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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[ ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934 For the Fiscal Year Ended March 31, 2001
or
[X] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
For the transition period from April 1, 2001 to December 31, 2001
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Commission File Number 1-16463
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PEABODY ENERGY CORPORATION
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(Exact name of registrant as specified in its charter)
DELAWARE 13-4004153
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
701 MARKET STREET, ST. LOUIS, MISSOURI 63101
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(Address of principal executive offices) (Zip Code)
(314) 342-3400
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Registrant's telephone number, including area code
Securities Registered Pursuant to Section 12(b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered
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Common Stock, par value $0.01 per share New York Stock Exchange
Securities Registered Pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Aggregate market value of the voting stock held by non-affiliates of the
Registrant as of March 1, 2002: Common Stock, par value $0.01 per share,
$559.7 million.
Number of shares outstanding of each of the Registrant's classes of Common
Stock, as of March 1, 2002: Common Stock, par value $0.01 per share,
52,020,274 shares outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Peabody Energy Corporation (the "Company") Annual Report for the
nine months ended December 31, 2001 are incorporated by reference into Part II
hereof. Portions of the Company's Proxy Statement to be filed with the SEC in
connection with the Company's Annual Meeting of Stockholders to be held on May
3, 2002 (the "Company's 2002 Proxy Statement") are incorporated by reference
into Part III hereof. Other documents incorporated by reference in this report
are listed in the Exhibit Index of this Form 10-K.
CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS
Some of the information included in this prospectus or any prospectus
supplement and the documents we have incorporated by reference contain
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are
intended to come within the safe harbor protection provided by those sections.
These statements relate to future events or our future financial performance. We
use words such as "anticipate," "believe," "expect," "may," "project," "will" or
other similar words to identify forward-looking statements.
Without limiting the foregoing, all statements relating to our:
o future outlook;
o anticipated capital expenditures;
o future cash flows and borrowings; and
o sources of funding
are forward-looking statements. These forward-looking statements are based on
numerous assumptions that we believe are reasonable, but they are open to a wide
range of uncertainties and business risks and actual results may differ
materially from those discussed in these statements.
Among the factors that could cause actual results to differ materially are:
o general economic conditions;
o modification or termination of our long-term coal supply
agreements;
o reduction of purchases by major customers;
o transportation costs;
o risks inherent to mining;
o government regulation of the mining industry;
o replacement of recoverable reserves;
o implementation of new accounting standards;
o inflationary trends and interest rates; and
o other factors, including those discussed in "Risk Factors" and
"Recent Developments."
When considering these forward-looking statements, you should keep in
mind the cautionary statements in this document, any prospectus supplement or
term sheet and the documents incorporated by reference. We will not update these
statements unless the securities laws require us to do so.
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TABLE OF CONTENTS
PART I. Page
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Item 1. Business........................................................................... 4
Item 2. Properties......................................................................... 19
Item 3. Legal Proceedings.................................................................. 24
Item 4. Submission of Matters to a Vote of Security Holders................................ 27
Item 4A. Executive Officers of the Company.................................................. 27
PART II.
Item 5. Market For Registrant's Common Equity and Related Stockholder Matters.............. 29
Item 6. Selected Financial Data............................................................ 29
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................................ 32
Item 7A. Quantitative and Qualitative Disclosures About Market Risk......................... 46
Item 8. Financial Statements and Supplementary Data........................................ 47
Item 9. Changes in and Disagreements With Accountants on Accounting and
Financial Disclosure............................................................. 47
PART III.
Item 10. Directors and Executive Officers of the Registrant................................. 47
Item 11. Executive Compensation............................................................. 47
Item 12. Security Ownership of Certain Beneficial Owners and Management..................... 47
Item 13. Certain Relationships and Related Transactions..................................... 47
PART IV.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K.................... 47
3
PART I
ITEM 1. BUSINESS.
OVERVIEW
We are the largest private-sector coal company in the world. During the
nine months ended December 31, 2001, we sold 146.5 million tons of coal. During
this period, we sold coal to more than 250 electric generating and industrial
plants in eleven countries, and fueled the generation of more than 9% of all
electricity in the United States and 2.5% of all electricity in the world. At
December 31, 2001, we had 9.1 billion tons of proven and probable coal reserves.
We own majority interests in 33 coal operations located throughout all
major U.S. coal producing regions, with 72% of our mining operations' coal sales
during the nine months ended December 31, 2001 shipped from the western United
States and the remaining 28% from the eastern United States. Most of our
production in the western United States is low sulfur coal from the Powder River
Basin. Our overall western U.S. coal production has increased from 37.0 million
tons in fiscal year 1990 to 127.1 million tons during calendar year 2001,
representing a compounded annual growth rate of 12%. In the west, we own and
operate mines in Arizona, Colorado, Montana, New Mexico and Wyoming. In the
east, we own and operate mines in Illinois, Indiana, Kentucky and West Virginia.
We produced 79% of our sales volume for the nine months ended December 31, 2001
from non-union mines.
For the nine months ended December 31, 2001, 94% of our sales were to U.S.
electricity generators, 4% were to the U.S. industrial sector and 2% were to
customers outside the United States. Approximately 83% of our coal sales during
the nine months ended December 31, 2001 were under long-term contracts. As of
December 31, 2001, nearly one billion tons of our future coal production were
committed under long-term contracts, with remaining terms ranging from one to 14
years and an average volume-weighted remaining term of approximately four years.
As of March 1, 2002, we had approximately 6 million tons and 65 million tons
of expected production available for sale at market-based prices in calendar
year 2002 and 2003, respectively.
In addition to our mining operations, we market and trade coal and emission
allowances. Our total tons traded as part of these activities were 39.4 million
for the nine months ended December 31, 2001. Finally, we are also expanding in
related energy businesses that include coalbed methane production,
transportation-related services, third-party coal contract restructuring and
participation in the development of coal-based generating plants.
HISTORY
Peabody, Daniels and Co. was founded in 1883 as a retail coal supplier,
entering the mining business in 1888 as Peabody & Co. with our first mine in
Illinois. In 1926, Peabody Coal Company was listed on the Chicago Stock Exchange
and, beginning in 1949, on the New York Stock Exchange. In 1955, Peabody Coal
Company, primarily an underground mine operator, merged with Sinclair Coal
Company, a major surface mining company. In 1968, Peabody Coal Company was
acquired by Kennecott Copper Company. In 1977, it was sold to Peabody Holding
Company, which was formed by a consortium of companies.
In July 1990, Hanson, plc acquired Peabody Holding Company. In February
1997, Hanson spun off its energy-related businesses, including Eastern Group and
Peabody Holding Company, into The Energy Group, plc. The Energy Group was a
publicly traded company in the United Kingdom and its American Depository
Receipts (ADR's) were publicly traded on the New York Stock Exchange. On May 19,
1997, The Energy Group, through Peabody, purchased Citizens Power LLC, a leading
power marketer.
On May 19, 1998, Lehman Brothers Merchant Banking Partners II L.P., an
affiliate of Lehman Brothers Inc., purchased Peabody Holding Company and its
affiliates, Peabody Resources Limited (Peabody Resources) and Citizens Power
LLC.
During the 1980s, Peabody grew through internal expansion and acquisition,
opening the North Antelope Mine in Wyoming's coal-rich Powder River Basin in
1983 and the Rochelle Mine in 1985. In 1984, we acquired the West Virginia coal
properties of ARMCO Steel and the following year purchased Coal Properties Corp.
and Eastern Associated Coal Corp., which included seven operating mines and
substantial low sulfur coal reserves in West Virginia.
From 1993 to 2001, we made 16 major acquisitions. In 1993, interests in
three mines in New South Wales, Australia, were acquired from Costain Group in
anticipation of the growing Pacific Rim market for coal. The properties included
100% ownership of the Ravensworth Mine, a 50% interest in the Narama Mine and a
28.75% interest in the Warkworth Mine,
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subsequently increased to 43.75%. We also subsequently developed a fourth mine,
Bengalla, which began shipments in early 1999. Our interest in the Bengalla
joint venture was increased from 35% to 37% in 1998 and to 40% in 2000.
In 1993 we also acquired the Lee Ranch Mine in New Mexico. The following
year, we purchased a one-third ownership in Black Beauty Coal Company (Black
Beauty), Indiana's largest coal producer. We increased our interest in Black
Beauty to 43.3% in February 1998 and to 81.7% in January 1999. Black Beauty
acquired Catlin Coal Company in 1999 and acquired an additional 25% of Arclar
Coal Company in 2000.
In 1994, we acquired the Caballo and Rawhide mines in Wyoming's Powder
River Basin from Exxon Coal USA Inc. This acquisition, along with the expansion
of the North Antelope and Rochelle Mines, positioned Peabody as the leading
producer in the Powder River Basin, the nation's largest and fastest growing
coal region. Our sales volume from the Powder River Basin increased from 31
million tons in 1993 to 106.3 million tons in calendar 2001.
In August 1999, we purchased a 55% interest in the Moura Mine in
Queensland, Australia. The Moura Mine supplies a range of steam and
metallurgical coals to Asia-Pacific customers and operates a coalbed methane
extraction operation. We sold our Australian operations to a subsidiary of Rio
Tinto Limited in January 2001.
In August 2000, we sold Citizens Power, our subsidiary that marketed and
traded electric power and energy-related commodity risk management products, to
Edison Mission Energy.
On April 10, 2001, we changed our name from P&L Coal Holdings Corporation
to Peabody Energy Corporation. On May 21, 2001, we completed an initial public
offering of Common Stock and our shares began trading on the New York Stock
Exchange under the symbol "BTU."
MINING OPERATIONS
The following provides a description of the operating characteristics of
the principal mines and reserves of each of our operating units and affiliates
in the United States.
[UNITED STATES MINING OPERATIONS MAP]
Within the United States, we conduct operations in the Powder River Basin,
Southwest, Appalachia and Midwest regions.
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POWDER RIVER BASIN OPERATIONS
We control approximately 2.7 billion tons of coal reserves in the Southern
Powder River Basin, the largest and fastest growing major U.S. coal-producing
region. We own and manage two active low sulfur, non-union surface mining
complexes in Wyoming that sold approximately 78.3 million tons of coal during
the nine months ended December 31, 2001, or approximately 53% of our total coal
sales volume. The North Antelope/Rochelle and Caballo mines are serviced by both
major western railroads, the Burlington Northern & Santa Fe and the Union
Pacific. In addition, we own the Rawhide Mine, which is located ten miles north
of Gillette, Wyoming and uses truck-and-shovel mining methods. The Rawhide Mine
is serviced by the Burlington Northern & Santa Fe railroad. Operations were
suspended at the Rawhide mine in 1999, and the mine reopened in January 2002 as
a result of favorable market conditions during 2001.
Our Wyoming Powder River Basin reserves are classified as surface mineable,
subbituminous coal with seam thickness varying from 70 to 105 feet. The sulfur
content of the coal in current production ranges from 0.2% to 0.4% and the heat
value ranges from 8,500 to 8,900 Btu per pound.
We also operate the Big Sky Mine in Montana in the Northern Powder River
Basin. Coal is shipped from this mine to customers in the upper Midwest by the
Burlington Northern & Santa Fe railroad.
North Antelope/Rochelle
The North Antelope/Rochelle Mine is located 65 miles south of Gillette,
Wyoming. This mine is the largest and most productive in the United States,
selling 56.8 million tons during the nine months ended December 31, 2001. The
North Antelope/Rochelle Mine produces premium quality coal with a sulfur content
averaging 0.2% and a heat value ranging from 8,500 to 8,900 Btu per pound. The
North Antelope/Rochelle Mine produces the lowest sulfur coal in the United
States, using a dragline along with six truck-and-shovel fleets. We expect to
add a second dragline in 2002 to improve productivity.
Caballo
The Caballo Mine is located 20 miles south of Gillette, Wyoming. During the
nine months ended December 31, 2001, it sold approximately 21.5 million tons of
compliance coal. Caballo is a truck-and-shovel operation with a coal handling
system that includes two 12,000-ton silos and two 11,000-ton silos.
Big Sky
The Big Sky Mine is located in the northern end of the Powder River Basin
near Colstrip, Montana, and uses dragline mining equipment. The mine sold 2.0
million tons of medium sulfur coal during the nine months ended December 31,
2001. Coal is shipped by rail to several major electric generating customers in
the upper midwestern United States. This mine is near the exhaustion of its
economically recoverable reserves, and we may close it in the next several
years, depending upon market and mining conditions. Hourly workers at the Big
Sky Mine are members of the United Mine Workers of America.
