Document is copied.
Filed Pursuant to Rule 424(b)(3)
File Nos. 333-59073
333-59073-01 to
333-59073-51
PEABODY ENERGY CORPORATION
SUPPLEMENT NO. 4 TO MARKET-MAKING PROSPECTUS DATED
AUGUST 11, 2000
THE DATE OF THIS SUPPLEMENT IS APRIL 27, 2001
ON JUNE 28, 2000, P&L COAL HOLDINGS CORPORATION FILED THE
ATTACHED REPORT ON FORM 10-K FOR THE FISCAL YEAR ENDED
MARCH 31, 2000
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934 For the Fiscal Year Ended March 31, 2000
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 333-59073
-------------------------------------------------
PEABODY ENERGY CORPORATION
- --------------------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
DELAWARE 13-4004153
- --------------------------------------- -------------------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
701 MARKET STREET, ST. LOUIS, MISSOURI 63101
- --------------------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
(314) 342-3400
- --------------------------------------------------------------------------------
Registrant's telephone number, including area code
Securities Registered Pursuant to Section 12(b) of the Act: NONE
Securities Registered Pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in any amendment to
this Form 10-K. [X]
================================================================================
This Form 10-K/A No. 1 is hereby filed with respect to the Annual Report on Form
10-K for the year ended March 31, 2000 of Peabody Energy Corporation filed
with the Securities and Exchange Commission on June 28, 2000 (the Form 10-K).
Part II, Item 6 "Selected Financial Data," Part II, Item 7 "Management's
Discussion and Analysis of Financial Condition and Results of Operations," Part
II, Item 8 "Financial Statements and Supplementary Data" and Part IV, Item 14
"Exhibits and Financial Statement Schedules" of the Form 10-K are hereby amended
and restated in their entirety due to the change in the compensation expense
related to the granting of Class B common stock during the period ended March
31, 1999. On April 10, 2001, P&L Coal Holdings Corporation changed its name to
Peabody Energy Corporation.
PART I
ITEM 1. BUSINESS.
OVERVIEW
We are the world's largest coal company. In addition to being the world's
largest producer and marketer of coal, we are engaged in coal and emission
allowance trading, coal contract restructurings, transportation services and we
generate revenues from our substantial property holdings. During the past
decade, we have transformed from a largely high sulfur, high-cost coal producer
to a producer and marketer of predominantly low sulfur, low-cost coal from
operations in the United States and Australia.
For the year ended March 31, 2000, we sold 190.3 million tons of coal worldwide.
These products were used to generate more than 9% of the electricity in the
United States and more than 2.5% of the world's electricity. Our share of the
U.S. coal market was approximately 16.0% in calendar 1999. We have approximately
10.0 billion tons of proven and probable coal reserves, the largest reserve base
of any 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 year 2000, we produced approximately 62% of our coal in the Western
United States, 32% from the eastern half of the United States and 6% from
Australia. Peabody's coal production in the Western United States has grown from
37 million tons in 1990 to 118 million tons in fiscal year 2000. Our highly
productive western operations produce low sulfur coal that utilities utilize to
comply with the more stringent standards resulting from the Clean Air Act.
Our large and diverse customer base includes more than 300 electricity
generating plants and industrial customers in the United States as well as steam
and metallurgical coal customers in 17 other countries. In fiscal year 2000, we
supplied 93% of our United States production to United States electric
utilities, 4% to the export market and 3% to the United States industrial
sector.
HISTORY
Peabody, Daniels and Co. was founded in 1883 as a retail coal supplier, entering
the mining business in 1888 as Peabody & Co. with our first mine in Illinois. In
1926, Peabody Coal Company was listed on the Chicago Stock Exchange and,
beginning in 1949, on the New York Stock Exchange. In 1955, Peabody Coal
Company, primarily an underground mine operator, merged with Sinclair Coal
Company, a major surface mining company. In 1968, Peabody Coal Company was
acquired by Kennecott Copper Company. In 1977, it was sold to Peabody Holding
Company, which was formed by a consortium of companies.
In July 1990, Hanson acquired Peabody Holding Company. In February 1997, Hanson
spun off its energy-related businesses, including Eastern Group and Peabody
Holding Company, into The Energy Group, plc. The Energy Group was a publicly
traded company in the United Kingdom and its American Depository Receipts
(ADR's) were publicly traded on the New York Stock Exchange. On May 19, 1997,
The Energy Group, through Peabody, purchased Citizens Power, a leading power
marketer.
On May 19, 1998, Lehman Brothers Merchant Banking Partners II L.P., an affiliate
of Lehman Brothers Inc. purchased Peabody Holding Company and its affiliates,
Peabody Resources Limited (Peabody Resources) and Citizens Power LLC, now
collectively called the Peabody Group. The transaction coincided with the
purchase by Texas Utilities of the remainder of The Energy Group.
During the 1980s, Peabody grew through expansion and acquisition, opening the
North Antelope Mine in Wyoming's coal-rich Powder River Basin in 1983 and the
Rochelle Mine in 1985. In 1984, we acquired the West Virginia coal properties of
ARMCO Steel and the following year purchased Coal Properties Corp. and Eastern
Associated Coal Corp., which included seven operating mines and substantial low
sulfur coal reserves in West Virginia.
2
From 1993 to 2000, we made 16 major acquisitions. In 1993, interests in three
mines in New South Wales, Australia, were acquired from Costain Group in
anticipation of the growing Pacific Rim market for coal. The properties included
100% ownership of the Ravensworth Mine, a 50% interest in the Narama Mine and a
28.75% interest in the Warkworth Mine, subsequently raised to 43.75%. We also
subsequently developed a fourth mine, Bengalla, which began shipments in early
1999. Our interest in the Bengalla joint venture was raised from 35% to 37% in
1998 and to 40% in 2000.
In 1993 we also acquired the Lee Ranch Mine in New Mexico. The following year,
we purchased a one-third ownership in Black Beauty Coal Company (Black Beauty),
Indiana's largest coal producer. We increased our interest in Black Beauty to
43.3% in February 1998 and to 81.7% in January 1999. Black Beauty acquired
Catlin Coal Company in 1999 and acquired an additional 25% of Arclar Coal
Company in 2000.
In 1994, we acquired the Caballo and Rawhide mines in Wyoming's Powder River
Basin from Exxon Coal USA Inc. This acquisition, along with the expansion of the
North Antelope and Rochelle Mines, positioned Peabody as the leading producer in
the Powder River Basin, the nation's largest and fastest growing coal region.
Our sales volume from the Powder River Basin increased from 31 million tons in
1993 to 96 million tons in fiscal year 2000.
In August 1999, we purchased a 55% interest in the Moura Mine in Queensland,
Australia. The Moura Mine supplies a range of steam and metallurgical coals to
Asia-Pacific customers and operates a coalbed methane extraction operation.
Since 1990, our coal sales volume has grown from approximately 93 million annual
tons to approximately 190 million annual tons, an increase of 104%.
OUR BUSINESSES
COMMERCIAL OPERATIONS
Our sales and marketing operations, Peabody COALSALES and Peabody COALTRADE,
sell coal produced by our large, diverse portfolio of operations, broker coal
sales of other producers to third parties (both as a principal and as an agent),
trade coal and emission allowances, and provide coal contract restructuring
services and transportation services. Total coal sales volume for fiscal year
2000 was 190.3 million tons.
RESOURCE MANAGEMENT
We hold approximately 10.0 billion of proven and probable coal reserves
worldwide. Our Resource Management group constantly reviews this reserve base to
generate revenues through the sale of non-strategic coal reserves and surface
land. In addition, revenue is generated through royalties from coal reserves
leased to third parties, and farm income from surface land under third party
contracts. The Resource Management group is also actively pursuing opportunities
in the area of coalbed methane extraction in the United States through a new
subsidiary, Peabody Natural Gas, LLC.
3
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
operating units and affiliates.
U. S. OPERATIONS
[MAP]
UNITED STATES
Within the United States, operations are divided into four operating
regions: Powder River Basin; Southwest; Appalachia; and Midwest.
POWDER RIVER BASIN OPERATIONS
We control approximately 3.5 billion tons of coal reserves in the southern
Powder River Basin, the largest and fastest growing major U.S. coal-producing
region. We own and manage three low sulfur, non-union surface mining complexes
in Wyoming that sold approximately 96.1 million tons of coal in fiscal year
2000, or approximately 50% of our total coal sales. The North Antelope/Rochelle
and Caballo mines are serviced by both major western railroads, the Burlington
Northern/Santa Fe and Union Pacific. The Rawhide Mine, which was idled in fiscal
year 1999, is serviced by the Burlington Northern/Santa Fe railroad only.
Our Wyoming Powder River Basin reserves are classified as surface mineable,
subbituminous coal with seam thickness varying from 70 to 105 feet. The sulfur
content of the coal in current production ranges from 0.2% to 0.4% and the heat
value ranges from 8,250 to 8,900 Btus per pound.
4
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 by the
Burlington Northern/Santa Fe railroad.
North Antelope/Rochelle
The North Antelope/Rochelle Mine is located 65 miles south of Gillette, Wyoming.
The mine is the largest surface mine and one of the most productive in the
United States, selling 69.3 million tons during fiscal year 2000. The North
Antelope/Rochelle Mine produces premium quality coal with a sulfur content
averaging 0.20% and a heat value ranging from 8,500 to 8,900 Btus per pound. It
produces the lowest sulfur coal in the United States, using a dragline along
with five truck-and-shovel fleets to uncover the coal.
Caballo
The Caballo Mine is located 20 miles south of Gillette, Wyoming. In fiscal year
2000, it sold approximately 26.8 million tons of low sulfur coal. Caballo is a
truck and shovel operation with a coal handling system that includes two
12,000-ton silos and two 11,000-ton silos.
Big Sky
The Big Sky Mine is located in the northern end of the Powder River Basin near
Colstrip, Montana and uses dragline mining equipment. The mine sold 2.5 million
tons of low sulfur coal in fiscal year 2000. 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. Hourly workers at the Big Sky Mine are members of the United Mine
Workers of America.
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 19.2
million tons of coal in fiscal year 2000.
Black Mesa
The Black Mesa Mine, which is located on the Navajo Nation and Hopi Tribe
reservations in Arizona, uses two draglines and sold 4.6 million tons of coal in
fiscal year 2000. Its coal is crushed, mixed with water and then transported 273
miles through the underground Black Mesa Pipeline to the Mohave Generating
Station near Laughlin, Nevada operated by Southern California Edison. 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 8.5 million tons of coal in fiscal
year 2000. The coal is crushed, then carried 17 miles by conveyor belt to
storage silos where it is loaded on to a private rail line and transported 83
miles to the Navajo Generating Station, operated by the Salt River Project near
Page, Arizona. The mine and the railroad were designed to deliver coal
exclusively to the power plant, which has no other source of coal. The Navajo
coal supply agreement extends until 2011. Hourly workers at this mine are
members of the United Mine Workers of America.
Seneca
The Seneca Mine near Hayden, Colorado shipped 1.4 million tons of low sulfur
coal in fiscal year 2000, operating with two draglines in two separate mining
areas. The mine's coal is hauled by truck to the nearby Hayden Generating
Station, operated by 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.
5
Lee Ranch Coal Company
The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 4.7
million tons of low sulfur coal in fiscal year 2000. Lee Ranch shipped the
majority of its coal to two customers in Arizona and New Mexico under coal
supply agreements extending until 2010 and 2014, respectively. Lee Ranch is a
non-union surface mine that uses a combination of dragline and truck-and-shovel
mining techniques.
APPALACHIA OPERATIONS
We own and manage five operating units and related facilities in West Virginia.
In fiscal year 2000, these operations sold approximately 16.8 million tons of
mid to 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 year 2000, the Big Mountain No. 16 and Robin Hood
No. 9 mines sold approximately 2.3 million tons of steam coal. Both are
underground mines using continuous mining equipment. Processed coal is
loaded on the CSX railroad.
Harris Operating Unit
The Harris Operating Unit consists of the Harris No. 1 Mine near Bald Knob, West
Virginia, which sold approximately 3.0 million tons of low sulfur coal in fiscal
year 2000. This mine uses both longwall and continuous mining equipment.
Rocklick Operating Unit and Contract Mines
The Rocklick preparation plant, located near Wharton, West Virginia, processes
coal produced by the Harris Mine and contract mining companies from coal
reserves that we control. This preparation plant shipped approximately 6.2
million tons of steam and metallurgical coal in fiscal year 2000 (including 3.0
million tons related to the Harris Operating Unit). Processed coal is loaded at
the plant site on the CSX railroad or transferred via conveyor to our Kopperston
loadout facility and loaded on the Norfolk Southern railroad.
Wells Operating Unit
The Wells Operating Unit, in Boone County, West Virginia, sold approximately 3.8
million tons of metallurgical and steam coal during fiscal year 2000. The unit
consists of the Lightfoot No. 2 Mine, contract mines and the Wells Preparation
Plant, located near Wharton, West Virginia. The mine uses continuous 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.
Federal No. 2 Mine
The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining
equipment and shipped approximately 4.5 million tons of steam coal in fiscal
year 2000. Coal shipped from the Federal No. 2 Mine has a sulfur content only
slightly above that of low sulfur coal and has an above average heating content
- - as a result, it is more marketable than some other mid-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 electricity
generating plants.
MIDWEST OPERATIONS
We own and operate six mines in the Midwestern United States, which collectively
sold 16.5 million tons of coal in fiscal year 2000. Included are four
underground and two 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 56% of the high sulfur coal sold from
these mining operations is shipped to electric generating stations equipped with
desulfurization units. Peabody Coal Company hourly workers are members of the
United Mine Workers of America; Patriot Coal Company operates union-free.
6
We control 16 additional mines in the Midwestern United States through our 81.7%
joint venture interest in Black Beauty, as discussed below.
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 6.6 million tons of coal in fiscal year 2000. 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 under contract to TVA.
Hawthorn and Lynnville Operating Units
In December 1999, we suspended operations at the Hawthorn and Lynnville
Operating Units pending improved market conditions. The Hawthorn Operating Unit
near Carlisle, Indiana sold 2.2 million tons of coal in fiscal year 2000. The
Lynnville Operating Unit, near Lynnville, Indiana, sold approximately 2.3
million tons of coal in fiscal year 2000.
Marissa Operating Unit
The Marissa Operating Unit, located near Marissa, Illinois, was closed in
October 1999 after the mine's primary customer shifted its supply to
lower-sulfur coal from our Powder River Basin operations. The Marissa Operating
Unit shipped 2.4 million tons of coal in fiscal year 2000.
Midwest Operating Unit
The Midwest Operating Unit near Graham, Kentucky, sold 1.1 million tons of coal
in fiscal year 2000. The unit includes the Martwick underground mine, which uses
continuous mining equipment, and the Gibraltar surface mining operations. Coal
from these mines is sold to under contract to TVA.
The unit is also responsible for managing closed and suspended mining operations
throughout Peabody's North American operations. These properties are managed
from bond release until final reclamation requirements are met.
Patriot Coal Company
Patriot Coal Company operates Patriot, a surface mine, and Freedom, an
underground mine, in Henderson County, Kentucky, and sold approximately 1.9
million tons of coal in fiscal year 2000. 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.
Black Beauty Coal Company
We also own 81.7% of Black Beauty, which operates 10 mines in Indiana and also
has interests in four mines in southern Illinois and two mines in western
Kentucky. Together these operations sold 19.8 million tons of low, medium and
high sulfur steam coal in fiscal year 2000. We purchased a one-third interest in
Black Beauty in 1994, and increased our interest to 43.3% in 1998 and 81.7% in
1999. Black Beauty Resources, Inc., owned by certain members of Black Beauty's
management team, owns the remaining interest.
Black Beauty's principal mines include Air Quality No. 1, a low sulfur
underground coal mine located near Monroe City, Indiana. In fiscal year 2000,
Air Quality No.1 shipped 1.8 million tons of low sulfur coal. Among other mines
in Indiana, Black Beauty also operates Farmersburg, a surface mine that produced
3.5 million tons of medium sulfur coal in fiscal year 2000, the Francisco Mine,
a 2.8 million ton per year surface mine, and Somerville, a 2.0 million ton per
year surface mine that is under development.
Black Beauty owns a 75% equity interest in Sugar Camp Coal, LLC, a 3.5 million
ton per year surface mine located in southern Illinois. Sugar Camp owns a 100%
interest in Arclar Coal Company, which operates two underground mines in
southern Illinois that sell 1.0 million tons per year.
Black Beauty controls approximately 385 million tons of coal reserves, including
100 million tons of reserves that are in compliance or near compliance with the
more stringent Clean Air Act restrictions.
7
AUSTRALIA
Through Peabody Resources, headquartered in Sydney, Australia, we own interests
in coal mining, coal trading and mining services in Australia. Peabody Resources
manages and owns interests in five surface coal mines in the Hunter Valley, New
South Wales, and one in the Bowen Basin in Queensland. All operating mines use
draglines as the primary overburden stripping method to uncover coal seams. The
mines sold 18.7 million tons during fiscal year 2000, of which Peabody
Resources' entitlement was approximately 11.1 million tons. Approximately 53% of
the coal is sold domestically via term contracts, and 47% is exported to
Asia-Pacific markets, where coal consumption is expanding to satisfy growing
electricity demand. See further information regarding our Australian operations
in the financial statements at note 21 - "Segment Information."
AUSTRALIAN MINING OPERATIONS
[MAP]
Ravensworth Mine
Located 12 miles northwest of Singleton, New South Wales, the Ravensworth Mine
is 100% owned and managed by Peabody Resources under a 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. Peabody Resources also holds low sulfur coal
resources at Ravensworth West for future domestic supply.
Ravensworth East
During fiscal year 2000, Peabody Resources was awarded a contract with Macquarie
Generation to deliver 1.9 million tons per annum from January 2001 for three
years from Ravensworth East. The coal reserves and surface land were purchased
as Swamp Creek Colliery from Pacific Power via a competitive tender. Swamp Creek
was a domestic mine that has been on "care and maintenance" since operations
ceased in 1991. The lease acquired by Peabody Resources was renamed Ravensworth
East. Coal will be transported by overland conveyor to the nearby Bayswater and
Liddell Power Stations.
8
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%, holds a 20 year contract extending through 2012 to supply
approximately 2.3 million tons annually to Macquarie Generation.
Warkworth Mine
Located 7 miles southwest of Singleton, the Warkworth Mine opened in 1981 and
produces about 5.8 million tons per year of thermal and semi- soft coking coal,
primarily for export. Peabody Resources manages the mine and owns 43.75% 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% of the Mount Thorley facility and
4.2% of the Port of Newcastle Coal Loading Terminal. Warkworth has also entered
into a 30-year supply agreement commencing in 2000 to produce and supply BDT
fuel (Beneficiated Dewatered Tailings) from a washery tailings facility for sale
to the adjacent Redbank Power Station that is under construction.
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 40% interest, and
manages the mine. Construction of the first stage of the 6.6 million ton per
year surface mine and facility was completed in 1999, with sales commencing in
April 1999. The mine sold 2.5 million tons in fiscal year 2000 and is expected
to expand to 4.6 million tons of thermal coal predominately for export in 2000.
Coal is mined by excavator and transported on site by overland conveyor to a
modern coal preparation plant and stockpiling facility. Coal is dispatched by
rail to domestic users or to the Port of Newcastle.
Moura Mine
Peabody Resources manages and owns a 55% interest in the Moura Mine acquired in
August 1999. The mine is located 115 miles by rail west of the port of
Gladstone, in Central Queensland. Moura has an annual production capacity of 5.3
million tons, comprising 2.5 million tons of semi-soft coking coal and 2.8
million tons of thermal coal. The acquisition includes coal and coalbed methane
operations, together with leases for nearly 1.8 billion tons of surface and
underground resources. Coal is mined from a variety of locations over a 21-mile
lease area. Overburden is removed by the use of three electric powered
draglines. Front-end loaders, loading a fleet of coal haulers, carry out coal
recovery. Highwall mining techniques are also utilized for coal extraction. Coal
is conveyed to the coal preparation plant prior to transportation by rail to the
Clinton and Barney Point coal terminals for export primarily to Japan and Korea.
The coalbed methane operation is steadily being built up to an annual output of
18 terrajoules to supply markets across the state, and will ultimately enhance
the prospects of future underground mining at Moura.
Mining Services
Peabody Resources' Mining Services Division, based in Brisbane, Queensland,
provides specialist 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 projects,
notably for leading mining companies including BHP Minerals at Cannington,
Western Mining Corporation at Olympic Dam, Placer Pacific at Osborne, Plutonic
Resources Limited at Darlot, Amalg Resources at Eloise and civil projects
including a tunneling project through a joint venture with Obayashi Corporation
of Japan for the Brisbane City Council. In November 1999, Mining Services
acquired the Archveyor highwall mining system. The Archveyor uses continuous
flexible haulage conveyors that are computer controlled and monitored by one
operator. The Archveyor system will commence operation at the Moura Mine in
mid-2000.
