registration Statement No. 333-59073). 3.31 Certificate of Incorporation of Eastern Royalty Corp. (Incorporated by reference to Exhibit 3.31 of the Company's Form S-4 Registration Statement No. 333-59073). 3.32 By-Laws of Eastern Royalty Corp. (Incorporated by reference to Exhibit 3.32 of the Company's Form S-4 Registration Statement No. 333-59073). 3.33 Certificate of Incorporation of Exploraciones y Minerales Sierra Morena S.A. (now known as Gold Fields Chile, S.A.) (Incorporated by reference to Exhibit 3.33 of the Company's Form S-4 Registration Statement No. 333-59073). 3.34 By-Laws of Exploraciones y Minerales Sierra Morena S.A. (now known as Gold Fields Chile, S.A.) (Incorporated by reference to Exhibit 3.34 of the Company's Form S-4 Registration Statement No. 333-59073). 3.35 Restated Certificate of Incorporation of Gold Fields Mining Corporation (Incorporated by reference to Exhibit 3.35 of the Company's Form S-4 Registration Statement No. 333-59073). 3.36 By-Laws of Gold Fields Mining Corporation (Incorporated by reference to Exhibit 3.36 of the Company's Form S-4 Registration Statement No. 333-59073). 3.37 Certificate of Incorporation of East Tennessee Coal Company (now known as Gold Fields Operating Co.-Ortiz) (Incorporated by reference to Exhibit 3.37 of the Company's Form S-4 Registration Statement No. 333-59073). 3.38 By-Laws of Gold Fields Operating Co.-Ortiz (Incorporated by reference to Exhibit 3.38 of the Company's Form S-4 Registration Statement No. 333-59073). 3.39 Articles of Incorporation of Grand Eagle Mining, Inc. (Incorporated by reference to Exhibit 3.39 of the Company's Form S-4 Registration Statement No. 333-59073). 3.40 By-Laws of Grand Eagle Mining, Inc. (Incorporated by reference to Exhibit 3.40 of the Company's Form S-4 Registration Statement No. 333-59073). 3.41 Certificate of Incorporation of Hayden Gulch Terminal, Inc. (Incorporated by reference to Exhibit 3.41 of the Company's Form S-4 Registration Statement No. 333-59073). 3.42 By-Laws of Hayden Gulch Terminal, Inc. (Incorporated by reference to Exhibit 3.42 of the Company's Form S-4 Registration Statement No. 333-59073). 3.43 Certificate of Incorporation of Independence Material Handling Company (Incorporated by reference to Exhibit 3.43 of the Company's Form S-4 Registration Statement No. 333-59073). 3.44 By-Laws of Independence Material Handling Company (Incorporated by reference to Exhibit 3.44 of the Company's Form S-4 Registration Statement No. 333-59073). 3.45 Certificate of Incorporation of Interior Holdings Corp. (Incorporated by reference to Exhibit 3.45 of the Company's Form S-4 Registration Statement No. 333-59073). 3.46 By-Laws of Interior Holdings Corp. (Incorporated by reference to Exhibit 3.46 of the Company's Form S-4 Registration Statement No. 333-59073). 3.47 Certificate of Incorporation of A.T. Two, Inc. (now known as James River Coal Terminal Company) (Incorporated by reference to Exhibit 3.47 of the Company's Form S-4 Registration Statement No. 333-59073). 3.48 Restated By-Laws of James River Coal Terminal Company (Incorporated by reference to Exhibit 3.48 of the Company's Form S-4 Registration Statement No. 333-59073). 3.49 Certificate of Incorporation of Juniper Coal Company (Incorporated by reference to Exhibit 3.49 of the Company's Form S-4 Registration Statement No. 333-59073).