SOUTHWEST OPERATIONS
We own and manage four mines in the western bituminous coal region - two in
Arizona, and one in each of Colorado and New Mexico. The Colorado and Arizona
mines supply primarily compliance coal and the New Mexico mine supplies medium
sulfur coal under long-term coal supply agreements to electricity generating
stations in the region. Together, these mines sold 16.0 million tons of coal
during the nine months ended December 31, 2001.
Black Mesa
The Black Mesa Mine, which is located on the Navajo Nation and Hopi Tribe
reservations in Arizona, uses two draglines and sold 3.6 million tons of coal
during the nine months ended December 31, 2001. The Black Mesa Mine coal is
crushed, mixed with water and then transported 273 miles through the underground
Black Mesa Pipeline (which is owned by a third party) to the Mohave Generating
Station near Laughlin, Nevada, which is operated and partially owned by Southern
California Edison. The mine and pipeline were designed to deliver coal
exclusively to the plant, which has no other source of coal. The Mohave
Generating Station coal supply agreement extends until 2005, with the customer's
option to extend the term up to an additional 15 years, subject to agreement on
specified terms. Hourly workers at this mine are members of the United Mine
Workers of America.
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Kayenta
The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines
in three mining areas. It sold approximately 6.5 million tons of coal during the
nine months ended December 31, 2001. The Kayenta Mine coal is crushed, then
carried 17 miles by conveyor belt to storage silos where it is loaded on to a
private rail line and transported 83 miles to the Navajo Generating Station,
operated by the Salt River Project near Page, Arizona. The mine and railroad
were designed to deliver coal exclusively to the power plant, which has no other
source of coal. The Navajo coal supply agreement extends until 2011. Hourly
workers at this mine are members of the United Mine Workers of America.
Seneca
The Seneca Mine near Hayden, Colorado shipped 1.3 million tons of
compliance coal during the nine months ended December 31, 2001, operating with
two draglines in two separate mining areas. The mine's coal is hauled by truck
to the nearby Hayden Generating Station, operated by the Public Service of
Colorado, under a coal supply agreement that extends until 2011. Hourly workers
at this mine are members of the United Mine Workers of America.
Lee Ranch Coal Company
The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 4.6
million tons of medium sulfur coal during the nine months ended December 31,
2001. Lee Ranch shipped the majority of its coal to two customers in Arizona and
New Mexico under coal supply agreements extending until 2010 and 2014,
respectively. Lee Ranch is a non-union surface mine that uses a combination of
dragline and truck-and-shovel mining techniques. Lee Ranch is currently
expanding to annual production capacity of 6.7 million tons to meet the
requirements of two new customers.
APPALACHIA OPERATIONS
We own and manage six operating units and related facilities in West
Virginia. During the nine months ended December 31, 2001, these operations sold
approximately 13.5 million tons of compliance, medium sulfur and high sulfur
steam and metallurgical coal to customers in the United States and abroad.
Hourly workers at these operations are members of the United Mine Workers of
America.
Big Mountain Operating Unit
The Big Mountain Operating Unit is based near Prenter, West Virginia. This
operating unit's primary mine is Big Mountain No. 16. In August 2000, we closed
the Robin Hood No. 9 Mine after depleting its mineable reserves and the White's
Branch Mine began production. White's Branch's operations are currently
suspended due to geologic problems. During the nine months ended December 31,
2001, the Big Mountain No. 16 and White's Branch mines sold approximately 1.8
million tons of steam coal. Big Mountain No. 16 is an underground mine using
continuous mining equipment. Processed coal is loaded on the CSX railroad.
Harris Operating Unit
The Harris Operating Unit consists of the Harris No. 1 Mine near Bald Knob,
West Virginia, which sold approximately 2.8 million tons of compliance coal
during the nine months ended December 31, 2001. This mine uses both longwall and
continuous mining equipment.
Rocklick Operating Unit and Contract Mines
The Rocklick preparation plant, located near Wharton, West Virginia,
processes coal produced by the Harris Mine and contract mining companies from
coal reserves that we control. This preparation plant shipped approximately 5.4
million tons of steam and metallurgical coal during the nine months ended
December 31, 2001, including 2.8 million tons related to the Harris Operating
Unit. Processed coal is loaded at the plant site on the CSX railroad or
transferred via conveyor to our Kopperston loadout facility and loaded on the
Norfolk Southern railroad.
Wells Operating Unit
The Wells Operating Unit, in Boone County, West Virginia, sold
approximately 2.4 million tons of metallurgical and steam coal during the nine
months ended December 31, 2001. The unit consists of the Lightfoot No. 2 Mine,
contract mines and the Wells preparation plant, located near Wharton, West
Virginia. The mine uses continuous mining equipment to produce coal from
reserves we own. Processed coal is loaded on the CSX railroad.
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Federal No. 2 Mine
The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining
equipment and shipped approximately 3.7 million tons of steam coal during the
nine months ended December 31, 2001. Coal shipped from the Federal No. 2 Mine
has a sulfur content only slightly above that of medium sulfur coal and has an
above average heating content. As a result, it is more marketable than some
other medium sulfur coals. The CSX and Norfolk Southern railroads jointly serve
the mine.
Colony Bay Mine
The Colony Bay mine is located in Boone County, West Virginia. The mine,
which reopened in January 2002, utilizes one spread of surface mining equipment
and one highwall miner. Coal produced from the mine is transported to the
Rocklick preparation plant prior to shipment to customers. It is anticipated
that this mine will produce approximately one million tons in 2002.
Kanawha Eagle Coal Joint Venture
We have a minority interest in Kanawha Eagle Coal, LLC, which owns a deep
mine, a preparation plant and barge-and-rail loading facilities near Marmet,
West Virginia. The union-free mine uses continuous mining equipment and shipped
1.7 million tons during the nine months ended December 31, 2001.
MIDWEST OPERATIONS
We own and operate five mines in the midwestern United States, which
collectively sold 5.7 million tons of coal during the nine months ended December
31, 2001. Our midwest operations include three underground and two surface
mines, along with five preparation plants and four barge loading facilities,
located in western Kentucky, southern Illinois and southwestern Indiana. We ship
coal from these mines primarily to electricity generators in the midwestern
United States, and we sell some coal to industrial customers that generate their
own power.
In addition to the five wholly-owned mines in our Midwest operating region,
we control 16 additional mines in the midwestern United States through our 81.7%
joint venture interest in Black Beauty, as discussed below.
Black Beauty Coal Company
We own 81.7% of Black Beauty, the largest coal company in the Illinois
Basin, which controls nine mines in Indiana, five mines in Illinois and one mine
in western Kentucky. Together, these operations sold 19.1 million tons of
compliance, medium sulfur and high sulfur steam coal during the nine months
ended December 31, 2001. We purchased a one-third interest in Black Beauty in
1994, and increased our interest to 43.3% in 1998 and 81.7% in 1999. Black
Beauty Resources, Inc., owned by certain members of Black Beauty's management
team, owns the remaining interest.
Black Beauty's principal Indiana mines include Air Quality No. 1,
Farmersburg, Francisco and two mines in Somerville, Indiana. Air Quality No. 1
is an underground coal mine located near Monroe City, Indiana that shipped 1.4
million tons of compliance coal during the nine months ended December 31, 2001.
Farmersburg is a surface mine situated in Vigo and Sullivan counties in Indiana
that sold 2.9 million tons of medium sulfur coal during the nine months ended
December 31, 2001. Francisco, a surface mine located in Gibson county, Indiana,
sold 2.0 million tons during the nine months ended December 31, 2001, and the
two Somerville mines, also located in Gibson county, shipped a total of 5.0
million tons in fiscal year 2001. All of Black Beauty's mines utilize non-union
labor.
Black Beauty owns a 75% equity interest in Arclar Company, LLC (formerly
Sugar Camp Coal, LLC), which operates a large surface and underground mining
complex in Gallatin and Saline counties in southern Illinois. During the nine
months ended December 31, 2001, these facilities sold 4.1 million tons of coal,
primarily shipped by barge to downriver utility plants. Black Beauty provides a
contract workforce for the Arclar surface mines; the workforce at the
underground operations is provided by a separate contractor which employs miners
represented under non-UMWA labor agreements.
Black Beauty also owns a 75% interest in United Minerals Company, LLC.
United Minerals currently acts as a contract miner for Black Beauty at the
Somerville North and Discovery mines and as contract operator for Black Beauty
at the Evansville River Terminal. Kentucky United, LLC, a small coal producer
with operations in Daviess County, Kentucky, is a wholly-owned subsidiary of
United Minerals.
During 2001, Black Beauty and Arclar each installed new underground mining
facilities. Black Beauty's Vermilion Grove portal, in east-central Illinois,
began operations early in the first quarter of 2002 and, together with the
existing Riola #1 portal, is
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expected to produce approximately 2.7 million tons of coal per year. Arclar's
new Willow Lake portal also began operations during the first quarter of 2002.
Willow Lake will replace Arclar's existing operations at Eagle Valley and Big
Ridge, which will both then be idled.
Camp Operating Unit
The Camp Operating Unit, located near Morganfield, Kentucky, currently
operates the Camp No. 11 Mine, an underground mine, and a large preparation
plant and barge loading facility. The Camp No. 1 Mine exhausted its economically
recoverable reserves and ceased operations in October 2000. Camp No. 11 Mine
sold 2.5 million tons of coal during the nine months ended December 31, 2001.
The Camp No. 11 Mine uses both longwall and continuous mining equipment. We sell
most of the production under contract to the Tennessee Valley Authority.
The Camp No. 11 Mine is expected to exhaust its economically recoverable
reserves in the fourth quarter of 2002, and its production will be replaced by
the Highland Operating Unit.
Highland Operating Unit
The Highland Operating Unit, located near Waverly, Kentucky, has two new
underground mines under development. The Highland No. 11 Mine will operate in
the No. 11 coal seam and Highland No. 9 Mine will operate in the No. 9 coal
seam. We expect both mines to begin production in 2002 utilizing continuous
mining equipment, and it is anticipated that these mines will produce up to 1.8
million tons of coal during 2002.
Midwest Operating Unit
The Midwest Operating Unit near Graham, Kentucky sold 1.3 million tons of
coal during the nine months ended December 31, 2001. The unit currently includes
the Gibraltar surface mining operation, which uses truck-and-shovel equipment,
and the Gibraltar Highwall Mine, which uses continuous mining equipment. The
unit used to include the Martwick mine; however in November 2000, the Martwick
Mine exhausted its economically recoverable reserves and ceased operations, and
the Gibraltar Highwall mine began operations to replace the production. We sell
coal from these mines under contract to the Tennessee Valley Authority. On March
4, 2002, a WARN Act notice was sent advising that the Gibraltar Highwall Mine
would be closed in the near future, as the mine is reaching the end of its
economically recoverable reserves.
Patriot Coal Company
Patriot Coal Company operates Patriot, a surface mine, and Freedom, an
underground mine, in Henderson County, Kentucky, and sold approximately 1.9
million tons of coal during the nine months ended December 31, 2001. The
underground mine uses continuous mining equipment, and the surface mine uses
truck-and-shovel equipment. Patriot Coal Company also operates a preparation
plant and a dock. The Patriot Coal Company mines utilize non-union labor.
LONG-TERM COAL SUPPLY AGREEMENTS
We currently have coal supply agreements to sell nearly one billion tons of
coal, with remaining terms ranging from one to 14 years and an average
volume-weighted remaining term of approximately four years. For the nine months
ended December 31, 2001, we sold 83% of our sales volume under coal supply
agreements. During the nine months ended December 31, 2001, we sold coal to more
than 250 electric generating and industrial plants in eleven countries.
We expect to continue selling a significant portion of our coal under
long-term supply agreements. Our strategy is to selectively renew, or enter into
new, long-term supply contracts when we can do so at prices we believe are
favorable. During 2001, prices for coal increased from prior year levels,
particularly in the Powder River Basin and in Appalachia, primarily due to
increased prices for competing fuels and increased demand for electricity. Late
in 2001, coal prices began to decline from the high levels experienced earlier
in 2001, due to a softer economy and milder than normal winter weather. During
calendar 2001, we signed contracts for nearly 200 million tons of new business
at higher prices than those realized in 2001. As of December 31, 2001 we had
sales commitments for approximately 93% of our calendar 2002 production which,
as of March 1, 2002, increased to 97% as a result of reduced production
estimates for calendar 2002.