COALTRADE Australia
COALTRADE Australia based in Newcastle, New South Wales was established in April
2000 to complement our existing U.S. coal trading operations and our Australian
export production sales.
9
The operations provide alternative commercial, logistical and product solutions
that are required in the rapidly expanding seaborne coal market, particularly
customers in the high growth areas of Japan, South Korea, Southeast Asia and the
Pacific Rim countries.
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. 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. In May 2000, we signed a purchase and
sale agreement to sell Citizens Power to Edison Mission Energy. See further
discussion in "Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations."
LONG-TERM COAL SUPPLY AGREEMENTS
United States
We have a large portfolio of coal supply agreements. For the fiscal year ended
March 31, 2000, 86% 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 16 years and with an average
volume-weighted remaining term of more than 4 years. In fiscal year 2000, we
sold coal to more than 300 power plants and industrial customers in the United
States and Canada and exported to 17 other countries.
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 often adjusted at
quarterly or annual intervals for changes due to inflation and/or changes in
actual costs such as taxes, fees and royalties. The inflation adjustments are
measured by public indices, the most common of which is the implicit price
deflator for the gross domestic product as published by the United States
Department of Commerce.
Quality and volumes for the coal are stipulated in coal supply agreements, and
in some instances have the option to vary annual or monthly volumes if
necessary. Variations to the quality and volumes of coal may lead to adjustments
in the contract price. Coal supply agreements typically stipulate procedures for
quality control, sampling and weighing. Most coal supply agreements contain
provisions requiring us to deliver coal within certain ranges for specific coal
characteristics such as heat content (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.
10
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% 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 52% of this total
commitment.
Australia
In fiscal year 2000, approximately 52% of Peabody Resources' 11.1 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, Ravensworth East
and Narama mines is sold to Macquarie Generation under contracts which expire in
2001, 2004 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 and Moura mines is exported. Approximately 72% is
sold under contracts, including contracts with the other joint venture partners
in Warkworth, and the remaining 28% is sold on the spot market. Warkworth has
now also entered into short-term domestic coal supply agreements with Macquarie
Generation and Delta Electricity, which expire in 2003.
The Bengalla mine commenced the sale of coal in April 1999. The large majority
of coal from Bengalla is exported. Of the coal exported, approximately 30% was
sold under long-term contracts, while the remaining 70% is sold on the spot
market. It is anticipated that the mix of contract and spot coal sold will
change over the next few years as Bengalla establishes its presence in the
export coal market. Bengalla does have a short-term domestic coal supply
agreement with Macquarie Generation, which represented approximately 10% of coal
sold in the current year. All coal from the Moura Mine, which was acquired in
August 1999, is exported under contract. Peabody Resources' export contracts for
its Warkworth, Bengalla and Moura mines normally provide for annual price
renegotiations.
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 1999 approximately 92% of all U.S. coal was shipped
by rail or barge, making these modes the keys to domestic coal distribution.
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% 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.
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SALES AND MARKETING
Our subsidiaries, Peabody COALSALES and Peabody COALTRADE, undertake the sales
and marketing functions for our U.S. 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 and sulfur
dioxide emission allowance forwards and options in the developing
over-the-counter markets. As of March 31, 2000, they had 57 employees located at
five sites, including personnel dedicated to performing market research,
contract administration and risk management activities. 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 63% of
total domestic coal, although there are approximately 740 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., RAG AG, CONSOL Energy Inc., AEI Resources, Inc.
and A.T. Massey Coal Company, which collectively produced approximately
40% of total United States coal production in 1999.
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 25% 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 20% and 25% of goods and services are supplied by the top ten suppliers,
and some 60% 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
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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 U.S. 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% 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% 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 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 U.S. 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 final amendments to the regulations are adopted that are
similar to the proposed amendments, the number of claimants who are awarded
benefits could significantly increase and the amounts of awards could
significantly increase.
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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 $1.7 million in fiscal
year 2000.
In October 1998, the Combined Fund sent a premium notice to all assigned
operators subject to the fund that included retroactive death benefit and health
benefit premiums dating back to February 1, 1993. On November 13, 1998, 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. Our subsidiaries' retroactive
premium amounts to approximately $1.3 million.
In 1996, the Combined Fund sued the Social Security Administration in the
District of Columbia seeking a declaration that the Social Security
Administration's original calculation of the per-beneficiary premium was proper.
Certain coal companies but not our subsidiaries intervened in the lawsuit. On
February 25, 2000, the federal District Court ruled in favor of the Combined
Fund. The Combined Fund has asked for an amended order and that request is
pending before the court. Once there is a final order in the case, we anticipate
that the intervenor coal companies will appeal the court's decision. If this
decision is upheld on appeal, our subsidiaries will be required to pay an
additional premium to the Combined Fund of approximately $2.4 million.
Eastern Associated Coal Corp. and Peabody Coal Company filed a lawsuit in the
Western District of Kentucky against the Social Security Administration
asserting that the Social Security Administration had improperly assigned, under
the Coal Act, certain beneficiaries to us. Subsequently, Peabody Coal and
Eastern Associated moved for summary judgment on the improper assignment of
certain beneficiaries that was granted by the federal District Court. The Social
Security Administration filed a motion seeking a final judgment. Peabody Coal
and Eastern Associated Coal Corp. believe that a final judgment has already been
issued by the federal District Court, and that the time to appeal the District
Court's decision has expired.
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,
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responsibility for any coal operator currently in violation of the act could be
imputed to other companies deemed, according to regulations, to "own or control"
the coal operator. Sanctions included being blocked from receiving new permits
and rescission or suspension of existing permits. Because of a recent federal
court action invalidating these ownership and control regulations, the scope and
potential impact of the "ownership and control" requirements on us are unclear.
The Office of Surface Mining Reclamation and Enforcement has responded to the
court action by promulgating interim regulations, which more narrowly apply the
ownership and control standards to coal companies. Although the federal action
could have, by analogy, a precedential effect on state regulations dealing with
"ownership and control," which are in many instances similar to the invalidated
federal regulations, it is not certain what impact the federal court decision
will have on these state regulations.
West Virginia Mountaintop Mining
On October 20, 1999, the U.S. District Court for the Southern District of West
Virginia issued a permanent injunction against the West Virginia Department of
Environmental Protection in a mountaintop-mining lawsuit. As interpreted by the
Director of the Department of Environmental Protection, the injunction prohibits
the Department from approving any new permits that would authorize the placement
of excess spoil in intermittent and perennial streams for the primary purpose of
waste (overburden) disposal. The Department also interpreted the injunction to
affect certain existing coal refuse ponds, sediment ponds and mountaintop mining
operations.
The Department has filed an appeal of the decision with the Fourth Circuit Court
of Appeals. On October 29, 1999, the District Court issued a stay of its
decision pending a resolution of the appeal. We do not believe the court order
will have any immediate effect on our West Virginia mines.
In late 1999 certain members of Congress pursued legislation which would have
resolved the issues raised by the district court's decision. That legislation
did not pass in 1999 but we anticipate that similar legislation will be
introduced in 2000. We cannot predict whether any such legislation will be
passed by Congress in 2000.
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 emission control requirements relating to particulate matter, such as
fugitive dust, including future regulation of fine particulate matter measuring
10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal
mining operations by extensively regulating the air emissions of sulfur dioxide
and other compounds, including nitrogen oxides, emitted by coal-fueled utility
power plants.
In July 1997, the Environmental Protection Agency adopted new, more stringent
National Ambient Air Quality Standards for very fine particulate matter and
ozone. As a result, some states will be required to change their existing
implementation plans to attain and maintain compliance with the new air quality
standards. Our mining operations and 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 existing 10 micrometer
particulate and new eight hour ozone standards were invalid. The Court also
ordered a new briefing on the validity of the very fine particulate standard.
The effect of this decision on us and our customers is unknown at this time.
Title IV of the Clean Air Act Amendments places limits on sulfur dioxide
emissions from electric power generation plants. The limits set baseline
emission standards for such facilities. Reductions in such emissions occurred in
Phase I in 1995 and in Phase II in 2000 and apply to all coal-fired power
plants. The affected utilities have been able to meet these requirements by,
among other ways, switching to lower sulfur fuels, installing pollution control
devices, such as flue gas desulfurization systems, which are known as
"scrubbers", reducing electricity generating levels or purchasing or trading
sulfur dioxide emission allowances. Emission sources receive these sulfur
dioxide emission allowances, which can be traded or sold to allow other units to
emit higher levels of sulfur dioxide. 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 has resulted in a downward pressure on
the price of higher sulfur coal, as additional coal-burning utility power plants
have complied with the restrictions of Title IV.
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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 Environmental Protection Agency recently
announced the final rules that would require 19 Eastern states to make
substantial reductions in nitrogen oxide emissions. Installation of additional
control measures required under the final rules will make it more costly to
operate coal- fired utility power plants.
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 granted four of the
eight petitions finding that certain sources are contributing to ozone
non-attainment 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, implementation of the
requirement to install control equipment could impact the amount of coal
supplied to those customers if they decide to switch to other sources of fuel,
which would result in lower emission of nitrogen oxides. The Clean Air Act
Amendments provisions for new source review require utilities to install the
best available control technology if they make a major modification to a
facility that results in an increase in its potential to emit. The Justice
Department on behalf of the Environmental Protection Agency filed seven lawsuits
in November 1999, alleging that electric utilities violated the new source
review provisions of the Clean Air Act Amendments at 29 power plants in the
Midwest and South. The Environmental Protection Agency issued an administrative
order alleging similar violations to the Tennessee Valley Authority affecting
seven plants and notices of violation for an additional eight plants owned by
the affected utilities. If the utilities are found guilty of the violations,
they could be subject to civil penalties and be required to install the required
control equipment or cease operations. Our customers are among the named
utilities and if found guilty, the fines and requirements to install additional
control equipment could impact the amount of coal they would burn if the plant
operating costs were to increase to the point that the plants were operated less
frequently. A coalition of 40 utilities and power companies have petitioned the
U.S. Court of Appeals for the District of Columbia to review the Environmental
Protection Agency's decision to grant the four petitions.
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 make a decision whether
regulate mercury emissions from coal-fired power plants until December 2000. If
the Environmental Protection Agency decides to regulate mercury emissions from
power plants, the regulations would probably not take affect until after 2007.
Regardless of any action by the Environmental Protection Agency, it is a
possibility that future 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, (RCRA) which was enacted in 1976,
affects coal mining operations by imposing requirements for the treatment,
storage and disposal of hazardous wastes. Coal mining operations covered by the
Surface Mining Control and Reclamation Act permits are exempted from regulation
under the Resource Conservation and Recovery Act by statute; however we cannot
predict whether this exclusion will continue.
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The Resource Conservation and Recovery Act excludes certain large-volume wastes
generated primarily from the combustion of coal from being regulated as a
hazardous waste, pending a report to Congress and a decision by the U.S.
Environmental Protection Agency either to regulate the coal combustion wastes as
a hazardous waste under RCRA or deem such regulation as unwarranted. The U.S.
Environmental Protection Agency made its report to Congress on March 1999 and
determined in May 2000 not to regulate coal wastes as a hazardous substance
under RCRA. The requirement to regulate coal combustion waste as a hazardous
waste could cause a switch to other lower ash fuels and reduce the amount of
coal used by electric generators.
Federal and State Superfund Statutes
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 Climate Change which is intended to limit emissions
of greenhouse gases such as carbon dioxide. In December 1997 in Kyoto, Japan,
the signatories to the convention established a binding set of emission targets
for developed nations. Although the specific emission targets vary from country
to country, the United States would be required to reduce emissions to 93% of
1990 levels over a five-year budget period from 2008 through 2012. Although the
United States has not ratified the emission targets and no comprehensive
regulations focusing on greenhouse gas emissions are in place, 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% 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 reviewed), 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 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.
17
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. First, obtaining the developmental application and, if that is granted,
obtaining the detailed operational pollution control licenses (which authorize
emissions up to a maximum level); and second, obtaining pollution control
approvals (which authorize the installation of pollution control equipment and
devices). In the first regulatory phase, an application to a regulatory
authority is filled. The relevant authority will either grant a conditional
consent, an unconditional consent, or deny the application based on the details
of the application and on any submissions or objections lodged by members of the
public. If the developmental application is granted, the detailed pollution
control license may then be issued and such license may regulate emissions to
the atmosphere; emissions in waters; noise impacts including impacts from
blasting; dust impacts; the generation, handling, storage and transportation of
waste; and requirements for the rehabilitation and restoration of land.
Each State and Territory in Australia also has either a specific statute or
certain sections in other environmental and planning statutes relating to the
contamination of land and vesting powers in the various regulatory authorities
in respect of the remediation of contaminated land. Those statutes are based on
varying policies - the primary difference between the statutes is that in
certain States and Territories, liability for remediation is placed upon the
occupier of the land, regardless of the culpability of that occupier for the
contamination. In other States and Territories, primary liability for
remediation is placed on the original polluter, whether or not the polluter
still occupies the land. If the original polluter cannot itself carry out the
remediation, then a number of the statutes contain provisions which enable
recovery of the costs of remediation from the polluter as a debt.
Many of the environmental planning statutes across the States and Territories
contain "third party" appeal rights in relation, particularly, to the first
regulatory phase. This means that any party has a right to take proceedings for
a threatened or actual breach of the statute, without first having to establish
that any particular interest of that person (other than as a member of the
public) stands to be affected by the threatened or actual breach.
Accordingly, in most States and Territories throughout Australia, mining
activities involve a number of regulatory phases. Following exploratory
investigations pursuant to a mining lease, the activity proposed to be carried
out must be the subject of an application for the activity or development. This
phase of the regulatory process, as noted above, usually involves the
preparation of extensive documents to constitute the application, addressing all
of the environmental impacts of the proposed activity. It also generally
involves extensive notification and consultation with other relevant statutory
authorities and members of the public. Once a decision is made to allow a mine
to be developed by the grant of a development consent, permit or other approval,
then a formal mining lease can be obtained under the mining statute. In
addition, operational licenses and approvals can then be applied for and
obtained in relation to pollution control devices and emissions to the
atmosphere, to waters and for noise. The obtaining of licenses and approvals,
during the operational phase, generally does not involve any extensive
notification or consultation with members of the public, as most of these issues
are anticipated to be resolved in the first regulatory phase.
Peabody is recognized as a leader in the field of environmental stewardship and
is a signatory to the Australian Federal Government's Greenhouse Challenge
Program and the Australian Minerals Industry Code of Environmental Management.
Annual independent environmental audits are conducted at our mining operations
to review our environmental management systems to maintain environmental
performance. Ravensworth, Narama, Bengalla and Warkworth maintain ISO 14001
certification for their respective environmental management systems.
OCCUPATIONAL HEALTH AND SAFETY
The combined effect of various State and Federal statutes requires an employer
to ensure that persons employed in a mine are safe from injury by providing a
safe working environment and systems of work; safety machinery; equipment, plant
and substances; and appropriate information, instruction, training and
supervision.
In recognition of the specialized nature of mining and mining activities,
specific occupational health and safety obligations have been mandated under
state legislation that deals specifically with the coal mining industry. Mining
employers, owners, directors and managers, persons in control of work places,
mine managers, supervisors and employees are all subject to these duties.
It is mandatory for an employer to have insurance coverage in respect of the
compensation of injured workers; similar schemes are in effect throughout
Australia which are of a no fault nature and which provide for benefits up to a
prescribed level. The specific benefits vary from jurisdiction to jurisdiction,
but generally include the payment of weekly compensation to an incapacitated
employee,
18
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.
Safety performance at the coal mining operations continues to be well below the
average for Australian open cut mines with annual independent audits conducted
of our safety management systems.
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, 22 states
and the District of Columbia have enacted programs leading to the deregulation
of the retail electricity market; 20 other states are considering such programs,
and the U.S. Congress is considering federal legislation. Due to the uncertainty
around timing and implementation of deregulation, it is difficult to predict the
impact on individual electric generators.
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 1999, 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 more
than one-half of all electricity produced in the United States last year.
Because of coal's 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.
Australia
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.
EMPLOYEES
As of March 31, 2000, we and our consolidated joint ventures had approximately
7,200 employees. Of these employees, approximately 5,900 worked in the United
States and 1,300 worked in foreign countries.
19
Approximately 39% of our United States coal employees are affiliated with
organized labor unions, which accounts for approximately 26% of the tons sold in
the United States during fiscal year 2000. 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. Negotiations for a successor labor agreement have not commenced. 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
United Mine Workers of America have stated that the union wishes to reopen the
National Bituminous Coal Wage Agreement, but no negotiations on a reopener have
commenced.
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 that
expires in October 2002. The miners at Ravensworth and Narama Mines have signed
a further enterprise labor agreement for two years that expires in May 2001. The
labor agreement for the Moura Mine is currently under negotiation.
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: Peabody Energy Corporation, 701 Market Street, Suite 700,
St. Louis, Missouri 63101, attention: Public Relations.
ITEM 2. PROPERTIES.
COAL RESERVES
We had an estimated 10.0 billion tons of proven and probable reserves as of
April 1, 2000, of which approximately 52% were low sulfur coal. We own
approximately 43% of these reserves and lease the remaining 57%.
Below is a table summarizing the locations and reserves of our major operating
units.
PROVEN AND PROBABLE
RESERVES AS OF APRIL 1, 2000(1)
(TONS IN MILLIONS)
---------------------------------------
OWNED LEASED TOTAL
OPERATING REGIONS LOCATIONS TONS TONS TONS
- -------------------------- ----------------------------------- --------- ---------- ---------
Powder River Basin Wyoming and Montana 244 3,234 3,478
Southwestern Arizona, Colorado and New Mexico 728 583 1,311
Appalachia West Virginia 315 510 825
Midwest Illinois, Indiana and Kentucky 3,028 877 3,905
Australia New South Wales and Queensland - 449 449
--------- ---------- ---------
Total 4,315 5,653 9,968
========= ========== =========
(1) Reserves have been adjusted to take into account losses involved in
producing a saleable product. The amounts include our share of reserves
in joint ventures.
20
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% of the gross
proceeds of coal mined and sold for surface mined coal and 8% 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 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. Development consent for Ravensworth East was received in March
2000, 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. The Moura lease is valid until 2019.
21
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 financial condition and results
of operations for a particular interim or annual period.
Navajo Nation
On June 18, 1999, The Navajo Nation served our subsidiaries, Peabody Holding
Company, Inc., Peabody Coal Company and Peabody Western Coal Company, with a
complaint that had been filed in the U. S. District Court for the District of
Columbia. Other defendants in the litigation are two utilities, two current
employees and one former employee. The Navajo Nation has alleged sixteen claims
including civil Racketeer Influenced and Corrupt Organizations Act, or RICO,
claims, fraud and tortious interference with contractual relationships. The
plaintiff is seeking various remedies including actual damages of at least $600
million which could be trebled under the RICO counts, punitive damages of at
least $1 billion, a determination that Peabody Western Coal Company's two coal
leases for the Kayenta and Black Mesa mines have terminated due to the failure
of a condition and a reformation of the two coal leases to adjust the royalty
rate to 20%. All defendants have filed a motion to dismiss the complaint.
In March 2000, the Hopi Tribe filed a motion to intervene in this lawsuit. The
Hopi Tribe has alleged seven claims, including fraud. The Hopi Tribe is seeking
various remedies, including unspecified actual and punitive damages, reformation
of its coal lease and a termination of the coal lease. The federal court has not
ruled on the Hopi Tribe's motion.
We believe this matter will be resolved without a material adverse effect on our
financial condition or results of operations.
Salt River Project Agricultural Improvement and Power District
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.
22
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 Arizona Court of Appeals ruled that
neither mine decommissioning costs nor retiree health care costs are to be
arbitrated and that both issues were to be resolved in litigation. The matter
has been remanded back to the Superior Court of Maricopa County, Arizona where a
trial has been set for April 2001.
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 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. Subsequent to the arbitration,
Seneca Coal Company and the Hayden Participants negotiated a termination of
their coal supply agreement and resolution of all outstanding disputes between
them. At that same time, the Hayden Participants negotiated a new coal supply
agreement with a term through 2011 with Peabody COALSALES Company, a company
affiliated with Seneca Coal Company.
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 had 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. Macquarie Generation abandoned any basis to a 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, which is scheduled to be heard in July 2000
by the New South Wales Court of Appeals. 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 a subsidiary of ours, subsequently merged into
Powder River Coal Company, had underpaid royalties owed to the federal
government. On October 15, 1999, we signed a settlement agreement with the
federal government on all civil claims related to the dispute. We paid $11.0
million in two installments, which was charged against a previously established
reserve.
23
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. The trial has been
set for April 2001.
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 10 sites and is a defendant in
litigation with private parties involving one site.