Exhibit No. Description of Exhibit - ------- ----------------------
3.50 By-Laws of Juniper Coal Company (Incorporated by reference to Exhibit 3.50 of the Company's Form S-4 Registration Statement No. 333-59073). 3.51 Certificate of Incorporation of Kayenta Mobile Home Park, Inc. (Incorporated by reference to Exhibit 3.51 of the Company's Form S-4 Registration Statement No. 333-59073). 3.52 By-Laws of Kayenta Mobile Home Park, Inc. (Incorporated by reference to Exhibit 3.52 of the Company's Form S-4 Registration Statement No. 333-59073). 3.53 Certificate of Incorporation of Martinka Coal Company (Incorporated by reference to Exhibit 3.53 of the Company's Form S-4 Registration Statement No. 333-59073). 3.54 By-Laws of Martinka Coal Company (Incorporated by reference to Exhibit 3.54 of the Company's Form S-4 Registration Statement No. 333-59073). 3.55 Articles of Incorporation of Midco Supply and Equipment Corporation (Incorporated by reference to Exhibit 3.55 of the Company's Form S-4 Registration Statement No. 333-59073). 3.56 By-Laws of Midco Supply and Equipment Corporation. (Incorporated by reference to Exhibit 3.56 of the Company's Form S-4 Registration Statement No. 333-59073). 3.57 Exhibit Intentionally Omitted. 3.58 Exhibit Intentionally Omitted. 3.59 Certificate of Incorporation of Nueast Mining Corp. (now known as Mountain View Coal Company) (Incorporated by reference to Exhibit 3.59 of the Company's Form S-4 Registration Statement No. 333-59073). 3.60 By-Laws of Nueast Mining Corp. (now known as Mountain View Coal Company) (Incorporated by reference to Exhibit 3.60 of the Company's Form S-4 Registration Statement No. 333-59073). 3.61 Articles of Incorporation of North Page Coal Corp. (Incorporated by reference to Exhibit 3.61 of the Company's Form S-4 Registration Statement No. 333-59073). 3.62 By-Laws of North Page Coal Corp. (Incorporated by reference to Exhibit 3.62 of the Company's Form S-4 Registration Statement No. 333-59073). 3.63 Articles of Incorporation of Ohio County Coal Company (Incorporated by reference to Exhibit 3.63 of the Company's Form S-4 Registration Statement No. 333-59073). 3.64 By-Laws of Ohio County Coal Company (Incorporated by reference to Exhibit 3.64 of the Company's Form S-4 Registration Statement No. 333-59073). 3.65 Certificate of Limited Partnership of Patriot Coal Company, L.P. (Incorporated by reference to Exhibit 3.65 of the Company's Form S-4 Registration Statement No. 333- 59073). 3.66 Limited Partnership Agreement of Patriot Coal Company, L.P. (Incorporated by reference to Exhibit 3.66 of the Company's Form S-4 Registration Statement No. 333-59073). 3.67 Certificate of Incorporation of Peabody America, Inc. (Incorporated by reference to Exhibit 3.67 of the Company's Form S-4 Registration Statement No. 333-59073). 3.68 By-Laws of Peabody America, Inc. (Incorporated by reference to Exhibit 3.68 of the Company's Form S-4 Registration Statement No. 333-59073). 3.69 Certificate of Incorporation of Peabody Coal Company (Incorporated by reference to Exhibit 3.69 of the Company's Form S-4 Registration Statement No. 333-59073). 3.70 Restated By-Laws of Peabody Coal Company (Incorporated by reference to Exhibit 3.70 of the Company's Form S-4 Registration Statement No. 333-59073). 3.71 Certificate of Incorporation of Peabody COALSALES Company (Incorporated by reference to Exhibit 3.71 of the Company's Form S-4 Registration Statement No. 333-59073). 3.72 By-Laws of Peabody COALSALES Company (Incorporated by reference to Exhibit 3.72 of the Company's Form S-4 Registration Statement No. 333-59073). 3.73 Certificate of Incorporation of COALTRADE Inc. (now known as Peabody COALTRADE, Inc.) (Incorporated by reference to Exhibit 3.73 of the Company's Form S-4 Registration Statement No. 333-59073). 3.74 By-Laws of COALTRADE Inc. (now known as Peabody COALTRADE, Inc.) (Incorporated by reference to Exhibit 3.74 of the Company's Form S-4 Registration Statement No. 333-59073).