Long-term contracts may be particularly attractive in regions where market
prices are expected to remain stable, particularly in cases such as high sulfur
coal that would otherwise not be in great demand or for sales under cost-plus
arrangements serving captive electric generating plants. To the extent we do not
renew or replace expiring long-term coal supply agreements, our future sales
will be exposed to market fluctuations, including unexpected downturns in market
prices.
9
Typically, customers enter into coal supply agreements to secure reliable
sources of coal at predictable prices, while we seek stable sources of revenue
to support the investments required to open, expand and maintain or improve
productivity at the mines needed to supply these contracts. The terms of coal
supply agreements result from bidding and extensive negotiations with customers.
Consequently, the terms of these contracts typically vary significantly in many
respects, including price adjustment features, price reopener terms, coal
quality requirements, quantity parameters, flexibility and adjustment mechanics,
permitted sources of supply, treatment of environmental constraints, extension
options and force majeure, termination and assignment provisions.
Each contract sets a base price. Base prices are sometimes adjusted at
quarterly or annual intervals for changes due to inflation and/or changes in
actual costs such as taxes, fees and royalties. The inflation adjustments are
measured by public indices, the most common of which is the implicit price
deflator for the gross domestic product as published by the Department of
Commerce.
Price adjustment provisions are present in most of our long-term coal
contracts greater than three years in duration. These provisions allow either
party to commence a renegotiation of the contract price at various intervals. If
the parties do not agree on a new price, the purchaser or seller often has an
option to terminate the contract. Some agreements provide that if the parties
fail to agree on a price adjustment caused by cost increases due to changes in
applicable law and regulations, the purchaser may terminate the agreement,
subject to the payment of liquidated damages. Under some contracts, we have the
right to match lower prices offered to our customers by other suppliers.
Quality and volumes for the coal are stipulated in coal supply agreements,
and in some instances buyers have the option to vary annual or monthly volumes
if necessary. Variations to the quality and volumes of coal may lead to
adjustments in the contract price. Coal supply agreements typically stipulate
procedures for quality control, sampling and weighing. Most coal supply
agreements contain provisions requiring us to deliver coal within certain ranges
for specific coal characteristics such as heat content (Btu), sulfur, ash,
grindability and ash fusion temperature. Failure to meet these specifications
can result in economic penalties, suspension or cancellation of shipments or
termination of the contracts.
Contract provisions in some cases set out mechanisms for temporary
reductions or delays in coal volumes in the event of a force majeure, including
events such as strikes, adverse mining conditions or serious transportation
problems that affect the seller or unanticipated plant outages that may affect
the buyer. More recent contracts stipulate that this tonnage can be made up by
mutual agreement or at the discretion of the buyer. Buyers often negotiate
similar clauses covering changes in environmental laws. We often negotiate the
right to supply coal that complies with a new environmental requirement to avoid
contract termination. Coal supply agreements typically contain termination
clauses if either party fails to comply with the terms and conditions of the
contract, although most termination provisions provide the opportunity to cure
defaults.
In some of our contracts, we have a right of substitution, allowing us to
provide coal from different mines as long as the replacement coal meets quality
specifications and will be sold at the same delivered cost. Contracts usually
contain specified sampling locations: in the eastern United States,
approximately 50% of customers require that the coal is sampled and weighed at
the destination, whereas in the western United States, samples are usually taken
at the shipping source.
SALES AND MARKETING
Our sales and marketing operations include Peabody COALSALES and Peabody
COALTRADE. Through these entities, we sell coal produced by our diverse
portfolio of operations, broker coal sales of other coal producers, both as
principal and agent, trade coal and emission allowances, and provide
transportation-related services. We also restructure third-party coal supply
agreements by acquiring a customer's right to receive coal from another coal
company under a coal supply agreement, reselling that coal, and supplying that
customer with coal from our own operations. As of December 31, 2001, we had 62
employees in our sales, marketing and trading operations, including personnel
dedicated to performing market research, contract administration and risk
management activities.
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TRANSPORTATION
Coal consumed domestically is usually sold at the mine, and transportation
costs are normally borne by the purchaser. Export coal is usually sold at the
loading port, with purchasers paying ocean freight. Producers usually pay
shipping costs from the mine to the port.
The majority of our sales volume is shipped by rail, but a portion of our
production is shipped by other modes of transportation. For example, coal from
our Camp operating unit in Kentucky is shipped by barge to the Tennessee Valley
Authority's Cumberland plant in Tennessee. Coal from our Black Mesa Mine in
Arizona is transported by a 273-mile coal-water pipeline to the Mohave
Generating Station in southern Nevada. Coal from the Seneca Mine in Colorado is
transported by truck to a nearby electric generating plant. Other mines
transport coal by rail and barge or by rail and lake carrier on the Great Lakes.
All coal from our Powder River Basin mines is shipped by rail, and two competing
railroads, the Burlington Northern & Santa Fe and the Union Pacific, serve our
North Antelope/Rochelle and Caballo mines. The Rawhide Mine is serviced by the
Burlington Northern & Santa Fe railroad. Approximately 8,000 unit trains are
loaded each year to accommodate the coal shipped by these mines. A unit train
generally consists of 100 to 140 cars, each of which can hold 100 to 120 tons of
coal.
Our transportation department manages the loading of trains and barges. We
believe we enjoy good relationships with rail carriers and barge companies due,
in part, to our modern coal-loading facilities and the experience of our
transportation coordinators.
SUPPLIERS
The main types of goods we purchase are mining equipment and replacement
parts, explosives, fuel, tires and lubricants. We also purchase coal from third
parties to satisfy some of our customer contracts. The supplier base providing
these goods has been relatively consistent in recent years and we have many long
established relationships with our key suppliers. We do not believe that we are
dependent on any of our individual suppliers.
TECHNICAL INNOVATION
We place great emphasis on the application of technical innovation to
improve new and existing equipment's performance. This research and development
effort is typically undertaken and funded by equipment manufacturers using our
input and expertise. Our engineering, maintenance and purchasing personnel work
together with manufacturers to design and produce equipment that we believe will
add value to the business. We have worked with manufacturers to design larger
trucks to haul overburden and coal at various mines throughout the company. In
Wyoming, we were the first coal company to use the current, state-of-the-art
400-ton haul trucks. Additionally, we worked with manufacturers to develop
higher horsepower, underground continuous mining machines and a continuous
haulage machine, which mine the coal more effectively, at a lower cost per ton.
We are a leader in retrofitting existing equipment to increase performance
and extend the lives of assets. For example, a dragline from the Midwest was
relocated to Wyoming and is being upgraded with new motors and digital
controllers that are expected to increase productivity by 10% to 15%. We also
deploy extensive lubrication analysis technology, finite element analysis and
remote monitoring to ensure full productive life of our equipment. As a result
of these efforts, many of our mines have become among the most productive in the
industry.
We use sophisticated software to schedule and monitor trains, mine/pit
blending, quality, and customer shipments. The integrated software has been
developed in-house and provides a competitive tool to differentiate our
reliability and product consistency. We are the largest user of advanced coal
quality analyzers among coal producers, according to the manufacturer of this
sophisticated equipment. These analyzers allow continuous analysis of certain
coal quality parameters, such as sulfur content. Their use helps ensure
consistent product quality and helps customers meet stringent air emission
requirements. We also support the Power Systems Development Facility, a highly
efficient electric generating plant using advanced emissions reduction
technology funded primarily through the Department of Energy and operated by an
affiliate of Southern Company.
COMPETITION
The markets in which we sell our coal are highly competitive. The top 10
coal producers in the United States produce approximately 64% of total domestic
coal, although there are approximately 730 coal producers in the United States.
Our principal competitors are other large coal producers, including Arch Coal,
Inc., Kennecott Energy Co., a subsidiary of Rio Tinto, RAG AG, CONSOL Energy
Inc., AEI Resources, Inc. and Massey Energy Company, which collectively
accounted for approximately 41% of total U.S. coal production in 2000.
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A number of factors beyond our control affect the markets in which we sell
our coal. Continued demand for our coal and the prices obtained by us depend
primarily on the coal consumption patterns of the electricity industries in the
United States, the availability, location, cost of transportation and price of
competing coal and other electricity generation and fuel supply sources such as
natural gas, oil, nuclear and hydroelectric. Coal consumption patterns are
affected primarily by the demand for electricity, environmental and other
governmental regulations and technological developments. We compete on the basis
of coal quality, delivered price, customer service and support and reliability.
POWER PLANT DEVELOPMENT
To best use our asset base and enhance long-term growth, we are also
developing coal-fueled generating plants. We are currently engaged in
permitting, engineering and economic analysis for the Thoroughbred Energy
Campus. Thoroughbred represents a planned 1,500 megawatt electricity generating
plant to be fueled by a 5 to 6 million ton-per-year coal mine on
company-controlled property in Western Kentucky. Thoroughbred has received a
draft air permit from Kentucky. The governor of Kentucky has issued an executive
order which prohibits the issuance of any final power plant permits in the
Commonwealth until July 16, 2002. We have also filed an air permit and
transmission access documents for a sister project, the Prairie State Energy
Campus. Prairie State is using the design, engineering and purchasing template
from Thoroughbred to achieve economies of scale, and speed the plant development
cycle. Prairie State would be built atop a six million ton-per-year coal mine
planned on our property in Southwestern Illinois. Thoroughbred and Prairie State
are modeled to be among the cleanest and lowest cost coal-fueled plants east of
the Mississippi River. We plan to secure partners for the projects with
complementary skills in generating plant construction, operation and power
marketing.
COALBED METHANE
Our subsidiary, Peabody Natural Gas, LLC is evaluating the potential for
coalbed methane development within our coal reserves. In addition, we purchased
coalbed methane assets near our Caballo Mine in Wyoming in January 2001 for
approximately $10 million. We are considering expansion of this business line
through acquisitions and development of our own reserves.
CERTAIN LIABILITIES
We have significant long-term liabilities for reclamation, work-related
injuries and illnesses, pensions and retiree health care. In addition, labor
contracts with the United Mine Workers of America and voluntary arrangements
with non-union employees include long-term benefits, notably health care
coverage for retired and future retirees and their dependents. The majority of
our existing liabilities relate to our past operations, which had more mines and
employees than we currently have.
Reclamation. Reclamation liabilities primarily represent the future costs
to restore surface lands to productivity levels equal to or greater than
pre-mining conditions, as required by the Surface Mining Control and Reclamation
Act. We also record other related liabilities, such as water treatment and
environmental costs. Our long-term reclamation costs, mine-closing and other
related liabilities totaled approximately $444.5 million as of December 31,
2001, $5.9 million of which was a current liability. Expense for the nine months
ended December 31, 2001 and the year ended March 31, 2001 was $9.6 million and
$4.1 million, respectively.
Workers' Compensation. These liabilities represent the actuarial estimates
for compensable, work-related injuries (traumatic claims) and occupational
disease, primarily black lung disease (pneumoconiosis). The Federal Black Lung
Benefits Act requires employers to pay black lung awards to former employees who
filed claims after June 1973. These liabilities totaled approximately $250.4
million as of December 31, 2001, $42.7 million of which was a current liability.
Expense for the nine months ended December 31, 2001 and the year ended March 31,
2001 was $36.5 million and $41.4 million, respectively.
Pension-Related Provisions. Pension-related costs represent the
actuarially-estimated cost of pension benefits. Annual contributions to the
pension plans are determined by consulting actuaries based on the Employee
Retirement Income Security Act minimum funding standards and an agreement with
the Pension Benefit Guaranty Corporation. Pension-related current liabilities
totaled approximately $16.1 million as of December 31, 2001.
Retiree Health Care. Consistent with Statement of Financial Accounting
Standards No. 106, we record a liability representing the estimated cost of
providing retiree health care benefits to current retirees and active employees
who will retire in the future. Provisions for active employees represent the
amount recognized to date, based on their service to date; additional amounts
are provided periodically so that the total estimated liability is accrued when
the employee retires.
A second category of retiree health care obligations represents the
liability for future contributions to the United Mine Workers of America
Combined Fund created by federal law in 1992. This multi-employer fund provides
health care benefits to a
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closed group of former employees who retired prior to 1976; no new retirees will
be added to this group. The liability is subject to increases or decreases in
per capita health care costs, offset by the mortality curve in this aging
population of beneficiaries.