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 $57.7 million as of March 31, 2000 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. 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.
24
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
Not applicable.
ITEM 6. SELECTED FINANCIAL DATA.
Peabody Energy 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. See other
factors affecting the comparability of operating results in "Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations."
(Tons sold in millions, dollars in thousands) PREDECESSOR COMPANY
Period --------------------------------------------------------
From Period
May 20, From Six
Year 1998 to April 1, Year Months
Ended Total March 31, 1998 to Ended Ended Year Ended
March 31, Fiscal 1999 May 19, March 31, March 31, September 30,
2000(1) 1999(2) Restated(3) 1998 1998 1997 1996(4) 1995
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
RESULTS OF OPERATIONS DATA:
- ---------------------------
Revenues:
Sales $2,610,991 $2,249,887 $1,970,957 $ 278,930 $2,048,694 $1,000,419 $2,075,142 $2,087,656
Other Revenues 99,509 97,603 85,875 11,728 169,328 63,674 118,444 88,180
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Total Revenues 2,710,500 2,347,490 2,056,832 290,658 2,218,022 1,064,093 2,193,586 2,175,836
Operating Costs and
Expenses 2,517,263 2,181,121 1,899,788 281,333 1,957,210 961,998 2,844,882 1,930,224
---------- ---------- ---------- ---------- ---------- ---------- ---------- ----------
Operating Profit (Loss) $ 193,237 $ 166,369 $ 157,044 $ 9,325 $ 260,812 $ 102,095 $ (651,296) $ 245,612
========== ========== ========== ========== ========== ========== ========== ==========
Income (Loss) from
Continuing Operations $ 118,570 $ (3,193) $ (5,433) $ 2,240 $ 158,895 $ 58,432 $ (446,282) $ 100,387
========== ========== ========== ========== ========== ========== ========== ==========
Income (Loss) from
Discontinued Operation $ (90,360) $ 4,678 $ 6,442 $ (1,764) $ 1,441 $ - $ - $ -
========== ========== ========== ========== ========== ========== ========== ==========
Net Income (Loss) $ 28,210 $ 1,485 $ 1,009 $ 476 $ 160,336 $ 58,432 $ (446,282) $ 100,387
========== ========== ========== ========== ========== ========== ========== ==========
BALANCE SHEET DATA:
- -------------------
Working Capital $ (88,046) $ 486,953 $ 486,953 $ 374,492 $ 535,971 $ 167,076 $ (129,465) $ (104,310)
Total Assets 5,826,849 7,023,931 7,023,931 6,403,151 6,343,009 5,025,812 4,916,693 5,676,923
Recourse Debt 2,076,166 2,208,512 2,208,512 339,640 308,354 321,723 456,867 316,847
Non-Recourse Debt - 333,867 333,867 293,922 293,922 - - -
Stockholders'
Equity/Invested
Capital 508,426 495,230 495,230 1,497,374 1,687,842 1,676,786 1,383,655 1,650,975
OTHER DATA:
- -----------
Tons Sold 190.3 176.0 154.3 21.7 167.5 81.4 163.0 151.0
EBITDA(5) $ 443,019 $ 371,067 $ 336,226 $ 34,841 $ 460,981 $ 203,825 $ (453,443) $ 435,942
Net Cash Provided by (Used in):
Operating Activities 262,911 253,865 282,022 (28,157) 187,852 62,829 211,535 272,543
Investing Activities (185,384) (2,270,886) (2,249,336) (21,550) (136,033) (56,170) (105,640) (462,113)
Financing Activities (205,181) 2,184,818 2,161,281 23,537 (235,389) 94,178 15,987 178,993
Depreciation, Depletion
and Amortization 249,782 204,698 179,182 25,516 200,169 101,730 197,853 190,330
Capital Expenditures 178,754 195,394 174,520 20,874 165,514 76,460 152,106 188,006
(1) Results of operations for the year ended March 31, 2000 include $144.0
million of income tax benefit associated with an increase in the tax
basis of a subsidiary's assets due to a change in federal income tax
regulations, and reclassification of the results of operations and cash
flows of Citizens Power LLC to a discontinued operation.
(2) For comparative purposes, the "Total Fiscal 1999" column has been
derived from adding the period ended March 31, 1999 with the
Predecessor Company results for the period ended May 19, 1998. The
effects of purchase accounting have not been reflected in the results
of the Predecessor Company.
(3) Results of operations for the period from May 20, 1998 to March 31,
1999 include $13.1 million of compensation expense related to the grant
of 708,767 shares of Class B common stock to certain members of
management in conjunction with the May 19, 1998 acquisition of the
Predecessor Company.
(4) Results of operations for the year ended September 30, 1996 include a
one-time, non-cash charge of $890.8 million made pursuant to SFAS No.
121, which had no effect on the Company's cash flow.
(5) EBITDA is defined as income from continuing operations before deducting
net interest expense, income taxes and depreciation, depletion and
amortization. EBITDA has been reduced by costs associated with
reclamation, retiree health care and workers' compensation. EBITDA is
not a substitute for operating income, net income and cash flow from
operating activities as determined in accordance with generally
accepted accounting principles as a measure of profitability or
liquidity. EBITDA is presented as additional information because
management believes it to be a useful indicator of our ability to meet
debt service and capital expenditure requirements. Because EBITDA is
not calculated identically by all companies, the presentation herein
may not be comparable to similarly titled measures of other companies.
25
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
FACTORS AFFECTING COMPARABILITY
Discontinued Operations:
In May 2000, we signed a purchase and sale agreement with Edison Mission Energy
to sell Citizens Power, our subsidiary that markets and trades electric power
and energy-related commodity risk management products. The anticipated loss from
the sale of this subsidiary and the monetization of non-trading assets ($78.3
million, net of income taxes), has been reclassified in the results of
operations and cash flows as a discontinued operation for all periods presented.
The fair value of the net assets of Citizens Power has been reclassified to a
single line in the balance sheet entitled "Net assets of discontinued
operations" in the current year only.
Fiscal Year 2000 vs. Fiscal Year 1999:
Effective January 1, 2000, Black Beauty realigned its investment structure and
invested $6.6 million to increase its ownership interest to obtain control of
three of its Midwestern coal mining affiliates - Sugar Camp Coal, LLC (Sugar
Camp), Arclar Coal Company, LLC (Arclar) and United Minerals Company, LLC
(United Minerals). Prior to fiscal year 2000, interests in these affiliates were
accounted for under the equity method, as Black Beauty did not hold
decision-making control over their respective operations. However, effective
January 1, 2000, Black Beauty obtained decision-making control and began
consolidating the affiliates as of that date. In order to provide comparability
to future periods, we have elected to consolidate these affiliates as part of
Black Beauty's results of operations effective April 1, 1999.
The current year results also include the consolidated results of operations for
Black Beauty for 12 months as compared to only three months in fiscal 1999. We
increased our ownership interest in Black Beauty from 43.3% to 81.7% effective
January 1, 1999. We accounted for our interest in Black Beauty under the equity
method from April 1 to December 31, 1998.
Fiscal Year 1999 vs. Fiscal Year 1998:
The results of operations and cash flows for the period ended March 31, 1999
reflects our results from April 1 to March 31 (we acquired the Predecessor
Company on May 19, 1998 and prior to such date had no separate operations) and
the results of the Predecessor Company for April 1 to May 19, 1998. In addition,
the results of operations and cash flows for the period ended March 31, 1999 may
not be directly comparable to the other period indicated 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.
FISCAL YEAR ENDED MARCH 31, 2000 COMPARED WITH TOTAL FISCAL 1999
Sales. For fiscal year 2000, sales increased $361.1 million, or 16.0%, to $2.6
billion. The fiscal year results include an increase attributable to Black
Beauty of $428.9 million, which is principally comprised of two amounts - the
inclusion of Black Beauty's results for an entire year ($264.1 million), and the
consolidation of Sugar Camp, Arclar and United Minerals on a retroactive basis
($164.8 million). Sales in Australia increased $75.5 million over fiscal 1999,
mainly as a result of the acquisition of the Moura Mine in August 1999 ($46.3
million), the opening of the Bengalla Mine in fiscal year 2000 ($16.6 million)
and higher customer demand. Powder River sales increased $13.1 million, due
mainly to a continuing improvement in pricing for the ultra-low sulfur coal in
the Powder River Basin. Offsetting these increases were declines in the Midwest
and Appalachia markets of $68.1 million and $53.8 million, respectively. Both
regions were negatively impacted by mild winter weather that increased customer
coal stockpiles, causing lower demand and pricing. The Midwest region declined
primarily due to the closure and suspension of three high-sulfur mines in the
current year, while results in Appalachia were hampered by price reductions for
coal utilized by the export metallurgical market, and operating difficulties
related to longwall panel development delays and adverse geological conditions.
Finally, brokerage and trading revenues declined $33.5 million, mainly due to
expiring contracts.
Other Revenues. Other revenues improved $1.9 million compared to fiscal 1999.
This increase is primarily due to a $13.0 million gain from a contract
restructuring, as Black Beauty executed the buyout of a contract to provide
capacity to meet a new long-term coal supply agreement and a $3.9 million gain
on the settlement of a contract dispute in the fourth quarter of the current
year, partially offset by the exclusion of $7.5 million of equity income in
affiliates now consolidated by Black Beauty as discussed above. We cannot assure
you we will be able to realize similar gains from future coal contract
restructurings.
26
Selling and Administrative Expenses. Selling and administrative expenses
increased $6.4 million compared to fiscal 1999, to $95.3 million. This increase
is the result of the inclusion of a full year of Black Beauty's operations vs.
three months in the prior year (an increase of $9.9 million) and full year
consolidation of Black Beauty affiliates previously mentioned, partially offset
by $13.1 million of compensation expense in fiscal 1999 related to the grant of
708,767 shares of Class B common stock to certain members of management in
conjunction with the May 20, 1998 acquisition of the Predecessor Company.
Operating Profit. Operating profit was $193.2 million for the year ended March
31, 2000, an increase of $26.8 million, or 16.1%. The impact of Black Beauty on
the current year results increased operating profit $43.8 million, including a
$13.0 million gain from the Black Beauty contract restructuring previously
mentioned.
Other regions showing year-over-year improvement were the Midwest ($15.0
million), Powder River ($13.2 million), and Australia ($12.8 million). The
Midwest improved over the prior year as a result of lower reclamation costs
occurring from a change in permitting requirements in the current year ($5.1
million), improved productivity and higher volume at the ongoing Midwestern
operations, partially offset by lower volumes due to the closure/suspension of
three mines in the current year. Powder River improved profit based upon higher
pricing and higher demand for coal from our lowest cost, most efficient
operations in the Powder River Basin. Australia experienced higher volumes due
to higher customer demand, the contribution of results from the Moura Mine
acquisition and the new Bengalla Mine, and higher profit from additional
construction projects in the current year at their Mining Services division.
Offsetting these increases were decreases in Appalachia ($32.1 million) and
Southwest ($4.1 million). Profitability in Appalachia was directly impacted by
soft market conditions and higher costs as a result of longwall panel
development delays. The decline in the Southwest region is the result of higher
operating expenses, primarily as a result of higher repair and maintenance
expenses than in fiscal 1999, offset partially by higher volumes and a gain from
the settlement of a customer contractual dispute of $3.9 million. In addition,
income from brokerage and trading activities decreased $19.8 million, mainly as
a result of lower volumes that were directly related to contract expirations.
Finally, we experienced higher costs for past mining obligations due to the
current year cost of mine closure and suspension in the Midwest, and $6.4
million in higher administrative costs primarily as a result of the inclusion of
Black Beauty and its affiliates.
Interest Expense. Interest expense for the year ended March 31, 2000 was $205.1
million, an increase of $24.8 million, or 13.8%. Fiscal 1999 reflects
acquisition-related indebtedness from the May 19, 1998 acquisition date forward.
Also affecting the current year is the inclusion of $12.6 million of additional
interest associated with Black Beauty.
Interest Income. Interest income decreased $15.8 million from fiscal 1999, to
$4.4 million. The decrease is primarily attributable to interest income from
higher average cash balances held in fiscal 1999 in anticipation of the Black
Beauty acquisition that occurred late in the prior fiscal year.
Income Taxes. For fiscal year 2000, we recorded an income tax benefit of $141.5
million on a pretax loss from continuing operations of $7.4 million, compared to
income tax expense of $7.5 million on pretax income from continuing operations
of $6.2 million in fiscal 1999. The current year amount reflects a $144.0
million income tax benefit associated with an election to treat Peabody Natural
Resources Company, a subsidiary of ours, as a corporation rather than a
partnership for federal income tax purposes. This election, which became
available through a change in tax law that occurred in December 1999, resulted
in an increase in the tax basis in the entity's assets and eliminated the
necessity for a deferred tax liability that had reflected the excess of the book
basis in that subsidiary over the tax basis.
Our effective book income tax rate 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.
Loss From Discontinued Operations. In fiscal year 2000, the discontinued
operation had a net loss of $12.1 million, as compared to net income of $4.7
million in fiscal 1999. The decrease is largely the result of a decline in the
number of power contract restructuring transactions completed in fiscal year
2000 as compared to fiscal 1999. In addition, the current year includes the
estimated after-tax loss on disposal of Citizens Power of $78.3 million.
27
TOTAL FISCAL 1999 COMPARED WITH FISCAL YEAR ENDED MARCH 31, 1998
Sales. For fiscal 1999, sales increased 9.8%, or $201.2 million, over the prior
twelve-month period. Excluding Black Beauty's results, sales increased $120.5
million, or 5.9%. 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% increase in sales volume from continued growth in demand for coal from this
region, while Southern Appalachia sales volumes improved 13.0%, 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 $71.7 million to $97.6 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. 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 $94.4 million to
$166.4 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; $13.1 million of
compensation expense associated with the grant of 708,767 shares of Class B
common stock to certain members of management in conjunction with the May 20,
1998 acquisition of the Predecessor Company; $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 $146.9 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 income tax provision for fiscal 1999 exceeded our pretax
income from continuing operations. 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.
Income From Discontinued Operations. Income from discontinued operations was
$4.7 million in fiscal 1999, as compared to income of $1.4 million in fiscal
year 1998. This increase is primarily related to a higher volume of asset
restructuring transactions in the current year, and higher income from trading
activities.
28
LIQUIDITY AND CAPITAL RESOURCES
For fiscal year 2000, net cash provided by operating activities was $262.9
million, which includes $100.0 million in proceeds from the securitization of a
portion of our trade accounts receivable in March 2000, and favorable cash flow
from operations during the year. In March 2000, we completed a transaction to
establish an accounts receivable securitization facility with a multi-seller
commercial paper conduit. Proceeds from the transaction totaled $100.0 million
and were applied to the repayment of long-term debt discussed above. The
facility is supported by $100.0 million in 364-day back-up bank lines that are
available to purchase accounts receivable if the conduit is unable to access
commercial paper markets. We pay funding costs based on the discount or yield
accrued on conduit commercial paper plus certain fees and expenses.
Accounts receivable decreased $159.7 million from the prior year, primarily due
to the $100.0 million sale of receivables discussed above, and the
reclassification of Citizens Power's accounts receivable to "Net assets of
discontinued operations."
Assets from power trading activities and liabilities from power trading
activities were reduced to zero in the current year as a result of the
reclassification of Citizens Power to a discontinued operation.
Assets from coal and emission allowance activities and liabilities from coal and
emission allowance activities were $78.7 million and $75.9 million,
respectively, as of March 31, 2000. The increase in these amounts is directly
related to higher volumes of coal and emission allowance trading in the current
year, as we have substantially increased our coal and emission allowance trading
activity to respond to changes and opportunities in the deregulated electricity
market.
Deferred income taxes decreased $155.1 million compared to March 31, 1999. This
decrease is primarily the result of the previously mentioned income tax benefit.
Net cash used in investing activities was $185.4 million, primarily consisting
of $63.3 million in acquisitions during the year, including $30.2 million for
the Moura Mine and $8.0 million for an additional 3% interest in the Bengalla
Mine in Australia, and $25.1 million related to several smaller mines purchased
by Black Beauty. We also had $178.8 million of capital expenditures, a decrease
of $16.6 million from fiscal 1999. We had $110.5 million of committed capital
expenditures (primarily related to coal reserves and mining machinery) at March
31, 2000. It is anticipated these capital expenditures will be funded through
available cash and credit facilities which are discussed in more detail below.
Net cash used in financing activities was $205.2 million, as compared to
$2,184.8 million of cash provided by financing activities in fiscal 1999. In
fiscal year 2000, we reduced total debt by $466.2 million after considering the
reclassification of $333.9 million of Citizens Power's debt to "Net assets of
discontinued operations." The remaining decrease in total debt of $132.3 million
relates to debt repayments during the current year of $210.0 million ($150.0
million of optional prepayments and other debt repayments of $60.0 million),
partially offset by an additional $48.5 million of long-term debt related to
previously unconsolidated affiliates of Black Beauty. Fiscal 1999 reflects a
$480.0 million capital contribution and $1,817.4 million in borrowings to fund
the acquisition of our Predecessor Company.
29
As of March 31, 2000, we had total indebtedness of $2,076.2 million, consisting
of the following:
(In millions)
Term loans under Senior Credit Facilities $ 690.0
9.625% Senior Subordinated Notes due 2008 ("Senior
Subordinated Notes") 498.7
8.875% Senior Notes due 2008 ("Senior Notes") 398.9
5.0% Subordinated Note 180.3
Senior unsecured notes under various agreements 99.3
Project finance facility 76.5
Capital lease obligations 27.9
Other 104.6
--------
$2,076.2
========
The following table sets forth the mandatory prepayments of our indebtedness as
of March 31, 2000:
(In millions)
Senior 5.0%
Fiscal Year Credit Facilities Subordinated Note Other Total
------------------- ----------------- ----------------- ------------ ------------
2001 $ 20.0 $ 38.1 $ 58.1
2002 20.0 77.5 97.5
2003 20.0 41.7 61.7
2004 $ 85.0 20.0 38.8 143.8
2005 69.0 20.0 25.5 114.5
2006 and thereafter 536.0 140.0 924.6 1,600.6
----------------- ----------------- ------------ ------------
$690.0 $240.0 $1,146.2 $2,076.2
================= ================= ============ ============
The Senior Credit Facilities include a Revolving Credit Facility that provides
for aggregate borrowings of up to $200 million and letters of credit of up to
$280 million. The Revolving Credit Facility commitment matures in fiscal year
2005. We had no borrowings outstanding under the Revolving Credit Facility
during fiscal year 2000 or 1999. 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% on $300 million of such
long-term debt for a period of three years ending October 1, 2001, and on $200
million of such long-term debt for two years ending October 1, 2000. As a
result, 72% of amounts outstanding under the Senior Credit Facilities are fixed
at approximately 7.0% as of March 31, 2000.
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.
30
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). We were in compliance
with all of the restrictive covenants of our loan agreements as of March 31,
2000.
Certain of our subsidiaries maintain short term lines and other working capital
borrowing facilities. Total commitments under such subsidiary facilities totaled
$167 million and borrowings thereunder totaled $55 million at March 31, 2000. In
addition, certain of our subsidiaries have long-term debt outstanding under
various agreements. These agreements contain certain customary restrictive
covenants including limitations on additional debt, dividends and investments.
OTHER
Mine Closure. In October 1999, we suspended operations at our Marissa Operating
Unit in Illinois. The Marissa Operating Unit, which shipped 4.4 million tons of
coal in fiscal 1999, had attempted to secure additional business after its
principal customer began shifting its supply to lower-sulfur coal from our
Powder River operations. These efforts were unsuccessful, and as a result the
mine was closed in December 1999. We do not anticipate a material adverse impact
on our results of operations or financial position from the mine closure.
Mine Suspensions. In addition, we suspended operations at our Lynnville and
Hawthorn mines in Indiana in December 1999. The suspension of operations at
these locations is not anticipated to materially affect the consolidated results
of operations or financial position, as the primary customers of these mines
have signed long-term coal supply agreements and will receive coal from another
Peabody affiliate, Black Beauty. We periodically evaluate the possibility of
suspending other mines due to market conditions. Such suspensions, if any, are
not expected to have a material adverse impact on our results of operations or
financial condition.
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. The Financial Accounting
Standards Board also issued SFAS No. 137, which defers the effective date of
SFAS No. 133 to all fiscal quarters of fiscal years beginning after June 15,
2000 (effective April 1, 2001 for us). We are evaluating the requirements of
SFAS No. 133 and have not determined the impact of adoption on the consolidated
financial statements.
Year 2000 Issue. The "Year 2000 Issue" is a term used to describe the problems
created by 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.
We have not experienced any significant impact on our systems or operations as a
result of the Year 2000 Issue. The total cost incurred to prepare for the Year
2000 Issue was approximately $6.4 million, which includes $2.3 million for the
purchase of new software and hardware that was capitalized and $4.1 million that
was expensed as incurred.