Exhibit No. Description of Exhibit - ------- ----------------------
3.75 Certificate of Incorporation of Premier Coal Sales Company, (now known as Peabody Development Company) (Incorporated by reference to Exhibit 3.75 of the Company's Form S-4 Registration Statement No. 333-59073). 3.76 Restated By-Laws of Peabody Development Company (Incorporated by reference to Exhibit 3.76 of the Company's Form S-4 Registration Statement No. 333-59073). 3.77 Certificate of Incorporation of Peabody Powertrade, Inc. (now known as Peabody Energy Solutions, Inc.) (Incorporated by reference to Exhibit 3.77 of the Company's Form S-4 Registration Statement No. 333-59073). 3.78 By-Laws of Peabody Powertrade, Inc. (now known as Peabody Energy Solutions, Inc.) (Incorporated by reference to Exhibit 3.78 of the Company's Form S-4 Registration Statement No. 333-59073). 3.79 Restated Certificate of Incorporation of Peabody Holding Company, Inc. (Incorporated by reference to Exhibit 3.79 of the Company's Form S-4 Registration Statement No. 333-59073). 3.80 Restated By-Laws of Peabody Holding Company, Inc. (Incorporated by reference to Exhibit 3.80 of the Company's Form S-4 Registration Statement No. 333-59073). 3.81 Exhibit Intentionally Omitted 3.82 Second Amended and Restated Partnership Agreement re: Peabody Natural Resources Company (Incorporated by reference to Exhibit 3.82 of the Company's Form S-4 Registration Statement No. 333-59073). 3.83 Certificate of Incorporation of Armco Terminal Company (now known as Peabody Terminals, Inc.) (Incorporated by reference to Exhibit 3.83 of the Company's Form S-4 Registration Statement No. 333-59073). 3.84 By-Laws of Peabody Terminals, Inc. (Incorporated by reference to Exhibit 3.84 of the Company's Form S-4 Registration Statement No. 333-59073). 3.85 Certificate of Incorporation of Peabody Venezuela Coal Corp. (Incorporated by reference to Exhibit 3.85 of the Company's Form S-4 Registration Statement No. 333-59073). 3.86 By-Laws of Peabody Venezuela Coal Corp. (Incorporated by reference to Exhibit 3.86 of the Company's Form S-4 Registration Statement No. 333-59073). 3.87 Certificate of Incorporation of Peabody Western Coal Company (Incorporated by reference to Exhibit 3.87 of the Company's Form S-4 Registration Statement No. 333-59073). 3.88 By-Laws of Peabody Western Coal Company (Incorporated by reference to Exhibit 3.88 of the Company's Form S-4 Registration Statement No. 333-59073). 3.89 Certificate of Incorporation of Pine Ridge Coal Company (Incorporated by reference to Exhibit 3.89 of the Company's Form S-4 Registration Statement No. 333-59073). 3.90 By-Laws of Pine Ridge Coal Company (Incorporated by reference to Exhibit 3.90 of the Company's Form S-4 Registration Statement No. 333-59073). 3.91 Certificate of Incorporation of Powder River Coal Company (Incorporated by reference to Exhibit 3.91 of the Company's Form S-4 Registration Statement No. 333-59073). 3.92 Restated By-Laws of Powder River Coal Company (Incorporated by reference to Exhibit 3.92 of the Company's Form S-4 Registration Statement No. 333-59073). 3.93 Certificate of Incorporation of Rio Escondido Coal Corp. (Incorporated by reference to Exhibit 3.93 of the Company's Form S-4 Registration Statement No. 333-59073). 3.94 By-Laws of Rio Escondido Coal Corp. (Incorporated by reference to Exhibit 3.94 of the Company's Form S-4 Registration Statement No. 333-59073). 3.95 Certificate of Incorporation of Seneca Coal Company (Incorporated by reference to Exhibit 3.95 of the Company's Form S-4 Registration Statement No. 333-59073). 3.96 By-Laws of Seneca Coal Company (Incorporated by reference to Exhibit 3.96 of the Company's Form S-4 Registration Statement No. 333-59073). 3.97 Certificate of Incorporation of Sentry Mining Company (Incorporated by reference to Exhibit 3.97 of the Company's Form S-4 Registration Statement No. 333-59073). 3.98 By-Laws of Sentry Mining Company (Incorporated by reference to Exhibit 3.98 of the Company's Form S-4 Registration Statement No. 333-59073). 3.99 Certificate of Incorporation of Snowberry Land Company (Incorporated by reference to Exhibit 3.99 of the Company's Form S-4 Registration Statement No. 333-59073). 3.100 By-Laws of Snowberry Land Company (Incorporated by reference to Exhibit 3.100 of the Company's Form S-4 Registration Statement No. 333-59073).