Our retiree health care liabilities totaled approximately $1,032.5 million
as of December 31, 2001, $70.4 million of which was a current liability. Expense
for the nine months ended December 31, 2001 and the year ended March 31, 2001
was $49.8 million and $70.7 million, respectively. Obligations to the United
Mine Workers of America Combined Fund totaled $57.1 million as of December 31,
2001, $7.4 million of which was a current liability. Expense for the nine months
ended December 31, 2001 was $3.3 million. For the year ended March 31, 2001,
income of $8.0 million was recorded, mainly due to the withdrawal by the Social
Security Administration of certain beneficiaries previously assigned to us.
DEREGULATION OF THE ELECTRICITY GENERATION INDUSTRY
In October 1992, Congress enacted the Energy Policy Act of 1992. To
stimulate competition in the electricity market, that legislation gave wholesale
suppliers access to the transmission lines of U.S. electricity generators. In
April 1996, the Federal Energy Regulatory Commission issued the first of a
series of orders establishing rules providing for open access to electricity
transmission systems. The federal government is currently exploring a number of
options concerning utility deregulation. Individual states are also proceeding
with their own deregulation initiatives.
The pace of deregulation differs significantly from state to state. To
date, 16 states and Washington, D.C. have either enacted legislation leading to
the deregulation of the electricity market or issued a regulatory order to
implement retail access; seven states have either passed legislation or issued
regulatory orders to delay implementing retail access; and 26 other states have
not enacted legislation to restructure the electric power industry or implement
retail access. In California, where market inefficiencies and supply and demand
imbalances created electricity supply shortages, the California Public Utilities
Commission has ordered suspension of retail access.
If ultimately implemented, full-scale deregulation of the power industry is
expected to enable both industrial and residential customers to shop for the
lowest-cost supply of power and the best service available. This fundamental
change in the power industry is expected to compel electricity generators to be
more aggressive in developing and defending market share, to be more focused on
their pricing and cost structures and to be more flexible in reacting to changes
in the market.
A possible consequence of deregulation is downward pressure on fuel prices.
However, because of coal's cost advantage and because some coal-based generating
facilities are underutilized in the current regulated electricity market, we
believe that additional coal demand would arise as electricity markets are
deregulated if the most efficient coal-based power plants are operated at
greater capacity.
EMPLOYEES
As of December 31, 2001, we and our subsidiaries had approximately 6,500
employees. Approximately 35% of our employees are affiliated with organized
labor unions, which accounted for approximately 21% of sales volume during the
nine months ended December 31, 2001. Relations with organized labor are
important to our success and we believe our relations with employees are
satisfactory. Hourly workers at our mines in Arizona, Colorado and Montana are
represented by the United Mine Workers of America under the Western Surface
Agreement, which was ratified in 2000 and is effective through September 1,
2005. Our union labor east of the Mississippi River is also represented by the
United Mine Workers of America and is subject to the National Bituminous Coal
Wage Agreement. The current five-year labor agreement was ratified in December
2001 and is effective from January 1, 2002 through December 31, 2006.
REGULATORY MATTERS
Federal, state and local authorities regulate the U.S. coal mining industry
with respect to matters such as employee health and safety, permitting and
licensing requirements, air quality standards, water pollution, plant and
wildlife protection, the reclamation and restoration of mining properties after
mining has been completed, the discharge of materials into the environment,
surface subsidence from underground mining and the effects of mining on
groundwater quality and availability. In addition, the industry is affected by
significant legislation mandating certain benefits for current and retired coal
miners. Numerous federal, state and local governmental permits and approvals are
required for mining operations. We believe that we have obtained all permits
currently required to conduct our present mining operations. We may be required
to prepare and present to federal, state or local authorities data pertaining to
the effect or impact that a proposed exploration for or production of coal may
have on the environment. These requirements could prove costly and
time-consuming, and could delay commencing or continuing exploration or
production operations. Future legislation and administrative regulations may
emphasize the protection of the environment and, as a consequence, our
activities may be more closely regulated. Such legislation and regulations, as
well as future interpretations and more rigorous enforcement of existing laws,
may require substantial increases in equipment and operating costs to us and
delays, interruptions or a termination of operations, the extent of which we
cannot predict.
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We endeavor to conduct our mining operations in compliance with all
applicable federal, state and local laws and regulations. However, because of
extensive and comprehensive regulatory requirements, violations during mining
operations occur from time to time in the industry. None of the violations to
date or the monetary penalties assessed upon us has been material.
Mine Safety and Health
Stringent health and safety standards have been in effect since Congress
enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and
Health Act of 1977 significantly expanded the enforcement of safety and health
standards and imposed safety and health standards on all aspects of mining
operations.
Most of the states in which we operate have state programs for mine safety
and health regulation and enforcement. Collectively, federal and state safety
and health regulation in the coal mining industry is perhaps the most
comprehensive and pervasive system for protection of employee health and safety
affecting any segment of U.S. industry. While regulation has a significant
effect on our operating costs, our U.S. competitors are subject to the same
degree of regulation.
Our goal is to achieve excellent safety and health performance. We measure
our success in this area primarily through the use of accident frequency rates.
We believe that a superior safety and health regime is inherently tied to
achieving our productivity and financial goals. We seek to implement this goal
by: training employees in safe work practices; openly communicating with
employees; establishing, following and improving safety standards; involving
employees in establishing safety standards; and recording, reporting and
investigating all accidents, incidents and losses to avoid reoccurrence.
Black Lung
Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung
Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must
secure payment of federal black lung benefits to claimants who are current and
former employees and to a trust fund for the payment of benefits and medical
expenses to claimants who last worked in the coal industry prior to July 1,
1973. Historically, less than 7% of the miners currently seeking federal black
lung benefits are awarded these benefits by the federal government. The trust
fund is funded by an excise tax on production of up to $1.10 per ton for
deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount
to exceed 4.4% of the gross sales price. This tax is passed on to the purchaser
under many of our coal supply agreements.
In December 2000, the Department of Labor issued new amendments to the
regulations implementing the federal black lung laws that, among other things,
establish a presumption in favor of a claimant's treating physician and limit a
coal operator's ability to introduce medical evidence regarding the claimant's
medical condition. Industry reports anticipate that the number of claimants who
are awarded benefits will increase significantly as will the amounts of those
awards. The National Mining Association has filed a lawsuit challenging these
regulations. The U.S. District Court of the District of Columbia upheld the
regulations. The National Mining Association has filed an appeal with the U.S.
Court of Appeals for the District of Columbia.
Coal Industry Retiree Health Benefit Act of 1992
The Coal Act provides for the funding of health benefits for certain United
Mine Workers of America retirees. The Coal Act established the Combined Fund
into which "signatory operators" and "related persons" are obligated to pay
annual premiums for beneficiaries. The Coal Act also created a second benefit
fund for miners who retired between July 21, 1992 and September 30, 1994 and
whose former employers are no longer in business. Companies that are liable
under the Coal Act must pay premiums to the Combined Fund. Annual payments made
by certain of our subsidiaries under the Coal Act totaled $3.9 million and $4.1
million, respectively, during the nine months ended December 31, 2001 and year
ended March 31, 2001.
In October 1998, the Combined Fund sent a premium notice to all assigned
operators subject to the fund that included retroactive death benefit and health
benefit premiums dating back to February 1, 1993. On November 13, 1998, 10
employers, including two of our subsidiaries, Peabody Coal Company and Eastern
Associated Coal Corp., challenged the fund's retroactive rebilling in a lawsuit
filed in the Northern District Court of Alabama. The District Court ruled
against us and the other employers and we and the employers filed an appeal with
the U.S. Court of Appeals for the 11th Circuit. If we are successful in this
litigation, we will be eligible for a $1.0 million credit as a reduction to
future premiums.
In 1996, the Combined Fund sued the Social Security Administration in the
District of Columbia seeking a declaration that the Social Security
Administration's original calculation of the per-beneficiary premium was proper.
Certain coal companies, but not our subsidiaries, intervened in the lawsuit. On
February 25, 2000, the federal District Court ruled in favor of the Combined
Fund. The Combined Fund has obtained an amended order and the intervenor coal
companies have appealed the court's decision. If this decision is upheld on
appeal and applied retroactively, our subsidiaries will be required to pay an
additional premium to the Combined Fund of approximately $3.6 million.
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Environmental Laws
We are subject to various federal, state and foreign environmental laws.
These laws, some of which are discussed below, place many requirements on our
coal mining operations, and both federal and state inspectors regularly visit
our mines and other facilities to ensure compliance.
Surface Mining Control and Reclamation Act
The Surface Mining Control and Reclamation Act, which is administered by
the Office of Surface Mining Reclamation and Enforcement, establishes mining,
environmental protection and reclamation standards for all aspects of surface
mining as well as many aspects of deep mining. The Surface Mining Control and
Reclamation Act and similar state statutes require, among other things, the
restoration of mined property in accordance with specified standards and an
approved reclamation plan. In addition, the Abandoned Mine Land Fund, which is
part of the Surface Mining Control and Reclamation Act, imposes a fee on all
current mining operations, the proceeds of which are used to restore mines
closed before 1977. The maximum tax is $0.35 per ton on surface-mined coal and
$0.15 per ton on deep-mined coal.
A mine operator must submit a bond or otherwise secure the performance of
these reclamation obligations. Mine operators must receive permits and permit
renewals for surface mining operations from the Office of Surface Mining
Reclamation and Enforcement or, where state regulatory agencies have adopted
federally approved state programs under the act, the appropriate state
regulatory authority. We accrue for the liability associated with all
end-of-mine reclamation on a ratable basis as the coal reserve is being mined.
All states in which we have active mining operations have achieved primary
control of enforcement through approved state programs. Although we do not
anticipate significant permit issuance or renewal problems, we cannot assure you
that our permits will be renewed or granted in the future or that permit issues
will not adversely affect operations. Under previous regulations of the act,
responsibility for any coal operator currently in violation of the act could be
imputed to other companies deemed, according to regulations, to "own or control"
the coal operator. Sanctions included being blocked from receiving new permits
and rescission or suspension of existing permits. Because of federal court
action invalidating these ownership and control regulations, the Office of
Surface Mining Reclamation and Enforcement responded to the court action by
promulgating interim regulations, which more narrowly apply the ownership and
control standards to coal companies.
West Virginia Mountaintop Mining
On October 20, 1999, the U.S. District Court for the Southern District of
West Virginia issued a permanent injunction against the West Virginia Department
of Environmental Protection in a mountaintop-mining lawsuit. As interpreted by
the Director of the Department of Environmental Protection, the injunction
prohibits the Department from approving any new permits that would authorize the
placement of excess soil in intermittent and perennial streams for the primary
purpose of waste (overburden) disposal. The Department also interpreted the
injunction to affect certain existing coal refuse ponds, sediment ponds and
mountaintop-mining operations.
The Department filed an appeal of the decision with the U.S. Court of
Appeals for the Fourth Circuit. In April 2001, the Fourth Circuit overturned the
District Court decision regarding the intermittent and perennial stream issue.
The U.S. Supreme Court recently denied the petition for certiorari filed by
certain environmental groups.
We currently have no mountaintop mining operations or plans to develop
mountaintop mining operations.
The Clean Air Act
The Clean Air Act, the Clean Air Act Amendments and the corresponding state
laws that regulate the emissions of materials into the air, affect coal mining
operations both directly and indirectly. Direct impacts on coal mining and
processing operations may occur through Clean Air Act permitting requirements
and/or emission control requirements relating to particulate matter, such as
fugitive dust, including future regulation of fine particulate matter measuring
ten micrometers in diameter or smaller. The Clean Air Act indirectly affects
coal mining operations by extensively regulating the air emissions of sulfur
dioxide and other compounds, including nitrogen oxides, emitted by coal-based
electricity generating plants.
In July 1997, the EPA adopted new, more stringent National Ambient Air
Quality Standards for very fine particulate matter and ozone. As a result, some
states will be required to change their existing implementation plans to attain
and maintain compliance with the new air quality standards. Our mining
operations and electric generating customers are likely to be directly affected
when the revisions to the air quality standards are implemented by the states.
State and federal regulations relating to implementation of the new air quality
standards may restrict our ability to develop new mines or could require us to
modify our
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existing operations. The extent of the potential direct impact of the new air
quality standards on the coal industry will depend on the policies and control
strategies associated with the state implementation process under the Clean Air
Act, but could have a material adverse effect on our financial condition and
results of operations.