In addition, we have not encountered any significant problems with third parties
such as our customers, suppliers, service providers and other business partners.
However, if these or other third parties with which we conduct business
experience lingering Year 2000 Issues, we could experience a material adverse
impact on our results of operations and financial position.
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 those
factors listed under "Risk Factors" and:
31
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; and the ability to
successfully implement operating strategies.
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 year 2000, 86% of our sales volume was sold under coal supply agreements.
At March 31, 2000, our coal supply agreements had terms ranging from one to 16
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 gains of $13.0 million, $5.3
million and $49.3 million in fiscal years 2000, 1999 and 1998, respectively. 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, some 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 year 2000, we derived 27% of our total coal revenues from sales to our
5 largest customers, under 13 coal supply agreements that expire in various
years from 2000 to 2014. We are currently engaged in discussions with several of
these 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.
32
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.
33
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 emission 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 began in 2000 and applies 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 limits nitrogen oxide emissions from new,
significantly modified or reconstructed boilers to amounts per megawatt- hour of
gross electric output. The rule requires 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 emission targets for developed nations. Although
the specific limits vary from country to country, the United States would be
required to reduce emissions to 93% of 1990 levels over a five-year budget
period from 2008 through 2012.
34
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 10 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 $57.7 million as of March 31, 2000 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.
35
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% 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% 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 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 and private leases,
producing properties and continued exploitation of 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 North
Antelope/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 2000, 86% 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 debt service 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.
36
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 39% of Peabody's and our joint venture's United States coal
employees, who accounted for 26% of our tons sold in the United States in fiscal
year 2000, 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 our current non-union operations were to become
unionized, we could incur an increased risk of work stoppages, reduced
productivity and higher labor costs. The ten month 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 October 2002. Peabody Resources' Ravensworth and
Narama mines entered into two-year labor agreements in May 1999. The labor
agreement for the Moura Mine is currently under negotiation. 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, 2000, we had
outstanding surety bonds with third parties for post- mining reclamation
totaling $529.1 million. Furthermore, surety bonds valued at an additional $78.7
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, 2000, had total indebtedness of
$2,076.2 million, of which (1) $690.0 million consisted of indebtedness under
the senior credit facilities, (2) $398.9 million of senior notes, (3) $498.7
million of senior subordinated notes, (4) a $180.3 million, 5% coupon
subordinated note, (5) $193.7 million in borrowings of Black Beauty and (5)
$111.5 million in borrowings by our Australian subsidiary, including $76.5
million to fund the development of the Bengalla Mine. In addition, we had
available borrowings of up to $312.1 million under our revolving credit
facilities. We and our Restricted Subsidiaries are permitted to incur additional
indebtedness in the future.
37
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. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
TRADING ACTIVITIES
We market and trade coal, emission allowances and energy-related commodities. We
also market and trade electric power and energy-related commodities and provide
services to the electric power industry through our subsidiary, Citizens Power,
which as previously discussed is no longer a component of continuing operations.
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.
Coal and emission allowance trading is 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 86% of our sales volume was sold under long-term coal
supply agreements in fiscal year 2000.
38
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, 2000, we had $1.2 billion of fixed-rate borrowings
and approximately $874 million of variable-rate borrowings outstanding. To
minimize our exposure to changes in interest rates, we have entered into two
interest rate swaps in the United States with a total notional amount of $500
million, and one interest rate swap in Australia with notional amount of $74
million.
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 $212 million, after considering $215
million of existing foreign exchange contracts, has been subjected to an assumed
10% appreciation and 10% 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. The resulting foreign
exchange gain or loss would be approximately $21 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 $3.0 million on our variable-rate
borrowings. With respect to our fixed-rate borrowings, a one-percentage point
increase in interest rates would result in a $12.9 million decrease in the fair
value of such borrowings.
39
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
Index to Financial Statements and Supplementary Data
Page
----
Report of Independent Auditors 41
Audited Financial Statements:
Statements of Operations - Year ended March 31, 2000, periods ended March
31, 1999 and May 19, 1998 and year ended March 31, 1998 42
Balance Sheets - March 31, 2000 and 1999 43
Statements of Cash Flows - Year ended March 31, 2000, periods ended March
31, 1999 and May 19, 1998 and year ended March 31, 1998 44
Statements of Changes in Stockholders' Equity/Invested Capital - Year
ended March 31, 2000, periods ended March 31, 1999 and May 19, 1998 and
year ended March 31, 1998 45
Notes to Financial Statements 46
40
Report of Independent Auditors
Board of Directors
Peabody Energy Corporation
We have audited the accompanying consolidated balance sheets of Peabody Energy
Corporation (the Company) as of March 31, 2000 and 1999, and the related
consolidated statements of operations, changes in stockholders' equity and cash
flows of the Company for the year and period then ended. We have also audited
the combined statements of operations, changes in invested capital and cash
flows of P&L Coal Group (the Predecessor Company) for the period ended May 19,
1998 and the year ended March 31, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion the financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Peabody Energy
Corporation at March 31, 2000 and 1999, the consolidated results of operations
and cash flows of the Company for the year ended March 31, 2000 and 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 and the year ended
March 31, 1998 in conformity with accounting principles generally accepted in
the United States.
As discussed more fully in Note 15, the Company has recalculated and restated
stock compensation expense related to Class B common stock granted during the
period ended March 31, 1999.
Ernst & Young LLP
April 27, 2000, except
for the restatement related
to stock compensation
referred to in Note 15 as
to which the date is April
20, 2001
St. Louis, Missouri
41
PEABODY ENERGY CORPORATION
STATEMENTS OF OPERATIONS
(Dollars in thousands)
PREDECESSOR COMPANY
Period Ended ------------------------------
Year Ended March 31, 1999 Period Ended Year Ended
March 31, 2000 Restated May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
REVENUES
Sales $2,610,991 $1,970,957 $278,930 $2,048,694
Other revenues 99,509 85,875 11,728 169,328
---------- ---------- -------- ----------
Total revenues 2,710,500 2,056,832 290,658 2,218,022
OPERATING COSTS AND EXPENSES
Operating costs and expenses 2,178,664 1,643,718 244,128 1,695,216
Depreciation, depletion and amortization 249,782 179,182 25,516 200,169
Selling and administrative expenses 95,256 76,888 12,017 83,640
Net gain on property and
equipment disposals (6,439) - (328) (21,815)
---------- ---------- -------- ----------
OPERATING PROFIT 193,237 157,044 9,325 260,812
Interest expense 205,056 176,105 4,222 33,410
Interest income (4,421) (18,527) (1,667) (14,543)
---------- ---------- -------- ----------
INCOME (LOSS) BEFORE INCOME TAXES
AND MINORITY INTERESTS (7,398) (534) 6,770 241,945
Income tax provision (benefit) (141,522) 3,012 4,530 83,050
Minority interests 15,554 1,887 - -
---------- ---------- -------- ----------
INCOME (LOSS) FROM CONTINUING OPERATIONS 118,570 (5,433) 2,240 158,895
Discontinued operations:
(Income) loss from discontinued operations,
net of income tax provision (benefit) of ($1,297),
$6,035, ($189) and $7,143, respectively 12,087 (6,442) 1,764 (1,441)
Loss from disposal of discontinued operations,
net of income tax benefit of $31,188 78,273 - - -
---------- ---------- -------- ----------
NET INCOME $ 28,210 $ 1,009 $ 476 $ 160,336
========== ========== ======== ==========
See accompanying notes to financial statements.
42
PEABODY ENERGY CORPORATION
BALANCE SHEETS
AS OF MARCH 31
(Dollars in thousands)
1999
2000 Restated
---------- ----------
ASSETS
Current assets
Cash and cash equivalents $ 65,618 $ 194,078
Accounts receivable, less allowance of $1,233 and $177, respectively 153,021 312,748
Materials and supplies 48,809 53,978
Coal inventory 193,341 195,919
Assets from power trading activities - 1,037,300
Assets from coal and emission allowance trading activities 78,695 2,514
Deferred income taxes 49,869 8,496
Other current assets 43,192 27,428
---------- ----------
Total current assets 632,545 1,832,461
Property, plant, equipment and mine development
Land and coal interests 4,135,010 4,023,546
Building and improvements 350,284 316,163
Machinery and equipment 741,486 651,728
Less accumulated depreciation, depletion and amortization (411,270) (193,492)
---------- ----------
Property, plant, equipment and mine development, net 4,815,510 4,797,945
Net assets of discontinued operations 90,000 -
Investments and other assets 288,794 393,525
---------- ----------
Total assets $5,826,849 $7,023,931
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Short-term borrowings and current maturities of long-term debt $ 57,977 $ 72,404
Income taxes payable 13,594 7,308
Liabilities from power trading activities - 638,062
Liabilities from coal and emission allowance trading activities 75,883 12
Accounts payable and accrued expenses 573,137 627,722
---------- ----------
Total current liabilities 720,591 1,345,508
Long-term debt, less current maturities 2,018,189 2,469,975
Deferred income taxes 625,124 780,175
Accrued reclamation and other environmental liabilities 502,092 498,032
Workers' compensation obligations 212,260 207,544
Accrued postretirement benefit costs 971,186 956,714
Obligation to industry fund 64,737 63,107
Other noncurrent liabilities 162,979 183,736
---------- ----------
Total liabilities 5,277,158 6,504,791
Minority interests 41,265 23,910
Stockholders' equity
Preferred stock - $0.01 per share par value; 10,000,000 shares authorized,
5,000,000 shares issued and outstanding as of March 31, 2000 and 1999 50 50
Common stock - Class A, $0.01 per share par value; 30,000,000 shares authorized,
19,000,000 shares issued and outstanding as of March 31, 2000 and 1999 190 190
Common stock - Class B, $0.01 per share par value; 3,000,000 shares authorized,
746,329 shares issued and 684,473 shares outstanding as of March 31, 2000; 3,000,000
shares authorized and 708,767 shares issued and outstanding as of March 31, 1999 7 7
Additional paid-in capital 494,237 493,972
Employee stock loans (2,391) (2,331)
Accumulated other comprehensive income (loss) (12,667) 2,333
Retained earnings 29,219 1,009
Treasury shares, at cost: 61,856 Class B shares as of March 31, 2000 (219) -
---------- ----------
Total stockholders' equity 508,426 495,230
---------- ----------
Total liabilities and stockholders' equity $5,826,849 $7,023,931
========== ==========
See accompanying notes to financial statements.
43
PEABODY ENERGY CORPORATION
STATEMENTS OF CASH FLOWS
(Dollars in thousands)
PREDECESSOR COMPANY
Period Ended ------------------------------
Year Ended March 31, 1999 Period Ended Year Ended
March 31, 2000 Restated May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 28,210 $ 1,009 $ 476 $160,336
(Income) loss from discontinued operations 12,087 (6,442) 1,764 (1,441)
Loss from disposal of discontinued operations 78,273 - - -
-------- ---------- -------- --------
Income from continuing operations 118,570 (5,433) 2,240 158,895
Adjustments to reconcile income from continuing operations
to net cash provided by (used in) continuing operations:
Depreciation, depletion and amortization 249,782 179,182 25,516 200,169
Deferred income taxes (157,803) (679) 2,835 65,508
Amortization of debt discount and debt issuance costs 18,911 16,120 1,379 11,205
Net gain on property and equipment disposals (6,439) - (328) (21,815)
Gain on coal contract restructurings (12,957) (5,300) - (49,270)
Stock compensation - 13,124 - -
Minority interests 15,554 1,887 - -
Changes in current assets and liabilities, excluding
effects of acquisitions:
Sale of accounts receivable 100,000 - - -
Accounts receivable, net of sale 18,712 20,164 (9,768) (18,622)
Materials and supplies 5,227 3,620 881 (438)
Coal inventory 10,774 5,781 (2,807) (16,160)
Net assets from coal and emission allowance trading
activities (310) - - -
Other current assets (16,862) 7,459 (10,707) (10,607)
Accounts payable and accrued expenses (15,064) (50,373) (34,685) (3,226)
Income taxes payable 7,549 173 1,234 (12,447)
Accrued reclamation and related liabilities (18,233) (4,468) (1,622) (18,509)
Workers' compensation obligations 4,716 (10,449) (2,156) (23,106)
Accrued postretirement benefit costs 14,472 6,094 6,092 15,292
Obligation to industry fund 1,630 (3,619) (2,379) (26,771)
Royalty prepayment - 135,903 - -
Other, net (34,814) 21,737 (5,586) 16,932
-------- ---------- -------- --------
Net cash provided by (used in) continuing operations 303,415 330,923 (29,861) 267,030
Net cash provided by (used in) discontinued operations (40,504) (48,901) 1,704 (79,178)
-------- ---------- -------- --------
Net cash provided by (used in) operating activities 262,911 282,022 (28,157) 187,852
-------- ---------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant, equipment and mine development (178,754) (174,520) (20,874) (165,514)
Additions to advance mining royalties (25,292) (11,509) (2,302) (6,174)
Acquisitions, net (63,265) (2,110,400) - (58,715)
Investment in joint venture (4,325) - - -
Proceeds from coal contract restructurings 32,904 2,515 328 57,460
Proceeds from property and equipment disposals 19,284 11,448 1,374 37,723
Proceeds from sale-leaseback transactions 34,234 - - -
-------- ---------- -------- --------
Net cash used in continuing operations (185,214) (2,282,466) (21,474) (135,220)
Net cash provided by (used in) discontinued operations (170) 33,130 (76) (813)
-------- ---------- -------- --------
Net cash used in investing activities (185,384) (2,249,336) (21,550) (136,033)
-------- ---------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowings and long-term debt 22,026 1,870,778 53,597 269,391
Payments of short-term borrowings and long-term debt (209,985) (222,715) (19,423) (350,737)
Capital contribution - 480,000 - -
Distributions to minority interests (3,353) (3,080) - -
Dividends paid - - (173,330) (65,109)
Transactions with affiliates:
Loan to affiliate - - - (141,000)
Proceeds from affiliated loan - - 141,000 -
Advances from affiliates - - - 16,882
Repayments to affiliates - (3,647) - -
Invested capital transactions with affiliates - (30,369) - (55,176)
-------- ---------- -------- --------
Net cash provided by (used in) continuing operations (191,312) 2,090,967 1,844 (325,749)
Net cash provided by (used in) discontinued operations (13,869) 70,314 21,693 90,360
-------- ---------- -------- --------
Net cash provided by (used in) financing activities (205,181) 2,161,281 23,537 (235,389)
Effect of exchange rate changes on cash and cash equivalents (806) 111 (292) (718)
-------- ---------- -------- --------
Net increase (decrease) in cash and cash equivalents (128,460) 194,078 (26,462) (184,288)
Cash and cash equivalents at beginning of period 194,078 - 96,821 281,109
-------- ---------- -------- --------
Cash and cash equivalents at end of period $ 65,618 $ 194,078 $ 70,359 $ 96,821
======== ========== ======== ========
See accompanying notes to financial statements.
44
PEABODY ENERGY CORPORATION
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY / INVESTED CAPITAL
(Dollars in thousands)
Accumulated
Other
Compre-
Additional Employee hensive
Preferred Common Paid-in Stock Income
Stock Stock Capital Loans (Loss)
--------- ------ ---------- -------- -----------
PREDECESSOR COMPANY
- -------------------
March 31, 1997 $ - $ - $ - $ - $ (2,799)
Comprehensive income:
Net income - - - - -
Foreign currency
translation adjustment - - - - (39,385)
Comprehensive income
Dividend paid - - - - -
Net transactions
with affiliates - - - - -
---- ---- -------- ------- --------
March 31, 1998 - - - - (42,184)
Comprehensive loss:
Net income - - - - -
Foreign currency
translation adjustment - - - - (17,974)
Comprehensive loss
Dividend paid - - - - -
Net transactions
with affiliates - - - - -
---- ---- -------- ------- --------
May 19, 1998 $ - $ - $ - $ - $(60,158)
==== ==== ======== ======= ========
- ---------------------------------------------------------------------------------------------------------------------------------
May 20, 1998 $ - $ - $ - $ - $ -
Capital contribution 50 190 479,760 - -
Comprehensive income:
Net income - - - - -
Foreign currency
translation adjustment - - - - 4,128
Minimum pension liability
(net of $1,248 tax provision) - - - - (1,795)
Comprehensive income
Stock grants to employees - 5 13,119 (1,236) -
Stock purchases
by employees - 2 1,093 (1,095) -
---- ---- -------- ------- --------
March 31, 1999 (restated) 50 197 493,972 (2,331) 2,333
Comprehensive income:
Net income - - - - -
Foreign currency
translation adjustment - - - - (16,795)
Minimum pension liability
(net of $1,248 tax benefit) - - - - 1,795
Comprehensive income
Stock grants to employees - - 265 (103) -
Loan repayments - - - 901 -
Additional loans - - - (858) -
Shares repurchased - - - - -
---- ---- -------- ------- --------
March 31, 2000 $ 50 $197 $494,237 $(2,391) $(12,667)
==== ==== ======== ======= ========
Total
Stockholders'
Retained Invested Treasury Equity / Invested
Earnings Capital Stock Capital
-------- ---------- -------- -----------------
PREDECESSOR COMPANY
- -------------------
March 31, 1997 $ - $1,679,585 $ - $1,676,786
Comprehensive income:
Net income - 160,336 - 160,336
Foreign currency
translation adjustment - - - (39,385)
----------
Comprehensive income 120,951
Dividend paid - (65,109) - (65,109)
Net transactions
with affiliates - (44,786) - (44,786)
------- ---------- ----- ----------
March 31, 1998 - 1,730,026 - 1,687,842
Comprehensive loss:
Net income - 476 - 476
Foreign currency
translation adjustment - - - (17,974)
----------
Comprehensive loss (17,498)
Dividend paid - (173,330) - (173,330)
Net transactions
with affiliates - 360 - 360
------- ---------- ----- ----------
May 19, 1998 $ - $1,557,532 $ - $1,497,374
======= ========== ===== ==========
- ---------------------------------------------------------------------------------------------------------------
May 20, 1998 $ - $ - $ - $ -
Capital contribution - - - 480,000
Comprehensive income:
Net income 1,009 - - 1,009
Foreign currency
translation adjustment - - - 4,128
Minimum pension liability
(net of $1,248 tax provision) - - - (1,795)
----------
Comprehensive income 3,342
Stock grants to employees - - - 11,888
Stock purchases
by employees - - - -
------- ---------- ----- ----------
March 31, 1999 (restated) 1,009 - - 495,230
Comprehensive income:
Net income 28,210 - - 28,210
Foreign currency
translation adjustment - - - (16,795)
Minimum pension liability
(net of $1,248 tax benefit) - - - 1,795
----------
Comprehensive income 13,210
Stock grants to employees - - - 162
Loan repayments - - - 901
Additional loans - - - (858)
Shares repurchased - - (219) (219)
------- ---------- ----- ----------
March 31, 2000 $29,219 $ - $(219) $ 508,426
======= ========== ===== ==========
See accompanying notes to financial statements.
45
PEABODY ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS, EXCEPT WHERE NOTED AND PER SHARE DATA)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF PRESENTATION
The consolidated financial statements include the consolidated balance
sheets of Peabody Energy Corporation (the "Company" or "Peabody") as of
March 31, 2000 and 1999, and the consolidated results of operations and
cash flows for the year ended March 31, 2000 and the period ended March 31,
1999. These financial statements include the subsidiaries (collectively,
known as the "Predecessor Company") of Peabody Holding Company, Inc.
("Peabody Holding Company"), Gold Fields Mining Corporation ("Gold Fields")
which owns Lee Ranch Coal Company ("Lee Ranch"), Citizens Power LLC
("Citizens Power") and Peabody Resources Limited ("Peabody Resources"), an
Australian company. The combined financial statements include the combined
results of operations and cash flows of the Predecessor Company from April
1, 1998 to May 19, 1998 and the fiscal year ended March 31, 1998.
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 Brothers Merchant Banking Partners II L.P.
and its affiliates ("Lehman Brothers 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. Peabody Energy Corporation,
a holding company with no direct operations and nominal assets other than
its investment in its subsidiaries, was formed by Lehman Brothers Merchant
Banking on February 27, 1998 for the purpose of acquiring the Predecessor
Company and had no significant activity until the acquisition.
Subsequent to March 31, 2000, the Company signed a purchase and sale
agreement with Edison Mission Energy to sell Citizens Power (see note 3).
Results of operations and cash flows have been restated for all periods
presented to properly reflect the discontinued operation.
DESCRIPTION OF BUSINESS
The Company is principally engaged in the mining of coal for sale primarily
to electric utilities. The Company also markets and trades coal and
emission allowances.
NEW PRONOUNCEMENTS
Effective April 1, 1998, the Company adopted Statement of
Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income." SFAS No. 130 requires that noncash changes
in stockholders' equity be combined with net income and reported
in a new financial statement category entitled "accumulated other
comprehensive income."