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3.101 Agreement of Incorporation of Low Volatile Coals, Inc. (now known as Sterling Smokeless Company) (Incorporated by reference to Exhibit 3.101 of the Company's Form S-4 Registration Statement No. 333-59073). 3.102 By-Laws of Sterling Smokeless Company (Incorporated by reference to Exhibit 3.102 of the Company's Form S-4 Registration Statement No. 333-59073). 3.103 Certificate of Formation of Thoroughbred, L.L.C. (Incorporated by reference to Exhibit 3.103 of the Company's Form S-4 Registration Statement No. 333-59073). 3.104 Operating Agreement of Thoroughbred, L.L.C. (Incorporated by reference to Exhibit 3.104 of the Company's Form S-4 Registration Statement No. 333-59073). 4.1 Senior Note Indenture dated as of May 18, 1998 between P&L Coal Holdings Corporation and State Street Bank and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.1 of the Company's Form S-4 Registration Statement No. 333-59073). 4.2 Senior Subordinated Note Indenture dated as of May 18, 1998 between P&L Coal Holdings Corporation and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.2 of the Company'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), P&L Coal Holdings Corporation 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 Company'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), P&L Coal Holdings Corporation, 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 Company'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 Company'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 Company's Form S-4 Registration Statement No. 333- 59073). 4.7 Senior Note Registration Rights Agreement dated as of May 18, 1998 between P&L Coal Holdings Corporation and Lehman Brothers Inc. (Incorporated by reference to Exhibit 4.7 of the Company's Form S-4 Registration Statement No. 333- 59073). 4.8 Senior Subordinated Note Registration Rights Agreement dated as of May 18, 1998 between P&L Coal Holdings Corporation and Lehman Brothers Inc. (Incorporated by reference to Exhibit 4.8 of the Company's Form S-4 Registration Statement No. 333-59073). 10.1 Amended and Restated Credit Agreement dated as of June 9, 1998 among P&L Coal Holdings Corporation, 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 Company'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 Company'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 Company'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 Company'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 Company'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 Company'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 Company's Form S-4 Registration Statement No. 333-59073).
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10.8 Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.7 of Amendment No. 1 of the Company'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 Company's Form 10-Q for the second quarter ended September 30, 1998). 10.10 1998 Stock Purchase and Option Plan for Key Employees of P&L Coal Holding Corporation (incorporated by reference to Exhibit 10.10 of the Company's Form 10-Q for the third quarter ended December 1998). 10.11 Employment Agreement between Irl F. Engelhardt and the Company dated May 19, 1998. 10.12 Employment Agreement between Richard M. Whiting and the Company dated May 19, 1998. 10.13 Employment Agreement between W. Howard Carson and the Company dated May 19, 1998. 10.14 Employment Agreement between Roger B. Walcott, Jr. and the Company dated May 19, 1998. 10.15 Employment Agreement between Mark Maisto and the Company dated May 19, 1998. 21 List of Subsidiaries. 24 Powers of Attorney. 27 Financial Data Schedule (filed electronically with the SEC only).
[FN] 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 P&L Coal Holdings Corporation
We have audited the consolidated financial statements of P&L Coal Holdings Corporation (the Company) as of March 31, 1999 and for the period ended March 31, 1999 and the combined financial statements of P&L Coal Group (the Predecessor Company) as of March 31, 1998, and for the period ended May 19, 1998, the year ended March 31, 1998, the six months ended March 31, 1997 and the year ended September 30, 1996, and have issued our report thereon dated April 30, 1999. Our audits also included the financial statement schedule listed in Item 14(a). This schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
Ernst & Young LLP
April 30, 1999 St. Louis, Missouri