Title IV of the Clean Air Act Amendments places limits on sulfur dioxide
emissions from electric power generation plants. The limits set baseline
emission standards for these facilities. Reductions in emissions occurred in
Phase I in 1995 and in Phase II in 2000 and apply to all coal-based power
plants. The affected electricity generators have been able to meet these
requirements by, among other ways, switching to lower sulfur fuels, installing
pollution control devices, such as flue gas desulfurization systems, which are
known as "scrubbers," reducing electricity generating levels or purchasing
sulfur dioxide emission allowances. Emission sources receive these sulfur
dioxide emission allowances, which can be traded or sold to allow other units to
emit higher levels of sulfur dioxide. We cannot ascertain the effect of these
provisions of the Clean Air Act Amendments on us in future years. At this time,
we believe that implementation of Phase II has resulted in an upward pressure on
the price of lower sulfur coals, as additional coal-based electric generating
plants have complied with the restrictions of Title IV.
The Clean Air Act Amendments also require electricity generators that
currently are major sources of nitrogen oxides in moderate or higher ozone
non-attainment areas to install reasonably available control technology for
nitrogen oxides, which are precursors of ozone. In addition, the EPA recently
announced the final rules that would require 19 eastern states and Washington,
D.C. to make substantial reductions in nitrogen oxide emissions. Installation of
additional control measures required under the final rules will make it more
costly to operate coal-based electric generating plants.
In accordance with Section 126 of the Clean Air Act, eight northeastern
states filed petitions requesting the EPA to make findings and require decreases
in nitrogen oxide emissions from certain sources in certain upwind states that
might contribute to ozone nonattainment in the petitioning states. The EPA has
granted four of the eight petitions finding that certain sources are
contributing to ozone non-attainment in certain of the petitioning states and
the EPA has proposed levels of nitrogen oxide control for the named sources. Our
customers are among the named sources and, implementation of the requirement to
install control equipment could impact the amount of coal supplied to those
customers if they decide to switch to other sources of fuel, which would result
in lower emission of nitrogen oxides.
The Clean Air Act Amendments provisions for new source review require
electricity generators to install the best available control technology if they
make a major modification to a facility that results in an increase in its
potential to emit regulated pollutants. The Justice Department on behalf of the
EPA filed a number of lawsuits since November 1999, alleging that ten
electricity generators violated the new source review provisions of the Clean
Air Act Amendments at power plants in the midwestern and southern United States.
The EPA issued an administrative order alleging similar violations by the
Tennessee Valley Authority, affecting seven plants and notices of violation for
an additional eight plants owned by the affected electricity generators. Four
electricity generators have announced settlements with the Justice Department
requiring the installation of additional control equipment on selected
generating units. If the remaining electricity generators are found to be in
violation, they could be subject to civil penalties and be required to install
the required control equipment or cease operations. Our customers are among the
named electricity generators and if found not to be in compliance, the fines and
requirements to install additional control equipment could adversely affect the
amount of coal they would burn if the plant operating costs were to increase to
the point that the plants were operated less frequently.
The Clean Air Act Amendments set a national goal for the prevention of any
future, and the remedying of any existing, impairment of visibility in 156
national parks and wildlife areas across the country. Visibility in these areas
is to be returned to natural conditions by 2064 through plans that must be
developed by the states. The state plans may require the application of "Best
Available Retrofit Technology" after 2010 on sources found to be contributing to
visibility impairment of regional haze in these areas. The control technology
requirements could cause our customers to install equipment to control sulfur
dioxide and nitrogen oxide emissions. The requirement to install control
equipment could affect the amount of coal supplied to those customers if they
decide to switch to other sources of fuel to lower emission of sulfur oxides and
nitrogen oxides.
The Clean Air Act Amendments require a study of electric generating plant
emissions of certain toxic substances, including mercury, and direct the EPA to
regulate these substances, if warranted. In December 2000, the EPA decided that
mercury air emissions from power plants should be regulated. The EPA will
propose regulations by December 2003 and will issue final regulations by
December 2004. It is possible that future regulatory activity may seek to reduce
mercury emissions and these requirements, if adopted, could result in reduced
use of coal if electricity generators switch to other sources of fuel.
In addition, Vice President Cheney, as the head of the National Energy
Policy Development Group, submitted to the President a National Energy Policy
which recommended, among other things, that the President direct the EPA
Administrator to work with Congress to propose legislation that would
significantly reduce and cap emissions of sulfur dioxide, nitrogen oxide and
mercury from electric power generators. In February 2002, the President proposed
to cut electric power generator emissions by approximately 70% by 2018 using a
cap and trade system similar to that now in effect for acid deposition control.
The President's proposal is expected to be translated into a legislative
proposal. In addition, similar emission reduction proposals have been
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introduced in the current session of Congress, some of which propose to regulate
the three pollutants and carbon dioxide, but no such legislation has passed
either house of the Congress. If this type of legislation were enacted into law,
it could impact the amount of coal supplied to those electricity generating
customers if they decide to switch to other sources of fuel whose use would
result in lower emission of sulfur oxides, nitrogen oxides, mercury and carbon
dioxide.
Clean Water Act
The Clean Water Act of 1972 affects coal mining operations by imposing
restrictions on effluent discharge into water. Regular monitoring, reporting
requirements and performance standards are preconditions for the issuance and
renewal of permits governing the discharge of pollutants into water.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act (RCRA), which was enacted in
1976, affects coal mining operations by imposing requirements for the treatment,
storage and disposal of hazardous wastes. Coal mining operations covered by the
Surface Mining Control and Reclamation Act permits are exempted from regulation
under RCRA by statute. We cannot, however, predict whether this exclusion will
continue.
Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous
waste regulation until the Environmental Protection Agency (EPA) completed a
report to Congress and made a determination on whether the wastes should be
regulated as hazardous. In a 1993 regulatory determination, the EPA addressed
some large volume coal combustion wastes generated at electric utility and
independent power producing facilities. In May 2000, the EPA concluded that coal
combustion wastes do not warrant regulation as hazardous under RCRA. The EPA is
retaining the hazardous waste exemption for these wastes. However, the EPA has
determined that national non-hazardous waste regulations under RCRA Subtitle D
are needed for coal combustion wastes disposed in surface impoundments and
landfills and used as minefill. The agency also concluded beneficial uses of
these wastes, other than for minefilling, pose no significant risk and no
additional national regulations are needed. As long as this exemption remains in
effect it is not anticipated that regulation of coal combustion waste will have
any material effect on the amount of coal used by electric generators.
Federal and State Superfund Statutes
Superfund and similar state laws affect coal mining and hard rock
operations by creating liability for investigation and remediation in response
to releases of hazardous substances into the environment and for damages to
natural resources. Under Superfund, joint and several liability may be imposed
on waste generators, site owners and operators and others regardless of fault.
Global Climate Change
The United States, Australia and more than 160 other nations are
signatories to the 1992 Framework Convention on Climate Change, which is
intended to limit emissions of greenhouse gases, such as carbon dioxide. In
December 1997, in Kyoto, Japan, the signatories to the convention established a
binding set of emission targets for developed nations. Although the specific
emission targets vary from country to country, the United States would be
required to reduce emissions to 93% of 1990 levels over a five-year budget
period from 2008 through 2012. Although the United States has not ratified the
emission targets and no comprehensive regulations focusing on greenhouse gas
emissions are in place, these restrictions, whether through ratification of the
emission targets or other efforts to stabilize or reduce greenhouse gas
emissions, could adversely affect the price and demand for coal. According to
the Energy Information Administration's Emissions of Greenhouse Gases in the
United States 2000, coal accounts for 32% of greenhouse gas emissions in the
United States, and efforts to control greenhouse gas emissions could result in
reduced use of coal if electric generators switch to lower carbon sources of
fuel. In March 2001, President Bush reiterated his opposition to the Kyoto
Protocol and further stated that he did not believe that the government should
impose mandatory carbon dioxide emission reductions on power plants. In February
2002, President Bush announced a new approach to climate change, confirming the
Administration's opposition to the Kyoto Protocol and proposing voluntary
actions to reduce the greenhouse gas intensity of the United States. Greenhouse
gas intensity measures the ratio of greenhouse gas emissions, such as carbon
dioxide, to economic output. The President's climate change initiative calls for
a reduction in greenhouse gas intensity over the next ten years which is
approximately equivalent to the reduction that has occurred over each of the
past two decades.
PERMITTING
Mining companies must obtain numerous permits that impose strict
regulations on various environmental and safety matters in connection with coal
mining. These provisions include requirements for coal prospecting; mine plan
development; topsoil removal, storage and replacement; selective handling of
overburden materials; mine pit backfilling and grading; protection of the
17
hydrologic balance; subsidence control for underground mines; surface drainage
control; mine drainage and mine discharge control and treatment; and
revegetation.
We must obtain permits from applicable state regulatory authorities before
we begin to mine reserves. The mining permit application process is initiated by
collecting baseline data to adequately characterize the pre-mine environmental
condition of the permit area. This work includes surveys of cultural resources,
soils, vegetation, wildlife, assessment of surface and ground water hydrology,
climatology and wetlands. In conducting this work, we collect geologic data to
define and model the soil and rock structures and coal that we will mine. We
develop mine and reclamation plans by utilizing this geologic data and
incorporating elements of the environmental data. The mine and reclamation plan
incorporates the provisions of the Surface Mining Control and Reclamation Act,
the state programs and the complementary environmental programs that impact coal
mining. Also included in the permit application are documents defining ownership
and agreements pertaining to coal, minerals, oil and gas, water rights, rights
of way, and surface land and documents required of the Office of Surface
Mining's Applicant Violator System.
Once a permit application is prepared and submitted to the regulatory
agency, it goes through a completeness review, technical review and public
notice and comment period before it can be approved. Some Surface Mining Control
and Reclamation Act mine permits can take over a year to prepare, depending on
the size and complexity of the mine and often take six months to sometimes two
years to receive approval. Regulatory authorities have considerable discretion
in the timing of the permit issuance and the public has rights to comment on and
otherwise engage in the permitting process, including through intervention in
the courts.
We do not believe there are any substantial matters that pose a risk to
maintaining our existing mining permits or hinder our ability to acquire future
mining permits. It is our policy to ensure that our operations are in full
compliance with the requirements of the Surface Mining Control and Reclamation
Act and the state laws and regulations governing mine reclamation.
ADDITIONAL INFORMATION
We file annual, quarterly and current reports, proxy statements and other
information with the SEC. You may access and read our SEC filings through the
SEC's Internet site at www.sec.gov. This site contains reports and other
information that we file electronically with the SEC. You may also read and copy
any document we file at the SEC's public reference room located at 450 Fifth
Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for
further information on the public reference room.
You may request copies of the filings, at no cost, by telephone at (314)
342-3400 or by mail at: Peabody Energy Corporation, 701 Market Street, Suite
700, St. Louis, Missouri 63101, attention: Investor Relations.
18
ITEM 2. PROPERTIES.
Coal Reserves
We had an estimated 9.1 billion tons of proven and probable coal reserves
as of December 31, 2001, of which approximately 38% is compliance coal and 62%
is non-compliance coal. We own approximately 46% of these reserves and lease
property containing the remaining 54%. Compliance coal is defined by Phase II of
the Clean Air Act as coal having sulfur dioxide content of 1.2 pounds or less
per million Btu. Electricity generators are able to use coal that exceeds these
specifications by using emissions reduction technology, using emission allowance
credits or blending higher sulfur coal with lower sulfur coal.
Below is a table summarizing the locations and reserves of our major
operating units.
PROVEN AND PROBABLE
RESERVES AS OF
DECEMBER 31, 2001(1)
----------------------------
OWNED LEASED TOTAL
OPERATING REGIONS LOCATIONS TONS TONS TONS
----------------- --------- ------- ------- -----
(Tons in millions)
Powder River Basin Wyoming and Montana................................................... 190 2,868 3,058
Southwest Arizona, Colorado and New Mexico...................................... 718 584 1,302
Appalachia West Virginia......................................................... 256 447 703
Midwest Illinois, Indiana and Kentucky........................................ 2,993 1,056 4,049
----- ----- -----
Total...................................................................................... 4,157 4,955 9,112
===== ===== =====
----------
(1) Reserves have been adjusted to take into account estimated losses involved
in producing a saleable product.