The Company also adopted SFAS No. 131, "Disclosures About Segments
of an Enterprise and Related Information," and SFAS No. 132,
"Employers' Disclosures About Pensions and Other Postretirement
Benefits" effective April 1, 1998. SFAS No. 131 and SFAS No. 132
address the disclosures required for the Company's operating
segments and employee benefit obligations, respectively.
The adoption of SFAS Nos. 130, 131 and 132 had no effect on the
Company's 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.
The financial statements include the following asset and operating amounts
for Australian entities utilizing pro rata consolidation:
PREDECESSOR COMPANY
------------------------------
Year Ended Period Ended Period Ended Year Ended
March 31, 2000 March 31, 1999 May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
Total revenue $122,689 $ 72,057 $10,996 $76,406
Operating profit 17,038 18,767 3,695 17,731
Total assets 149,864 189,363
46
Notes (continued)
ACCOUNTING FOR COAL AND EMISSION ALLOWANCE TRADING
The Company engages in risk management activities for both trading and
non-trading purposes. Activities for trading purposes, generally consisting
of coal and emission allowance trading, are accounted for using the fair
value method. Under such method, the derivative commodity instruments
(forwards, options and swaps) with third parties are reflected at market
value and are included in "Assets and liabilities from coal and emission
allowance trading activities" in the consolidated balance sheets. In the
absence of quoted values, financial commodity instruments are valued at
fair value, considering the net present value of the underlying sales and
purchase obligations, volatility of the underlying commodity, appropriate
reserves for market and credit risks and other factors, as determined by
management. Subsequent changes in market value are recognized as gains or
losses in "Other revenues" in the period of change.
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 and
certain commodity supplies. The Company's Australian operations use forward
currency contracts to manage their exposure against foreign currency
fluctuations on sales denominated in U.S. dollars. These financial
instruments are accounted for using the deferral method. Changes in the
market value of these transactions are deferred until the gain or loss on
the underlying hedged item is recognized as part of the related sales
transaction. If the future sale is no longer anticipated, the changes in
market value of the forward currency contracts would be recognized as an
adjustment to revenue in the period of change.
A portion of the Company's long-term indebtedness bears interest at rates
that fluctuate based upon certain indices. The Company utilizes financial
instruments, such as interest rate swap agreements, to mitigate the impact
of changes in interest rates on a portion of its floating rate debt. Gains
or losses on interest rate swap agreements are recognized as they occur and
are included as a component of interest expense.
As a writer of options, the Company receives a premium where the option is
written and then bears the risk of unfavorable changes in the price of the
financial instruments underlying the option. Forwards, swaps and
over-the-counter options are traded in unregulated markets.
Over-the-counter forwards, options and swaps are either liquidated with the
same counterparty or held to settlement date. For these financial
instruments, the unrealized gains or losses on financial settlements,
rather than the contract amounts, represent the approximate future cash
requirements. Realized gains and losses on trading activities are recorded
as part of "Other revenues" as they occur. Physical settlements are
recorded on a gross basis within "Sales" and "Operating costs and
expenses."
REVENUE RECOGNITION
The Company incurs certain "add-on" taxes and fees on coal sales. Coal
sales are reported including taxes and fees charged by various federal and
state governmental bodies. The Company recognizes revenue from coal sales
when title passes to the customer.
OTHER REVENUES
Other revenues include royalties related to coal lease agreements, earnings
and losses from joint ventures, management fees, farm income, contract
restructuring payments, coal trading activities and revenues from contract
mining services. Royalty income generally results from the lease or
sub-lease of mineral rights to third parties, with payments based upon a
percentage of the selling price or an amount per ton of coal produced.
Certain agreements require minimum annual lease payments regardless of the
extent to which minerals are produced from the leasehold. The terms of
these agreements generally range from specified periods of 5 to 20 years,
or can be for an unspecified period until all reserves are depleted.
Revenues from coal trading activities are recognized for the differences
between contract and market prices.
47
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 original
maturities of three months or less.
INVENTORIES
Materials and supplies and coal inventory are valued at the lower of
average cost or market. Coal inventory costs include labor, supplies,
equipment costs, operating overhead and other related costs.
PROPERTY, PLANT, EQUIPMENT AND MINE DEVELOPMENT
Property, plant, equipment and mine development are recorded at cost.
Interest costs applicable to major asset additions are capitalized during
the construction period, including $1.8 million for the year ended March
31, 2000, $3.0 million for the period ended March 31, 1999, $0.2 million
for the period ended May 19, 1998 and $1.5 million for the year ended March
31, 1998.
Expenditures which extend the useful lives of existing plant and equipment
are capitalized. Maintenance and repairs are charged to operating costs and
expensed 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 interests is computed using the units-of- production
method utilizing only proven and probable reserves in the depletion base.
Mine development costs are principally amortized over the estimated lives
of the mines using the straight-line method. Depreciation of plant and
equipment (excluding life of mine assets) is computed using the straight-
line method over the estimated useful lives as follows:
Years
-----
Building and improvements 10 to 20
Machinery and equipment 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 24 years.
ACCRUED RECLAMATION AND OTHER ENVIRONMENTAL LIABILITIES
The Company records a liability for the estimated costs to reclaim land as
the acreage is disturbed during the ongoing surface mining process. The
estimated costs to reclaim support acreage and to perform other related
functions at both surface and underground mines are recorded ratably over
the lives of the mines. As of March 31, 2000, the Company had $529.1
million in surety bonds outstanding and $19.4 million in letters of credit
to secure reclamation. 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
was $186.1 million and $240.5 million at March 31, 2000 and March 31, 1999,
respectively.
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 they extend the life
of the asset, mitigate environmental contamination that has yet to occur,
or are incurred in preparing an asset for sale.
48
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, coal and emission allowance trading and risk
management activities give rise to market risk, which represents the
potential loss caused by a change in the market value of a particular
commitment. Market risks are actively monitored to ensure compliance with
the risk management policies of the Company. Policies are in place that
limit the Company's total net exposure at any point in time. Procedures
exist which allow for monitoring of all commitments and positions, with
daily reporting to senior management.
The Company's concentration of credit risk is substantially with
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. Counterparty risk with respect to interest rate swap
transactions is not considered to be significant based upon the
creditworthiness of the participating financial institutions.
Approximately 39 percent of the Company's U.S. coal employees are
affiliated with organized labor unions, which accounts for approximately 26
percent of the tons sold in the U.S. during fiscal year 2000. Hourly
workers at the Company's mines in Arizona, Colorado and Montana are
represented by the United Mine Workers' of America under the Western
Surface Agreement, which was ratified in 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 that expires in October 2002. The miners at Ravensworth and
Narama Mines have signed a further enterprise labor agreement for two years
that expires in May 2001. The labor agreement for the Moura Mine is
currently under negotiation.
USE OF ESTIMATES IN THE PREPARATION OF THE FINANCIAL STATEMENTS
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
IMPAIRMENT OF LONG-LIVED ASSETS
The Company records impairment losses on long-lived assets used in
operations when events and circumstances indicate that the assets might be
impaired and the undiscounted cash flows estimated to be generated by those
assets under various assumptions are less than the carrying amounts of
those assets. Impairment losses are measured by comparing the estimated
fair value of the assets to their carrying amount.
49
Notes (continued)
FOREIGN CURRENCY TRANSLATION
Assets and liabilities of foreign affiliates are generally translated at
current exchange rates, and related translation adjustments are reported as
a component of comprehensive income. Income statement accounts are
translated at an average rate for each period.
RECLASSIFICATIONS
Certain amounts in prior periods have been reclassified to conform with the
report classifications of the year ended March 31, 2000, with no effect on
previously reported net income or stockholders' equity.
(2) BUSINESS COMBINATIONS
Peabody Resources
Effective August 20, 1999, Peabody Resources purchased a 55 percent
interest in the Moura Mine in Queensland, Australia for $30.2 million. The
acquisition was accounted for as a purchase and the operating results have
been included in the Company's financial statements since the date of
acquisition using pro rata consolidation. The acquisition includes the coal
mining and coalbed methane operations, along with 67 million tons of
saleable coal reserves and rights to more than 1.9 billion tons in place
surface and underground coal resources.
Black Beauty Coal Company
Effective January 1, 2000, Black Beauty Coal Company ("Black Beauty"), a
subsidiary of the Company, invested $6.6 million to increase its ownership
interest and obtain control of three of its Midwestern coal mining
affiliates - Sugar Camp Coal, LLC, Arclar Coal Company, LLC and United
Minerals Company, LLC. Prior to fiscal year 2000, interests in these
affiliates were accounted for under the equity method, as Black Beauty did
not hold decision- making control over their respective operations.
However, effective January 1, 2000, Black Beauty obtained decision-making
control and began consolidating the affiliates as of that date. In order to
provide comparability to future periods, the Company has elected to
consolidate these affiliates as part of Black Beauty's results of
operations effective April 1, 1999.
Effective January 1, 1999, the Company purchased an additional 38.3 percent
interest in 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.
Effective January 1, 1998, 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.
P&L Coal Group
The acquisition of Peabody Group by the Company on May 19, 1998 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
Brothers 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 was accounted for under the purchase method of accounting.
50
Notes (continued)
The following unaudited pro forma results of operations assumed the
acquisitions had occurred as of April 1:
2000 1999
---------- ----------
Total revenues $2,728,694 $2,765,979
Loss before income taxes, minority interests
and discontinued operations (6,278) (1,464)
Net income (loss) 28,916 (8,964)
(3) DISCONTINUED OPERATIONS
Subsequent to March 31, 2000, the Company signed a purchase and sale
agreement with Edison Mission Energy to sell Citizens Power, its
wholly-owned subsidiary that engages in power trading and power contract
restructuring transactions. The estimated loss on disposal of the entity is
$109.5 million on a pretax basis ($78.3 million after-tax), which includes
a provision for estimated operating losses until disposal and estimated
proceeds from the monetization of non-trading assets concurrent with the
disposal of Citizens Power. The Company expects to complete the disposal
before the end of the next fiscal year.
The results of operations of Citizens Power have been reported separately
as a discontinued operation in the statements of operations for all periods
presented, and are summarized as follows:
PREDECESSOR COMPANY
------------------------------
Year Ended Period Ended Period Ended Year Ended
March 31, 2000 March 31, 1999 May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
Revenues $ 17,225 $37,394 $ 1,750 $26,440
Income (loss) before income taxes (13,369) 12,477 (1,953) 8,584
Income tax provision (benefit) (1,297) 6,035 (189) 7,143
Net income (loss) from discontinued
operations (12,087) 6,442 (1,764) 1,441
The fair value of net assets related to the discontinued operation have
been segregated in the March 31, 2000 consolidated balance sheet and
include the following:
Cash $ 41,222
Accounts receivable 46,339
Assets from power trading activities 908,256
Liabilities from power trading activities (524,366)
Other current liabilities (75,701)
Non-recourse debt (305,750)
--------
$ 90,000
========
(4) ACCOUNTS RECEIVABLE SECURITIZATION
In March 2000, the Company and a wholly-owned subsidiary ("Seller") entered
into agreements with certain financial institutions to establish a
five-year receivables purchase facility. Under the facility, up to $100.0
million of beneficial interests in accounts receivable that have been
contributed to the Seller may be sold, without recourse, to a commercial
paper conduit ("Conduit"). Under the provisions of SFAS No. 125,
"Accounting for Transfers and Servicing of
51
Notes (continued)
Financial Assets and Extinguishments of Liabilities," the transaction was
recorded as a sale, with those accounts receivable sold to the Conduit
removed from the consolidated balance sheet. The Seller is a separate legal
entity and its assets are available first and foremost to satisfy the
claims of its creditors.
As of March 31, 2000, $100.0 million in beneficial interests were sold to
the Conduit under the facility. The Seller also maintained a subordinated
interest in $20.5 million of remaining accounts receivable under the terms
of the facility. Proceeds from the sale were used to repay long-term debt.
(5) COAL INVENTORY
Coal inventory consisted of the following as of March 31:
2000 1999
-------- --------
Saleable coal $ 41,047 $ 50,293
Raw coal 18,400 23,299
Work in process 133,894 122,327
-------- --------
$193,341 $195,919
======== ========
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.
(6) LEASES
The Company leases equipment and facilities under various noncancelable
lease agreements. Certain lease agreements require the maintenance of
specified ratios and contain restrictive covenants which limit
indebtedness, subsidiary dividends, investments, asset sales and other
Company actions. Rental expense under operating leases was $39.7 million
for the year ended March 31, 2000, $34.6 million for the period ended March
31, 1999, $5.4 million for the period ended May 19, 1998 and $39.9 million
for the year ended March 31, 1998. The cost of property, plant, equipment
and mine development assets acquired under capital leases was $31.2 million
and $34.8 million at March 31, 2000 and 1999, respectively. The related
accumulated amortization was $6.3 million and $2.2 million at March 31,
2000 and 1999, respectively.
The Company also leases coal reserves under agreements that require
royalties to be paid as the coal is mined. Total royalty expense was $164.2
million for the year ended March 31, 2000, $123.2 million for the period
ended March 31, 1999, $17.3 million for the period ended May 19, 1998 and
$132.9 million for the year ended March 31, 1998. 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 which it mines in Wyoming, Montana and Colorado under terms set by
Congress and administered by the U.S. Bureau of Land Management. The terms
of these leases are generally for an initial term of ten years but may be
extended by diligent development and mining of the reserve until all
economically recoverable reserves are depleted. The Company has met the
diligent development requirements for substantially all of these federal
leases either directly through production or by including the lease as a
part of a logical mining unit with other leases upon which development has
occurred. Annual production on these federal leases must total at least 1
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 a 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
52
Notes (continued)
varies greatly. Typically, the lease terms are automatically extended as
long as active mining continues. Royalty payments are generally based upon
a specified rate per ton or a percentage of the gross realization from the
sale of the coal.
In fiscal year 2000, the Company sold certain assets for $34.2 million and
those assets were leased back under operating lease agreements from the
purchasers over a period of seven to 13 years. No gains were recognized on
these transactions. Each lease agreement contains renewal options at lease
termination and purchase options at amounts approximating fair market value
during the lease and at lease termination.
Future minimum lease and royalty payments as of March 31, 2000 are as
follows:
Capital Operating Coal
Fiscal Year Ending March 31 Leases Leases Reserves
----------------------------- ------- --------- --------
2001 $ 6,873 $ 51,394 $ 38,559
2002 3,641 47,399 33,201
2003 3,560 41,473 31,407
2004 4,081 36,674 31,007
2005 2,378 30,988 8,930
2006 and thereafter 16,245 64,147 33,935
------- -------- --------
Total minimum lease payments 36,778 $272,075 $177,039
======== ========
Less interest 8,919
-------
Present value of minimum
capital lease payments $27,859
=======
53
Nptes (continued)
(7) ACCOUNTS PAYABLE AND ACCRUED EXPENSES
Accounts payable and accrued expenses consisted of the following as of
March 31:
2000 1999
-------- --------
Trade accounts payable $180,682 $211,993
Accrued payroll and related benefits 85,281 71,508
Accrued taxes other than income 76,841 77,839
Accrued health care 62,127 63,422
Accrued interest 46,166 41,219
Workers' compensation obligations 35,246 38,542
Accrued royalties 18,624 22,425
Accrued lease payments 11,188 11,536
Other accrued expenses 56,982 89,238
-------- --------
Total accounts payable and accrued expenses $573,137 $627,722
======== ========
(8) INCOME TAXES
Pretax income (loss) from continuing operations consisted of:
PREDECESSOR COMPANY
-----------------------------
Year Ended Period Ended Period Ended Year Ended
March 31, 2000 March 31, 1999 May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
Pretax income (loss) from
continuing operations:
United States $(49,550) $(32,142) $4,134 $199,300
Non U.S. 42,152 31,608 2,636 42,645
-------- -------- ------ --------
$ (7,398) $ (534) $6,770 $241,945
======== ======== ====== ========
54
Notes (continued)
Total income tax provision (benefit) from continuing operations consisted
of:
PREDECESSOR COMPANY
------------------------------
Year Ended Period Ended Period Ended Year Ended
March 31, 2000 March 31, 1999 May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
Current:
U.S. federal $ - $ - $ - $ -
Non U.S. 16,224 9,700 1,427 21,001
State 57 26 79 3,684
--------- ------- ------ -------
Total current 16,281 9,726 1,506 24,685
--------- ------- ------ -------
Deferred:
U.S. federal (124,807) (8,309) 1,904 61,288
Non U.S. (4,037) 2,026 - (5,457)
State (28,959) (431) 1,120 2,534
--------- ------- ------ -------
Total deferred (157,803) (6,714) 3,024 58,365
--------- ------- ------ -------
Total provision (benefit) $(141,522) $ 3,012 $4,530 $83,050
========= ======= ====== =======
The deferred tax benefit for the year ended March 31, 2000 includes the
effect of a change in tax regulations and statutes in the current period
which allowed the Company to make a tax election to treat a wholly owned
partnership as a corporation. The election eliminated a $144.0 million
deferred tax liability previously recognized pursuant to the provisions of
SFAS No. 109 on the "outside tax basis," which represents the tax effected
difference between the book value and the tax basis of the investment in
the partnership interest. The election allowed the Company to treat the
partnership as a corporation and look to the "inside tax basis," which
represents the tax effected difference between the book value of the assets
and liabilities recorded on the balance sheet of the partnership and the
tax basis of the individual assets and liabilities. The Company recognized
deferred tax benefit of $144.0 million in the year ended March 31, 2000
related to this election.
The non U.S. tax deferred tax provision includes a benefit of $3.2 million
due to changes in the Australian tax rate from 36 percent to 34 percent
effective April 1, 2000. In addition, the Australian rate is scheduled to
change to 30 percent effective April 1, 2001.
55
Notes (continued)
The income tax rate on income (loss) from continuing operations differed
from the U.S. federal statutory rate as follows:
PREDECESSOR COMPANY
-------------------------------
Year Ended Period Ended Period Ended Year Ended
March 31, 2000 March 31, 1999 May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
Federal statutory rate $ (2,590) $ (187) $2,369 $84,681
Changes in valuation allowance 31,907 16,386 6,012 14,280
Partnership tax basis election (144,028) - - -
Foreign earnings (2,566) 676 506 1,002
State income taxes, net of U.S. federal
tax benefit (6,458) (3,391) 2,881 4,047
Depletion (26,151) (13,320) (2,182) (20,794)
Other, net 8,364 2,848 (5,056) (166)
--------- ------- ------ -------
$(141,522) $ 3,012 $4,530 $83,050
========= ======= ====== =======
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:
2000 1999
---------- ----------
Deferred tax assets:
Accrued long-term reclamation and mine closing liabilities $ 107,854 $ 104,777
Accrued long-term workers' compensation liabilities 92,778 99,776
Postretirement benefit obligations 402,747 401,994
Intangible tax asset and purchased contract rights 168,092 164,239
Tax credits and loss carryforwards 155,626 84,862
Obligation to industry fund 26,169 39,389
Others 136,471 79,986
---------- ----------
Total gross deferred tax assets 1,089,737 975,023
---------- ----------
Deferred tax liabilities:
Property, plant, equipment and mine development, principally due to
differences in depreciation, depletion and asset writedowns 1,385,195 1,226,002
Long-term debt, principally due to amortization of debt discount 24,704 19,756
Others 150,047 432,026
---------- ----------
Total gross deferred tax liabilities 1,559,946 1,677,784
---------- ----------
Valuation allowance (105,046) (68,918)
---------- ----------
Net deferred tax liability $ (575,255) $ (771,679)
========== ==========
56
Notes (continued)
Deferred taxes consisted of the following as of March 31:
2000 1999
--------- ---------
Current deferred income taxes $ 49,869 $ 8,496
Noncurrent deferred income taxes (625,124) (780,175)
--------- ---------
Net deferred tax liability $(575,255) $(771,679)
========= =========
The Company's deferred tax assets include alternative minimum tax ("AMT")
credits of $50.6 million and net operating loss ("NOL") carryforwards of
$105.0 million at March 31, 2000. The AMT credits have no expiration date
and the NOL carryforwards expire beginning in the year 2019. The AMT
credits and NOL carryforwards are offset by a valuation allowance of $105.0
million.
The Company made U.S. federal tax payments totaling $0.3 million for the
year ended March 31, 2000 and $0.1 million for the year ended March 31,
1998. No payments for U.S. federal taxes were made for the periods ended
March 31, 1999 or May 19, 1998. The Company paid state and local income
taxes totaling $0.6 million for the year ended March 31, 2000, $0.7 million
for the period ended March 31, 1999 and $0.8 million for the year ended
March 31, 1998. No state or local income tax payments were made for the
period ended May 19, 1998.
Non U.S. tax payments were $8.8 million for the year ended March 31, 2000,
$11.9 million for the period ended March 31, 1999, $0.3 million for the
period ended May 19, 1998 and $18.3 million for the year ended March 31,
1998.