Proven and probable coal reserves are classified as follows:
Proven Reserves--Reserve estimates in this category have the highest
degree of geologic assurance. Proven coal lies within one-quarter mile of a
valid point of measurement or point of observation (such as exploratory
drill holes or previously mined areas) supporting such measurements. The
sites for thickness measurement are so closely spaced, and the geologic
character is so well defined, that the average thickness, areal extent,
size, shape and depth of coalbeds are well established.
Probable Reserves--Reserve estimates in this category have a moderate
degree of geologic assurance. There are no sample and measurement sites in
areas of indicated coal. However, a single measurement can be used to
classify coal lying beyond measured as probable. Probable coal lies more
than one-quarter mile, but less than three quarters of a mile from a point
of thickness measurement. Further exploration is necessary to place
probable coal into the proven category.
In areas where geologic conditions indicate potential inconsistencies
related to coal reserves, we perform additional drilling to ensure the
continuity and mineability of the coal reserves. Consequently, sampling in those
areas involves drill holes that are spaced closer together than those distances
cited above.
We prepare our reserve estimates based on geological data assembled and
analyzed by our staff, which includes various geologists and engineers. We
periodically update our reserve estimates to reflect production of coal from the
reserves and new drilling or other data received. Accordingly, reserve estimates
will change from time to time to reflect mining activities, analysis of new
engineering and geological data, changes in reserve holdings, modification of
mining methods and other factors. We maintain reserve information, including the
quantity and quality (where available) of reserves as well as production rates,
surface ownership, lease payments and other information relating to our coal
reserve and land holdings, through a computerized land management system that we
developed.
Our reserve estimates are predicated on information obtained from our
extensive drilling program, which totals nearly 500,000 individual drill holes.
We compile data from individual drill holes in a computerized drill-hole system
from which the depth, thickness and, where core drilling is used, the quality of
the coal are determined. The density of the drill pattern determines whether the
reserves will be classified as proven or probable. The drill hole data are then
input into our computerized land management system, which overlays the
geological data with data on ownership or control of the mineral and surface
interests to determine the extent of our reserves in a given area. In addition,
we periodically engage independent mining and geological consultants to review
estimates of our coal reserves. The most recent of these reviews, which was
completed in March 2001, included a review of the procedures used by us to
prepare our internal estimates, verification of the accuracy of selected
property
19
reserve estimates and retabulation of reserve groups according to standard
classifications of reliability. This study confirmed that we controlled
approximately 9.5 billion tons of proven and probable reserves as of April 1,
2000. After adjusting for production through December 31, 2001, proven and
probable reserves totaled 9.1 billion tons.
We have numerous federal coal leases that are administered by the
Department of the Interior under the Federal Coal Leasing Amendments Act of
1976. These leases cover our principal reserves in Wyoming and other reserves in
Montana and Colorado. Each of these leases continues indefinitely, provided
there is diligent development of the property and continued operation of the
related mine or mines. The Bureau of Land Management has asserted the right to
adjust the terms and conditions of these leases, including rent and royalties,
after the first 20 years of their term and at 10-year intervals thereafter.
Annual rents under our federal coal leases are now set at $3.08 per acre.
Production royalties on federal leases are set by statute at 12.5% of the gross
proceeds of coal mined and sold for surface-mined coal and 8% for
underground-mined coal. The federal government limits by statute the amount of
federal land that may be leased by any company and its affiliates at any time to
75,000 acres in any one state and 150,000 acres nationwide. As of December 31,
2001, we leased or had applied to lease 26,249 acres of federal land in
Colorado, 10,322 acres in Montana and 30,225 acres in Wyoming, for a total of
66,796 nationwide.
Similar provisions govern three coal leases with the Navajo and Hopi Indian
tribes. These leases cover coal contained in 65,000 acres of land in northern
Arizona lying within the boundaries of the Navajo Nation and Hopi Indian
reservations. We also lease coal-mining properties from various state
governments.
Private coal leases normally have terms of between ten and 20 years and
usually give us the right to renew the lease for a stated period or to maintain
the lease in force until the exhaustion of mineable and merchantable coal
contained on the relevant site. These private leases provide for royalties to be
paid to the lessor either as a fixed amount per ton or as a percentage of the
sales price. Many leases also require payment of a lease bonus or minimum
royalty, payable either at the time of execution of the lease or in periodic
installments.
The terms of our private leases are normally extended by active production
on or near the end of the lease term. Leases containing undeveloped reserves may
expire or these leases may be renewed periodically. With a portfolio of
approximately 9.1 billion tons, we believe that we have sufficient reserves to
replace capacity from depleting mines for the foreseeable future and that our
reserve base is one of our strengths. We believe that the current level of
production at our major mines is sustainable for the foreseeable future.
Consistent with industry practice, we conduct only limited investigation of
title to our coal properties prior to leasing. Title to lands and reserves of
the lessors or grantors and the boundaries of our leased properties are not
completely verified until we prepare to mine those reserves.
20
The following chart provides a summary, by mining complex, of production
for fiscal years ended March 31, 2000 and 2001 and the nine months ended
December 31, 2001, tonnage of coal reserves that is assigned to our operating
mines, our property interest in those reserves and other characteristics of the
facilities.
PRODUCTION AND ASSIGNED RESERVES (1)
(Tons in millions)
Sulfur Content (2)
Production ---------------------------------
---------------------------------------- less than more than
Nine Months Year Year 1.2 lbs. 1.2 to 2.5 lbs.
Ended Ended Ended sulfur dioxide sulfur dioxide
Dec. 31, March 31, March 31, Type of per per
Mining Complex 2001 2001 2000 Coal Million Btu Million Btu
------------------------------------------------------------------------------------------------------------------------------------
Northern Appalachia:
Federal No. 2 3.6 4.7 4.2 Steam - -
---------------------------------------- ---------------------------------
Northern Appalachia 3.6 4.7 4.2 - -
Southern Appalachia:
Big Mountain/White's Branch 1.6 2.0 2.1 Steam 4.7 16.6
Harris #1 2.7 3.9 3.2 Steam/Metallurgical 0.4 11.5
Rocklick 2.5 3.2 3.3 Steam/Metallurgical 31.3 11.2
Wells 1.2 1.6 2.0 Steam/Metallurgical 8.9 2.4
---------------------------------------- ---------------------------------
Southern Appalachia 7.9 10.7 10.5 45.3 41.7
Midwest:
Camps (4) 2.4 5.4 6.4 Steam - -
Hawthorn (5) - - 2.1 Steam - -
Lynnville (6) - - 2.2 Steam - -
Marissa (7) - - 2.3 Steam - -
Midwest 1.3 1.2 1.2 Steam - -
Patriot 1.8 2.0 1.9 Steam - -
Black Beauty
Air Quality No. 1 1.4 1.7 1.8 Steam 54.9 -
Riola No 1 (8) 0.8 1.0 0.4 Steam - -
Miller Creek / Sugar Ridge (9) 0.8 0.1 - Steam - -
Francisco 2.0 2.2 2.8 Steam - -
Columbia 0.5 0.8 0.7 Steam - -
Discovery (10) 0.8 0.3 0.6 Steam - -
Farmersburg 2.9 4.1 3.5 Steam - 26.8
Birdwell - 0.9 1.4 Steam - -
Somerville Central (11) 2.4 2.0 - Steam - -
Somerville North / West 2.3 2.8 2.0 Steam - -
Viking / Corning 1.1 1.0 1.3 Steam - 2.3
Sugar Camp Coal 4.1 5.0 5.6 Steam - -
West Fork (12) - 0.2 0.5 Steam - -
Deanefield 0.1 0.8 0.4 Steam - -
---------------------------------------- ---------------------------------
Midwest 24.7 31.5 37.0 54.9 29.1
Powder River Basin:
Big Sky 2.0 1.7 2.4 Steam - 24.5
North Antelope/Rochelle 56.3 72.3 68.3 Steam 1,360.3 -
Caballo 20.7 25.6 26.1 Steam 801.2 31.5
---------------------------------------- ---------------------------------
Powder River Basin 79.0 99.6 96.9 2,161.5 56.0
Southwest:
Black Mesa 3.4 4.9 4.5 Steam 79.0 11.8
Kayenta 6.2 8.5 7.6 Steam 235.1 85.6
Lee Ranch 4.7 5.2 4.9 Steam - 161.8
Seneca 1.3 1.5 1.4 Steam 13.3 0.1
---------------------------------------- ---------------------------------
Southwest 15.6 20.1 18.5 327.4 259.3
---------------------------------------- ---------------------------------
Total 130.9 166.6 167.1 2,589.1 386.1
======================================== =================================
Sulfur Content (2)
------------------
more than As As of December 31, 2001
2.5 lbs. Received --------------------------------------------------------------
sulfur dioxide Btu Assigned
per per Proven and Under-
Mining Complex Million Btu Pound (3) Probable Reserves Owned Leased Surface ground
------------------------------------------------------------------------------------------------------------------------------------
Northern Appalachia:
Federal No. 2 41.4 13,335 41.4 41.4 - - 41.4
----------- --------------------------------------------------------------
Northern Appalachia 41.4 41.4 41.4 - - 41.4
Southern Appalachia:
Big Mountain/White's Branch - 12,538 21.3 - 21.3 - 21.3
Harris #1 - 13,473 11.9 - 11.9 - 11.9
Rocklick - 13,067 42.5 - 42.5 24.6 17.9
Wells - 13,692 11.3 - 11.3 - 11.3
----------- --------------------------------------------------------------
Southern Appalachia - 87.0 - 87.0 24.6 62.4
Midwest: -
Camps (4) 117.9 11,242 117.9 3.6 114.3 - 117.9
Hawthorn (5) - N/A N/A - - - -
Lynnville (6) - N/A N/A - - - -
Marissa (7) - N/A N/A - - - -
Midwest 9.0 10,596 9.0 6.9 2.1 6.9 2.1
Patriot 53.6 10,922 53.6 0.2 53.4 5.8 47.8
Black Beauty
Air Quality No. 1 - 11,040 54.9 0.5 54.4 - 54.9
Riola No 1 (8) 10.7 10,683 10.7 - 10.7 - 10.7
Miller Creek / Sugar Ridge (9) 2.2 11,504 2.2 0.7 1.5 2.2 -
Francisco 14.7 11,187 14.7 3.6 11.1 14.7 -
Columbia 0.3 11,502 0.3 - 0.3 0.3 -
Discovery (10) 0.8 10,583 0.8 - 0.8 - 0.8
Farmersburg - 10,871 26.8 19.2 7.6 26.8 -
Birdwell - N/A N/A - - - -
Somerville Central (11) 16.7 11,066 16.7 12.4 4.3 16.7 -
Somerville North / W est 12.7 11,038 12.7 10.0 2.7 12.7 -
Viking / Corning 11.7 11,697 14.0 - 14.0 14.0 -
Sugar Camp Coal 86.2 12,029 86.2 27.2 59.0 7.6 78.6
West Fork (12) - N/A N/A - - - -
Deanefield 0.1 10,716 0.1 - 0.1 0.1 -
----------- --------------------------------------------------------------
Midwest 336.6 420.6 84.3 336.3 107.8 312.8
Powder River Basin:
Big Sky 16.8 8,658 41.3 - 41.3 41.3 -
North Antelope/Rochelle - 8,756 1,360.3 - 1,360.3 1,360.3 -
Caballo 0.7 8,692 833.4 - 833.4 833.4 -
----------- --------------------------------------------------------------
Powder River Basin 17.5 2,235.0 - 2,235.0 2,235.0 -
Southwest:
Black Mesa - 10,792 90.8 - 90.8 90.8 -
Kayenta 5.1 10,948 325.8 - 325.8 325.8 -
Lee Ranch 8.7 10,054 170.5 165.1 5.4 170.5 -
Seneca 0.6 10,426 14.0 1.1 12.9 14.0 -
----------- --------------------------------------------------------------
Southwest 14.4 601.1 166.2 434.9 601.1 -
----------- --------------------------------------------------------------
Total 409.9 3,385.1 291.9 3,093.2 2,968.5 416.6
=========== ==============================================================
21
The following chart provides a summary of the amount of our proven and
probable coal reserves in each state, the predominant type of coal mined in the
applicable state, our property interest in the reserves and other
characteristics of the facilities.
ASSIGNED AND UNASSIGNED PROVEN AND PROBABLE COAL RESERVES(1)
AS OF DECEMBER 31, 2001
(Tons in millions)
Total Tons Proven and
----------------------------- Probable Type of
Location Assigned Unassigned Reserves Proven Probable Coal
-------------------------------------------------------------------------------------------------------------------------------
Northern Appalachia:
Ohio - 40.4 40.4 28.1 12.3 Steam
West Virginia 41.4 219.2 260.6 94.5 166.1 Steam
--------------------------------------------------------------
Northern Appalachia 41.4 259.6 301.0 122.6 178.4
Southern Appalachia: Steam/
West Virginia 87.0 314.9 401.9 279.5 122.4 Metallurgical
--------------------------------------------------------------
Southern Appalachia 87.0 314.9 401.9 279.5 122.4
Midwest:
Illinois - 2,233.9 2,233.9 1,039.7 1,194.2 Steam
Indiana - 324.7 324.7 208.2 116.5 Steam
Kentucky 180.5 879.0 1,059.5 633.5 426.0 Steam
Black Beauty 240.1 177.2 417.3 384.6 32.7 Steam
(Illinois, Indiana, Kentucky )
Missouri - 11.8 11.8 10.7 1.1 Steam
Oklahoma - 1.4 1.4 1.4 - Steam
--------------------------------------------------------------
Midwest 420.6 3,628.0 4,048.6 2,278.1 1,770.5
Powder River Basin:
Montana 41.3 301.3 342.6 314.3 28.3 Steam
Wyoming 2,193.7 521.4 2,715.1 2,604.9 110.2 Steam
--------------------------------------------------------------
Powder River Basin 2,235.0 822.7 3,057.7 2,919.2 138.5
Southwest:
Arizona 416.6 - 416.6 416.6 - Steam
Colorado 14.0 152.9 166.9 136.5 30.4 Steam
New Mexico 170.5 544.7 715.2 358.0 357.2 Steam
Utah - 3.6 3.6 - 3.6 Steam
--------------------------------------------------------------
Southwest 601.1 701.2 1,302.3 911.1 391.2
--------------------------------------------------------------
Total Proven and Probable 3,385.1 5,726.4 9,111.5 6,510.5 2,601.0
==============================================================
Sulfur Content (2)
-------------------------------------------------------------------
less than more than more than
1.2 lbs. 1.2 to 2.5 lbs 2.5 lbs. As
sulfur dioxide sulfur dioxide sulfur dioxide Received
per per per Btu
Location Million Btu Million Btu Million Btu per pound (13)
---------------------------------------------------------------------------------------------------------------
Northern Appalachia:
Ohio - - 40.4 11,255
West Virginia - 116.6 144.0 12,723
---------------------------------------------
Northern Appalachia - 116.6 184.4
Southern Appalachia:
West Virginia 216.9 149.7 35.3 13,202
---------------------------------------------
Southern Appalachia 216.9 149.7 35.3
Midwest:
Illinois 4.9 65.9 2,163.1 10,290
Indiana 0.1 2.9 321.7 10,533
Kentucky 0.2 0.3 1,059.0 10,939
Black Beauty 54.9 30.4 332.0 11,414
(Illinois, Indiana, Kentucky )
Missouri - - 11.8 10,036
Oklahoma - - 1.4 N/A
---------------------------------------------
Midwest 60.1 99.5 3,889.0
Powder River Basin:
Montana 42.1 138.7 161.8 8,594
Wyoming 2,541.1 140.6 33.4 8,690
---------------------------------------------
Powder River Basin 2,583.2 279.3 195.2
Southwest:
Arizona 314.1 97.5 5.0 10,914
Colorado 64.6 101.7 0.6 10,763
New Mexico 243.7 434.7 36.8 9,235
Utah 3.6 - - 10,444
---------------------------------------------
Southwest 626.0 633.9 42.4
---------------------------------------------
Total Proven and Probable 3,486.2 1,279.0 4,346.3
=============================================
Reserve Control Mining Method
-----------------------------------------------
Location Owned Leased Surface Underground
-------------------------------------------------------------------------------------------
Northern Appalachia:
Ohio 39.7 0.7 - 40.4
West Virginia 205.1 55.5 - 260.6
----------------------------------------------
Northern Appalachia 244.8 56.2 - 301.0
Southern Appalachia:
West Virginia 11.6 390.3 43.0 358.9
----------------------------------------------
Southern Appalachia 11.6 390.3 43.0 358.9
Midwest:
Illinois 2,163.8 70.1 49.9 2,184.0
Indiana 271.8 52.9 92.6 232.1
Kentucky 397.9 661.6 121.8 937.7
Black Beauty 157.2 260.1 113.2 304.1
(Illinois, Indiana, Kentucky )
Missouri 1.1 10.7 11.8 -
Oklahoma 1.4 - - 1.4
----------------------------------------------
Midwest 2,993.2 1,055.4 389.3 3,659.3
Powder River Basin:
Montana 189.2 153.4 342.6 -
Wyoming 1.0 2,714.1 2,715.1 -
----------------------------------------------
Powder River Basin 190.2 2,867.5 3,057.7 -
Southwest:
Arizona - 416.6 416.6 -
Colorado 4.6 162.3 14.6 152.3
New Mexico 709.8 5.4 682.9 32.3
Utah 3.6 - - 3.6
----------------------------------------------
Southwest 718.0 584.3 1,114.1 188.2
----------------------------------------------
Total Proven and Probable 4,157.8 4,953.7 4,604.1 4,507.4
==============================================
22
--------------
(1) Assigned reserves represent recoverable coal reserves that we have
committed to mine at locations operating as of December 31, 2001.
Unassigned reserves represent coal at suspended locations and coal that has
not been committed, and that would require new mine development, mining
equipment or plant facilities before operations could begin on the
property.
(2) Compliance coal is defined by Phase II of the Clean Air Act as coal having
sulfur dioxide content of 1.2 pounds or less per million Btu.
Non-compliance coal is defined as coal having sulfur dioxide content in
excess of this standard. Electricity generators are able to use coal that
exceeds these specifications by using emissions reduction technology, using
emissions allowance credits or blending higher sulfur coal with lower
sulfur coal.
(3) As-received Btu per pound includes the weight of moisture in the coal on an
as-sold basis.
(4) The Camp No. 1 mine at the Camp operating unit was closed in October 2000.
(5) Production at the Hawthorn mine has been suspended since December 1999.
(6) Production at the Lynnville mine has been suspended since December 1999.
(7) The Marissa mine was closed in October 1999.
(8) The Riola No. 1 mine was acquired in October 1999.
(9) The Sugar Ridge mine opened in December 2000.
(10) The Discovery mine was temporarily idled from April 2000 to July 2000.
(11) The Somerville Central mine opened in March 2000.
(12) The West Fork mine closed in August 2000.
(13) As-received Btu per pound includes the weight of moisture in the coal on an
as sold basis. The following table reflects the average moisture content
used in the determination of as-received Btu for the region:
Northern Appalachia.......................................................................... 6.0%
Southern Appalachia.......................................................................... 7.0%
Midwest:
Illinois................................................................................ 14.0%
Indiana................................................................................. 15.0%
Kentucky................................................................................ 12.5%
Black Beauty Coal Company............................................................... 14.5%
Missouri/Oklahoma....................................................................... 12.0%
Powder River Basin:
Montana................................................................................. 26.5%
Wyoming................................................................................. 27.5%
Southwest:
Arizona................................................................................. 13.0%
Colorado................................................................................ 14.0%
New Mexico.............................................................................. 15.5%
Utah.................................................................................... 15.5%
23
Resource Development
We hold approximately 9.1 billion tons of proven and probable coal
reserves. Our Resource Development group constantly reviews this reserve base
for opportunities to generate revenues through the sale of non-strategic coal
reserves and surface land. In addition, we generate revenue through royalties
from coal reserves leased to third parties and farm income from surface land
under third party contracts. The Resource Development group is also pursuing
opportunities in the area of coalbed methane extraction in the United States
through a subsidiary, Peabody Natural Gas, LLC. In January 2001, we purchased
the coalbed methane assets of JN Exploration & Production Limited Partnership
for approximately $10 million.
ITEM 3. LEGAL PROCEEDINGS.
From time to time, we are involved in legal proceedings arising in the
ordinary course of business. We believe we have recorded adequate reserves for
these liabilities and that there is no individual case pending that is likely to
have a material adverse effect on our financial condition or results of
operations. We discuss our significant legal proceedings below.
Navajo Nation
On June 18, 1999, the Navajo Nation served our subsidiaries, Peabody
Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company
("Peabody Western"), with a complaint that had been filed in the U. S. District
Court for the District of Columbia. Other defendants in the litigation are one
customer, one current employee and one former employee. The Navajo Nation has
alleged 16 claims, including Civil Racketeer Influenced and Corrupt
Organizations Act, or RICO, violations and fraud and tortious interference with
contractual relationships. The complaint alleges that the defendants jointly
participated in unlawful activity to obtain favorable coal lease amendments.
Plaintiff also alleges that defendants interfered with the fiduciary
relationship between the United States and the Navajo Nation. The plaintiff is
seeking various remedies including actual damages of at least $600 million,
which could be trebled under the RICO counts, punitive damages of at least $1
billion, a determination that Peabody Western's two coal leases for the Kayenta
and Black Mesa mines have terminated due to Peabody Western's breach of these
leases and a reformation of the two coal leases to adjust the royalty rate to
20%. All defendants have filed motions to dismiss the complaint. On March 15,
2001, the court denied the Peabody defendants' motions to dismiss. Discovery for
this litigation has commenced.
In March 2000, the Hopi Tribe filed a motion to intervene in this lawsuit.
The Hopi Tribe has alleged seven claims, including fraud. The Hopi Tribe is
seeking various remedies, including unspecified actual and punitive damages, and
reformation of its coal lease. On March 15, 2001, the court granted the Hopi
Tribe's motion. On April 17, 2001, we filed a motion to dismiss the Hopi
complaint. On October 31, 2001, the court denied our motion to dismiss the Hopi
complaint.
On February 21, 2002, our subsidiaries commenced a lawsuit against the
Navajo Nation in the U.S. District Court for the District of Arizona seeking
enforcement of an arbitration award or, alternatively, to compel arbitration
pursuant to the April 1, 1998 Arbitration Agreement with the Navajo Nation. The
complaint was filed under seal because it describes material that is the subject
of an arbitration confidentiality agreement. On February 22, 2002, our
subsidiaries filed in the U.S. District Court for the District of Columbia a
motion for leave to file an amended answer and conditional counterclaim. Our
subsidiaries sought leave to file the counterclaim under seal because it
describes material that is the subject of the same arbitration confidentiality
agreement. The counterclaim is conditional because our subsidiaries contend that
the lease provisions the Navajo Nation seeks to invalidate have previously been
upheld in an arbitration proceeding and are not subject to further litigation.
On March 4, 2002, our subsidiaries filed in the U.S. District Court for the
District of Columbia a motion to transfer that case to Arizona or,
alternatively, to stay the District of Columbia litigation.
While the outcome of litigation is subject to uncertainties, based on our
preliminary evaluation of the issues and the potential impact on us, we believe
this matter will be resolved without a material adverse effect on our financial
condition or results of operations.
Salt River Project Agricultural Improvement and Power District--Price Review
In May 1997, Salt River Project Agricultural Improvement and Power
District, or Salt River, acting for all owners of the Navajo Generating Station,
exercised their contractual option to review certain cumulative cost changes
during a five-year period from 1992 to 1996. Peabody Western sells approximately
7 to 8 million tons of coal per year to the owners of the Navajo Generation
Station under a long-term contract. In July 1999, Salt River notified Peabody
Western that it believed the owners were entitled to a price decrease of $1.92
per ton as a result of the review. Salt River also claimed entitlement to a
retroactive price adjustment to January 1997 and that an overbilling of $50.5
million had occurred during the same five-year period. In October 1999, Peabody
Western notified Salt River that it believed it was entitled to a $2.00 per ton
price increase as a result of the review. The parties were unable to settle the
dispute and Peabody Western filed a demand for arbitration in September 2000.
The arbitration panel has been selected and the hearing is scheduled to start on
April 8, 2002.