(9) SHORT-TERM BORROWINGS
Short-term borrowings were $9.9 million and $9.5 million at March 31, 2000
and 1999, respectively.
The Company maintains a Revolving Credit Facility that provides for
aggregate borrowings of up to $200.0 million and letters of credit of up to
$280.0 million. During the period ended March 31, 2000, 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 8.9 percent at March 31, 2000. The Revolving Credit Facility
commitment matures in fiscal 2005.
At March 31, 2000, Peabody Resources maintained four 365-day corporate debt
facilities with several banks totaling $110.0 million in Australian dollars
(approximately $66.7 million in 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, 2000, $9.9 million was outstanding and the effective
annual interest rate was 6.0 percent.
The amount of interest paid was $2.1 million for the year ended March 31,
2000, $1.4 million for the period ended March 31, 1999, $0.2 million for
the period ended May 19, 1998 and $1.8 million for the year ended March 31,
1998.
57
Notes (continued)
(10) LONG-TERM DEBT
Long-term debt consisted of the following as of March 31:
2000 1999
---------- ----------
Term loans under Senior Credit Facilities $ 690,000 $ 840,000
9.625% Senior Subordinated Notes
("Senior Subordinated Notes") due 2008 498,747 498,649
8.875% Senior Notes ("Senior Notes") due 2008 398,971 398,887
Non-Recourse Debt (see note 3) - 333,867
5.0% Subordinated Note 180,335 190,567
Senior unsecured notes under various agreements 99,286 107,143
Project finance facility 76,539 66,588
Unsecured revolving credit agreement 44,721 45,400
Capital lease obligations 27,859 26,881
Other 49,773 24,876
---------- ----------
Total long-term debt 2,066,231 2,532,858
Less current maturities (48,042) (62,883)
---------- ----------
Long-term debt, less current maturities $2,018,189 $2,469,975
========== ==========
The Senior Credit Facilities are secured by a first priority lien on
certain assets of the Company and its domestic subsidiaries. During fiscal
2000, the Company made optional prepayments of $150.0 million on the Senior
Credit Facilities, which it applied against mandatory Term Loan A and B
payments in order of maturity.
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.
The Company maintains 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 ending
October 1, 2001, and on $200.0 million of such long-term debt for two years
ending October 1, 2000. The Company also has an interest rate swap
agreement to fix the interest cost on 90 percent of the project finance
facility for a period of ten years ending December 2010 at a fixed rate of
6.75 percent.
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. At March 31, 2000, restricted net assets of the Company's
consolidated subsidiaries was $634.6 million.
58
Notes (continued)
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 2001 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 $39.3 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 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
$76.5 million and $66.6 million as of March 31, 2000 and 1999,
respectively, with an effective annual interest rate of 6.75 percent.
At March 31, 2000, Black Beauty maintained a $100.0 million revolving
credit facility with several banks that matures on February 28, 2002. Black
Beauty may elect one or a combination of interest rates on its borrowings;
the effective annual interest rate was 6.7 percent at March 31, 2000.
Borrowings outstanding at March 31, 2000 were $44.7 million. Quarterly
commitment fees are paid on the unused portion of the facility at a 0.15
percent rate.
Capital lease obligations are payable in installments through 2008 with a
weighted average effective interest rate of 5.9 percent. Other, principally
notes payable, is due in installments through 2005 with a weighted average
effective interest rate of 7.9 percent.
The aggregate amounts of long-term debt maturities subsequent to March 31,
2000 are as follows:
2001 $ 48,042
2002 97,461
2003 61,741
2004 143,817
2005 114,533
2006 and thereafter 1,600,637
----------
$2,066,231
==========
The amount of interest paid was $196.9 million for the year ended March 31,
2000, $138.8 million for the period ended March 31, 1999, $0.5 million for
the period ended May 19, 1998 and $44.6 million for the year ended March
31, 1998.
59
Notes (continued)
(11) WORKERS' COMPENSATION OBLIGATIONS
The workers' compensation obligations consisted of the following as of
March 31:
2000 1999
-------- --------
Occupational disease costs $156,729 $154,311
Traumatic injury claims 89,355 90,361
State assessment taxes 1,422 1,414
-------- --------
Total obligations 247,506 246,086
Less current portion (35,246) (38,542)
-------- --------
Noncurrent obligations $212,260 $207,544
======== ========
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, 2000, the Company had $78.7 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 $12.0 million
for the year ended March 31, 2000, a charge of $11.1 million for the period
ended March 31, 1999, a benefit of $0.4 million for the period ended May
19, 1998 and a benefit of $9.4 million for the year ended March 31, 1998.
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, 2000 were based on a 7.125 percent per annum interest discount
rate and a 3.5 percent estimate for the annual rate of inflation, and 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. Traumatic injury workers' compensation obligations are estimated
from both case reserves and actuarial determinations of historical trends,
discounted at approximately 7.125 and 7.25 percent per annum at March 31,
2000 and 1999, respectively.
60
Notes (continued)
(12) 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:
PREDECESSOR COMPANY
-------------------------------
Year Ended Period Ended Period Ended Year Ended
March 31, 2000 March 31, 1999 May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
Service cost for benefits earned $ 9,773 $ 9,098 $2,323 $10,282
Interest cost on projected
benefit obligation 34,389 29,640 7,543 33,095
Expected return on plan assets (42,691) (48,546) (9,125) (50,755)
Other amortizations and deferrals (455) 12,083 - 16,135
------- ------- ------ -------
Net periodic pension costs $ 1,016 $ 2,275 $ 741 $ 8,757
======= ======= ====== =======
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 the year ended March
31, 1998 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, a charge
of $0.6 million was recognized during the year ended March 31, 1998, in
accordance with SFAS No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination
Benefits."
61
Notes (continued)
The following summarizes the change in benefit obligation, change in plan
assets and funded status of the Company's plans:
2000 1999
-------- --------
Change in benefit obligation:
Benefit obligation at beginning of year $492,867 $496,037
Service cost 9,773 9,098
Interest cost 34,389 29,640
Plan amendments - (5,803)
Benefits paid (28,506) (23,235)
Curtailments - (20,701)
Actuarial (gain) loss (49,328) 7,831
-------- --------
Benefit obligation at end of year 459,195 492,867
-------- --------
Change in plan assets:
Fair value of plan assets at beginning of year 474,385 473,922
Actual return on plan assets 60,375 18,296
Employer contributions 1,522 5,402
Benefits paid (28,506) (23,235)
-------- --------
Fair value of plan assets at end of year 507,776 474,385
-------- --------
Funded status 48,581 (18,482)
Unrecognized actuarial (gain) loss (54,773) 12,262
Unrecognized prior service cost (benefit) (5,205) (5,683)
-------- --------
Accrued pension expense $(11,397) $(11,903)
======== ========
Amounts recognized in the balance sheets:
Prepaid benefit cost $ 2,832 $ 488
Accrued benefit liability (14,229) (15,434)
Additional minimum pension liability - 3,043
-------- --------
Net amount recognized $(11,397) $(11,903)
======== ========
As of March 31, 2000, the only pension plans with accumulated benefit
obligation in excess of plan assets were the unfunded supplemental
retirement plans. The projected benefit obligation and accumulated benefit
obligation for those plans were $13.2 million and $13.0 million,
respectively. The projected benefit obligation, accumulated benefit
obligation, and the 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.
The provisions of SFAS No. 87, "Employers' Accounting for Pensions,"
require the recognition of an additional minimum liability and related
intangible asset to the extent that accumulated benefits exceed plan
assets. As of March 31, 2000, the Company's pension plans' assets exceeded
the accumulated benefit obligation and therefore no additional minimum
liability was recorded. The $3.0 million adjustment recorded as of March
31, 1999, relating to the plans' underfunded status, was reversed in the
current year.
62
Notes (continued)
The assumptions used to determine the above projected benefit obligation at
the end of each fiscal period were as follows:
March 31, March 31,
2000 1999
--------- ---------
Discount rate 8.1% 7.125%
Rate of compensation increase 4.25% 3.75%
Expected rate of return on plan assets 9.0% 9.0%
Certain subsidiaries make contributions to multiemployer pension plans,
which provide defined benefits to substantially all hourly coal production
workers represented by the United Mine Workers of America other than those
covered by the Western Plan. Benefits under the United Mine Workers of
America plans are computed based on service with the subsidiaries or other
signatory employers. The amounts contributed to the plans and included in
operating costs were $0.3 million for the year ended March 31, 2000, $1.1
million for the period ended March 31, 1999, $0.6 million for the period
ended May 19, 1998 and $4.9 million for the year ended March 31, 1998.
The Company sponsors savings and long-term investment plans for eligible
salaried U.S. employees. The Company matches between 50.0 and 75.0 percent
of voluntary contributions up to a maximum matching contribution between
3.0 and 4.5 percent of a participant's salary. Effective January 1, 2001,
the Company will increase the matching contribution to a maximum of 6.0
percent of a participant's salary. The expense for these plans was $4.2
million for the year ended March 31, 2000, $4.1 million for the period
ended March 31, 1999, $0.6 million for the period ended May 19, 1998 and
$4.2 million for the year ended March 31, 1998.
The amount contributed and expensed by Peabody Resources to superannuation
funds was $5.1 million for the year ended March 31, 2000, $0.9 million for
the period ended March 31, 1999, $0.4 million for the period ended May 19,
1998 and $2.9 million for the year ended March 31, 1998.
(13) 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.
Net periodic postretirement benefits costs for each fiscal period included
the following components:
PREDECESSOR COMPANY
------------------------------
Year Ended Period Ended Period Ended Year Ended
March 31, 2000 March 31, 1999 May 19, 1998 March 31, 1998
-------------- -------------- ------------ --------------
Service cost for benefits earned $ 4,835 $ 4,750 $ 897 $ 6,569
Interest cost on accumulated
postretirement benefit obligation 70,029 60,519 10,075 69,614
Prior service cost amortization (2,488) (625) (242) (10,071)
------- ------- ------- -------
Net periodic postretirement
benefit costs $72,376 $64,644 $10,730 $66,112
======= ======= ======= =======
63
Notes (continued)
The following table sets forth the plans' combined funded status reconciled
with the amounts shown in the balance sheets:
2000 1999
----------- -----------
Change in benefit obligation:
Benefit obligation at beginning of year $ 1,008,702 $ 995,265
Service cost 4,835 4,750
Interest cost 70,029 60,519
Plan amendments (1,097) (21,777)
Benefits paid (57,586) (49,088)
Actuarial (gain) loss (60,503) 19,033
----------- -----------
Benefit obligation at end of year 964,380 1,008,702
----------- -----------
Change in plan assets:
Fair value of plan assets at beginning of year - -
Employer contributions 57,586 49,088
Benefits paid (57,586) (49,088)
----------- -----------
Fair value of plan assets at end of year - -
----------- -----------
Funded status (964,380) (1,008,702)
Unrecognized actuarial (gain) loss (41,420) 19,076
Unrecognized prior service cost (20,386) (21,777)
----------- -----------
Accrued postretirement benefit obligation $(1,026,186) $(1,011,403)
=========== ===========
The assumptions used to determine the accumulated postretirement benefit
obligation at the end of each fiscal period were as follows:
March 31, 2000 March 31, 1999
------------------ ------------------
Discount rate 8.1% 7.125%
Salary increase rate for life insurance benefit 4.25% 3.75%
Health care trend rate:
Pre-65 6.95% down to 6.95% down to
4.75% over 4 years 4.75% over 4 years
Post-65 6.13% down to 6.13% down to
4.75% over 4 years 4.75% over 4 years
Medicare 5.68% down to 5.68% down to
4.75% over 4 years 4.75% over 4 years
Assumed health care cost trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage-point change in
the assumed health care cost trend would have the following effects:
One-Percentage- One-Percentage-
Point Increase Point Decrease
--------------- ---------------
Effect on total service and interest cost components $ 9,648 $ (9,213)
Effect on postretirement benefit obligation $123,238 $(103,059)
64
Notes (continued)
Retirees formerly employed by certain subsidiaries and their predecessors,
who were members of the United Mine Workers of America, last worked before
January 1, 1976 and were receiving health benefits on July 20, 1992,
receive health benefits provided by the Combined Fund, a fund created by
the Coal Industry Retiree Health Benefit Act of 1992 (the "Coal Act"). The
Coal Act requires former employers (including certain subsidiaries of the
Company) and their affiliates to contribute to the Combined Fund according
to a formula. In addition, certain Federal Abandoned Mine Lands funds will
be used to pay benefits to orphaned retirees through 2004.
The Company has recorded an actuarially determined liability representing
the amounts anticipated to be due for the Combined Fund. The "Obligation to
industry fund" reflected in the balance sheets at March 31, 2000 and 1999
was $64.7 million and $63.1 million, respectively. The current portion
related to this obligation reflected in "Accounts payable and accrued
expenses" in the balance sheets at March 31, 2000 and 1999 was $5.1 million
and $9.2 million, respectively.
Expense of $2.6 million was recognized for the period ended March 31, 2000
which includes interest discount of $4.8 million, net of the amortization
of an actuarial gain of $2.2 million. Expense of $4.5 million was
recognized for the period ended March 31, 1999 due to the interest discount
accrual. A benefit of $0.9 million was recognized for the period ended May
19, 1998 which included amortization of an actuarial gain of $1.7 million,
net of the interest discount accrual of $0.8 million. 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.
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 $1.7 million for the year ended March 31, 2000, $0.7
million for the period ended March 31, 1999, $0.2 million for the period
ended May 19, 1998 and $4.5 million for the year ended March 31, 1998.
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, 2000 of $103.7 million. The surety bonds
represent security for the postretirement liability included on the balance
sheets.
In October 1999, Powder River announced changes in its medical plan for
active employees and retirees. Employees who retired prior to December 31,
1999 were not affected by these changes. The changes included: 90/10
coinsurance, maximum out-of-pocket limits, copay for prescription drugs and
mandatory generic drug usage. The effect of the change on the salaried
retiree health care liability is $1.1 million. Powder River is recognizing
the effect of the plan amendment over nine years.
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 year ended March 31, 2000 and the three
months ended March 31, 1999 was $2.5 million and $0.6 million,
respectively.
65
Notes (continued)
(14) RESTRUCTURING LIABILITY
In conjunction with the acquisition of P&L Coal Group, the Company
established a $39.4 million liability for estimated costs associated with a
restructuring plan resulting from the business combination. The estimate
was comprised of costs associated with exiting certain activities ("exit
plan") and consolidating and restructuring certain management and
administrative functions ("restructuring plan") and included costs
resulting from a plan to terminate or relocate employees. Costs associated
with the restructuring and exit plans have been charged against the
liability as incurred. The total costs charged against the liability were
$6.4 million for the year ended March 31, 2000 and $28.8 million for the
period ended March 31, 1999, of which $3.6 million represented noncash
charges associated with the exit plan for the period ended March 31, 1999.
The exit plan was completed in the third quarter of fiscal year 2000 and
the liability was reduced by $3.8 million at that time to reflect the most
recent cost estimates. This amount was recorded as an adjustment to the
cost of the acquisition. The majority of the adjustment related to lower
exit plan costs than originally estimated. The $0.3 million remaining
liability relates to residual spending, including continuing lease costs at
administrative offices that were vacated as part of the restructuring plan.
If the ultimate amount of cost expended is less than the $0.3 million
remaining liability, the cost of the acquisition will be further reduced.
The following table displays a rollforward of the restructuring liability
from the acquisition date to March 31, 2000:
Adjustment to
May 19, 1998 March 31, 1999 Cost of March 31, 2000
Balance Charges Balance Charges Acquisition Balance
------------ -------- -------------- ------- ------------- --------------
Restructuring plan $26,154 $(20,536) $ 5,618 $(4,409) $ (880) $329
Exit plan 13,214 (8,296) 4,918 (1,995) (2,923) -
------- -------- ------- ------- ------- ----
Total $39,368 $(28,832) $10,536 $(6,404) $(3,803) $329
======= ======== ======= ======= ======= ====
(15) 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.
During the period ended March 31, 1999 the Company granted 708,767 shares
to members of management of the Company. The Company recorded compensation
expense of $3.9 million related to the grant of the shares. The statements
of operations, changes in stockholders' equity and cash flows have been
restated for the period ended March 31, 1999 to record additional
compensation expense of $9.2 million for the difference between the value
of Class B common stock as determined by an independent valuation of $7.08
per share, and the price paid for Class A shares of $20.00 per share. Net
income for the period ended March 31, 1999 of $10.2 million was restated to
$1.0 million.
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.
66
Notes (continued)
During the year ended March 31, 2000, the Company granted 201,625 options
to purchase Class A common stock, 58,153 of which are incentive stock
options that vest at a rate of 20 percent for five years (incentive
options) and 143,472 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 (performance
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 options and 2,863,988 are performance options.
A summary of the outstanding options is as follows:
Weighted Average
Weighted Average Fair Value of
Shares Exercise Price Options Granted
--------- ---------------- ----------------
Beginning balance at May 19, 1998 -
Granted 3,795,873 $20.00 $6.60
Exercised - -
Forfeited - -
---------
Outstanding at March 31, 1999 3,795,873 20.00
Granted 201,625 20.00 6.60
Exercised - -
Forfeited (307,828) 20.00
---------
Outstanding at March 31, 2000 3,689,670 $20.00
========= ======
Options exercisable at:
March 31, 2000 348,589 $20.00
March 31, 1999 - -
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 minimum value method set forth under SFAS No. 123,
"Accounting for Stock- Based Compensation," the Company's net income would
have decreased by approximately $3.4 million and $3.3 million for the year
ended March 31, 2000 and the period ended March 31, 1999, respectively.
The weighted average fair value of options granted was $6.60 for fiscal
years 2000 and 1999. The fair value of fiscal year 2000 and 1999 options
granted was estimated on each respective grant date using the following
assumptions: a risk-free interest rate of 5.7 percent, an expected life of
seven years and a dividend yield of zero percent. The weighted average
remaining contractual life of options outstanding as of March 31, 2000 was
8.3 years.
67
Notes (continued)
(16) COMPREHENSIVE INCOME
The after-tax components of accumulated other comprehensive income (loss)
are as follows:
Total Accumulated
Foreign Currency Minimum Pension Other Comprehensive
Translation Adjustment Liability Adjustment Income/(Loss)
---------------------- -------------------- -------------------
PREDECESSOR COMPANY
-------------------
Beginning balance March 31, 1997 $ (2,799) $ - $ (2,799)
Current period change (39,385) - (39,385)
-------- ------- --------
Ending balance March 31, 1998 (42,184) - (42,184)
Current period change (17,974) - (17,974)
-------- ------- --------
Ending balance May 19, 1998 $(60,158) $ - $(60,158)
======== ======= ========
------------------------------------------------------------------------------------------------------------------
Beginning balance May 20, 1998 $ - $ - $ -
Current period change 4,128 (1,795) 2,333
-------- ------- --------
Ending balance March 31, 1999 4,128 (1,795) 2,333
Current period change (16,795) 1,795 (15,000)
-------- ------- --------
Ending balance March 31, 2000 $(12,667) $ - $(12,667)
======== ======= ========
The foreign currency translation adjustments are not currently adjusted for
income taxes since they relate to indefinite investments in non-U.S.
subsidiaries.
(17) RELATED PARTY TRANSACTIONS
For the year ended March 31, 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.
(18) 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 $13.0 million for the year ended March 31, 2000, $5.3
million for the period ended March 31, 1999 and $49.3 million for the year
ended March 31, 1998. There were no gains related to coal supply agreement
terminations for the period ended May 19, 1998.
(19) FINANCIAL INSTRUMENTS WITH OFF-BALANCE-SHEET RISK
The Company owns a 30.0 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 from a commercial bank. The Company's
reimbursement obligation to the commercial bank is in turn supported by a
letter of credit totaling $42.8 million.
In December 1999, the Company entered into a 49.0 percent interest in a
joint venture to develop and rehabilitate an underground mine and prep
plant facility. The partners have jointly and severally agreed to guarantee
the $28.8 million five-
68
Notes (continued)
year financing agreement provided by two commercial banks of which 49.0
percent ($14.1 million) is guaranteed by the Company. Principal payments
are due beginning December 1, 2000 at $0.3 million for 48 months with a
final principal payment of $14.4 million due December 2005. Interest
payments are due monthly and accrue at prime, which was 9.0 percent at
March 31, 2000.
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) of ($13.9 million) for the year ended March 31, 2000, $16.2
million for the period ended March 31, 1999, $33.6 million for the period
ended May 19, 1998 and ($17.3 million) for the year ended March 31, 1998.
The Company had forward currency contracts outstanding at March 31, 2000
and 1999 of $215.0 million and $217.1 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.
(20) 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.
The carrying amounts and estimated fair values of the Company's
financial instruments are summarized as follows:
2000 1999
---------------------------- ----------------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
---------- ---------- ---------- ----------
Notes receivable $ 10,620 $ 10,620 $ 4,754 $ 4,754
Interest rate swaps - 20,022 - 6,764
Long-term debt 2,066,231 1,943,440 2,532,858 2,629,601
Deferred purchase obligation 28,377 25,033 30,331 30,039
69
Notes (continued)
The fair value of the financial instruments related to coal trading
activities as of March 31, 2000, which include energy commodities, and
average fair value of those instruments held are set forth below:
Assets Liabilities
------- -----------
Forward contracts $75,797 $75,025
Option contracts 2,898 858
------- -------
Total $78,695 $75,883
======= =======
The approximate gross contract or notional amounts of financial instruments
are as follows:
Assets Liabilities
-------- -----------
Forward contracts $ 75,025 $ 58,968
Option contracts 147,206 116,010
The net gain arising from coal and emission allowance trading activities
was $1.3 million for the year ended March 31, 2000 and $0.5 million for the
period ended March 31, 1999. There was no net gain or loss from coal and
emission allowance trading activities for the period ended May 19, 1998 and
the year ended March 31, 1998. The change in unrealized gain from coal
trading activities for the year ended March 31, 2000 was $1.0 million.
(21) COMMITMENTS AND CONTINGENCIES
Environmental claims have been asserted against a subsidiary of the Company
at 18 sites in the United States. Some of these claims are based on the
Comprehensive Environmental Response Compensation and Liability Act of
1980, as amended, and on similar state statutes. The majority of these
sites are related to activities of former subsidiaries of the Company.
The Company's policy is to accrue environmental cleanup-related costs of a
noncapital nature when those costs are believed to be probable and can be
reasonably estimated. The quantification of environmental exposures
requires an assessment of many factors, including changing laws and
regulations, advancements in environmental technologies, the quality of
information available related to specific sites, the assessment stage of
each site investigation, preliminary findings and the length of time
involved in remediation or settlement. For certain sites, the Company also
assesses the financial capability of other potentially responsible parties
and, where allegations are based on tentative findings, the reasonableness
of the Company's apportionment. The Company has not anticipated any
recoveries from insurance carriers or other potentially responsible third
parties in its balance sheets. The undiscounted liabilities for
environmental cleanup-related costs recorded as part of "Other noncurrent
liabilities" at March 31, 2000 and 1999 were $57.7 million and $61.8
million, respectively. This amount represents those costs that the Company
believes are probable and reasonably estimable.
On June 18, 1999, The Navajo Nation served our subsidiaries, Peabody
Holding Company, Inc., Peabody Coal Company and Peabody Western Coal
Company, with a complaint that had been filed in the U.S. District Court
for the District of Columbia. Other defendants in the litigation are two
utilities, two current employees and one former employee. The Navajo Nation
has alleged sixteen claims including civil Racketeer Influenced and Corrupt
Organizations Act, or RICO, claims, fraud and tortious interference with
contractual relationships. The plaintiff is seeking various remedies
including actual damages of at least $600 million which could be trebled
under the RICO counts, punitive damages of at least $1 billion, a
determination that Peabody Western Coal Company's two coal leases for the
Kayenta and Black Mesa mines have terminated due to the failure of a
condition and a reformation of the two coal leases to adjust the royalty
rate to 20 percent. All defendants have filed a motion to dismiss the
complaint.
In March 2000, the Hopi Tribe filed a motion to intervene in this lawsuit.
The Hopi Tribe has alleged seven claims, including fraud. The Hopi Tribe is
seeking various remedies, including unspecified actual and punitive
damages, reformation of its coal lease and a termination of the coal lease.
The federal court has not ruled on the Hopi Tribe's motion.
70
Notes (continued)
The Company believes this matter will be resolved without a material
adverse effect on the financial condition or results of operations.
In addition, the Company at times becomes a party to claims, lawsuits,
arbitration proceedings and administrative procedures in the ordinary
course of business. Management believes that the ultimate resolution of
pending or threatened proceedings will not have a material effect on the
financial position, results of operations or liquidity of the Company.
At March 31, 2000, purchase commitments for capital expenditures were
approximately $110.5 million.
71
Notes (continued)
(22) SEGMENT INFORMATION
The Company operates primarily in the coal industry. "Other" data
represents an aggregation of the Company's other non-mining entities
including Gold Fields. Total assets for "Other" as of March 31, 1999
includes amounts related to Citizens Power, a discontinued operation. The
Company's material operations outside the U.S. are in Australia. The
Company's industry and geographic data for continuing operations are as
follows:
PREDECESSOR COMPANY
-------------------------------------
Year Ended Period Ended Period Ended Year Ended
March 31, 2000 March 31, 1999 May 19, 1998 March 31, 1998
---------------- ---------------- --------------- ----------------
Revenues:
U.S. Mining $ 2,462,166 $ 1,903,214 $ 269,597 $ 1,987,719
Non U.S. Mining 244,347 145,687 20,882 224,053
Other 3,987 7,931 179 6,250
---------------- ---------------- --------------- ----------------
$ 2,710,500 $ 2,056,832 $ 290,658 $ 2,218,022
================ ================ =============== ================
Operating profit (loss):
U.S. Mining $ 140,699 $ 122,827 $ 6,929 $ 211,967
Non U.S. Mining 48,355 32,676 2,950 44,812
Other 4,183 1,541 (554) 4,033
---------------- ---------------- --------------- ----------------
$ 193,237 $ 157,044 $ 9,325 $ 260,812
================ ================ =============== ================
Depreciation, depletion
and amortization:
U.S. Mining $ 216,327 $ 155,220 $ 22,475 $ 169,623
Non U.S. Mining 33,455 23,962 3,041 30,546
---------------- ---------------- --------------- ----------------
$ 249,782 $ 179,182 $ 25,516 $ 200,169
================ ================ =============== ================
Total assets:
U.S. Mining $ 5,038,423 $ 5,141,661
Non U.S. Mining 527,771 494,123
Other 260,655 1,388,147
---------------- ----------------
$ 5,826,849 $ 7,023,931
================ ================
Revenues:
United States $ 2,466,153 $ 1,911,145 $ 269,776 $ 1,993,969
Non U.S. 244,347 145,687 20,882 224,053
---------------- ---------------- --------------- ----------------
$ 2,710,500 $ 2,056,832 $ 290,658 $ 2,218,022
================ ================ =============== ================
Operating profit:
United States $ 144,882 $ 124,368 $ 6,375 $ 216,000
Non U.S. 48,355 32,676 2,950 44,812
---------------- ---------------- --------------- ----------------
$ 193,237 $ 157,044 $ 9,325 $ 260,812
================ ================ =============== ================
Depreciation, depletion
and amortization:
United States $ 216,327 $ 155,220 $ 22,475 $ 169,623
Non U.S. 33,455 23,962 3,041 30,546
---------------- ---------------- --------------- ----------------
$ 249,782 $ 179,182 $ 25,516 $ 200,169
================ ================ =============== ================
Total assets:
United States $ 5,299,078 $ 6,529,808
Non U.S. 527,771 494,123
---------------- ----------------
$ 5,826,849 $ 7,023,931
================ ================
72
Notes (continued)
(23) SUPPLEMENTAL GUARANTOR/NON-GUARANTOR FINANCIAL INFORMATION
In accordance with the indentures governing the Senior Notes and Senior
Subordinated Notes, certain wholly owned U.S. subsidiaries of the Company
have fully and unconditionally guaranteed the 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
holders of the Senior Notes and the Senior Subordinated Notes. The
following condensed historical financial statement information is provided
for such Guarantor/Non-Guarantor Subsidiaries.
Supplemental Condensed Statements of Consolidated Operations
For the Year Ended March 31, 2000
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
----------- ------------ ------------- ------------ ------------
Total revenues $ - $1,963,823 $ 777,165 $ (30,488) $2,710,500
Costs and expenses:
Operating costs and expenses - 1,651,477 557,675 (30,488) 2,178,664
Depreciation, depletion and amortization - 180,287 69,495 - 249,782
Selling and administrative expenses 1,251 72,093 21,912 - 95,256
Net gain on property and equipment
disposals - (6,034) (405) - (6,439)
Interest expense 174,949 73,330 21,080 (64,303) 205,056
Interest income (43,896) (23,933) (895) 64,303 (4,421)
----------- ------------ ------------- ------------ ------------
Income (loss) before income taxes and
minority interests (132,304) 16,603 108,303 - (7,398)
Income tax provision (benefit) (34,804) (136,307) 29,589 - (141,522)
Minority interests - - 15,554 - 15,554
Loss from discontinued operations,
net of income taxes - - 12,087 - 12,087
Loss from disposal of discontinued
operations, net of income taxes 783 77,490 - - 78,273
----------- ------------ ------------- ------------ -------------
Net income (loss) $ (98,283) $ 75,420 $ 51,073 $ - $ 28,210
=========== ============ ============= ============ =============
73
Notes (continued)
Supplemental Condensed Statements of Consolidated Operations
For the Period Ended March 31, 1999
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
----------- ------------ ------------- ------------ ------------
Total revenues $ - $1,829,438 $ 229,150 $ (1,756) $2,056,832
Costs and expenses:
Operating costs and expenses - 1,494,487 150,987 (1,756) 1,643,718
Depreciation, depletion and amortization - 150,584 28,598 - 179,182
Selling and administrative expenses 13,124 60,142 3,622 - 76,888
Interest expense 160,068 11,292 4,745 - 176,105
Interest income (5,716) (11,897) (914) - (18,527)
----------- ------------ ------------- ------------ ------------
Income (loss) before income taxes and
minority interest (167,476) 124,830 42,112 - (534)
Income tax provision (benefit) (36,873) 31,213 8,672 - 3,012
Minority interest - - 1,887 - 1,887
Income from discontinued operations,
net of income taxes - - (6,442) - (6,442)
----------- ------------ ------------- ------------ ------------
Net income (loss) $(130,603) $ 93,617 $ 37,995 $ - $ 1,009
=========== ============ ============= ============ ============
Supplemental Condensed Statements of Combined Operations
For the Period Ended May 19, 1998
PREDECESSOR COMPANY
-------------------------------------------
Guarantor Non-Guarantor
Subsidiaries Subsidiaries Combined
-------------- ------------- ------------
Total revenues $ 269,776 $ 20,882 $ 290,658
Costs and expenses:
Operating costs and expenses 229,711 14,417 244,128
Depreciation, depletion and amortization 22,475 3,041 25,516
Selling and administrative expenses 11,523 494 12,017
Net gain on property and equipment disposals (308) (20) (328)
Interest expense 3,856 366 4,222
Interest income (1,615) (52) (1,667)
-------------- ------------- ------------
Income before income taxes 4,134 2,636 6,770
Income tax provision 3,185 1,345 4,530
Loss from discontinued operations, net of income taxes - 1,764 1,764
-------------- ------------- ------------
Net income (loss) $ 949 $ (473) $ 476
============== ============= ============
74
Notes (continued)
Supplemental Condensed Statements of Combined Operations
For the Year Ended March 31, 1998
PREDECESSOR COMPANY
-------------------------------------------
Guarantor Non-Guarantor
Subsidiaries Subsidiaries Combined
-------------- ------------- -----------
Total revenues $1,993,969 $224,053 $2,218,022
Costs and expenses:
Operating costs and expenses 1,552,176 143,040 1,695,216
Depreciation, depletion and amortization 169,623 30,546 200,169
Selling and administrative expenses 78,249 5,391 83,640
Net (gain) loss on property and equipment disposals (22,079) 264 (21,815)
Interest expense 30,684 2,726 33,410
Interest income (13,984) (559) (14,543)
-------------- ------------- -----------
Income before income taxes 199,300 42,645 241,945
Income tax provision 74,649 8,401 83,050
Income from discontinued operations, net of income taxes - (1,441) (1,441)
-------------- ------------- -----------
Net income $ 124,651 $ 35,685 $160,336
============== ============= ===========
75
Notes (continued)
Supplemental Condensed Consolidated Balance Sheets
As of March 31, 2000
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
------------ -------------- ------------- ------------ ------------
ASSETS
Current assets
Cash and cash equivalents $ 347 $ 45,931 $ 19,340 $ - $ 65,618
Accounts receivable 1,605 95,055 92,083 (35,722) 153,021
Inventories - 187,965 54,185 - 242,150
Assets from coal and emission allowance
trading activities - 78,695 - - 78,695
Deferred income taxes - 49,869 - - 49,869
Other current assets 1,282 14,351 27,559 - 43,192
------------ -------------- ------------- ------------ ------------
Total current assets 3,234 471,866 193,167 (35,722) 632,545
Property, plant, equipment and mine
development - at cost - 4,360,648 866,132 - 5,226,780
Less accumulated depreciation,
depletion and amortization - (323,870) (87,400) - (411,270)
------------ -------------- ------------- ------------ ------------
- 4,036,778 778,732 - 4,815,510
Net assets of discontinued operations 900 89,100 - - 90,000
Investments and other assets 1,883,781 1,444,307 208,095 (3,247,389) 288,794
------------ -------------- ------------- ------------ ------------
Total assets $1,887,915 $6,042,051 $1,179,994 $(3,283,111) $5,826,849
============ ============== ============= ============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Short-term borrowings and current
maturities of long-term debt $ - $ 21,122 $ 36,855 $ - $ 57,977
Payable to affiliates, net (284,294) 319,473 (35,179) - -
Income taxes payable - 521 13,073 - 13,594
Liabilities from coal and emission allowance
trading activities - 75,883 - - 75,883
Accounts payable and accrued expenses 76,066 416,505 116,288 (35,722) 573,137
------------ -------------- ------------- ------------ ------------
Total current liabilities (208,228) 833,504 131,037 (35,722) 720,591
Long-term debt, less current maturities 1,587,717 162,116 268,356 - 2,018,189
Deferred income taxes - 567,918 57,206 - 625,124
Other noncurrent liabilities - 1,873,508 39,746 - 1,913,254
------------ -------------- ------------- ------------ ------------
Total liabilities 1,379,489 3,437,046 496,345 (35,722) 5,277,158
Minority interests - - 41,265 - 41,265
Stockholders' equity 508,426 2,605,005 642,384 (3,247,389) 508,426
------------ -------------- ------------- ------------ ------------
Total liabilities and stockholders'
equity $1,887,915 $6,042,051 $1,179,994 $(3,283,111) $5,826,849
============ ============== ============= ============ ============
76
Notes (continued)
Supplemental Condensed Consolidated Balance Sheets
As of March 31, 1999
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
----------- ------------ ------------- ------------ --------------
ASSETS
Current assets
Cash and cash equivalents $ - $ 130,861 $ 63,217 $ - $ 194,078
Accounts receivable - 220,287 107,770 (15,309) 312,748
Inventories - 202,749 47,148 - 249,897
Assets from power trading activities - - 1,037,300 - 1,037,300
Assets from coal and emission allowance
trading activities - 2,514 - - 2,514
Deferred income taxes - 8,496 - - 8,496
Other current assets - 13,283 14,145 - 27,428
----------- ------------ ------------- ------------ --------------
Total current assets - 578,190 1,269,580 (15,309) 1,832,461
Property, plant, equipment and mine
development - at cost - 4,298,203 693,234 - 4,991,437
Less accumulated depreciation,
depletion and amortization - (158,295) (35,197) - (193,492)
----------- ------------ ------------- ------------ --------------
- 4,139,908 658,037 - 4,797,945
Investments and other assets 2,461,362 1,464,147 158,912 (3,690,896) 393,525
----------- ------------ ------------- ------------ --------------
Total assets $2,461,362 $6,182,245 $2,086,529 $(3,706,205) $7,023,931
=========== ============ ============= ============ ==============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Short-term borrowings and current
maturities of long-term debt $ 19,670 $ 21,666 $ 31,068 $ - $ 72,404
Payable to affiliates, net 152,364 (151,199) (1,165) - -
Income taxes payable - 229 7,079 - 7,308
Liabilities from power trading activities - - 638,062 - 638,062
Liabilities from coal and emission allowance
trading activities - 12 - - 12
Accounts payable and accrued expenses 56,562 440,319 146,150 (15,309) 627,722
----------- ------------ ------------- ------------ --------------
Total current liabilities 228,596 311,027 821,194 (15,309) 1,345,508
Long-term debt, less current maturities 1,737,536 173,364 559,075 - 2,469,975
Deferred income taxes - 711,932 68,243 - 780,175
Other noncurrent liabilities - 1,886,337 22,796 - 1,909,133
----------- ------------ ------------- ------------ --------------
Total liabilities 1,966,132 3,082,660 1,471,308 (15,309) 6,504,791
Minority interest - - 23,910 - 23,910
Stockholders' equity 495,230 3,099,585 591,311 (3,690,896) 495,230
----------- ------------ ------------- ------------ --------------
Total liabilities and stockholders'
equity $2,461,362 $6,182,245 $2,086,529 $(3,706,205) $7,023,931
=========== ============ ============= ============ ==============
77
Notes (continued)
Supplemental Condensed Statements of Consolidated Cash Flows
For the Year Ended March 31, 2000
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Consolidated
---------- ------------ ------------- ------------
Net cash provided by (used in)
continuing operations $ (83,810) $ 283,472 $ 103,753 $ 303,415
Net cash used in discontinued operations - - (40,504) (40,504)
---------- ------------ ------------- ------------
Net cash provided by (used in)
operating activities (83,810) 283,472 63,249 262,911
---------- ------------ ------------- ------------
Additions to property, plant, equipment
and mine development - (106,593) (72,161) (178,754)
Additions to advance mining royalties - (7,475) (17,817) (25,292)
Acquisitions, net - - (63,265) (63,265)
Investment in joint venture - (4,325) - (4,325)
Proceeds from coal contract restructurings - 11,904 21,000 32,904
Proceeds from property and
equipment disposals - 9,637 9,647 19,284
Proceeds from sale-leaseback
transactions - 34,234 - 34,234
---------- ------------ ------------- ------------
Net cash used in continuing operations - (62,618) (122,596) (185,214)
Net cash used in discontinued operations - - (170) (170)
---------- ------------ ------------- ------------
Net cash used in investing activities - (62,618) (122,766) (185,384)
---------- ------------ ------------- ------------
Proceeds from short-term borrowings and
long-term debt - - 22,026 22,026
Payments of short-term borrowings and
long-term debt (171,088) (21,695) (17,202) (209,985)
Capital contribution (distribution) - (1,073) 1,073 -
Distributions to minority interests - - (3,353) (3,353)
Dividends (paid) received 121,903 15,422 (137,325) -
Other 133,342 (298,438) 165,096 -
---------- ------------ ------------- ------------
Net cash provided by (used in) continuing operations 84,157 (305,784) 30,315 (191,312)
Net cash used in discontinued operations - - (13,869) (13,869)
---------- ------------ ------------- ------------
Net cash provided by (used in) financing activities 84,157 (305,784) 16,446 (205,181)
Effect of exchange rate changes
on cash and equivalents - - (806) (806)
---------- ------------ ------------- ------------
Net increase (decrease) in cash and
cash equivalents 347 (84,930) (43,877) (128,460)
Cash and cash equivalents at
beginning of period - 130,861 63,217 194,078
---------- ------------ ------------- ------------
Cash and cash equivalents at
end of period $ 347 $ 45,931 $ 19,340 $ 65,618
========== ============ ============= ============
78
Notes (continued)
Supplemental Condensed Statements of Consolidated Cash Flows
For the Period Ended March 31, 1999
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Consolidated
------------ ------------ ------------- ------------
Net cash provided by (used in)
continuing operations $ (140,674) $ 407,889 $ 63,708 $ 330,923
Net cash used in discontinued operations - - (48,901) (48,901)
------------ ------------ ------------- ------------
Net cash provided by (used in)
operating activities (140,674) 407,889 14,807 282,022
------------ ------------ ------------- ------------
Additions to property, plant, equipment
and mine development - (108,186) (66,334) (174,520)
Additions to advance mining royalties - (8,836) (2,673) (11,509)
Acquisitions, net (1,933,178) (143,742) (33,480) (2,110,400)
Proceeds from coal contract restructurings - 2,515 - 2,515
Proceeds from property and equipment disposals - 10,494 954 11,448
------------ ------------ ------------- ------------
Net cash used in continuing operations (1,933,178) (247,755) (101,533) (2,282,466)
Net cash provided by discontinued operations - - 33,130 33,130
------------ ------------ ------------- ------------
Net cash used in investing activities (1,933,178) (247,755) (68,403) (2,249,336)
------------ ------------ ------------- ------------
Proceeds from short-term borrowings and
long-term debt 1,817,390 - 53,388 1,870,778
Payments of short-term borrowings and
long-term debt (158,263) (21,470) (42,982) (222,715)
Capital contribution 480,000 - - 480,000
Distributions to minority interests - 9,096 (12,176) (3,080)
Other (65,275) (16,899) 48,158 (34,016)
------------ ------------ ------------- ------------
Net cash provided by (used in) continuing operations 2,073,852 (29,273) 46,388 2,090,967
Net cash provided by discontinued operations - - 70,314 70,314
------------ ------------ ------------- ------------
Net cash provided by (used in) financing activities 2,073,852 (29,273) 116,702 2,161,281
Effect of exchange rate changes
on cash and equivalents - - 111 111
------------ ------------ ------------- ------------
Net increase in cash and cash equivalents - 130,861 63,217 194,078
Cash and cash equivalents at
beginning of period - - - -
------------ ------------ ------------- ------------
Cash and cash equivalents at
end of period $ - $ 130,861 $ 63,217 $ 194,078
============ ============ ============= ============
79
Notes (continued)
Supplemental Condensed Statements of Combined Cash Flows
For the Period Ended May 19, 1998
PREDECESSOR COMPANY
--------------------------------------------------
Guarantor Non-Guarantor
Subsidiaries Subsidiaries Combined
-------------- ------------- -----------
Net cash provided by (used in) continuing operations $ (41,999) $ 12,138 $ (29,861)
Net cash provided by discontinued operations - 1,704 1,704
-------------- ------------- -----------
Net cash provided by (used in) operating activities (41,999) 13,842 (28,157)
-------------- ------------- -----------
Additions to property, plant, equipment and mine development (13,582) (7,292) (20,874)
Additions to advance mining royalties (1,767) (535) (2,302)
Proceeds from coal contract restructurings 308 20 328
Proceeds from property and equipment disposals 1,374 - 1,374
-------------- ------------- -----------
Net cash used in continuing operations (13,667) (7,807) (21,474)
Net cash used in discontinued operations - (76) (76)
-------------- ------------- -----------
Net cash used in investing activities (13,667) (7,883) (21,550)
-------------- ------------- -----------
Proceeds from short-term borrowings and long-term debt - 53,597 53,597
Payments of short-term borrowings and long-term debt (464) (18,959) (19,423)
Dividends paid (141,000) (32,330) (173,330)
Other 141,831 (831) 141,000
-------------- ------------- -----------
Net cash provided by continuing operations 367 1,477 1,844
Net cash provided by discontinued operations - 21,693 21,693
-------------- ------------- -----------
Net cash provided by financing activities 367 23,170 23,537
Effect of exchange rate changes on cash and equivalents - (292) (292)
-------------- ------------- -----------
Net increase (decrease) in cash and cash equivalents (55,299) 28,837 (26,462)
Cash and cash equivalents at beginning of period 83,812 13,009 96,821
-------------- ------------- -----------
Cash and cash equivalents at end of period $ 28,513 $ 41,846 $ 70,359
============== ============= ===========
80
Notes (continued)
Supplemental Condensed Statements of Combined Cash Flows
For the Year Ended March 31, 1998
PREDECESSOR COMPANY
--------------------------------------------------
Guarantor Non-Guarantor
Subsidiaries Subsidiaries Combined
-------------- ------------- -----------
Net cash provided by (used in)
continuing operations $ 272,348 $ (5,318) $ 267,030
Net cash used in discontinued operations - (79,178) (79,178)
-------------- ------------- -----------
Net cash provided by (used in)
operating activities 272,348 (84,496) 187,852
-------------- ------------- -----------
Additions to property, plant, equipment
and mine development (112,383) (53,131) (165,514)
Additions to advance mining royalties (6,174) - (6,174)
Acquisitions, net (58,715) - (58,715)
Proceeds from coal contract restructurings 57,460 - 57,460
Proceeds from property and equipment disposals 36,948 775 37,723
-------------- ------------- -----------
Net cash used in continuing operations (82,864) (52,356) (135,220)
Net cash used in discontinued operations - (813) (813)
-------------- ------------- -----------
Net cash used in investing activities (82,864) (53,169) (136,033)
-------------- ------------- -----------
Proceeds from short-term borrowings and long-term debt 90,000 179,391 269,391
Payments of short-term borrowings and long-term debt (162,420) (188,317) (350,737)
Capital contribution (distribution) (50,230) 50,230 -
Dividends paid (65,109) - (65,109)
Other (184,529) 5,235 (179,294)
-------------- ------------- -----------
Net cash provided by (used in) continuing operations (372,288) 46,539 (325,749)
Net cash provided by discontinued operations - 90,360 90,360
-------------- ------------- -----------
Net cash provided by (used in) financing activities (372,288) 136,899 (235,389)
Effect of exchange rate changes
on cash and equivalents - (718) (718)
-------------- ------------- -----------
Net decrease in cash and cash equivalents (182,804) (1,484) (184,288)
Cash and cash equivalents at
beginning of period 266,616 14,493 281,109
-------------- ------------- -----------
Cash and cash equivalents at
end of period $ 83,812 $ 13,009 $ 96,821
============== ============= ===========
81
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Set forth below are the names, ages as of March 31, 2000 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.
Name Age Position
---- --- --------
Irl F. Engelhardt 53 Chairman, Chief Executive Officer and Director
Richard M. Whiting 45 President, Chief Operating Officer and Director
Roger B. Walcott, Jr. 44 Executive Vice President
Mark Maisto 44 Chief Executive Officer and President, Citizens Power
Christopher G. Farrand 59 Vice President - Corporate Affairs
George J. Holway 50 Vice President - Mining Business Development
Robert D. Humphris 57 Managing Director-Australia
Jeffery L. Klinger 53 Vice President, Legal Services and Secretary
Richard A. Navarre 39 Vice President and Chief Financial Officer
Sharon K. Schergen 43 Vice President - Human Resources
Paul H. Vining 45 President, Peabody COALSALES Company
William E. Broshears 51 Group Executive - Resource Development
Roger H. Goodspeed 49 Director
Henry E. Lentz 55 Director
Alan H. Washkowitz 59 Director
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 Co-Chairman
of the Coal Utilization Research Council and past Chairman of the National
Mining Association and the Coal Industry Advisory Board of the International
Energy Agency. He is also a director of Firstar (formerly 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.
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.
82
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.
George J. Holway was appointed to his current position as Vice President-Mining
Business Development in October 1999. Previously he had served as Vice President
and Chief Financial Officer from June 1998 to October 1999. 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 immediate
past Chairman of the New South Wales Minerals Council, past Chairman of the
Australian Coal Association and the Chairman of Newcastle Coal Shippers. He is a
member of the Coal Industry Advisory Board of the International Energy Agency
and the State Minerals Advisory Council.
In May 2000, Mr. Humphris announced that he will retire in October 2000.
Ian Craig, Deputy Managing Director of Peabody Resources, will succeed
Mr. Humphris.
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 of the Energy and Mineral Law Foundation.
Richard A. Navarre was named Vice President and Chief Financial Officer in
October 1999. Prior to that, he was President of Peabody COALSALES Company from
January 1998 to October 1999 and previously served as President of Peabody
Energy Solutions, Inc. Prior to his roles in sales and marketing, he was Vice
President of Finance and served as Vice President and Controller of Peabody. He
joined Peabody in 1993 as Director of Financial Planning. Prior to joining
Peabody, Mr. Navarre was a senior manager with KPMG Peat Marwick. Mr. Navarre is
a member of the Trade and International Affairs Committee and the Transportation
Committee of the National Mining Association. He is also a member of the NYMEX
Coal Advisory Council.
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.
83
Paul H. Vining was named President of Peabody COALSALES Company in October 1999.
Prior to that, he was President of Peabody COALTRADE, Inc. from March 1997 to
October 1999, and Senior Vice President of Peabody COALSALES Company from August
1995 - February 1997. Mr. Vining is a member of the Board of Directors of the
Coal Exporters Association.
William E. Broshears was named Group Executive - Resource Development in
July 1999. Prior to that he was Group Executive - Mining Services from
May 1999 to July 1999, Vice President-Operations of Peabody Coal Company
from October 1996 to May 1999 and Vice President-Surface Operations of
Eastern Associated Coal Corp. from November 1995 to October 1996. Mr.
Broshears is the Chairman of the West Virginia Mining and Reclamation
Association.
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% 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
Consort Holdings plc. Mr. Lentz holds an MBA, with honors, from the
Wharton School of the University of Pennsylvania.
Alan H. Washkowitz became a Director in May 1998. He is also a Managing
Director of Lehman Brothers and the head of the firm's Merchant Banking
Group, responsible for the oversight of Lehman Brothers Merchant Banking
Partners II L.P. Mr. Washkowitz joined Kuhn Loeb & Co. in 1968 and
became a general partner of Lehman Brothers in 1978 when 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. 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 years 2000, 1999 and 1998.
84
SUMMARY COMPENSATION TABLE
Annual Compensation Long-Term Compensation
------------------------------ --------------------------------------------------------
Other
Annual Restricted Securities
Compen- Stock Underlying LTIP All Other
Fiscal Salary Bonus sation Award(s) Options/SARs Payments Compensation
Name and Principal Position Year ($) ($) ($) (#) (1) (#) (2) ($) (3) ($) (4)
- ------------------------------- -------- --------- --------- -------- ------------ -------------- ---------- --------------
Irl F. Engelhardt 2000 700,000 875,000 ---- ---- ---- ---- 51,525
Chairman, Chief 1999 681,264 700,000 ---- 154,639 499,855 441,240 23,998
Executive Officer and 1998 550,000 412,500 ---- ---- ---- 42,644 15,754
Director
Richard M. Whiting 2000 400,000 500,000 ---- ---- ---- ---- 28,662
President, Chief Operating 1999 385,834 400,000 ---- 51,546 179,828 168,051 12,238
Officer and Director 1998 244,851 182,501 ---- ---- ---- 12,326 7,058
Roger B. Walcott, Jr. 2000 350,000 437,500 ---- 51,546 ---- ---- 24,955
Executive Vice President 1999 291,667 350,000 ---- ---- 179,828 ---- 8,374
1998 ---- ---- ---- ---- ---- ---- ----
Mark Maisto 2000 300,000 600,000 ---- 51,546 ---- ---- 14,272
President and Chief 1999 282,485 450,000 ---- ---- 179,828 ---- 10,650
Executive Officer, 1998 208,333 300,000 ---- ---- ---- ---- 9,167
Citizens Power LLC
Richard A. Navarre 2000 233,750 343,750 ---- ---- ---- ---- 17,203
Vice President and Chief 1999 220,000 220,000 ---- 38,660 134,902 45,030 6,824
Financial Officer 1998 182,917 132,000 ---- ---- ---- 3,096 5,488
W. Howard Carson (5) 2000 331,758 381,875 ---- ---- ---- ---- 660,678
Former Chief Commercial 1999 312,633 325,000 ---- 51,546 179,828 169,716 37,055
Officer 1998 225,750 130,368 ---- ---- ---- 20,391 6,773
- ------------
(1) Represents number of shares of our Class B common stock granted to
executives as of May 19, 1998. In addition, shares purchased by Mr. Walcott
and Mr. Maisto on May 19, 1998 were converted to granted shares during the
year ended March 31, 2000.
(2) Represents number of shares of our Class A common stock underlying options
issued as of May 19, 1998.
(3) Represents certain long-term incentive payments earned during the fiscal
year that relate to Predecessor Company compensation plans.
(4) Represents annual matching contributions and performance contributions to
qualified and non-qualified savings and investment plans, and group term
life insurance. Also includes amounts related to Mr. Carson's resignation
in fiscal year 2000, and his relocation benefit received in fiscal year
1999.
(5) Mr. Carson resigned effective March 8, 2000.
Pension Benefits
Our Salaried Employees Retirement Plan, or pension plan, is a "defined benefit"
plan. The pension plan provides a monthly annuity to salaried employees when
they retire. A salaried employee must have at least five years of service to be
vested in the pension plan. A full benefit is available to a retiree at age 62.
A retiree can begin receiving a benefit as early as age 55; however, a 4%
reduction factor applies for each year a retiree receives a benefit prior to age
62.
An individual's retirement benefit under the pension plan is equal to the sum of
(1) 1.112% of the average monthly earnings over 60 consecutive months up to the
"covered compensation limit" multiplied by the employee's years of service, not
to exceed 35 years, and (2) 1.5% of the average monthly earnings over 60
consecutive months over the "covered compensation limit" multiplied by the
employee's years of service, not to exceed 35 years.
85
We announced in February 1999 that the pension plan would be phased out
beginning January 1, 2001. Certain transition benefits were introduced based on
the age and/or service of the employee at December 31, 2000: (1) employees age
50 or older will continue to accrue service at 100%; (2) employees between the
ages of 45 and 49 or with 20 years or more of service will accrue service at the
rate of 50% for each year of service worked after December 31, 2000; and (3)
employees under age 45 with less than 20 years of service will have their
pension 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 $487,883
Richard M. Whiting 262,395
Roger B. Walcott, Jr. 24,663
Richard A. Navarre 38,138
W. Howard Carson 144,820
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.
Beginning with fiscal year 2000, a performance contribution feature was added to
the savings and long-term investment plan to allow for Company contributions up
to a maximum of 4% of employees' salary based upon meeting certain Company
performance targets. Effective January 1, 2001, we will increase our match for
the savings and long-term investment plan.
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 (total 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, Walcott, Maisto, Navarre
and seven 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% 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
86
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% 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% of our initial fully-diluted equity; 931,885 of which 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 2,863,988 of which were
granted in the form of nonqualified stock options as "performance options." Time
options become exercisable with respect to 20% 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% 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% 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% 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% 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.
87
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.
FY-END OPTION/SAR VALUES
Number of securities underlying
unexercised options/SARs at FY-end
------------------------------------------------
Name Exercisable (#) Unexercisable (#)
-------------------------- ------------------ --------------------
Irl F. Engelhardt 44,000 455,855
Richard M. Whiting 15,985 163,843
Roger B. Walcott, Jr. 15,985 163,843
Mark Maisto 15,985 163,843
Richard A. Navarre 11,992 122,910
W. Howard Carson 15,985 -----
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. 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, 2000: (1) persons who beneficially own more than
5% 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.
88
NUMBER OF SHARES BENEFICIALLY OWNED
-----------------------------------
CLASS A CLASS B PERCENT PERCENT
COMMON COMMON PREFERRED OF OF
NAME AND ADDRESS OF BENEFICIAL OWNER STOCK(1) STOCK STOCK(2) CLASS A CLASS B
- ------------------------------------------------------- ------------ --------- ----------- --------- ---------
Lehman Brothers Merchant Banking Partners II L.P.,
LBI Group Inc. and their affiliated co-investors 16,000,000 ---- 5,000,000 85.0% ----
c/o Lehman Brothers Holdings Inc.
3 World Financial Center, 200 Versey Street
New York, NY 10285
Co-Investment Partners, L.P. 2,500,000 ---- ---- 13.3% ----
c/o Lexington Partners Inc.
659 Madison Avenue, 23rd Floor
New York, NY 10021
Irl F. Engelhardt 88,000 154,639 ---- 0.4% 22.6%
Richard M. Whiting 31,970 51,546 ---- 0.1% 7.5%
Roger B. Walcott, Jr. 31,970 51,546 ---- 0.1% 7.5%
Mark Maisto 31,970 51,546 ---- 0.1% 7.5%
Richard A. Navarre 23,984 38,660 ---- 0.1% 5.6%
All executives and directors as a group (15 people) 327,230 548,966 ---- 1.5% 73.6%
(1) Totals for named executive officers represent options exercisable
within 60 days after March 31, 2000.
(2) Lehman Brothers Merchant Banking Partners II L.P., LBI Group Inc. and
their affiliated co-investors own 100% of the outstanding Preferred
Stock of P&L Coal Holdings Inc.
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 the fiscal year ended March 31, 2000, Lehman Brothers Inc. received
approximately $1 million in cash for advising on the acquisition of an
additional 38.3% of Black Beauty in the prior fiscal year, and $0.8 million in
fees associated with a power contract restructuring by Citizens Power during
fiscal year 2000.
Transactions with Management
During the fiscal years ended March 31, 2000 and 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
89
officers who purchased capital stock are payable in equal amounts on from March
31, 1999 to 2003 and have a 5% 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, 2000:
LARGEST AGGREGATE INDEBTEDNESS
DURING FISCAL OUTSTANDING INDEBTEDNESS
NAME YEAR ENDED MARCH 31, 2000 AT MARCH 31, 2000
---- ------------------------- -----------------
Irl F. Engelhardt $551,593 $551,593
Richard M. Whiting 183,852 183,852
Roger B. Walcott, Jr. 182,500 182,500
Mark Maisto 182,500 182,500
Christopher G. Farrand 91,925 91,925
George J. Holway 137,889 137,889
Robert D. Humphris 95,058 95,058
Jeffery L. Klinger 91,932 91,932
Richard A. Navarre 137,883 137,883
Sharon K. Schergen 91,928 91,928
90
PART IV
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 41
Audited Financial Statements:
Statements of Operations - Year ended March 31, 2000, Periods ended
March 31, 1999 and May 19, 1998 and Year ended March 31, 1998 42
Balance Sheets - March 31, 2000 and 1999 43
Statements of Cash Flows - Year ended March 31, 2000, Periods
ended March 31, 1999 and May 19, 1998 and Year ended
March 31, 1998 44
Statements of Changes in Stockholders' Equity/Invested Capital -
Year ended March 31, 2000 and Periods ended March 31, 1999 and
May 19, 1998 and Year ended March 31, 1998 45
Notes to Financial Statements 46
(2) Financial Statement Schedule.
The following financial statement schedule of Peabody Energy Corporation
is included in Item 14, along with the report of independent auditors
thereon, at the pages indicated:
Page
----
Report of Independent Auditors on Financial Statement Schedule F-1
Valuation and Qualifying Accounts F-2
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:
Exhibit
No. Description of Exhibit
------- ----------------------
10.16 Receivables Sale Agreement dated as of March 31, 2000,
by and among Originators and P&L Coal Holdings
Corporation ("P&L")
10.17 Receivables Contribution Agreement dated as of March
31, 2000, by and between P&L and P&L Receivables
Company, LLC ("Seller")
10.18 Receivables Purchase Agreement as of March 31, 2000, by and among
Seller, P&L, International Securitization Corporation, Bank One,
NA, as Agent ("Agent") and the Financial Institutions named
therein.
21 List of Subsidiaries
24 Power of Attorney
27 Financial Data Schedule (filed electronically with the
SEC only)
(b) Reports on Form 8-K.
No reports were filed on Form 8-K for the year ended March 31, 2000.
91
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
PEABODY ENERGY CORPORATION
/s/ IRL F. ENGELHARDT
------------------------------------
Irl F. Engelhardt
Chairman and Chief Executive Officer
Date: April 27, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons, on behalf of the registrant and
in the capacities and on the dates indicated.
SIGNATURE TITLE
--------- -----
/s/ IRL F. ENGELHARDT
- ------------------------------------
Irl F. Engelhardt Chairman, Chief Executive Officer and Director
(principal executive officer)
*
- ------------------------------------
Richard M. Whiting President, Chief Operating Officer and Director
/s/ RICHARD A. NAVARRE
- ------------------------------------
Richard A. Navarre Executive Vice President and Chief Financial Officer
(principal financial and accounting officer)
*
- ------------------------------------
Henry E. Lentz Vice President, Assistant Secretary and Director
*
- ------------------------------------
Roger H. Goodspeed Director
*
- ------------------------------------
Alan H. Washkowitz Director
* By: /s/ RICHARD A. NAVARRE
-----------------------------
Richard A. Navarre
Attorney-In-Fact
92
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).
93
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).
94
Exhibit
No. Description of Exhibit
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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-8 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).
95
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).
96
Exhibit
No. Description of Exhibit
- --------- ----------------------
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).
4.9 Second Supplemental Senior Note Indenture dated as of December 31,
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.
4.10 Second Supplemental Senior Subordinated Note Indenture dated as of
December 31, 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.
4.11 Third Supplemental Senior Note Indenture dated as of June 30, 1999
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.
4.12 Third Supplemental Senior Subordinated Note Indenture dated as of
June 30, 1999 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.
97
Exhibit
No. Description of Exhibit
- --------- ----------------------
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).
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.
10.16** Receivables Sale Agreement dated as of March 31, 2000, by
and among Originators and P&L Coal Holdings Corporation
("P&L")
10.17** Receivables Contribution Agreement dated as of March 31,
2000, by and between P&L and P&L Receivables Company, LLC
("Seller")
10.18** Receivables Purchase Agreement as of March 31, 2000, by and
among Seller, P&L, International Securitization Corporation,
Bank One, NA, as Agent ("Agent") and the Financial
Institutions named therein.
21** List of Subsidiaries.
24 Power of Attorney (filed herewith).
27** Financial Data Schedule
* 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.
** Previously filed as an exhibit to the Company's Annual Report on Form
10-K for the year ended March 31, 2000 as filed with the Securities
and Exchange Commission on June 28, 2000.
98