24
On February 12, 2001 in a related action, Salt River, again acting for all
owners of the Navajo Generating Station, filed a lawsuit against Peabody Western
in the Superior Court in Maricopa County in Arizona. This lawsuit seeks to
compel arbitration of issues that Peabody Western does not believe are subject
to arbitration, namely, (1) the effective date of any price change resulting
from the resolution of the price review arbitration discussed above and (2) the
validity of Salt River's $50.5 million claim for alleged overcharges by Peabody
Western for the period from 1992 through 1996 (the five-year period that was the
subject of the price review). If the court declines to compel arbitration of
these issues, the lawsuit alternatively requests that the court find in favor of
Salt River on these issues. We have removed this matter to the U.S. District
Court for the District of Arizona.
On October 3, 2001, the U.S. District Court issued an order compelling
arbitration with respect to the effective date of any price change and
conditionally compelling arbitration with respect to the validity of Salt
River's $50.5 million claim. We have filed an appeal of this decision with the
U.S. Ninth Circuit Court of Appeals.
While the outcome of arbitration and litigation is subject to
uncertainties, based on our preliminary evaluation of the issues and the
potential impact on us, we believe that the matter will be resolved without a
material adverse effect on our financial condition or results of operations.
Salt River Project Agricultural Improvement and Power District--Mine Closing and
Retiree Health Care
Salt River and the other owners of the Navajo Generating Station filed a
lawsuit on September 27, 1996 in the Superior Court of Maricopa County in
Arizona seeking a declaratory judgment that certain costs relating to final
reclamation, environmental monitoring work and mine decommissioning and costs
primarily relating to retiree health care benefits are not recoverable by our
subsidiary, Peabody Western Coal Company, under the terms of a coal supply
agreement dated February 18, 1977. The contract expires in 2011.
Peabody Western filed a motion to compel arbitration of these claims, which
was granted in part by the trial court. Specifically, the trial court ruled that
the mine decommissioning costs were subject to arbitration but that the retiree
health care costs were not subject to arbitration. Peabody Western appealed and
the Arizona Court of Appeals affirmed the trial court's order. Peabody Western
filed a petition for review with the Arizona Supreme Court. That petition was
denied on September 24, 1998. As a result, Peabody Western, Salt River and the
other owners of the Navajo Generating Station will arbitrate the mine
decommissioning costs issue and will litigate the retiree health care costs
issue.
While the outcome of litigation and arbitration is subject to
uncertainties, based on our preliminary evaluation of the issues and the
potential impact on us, and based on outcomes in similar proceedings, we believe
that the matter will be resolved without a material adverse effect on our
financial condition or results of operations.
Southern California Edison Company
In response to a demand for arbitration by one of our subsidiaries, Peabody
Western, Southern California Edison and the other owners of the Mohave
Generating Station filed a lawsuit on June 20, 1996 in the Superior Court of
Maricopa County, Arizona. The lawsuit sought a declaratory judgment that mine
decommissioning costs and retiree health care costs are not recoverable by
Peabody Western under the terms of a coal supply agreement dated May 26, 1976.
The contract expires in 2005.
Peabody Western filed a motion to compel arbitration which was granted by
the trial court. Southern California Edison appealed this order to the Arizona
Court of Appeals, which denied its appeal. Southern California Edison then
appealed the order to the Arizona Supreme Court which remanded the case to the
Arizona Court of Appeals and ordered the appellate court to determine whether
the trial court was correct in determining that Peabody Western's claims are
arbitrable. The Arizona Court of Appeals ruled that neither mine decommissioning
costs nor retiree health care costs are to be arbitrated and that both issues
should be resolved in litigation. The matter has been remanded to the Superior
Court of Maricopa County, Arizona, where a trial has been set for May 20, 2002.
Peabody Western answered the complaint and asserted counterclaims. The court
then permitted Southern California Edison to amend its complaint to add a claim
of overcharges of at least $19.2 million by Peabody Western.
By order filed July 2, 2001, the court granted Peabody Western's motion for
summary judgment on liability with respect to retiree healthcare costs. Southern
California Edison filed a motion for reconsideration, which was denied by the
court on October 16, 2001. Peabody Western filed a supplemental motion for
summary judgment on liability with respect to mine decommissioning costs. The
court denied Peabody Western's supplemental motion for summary judgment in an
order filed on February 6, 2002.
While the outcome of litigation is subject to uncertainties, based on our
preliminary evaluation of the issues and the potential impact on us, and based
on outcomes in similar proceedings, we believe that the matter will be resolved
without a material
25
adverse effect on our financial condition or results of operations. We had a
receivable on our balance sheet at December 31, 2001 for the mine closing costs
associated with the Salt River and Southern California Edison matters of $83.8
million.
Social Security Administration
In 1999, Eastern Associated Coal Corp. and Peabody Coal Company filed a
lawsuit in the U.S. District Court for the Western District of Kentucky against
the Social Security Administration asserting that the Social Security
Administration, under the Coal Act, had improperly assigned certain
beneficiaries to us. Subsequently, Peabody Coal and Eastern Associated moved for
summary judgment on this claim. Summary judgment was granted and in 2000, the
Social Security Administration filed an appeal of the district court's decision
with the U.S. Court of Appeals for the Sixth Circuit. On June 21, 2001, the
Sixth Circuit Court denied the Social Security Administration's appeal. The U.S.
Supreme Court granted the federal government's petition for certiorari in
January 2002 and the case will be argued in the term commencing October 2002. We
believe that the matter will be resolved without a material adverse effect on
our financial condition or results of operations.
Indiana Michigan Power Company
On September 27, 2001, our subsidiaries, Caballo Coal Company and Peabody
COALSALES Company, filed suit in the U.S. District Court for the Eastern
District of Missouri against Indiana Michigan Power Company, AEP Energy
Services, Inc. and American Electric Power Service Corporation. Our subsidiaries
contend that Indiana Michigan Power and American Electric Power Service
Corporation breached their obligations under a coal supply agreement dated
January 17, 1974. The agreement provides for a price renegotiation every five
years. Our subsidiaries called for a price renegotiation in 2001, effective for
coal delivered during 2002 through 2006. Our subsidiaries assert that Indiana
Michigan Power and American Electric Power Service Corporation did not negotiate
in good faith in that they did not submit a competitive offer to supply coal, as
required under the contract, when they did not accept the $8.35 per ton offer
submitted by our subsidiaries. Our subsidiaries are seeking specific performance
of the agreement, injunctive relief, declaratory judgment, damages for breach of
contract and damages for tortious interference committed by AEP Energy Services.
In January 2002, the court denied our motion for a preliminary injunction. We
have filed an appeal of that ruling.
Since the court did not grant our motion for a preliminary injunction, we
are not shipping any coal to Indiana Michigan Power under this contract. Indiana
Michigan Power contends that the contract terminated on December 31, 2001, which
ended its obligation to purchase 3.5 million tons of coal annually. While the
outcome of litigation is subject to uncertainties, based on our preliminary
evaluation of the issues and the potential impact on us, we believe that the
only potential adverse impact on us, if Indiana Michigan Power is ultimately
successful, will be our inability to ship further coal to the utility under the
contract.
Department of Justice
During 2001, along with other coal producers in the Powder River Basin in
Wyoming, we received a request for information from the U.S. Department of
Justice regarding an alleged agreement to restrict production of coal from this
region. We have responded to that request.
Environmental
Federal and State Superfund Statutes. Superfund and similar state laws
create liability for investigation and remediation in response to releases of
hazardous substances in the environment and for damages to natural resources.
Under that legislation and many state Superfund statutes, joint and several
liability may be imposed on waste generators, site owners and operators and
others regardless of fault.
Our subsidiary, Gold Fields Mining Corporation ("Gold Fields"), its
predecessors and its former parent company are or may become parties to
environmental proceedings that have commenced or may commence in the United
States in relation to certain sites previously owned or operated by those
entities or companies associated with them. We have agreed to indemnify Gold
Fields' former parent company for any environmental claims resulting from any
activities, operations or conditions that occurred prior to the sale of Gold
Fields to us. Gold Fields is currently involved in environmental investigation,
litigation or remediation at ten sites.
These ten sites were formerly owned or operated by Gold Fields. The
Environmental Protection Agency has placed four of these sites on the National
Priorities List, promulgated pursuant to Superfund, and one of the sites is on a
similar state priority list. There are a number of additional sites in the
United States that were previously owned or operated by such companies that
could give rise to environmental proceedings in which Gold Fields could incur
liabilities.
26
Where the sites were identified, independent environmental consultants were
employed in 1997 in order to assess the estimated total amount of the liability
per site and the proportion of those liabilities that Gold Fields is likely to
bear. The available information on which to base this review was very limited
since all of the sites except for two sites (on which no remediation is
currently taking place) are no longer owned by Gold Fields. Independent
environmental consultants conducted another assessment in 2000. We have accrued
liabilities of $46.6 million as of December 31, 2001 for the environmental
liabilities described above relating to Gold Fields that are included as part of
accrued reclamation and other environmental liabilities in our consolidated
balance sheet. Significant uncertainty exists as to whether these claims will be
pursued against Gold Fields in all cases, and where they are pursued, the amount
of the eventual costs and liabilities, which could be greater or less than this
provision. We believe that the remaining amount of the provision is adequate to
cover these environmental liabilities.
Although waste substances generated by coal mining and processing are
generally not regarded as hazardous substances for the purposes of Superfund and
similar legislation, some products used by coal companies in operations, such as
chemicals, and the disposal of these products are governed by the statute. Thus,
coal mines currently or previously owned or operated by us, and sites to which
we have sent waste materials, may be subject to liability under Superfund and
similar state laws.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of security holders during the quarter
ended December 31, 2001.
ITEM 4A. EXECUTIVE OFFICERS OF THE COMPANY
Set forth below are the names, ages as of March 15, 2002 and current
positions of our executive officers. Executive officers are appointed by, and
hold office at, the discretion of the Company's Board of Directors.
NAME AGE POSITION
---- --- --------
Irl F. Engelhardt 55 Chairman, Chief Executive Officer and Director
Richard M. Whiting 47 President, Chief Operating Officer and Director
Roger B. Walcott, Jr. 45 Executive Vice President-Corporate Development
Richard A. Navarre 41 Executive Vice President and Chief Financial Officer
Fredrick D. Palmer 57 Executive Vice President-Legal and External
Affairs and Secretary
Paul H. Vining 47 Executive Vice President-Sales and Trading
Jeffery L. Klinger 55 Vice President-Legal Services and Assistant Secretary
Sharon D. Fiehler 45 Vice President-Human Resources
Irl F. Engelhardt has been a director of the Company since 1998. He is
Chairman and Chief Executive Officer of the Company, a position he has held
since 1998. He served as Chief Executive Officer of a predecessor of the Company
from 1990 to 1998. He also served as Chairman of a predecessor of the Company
from 1993 to 1998 and as President from 1990 to 1995. Since joining a
predecessor of the Company in 1979, he has held various officer level positions
in the executive, sales, business development and administrative areas,
including serving as Chairman of Peabody Resources Ltd. (Australia) and Chairman
of Citizens Power LLC. Mr. Engelhardt also served as Co-Chief Executive Officer
and executive director of The Energy Group from February 1997 to May 1998,
Chairman of Cornerstone Construction & Materials, Inc. from September 1994 to
May 1995 and Chairman of Suburban Propane Company from May 1995 to February
1996. He also served as a director and Group Vice President of Hanson Industries
from 1995 to 1996. Mr. Engelhardt is Co-Chairman of the Coal Utilization
Research Council, Co-Chairman of the Coal Based Generators Stakeholders Group
and past Chairman of the National Mining Association and the Coal Industry
Advisory Board of the International Energy Agency. He is also a director of U.S.
Bank, N.A.
Richard M. Whiting has been a director of the Company since 1998. He is
also President and Chief Operating Officer of the Company, a position he has
held since 1998. Previously, Mr. Whiting served as President of Peabody
COALSALES Company from 1992 to 1998. He joined a predecessor of the Company in
1976 and has held a number of operations, sales and engineering positions both
at the corporate offices and at field locations. Mr. Whiting is currently
Chairman of the Bituminous Coal Operators' Association, Chairman of the National
Mining Association's Safety and Health Committee and a member of the National
Coal Council.
Roger B. Walcott, Jr. became Executive Vice President-Corporate Development
of our company in February 2001. Prior to that, he was Executive Vice President
of our company since June 1998. From 1981 to 1998, he was a Senior Vice
President and a
27
director with The Boston Consulting Group where he served a variety of clients
in strategy and operational assignments. He was also Chairman of The Boston
Consulting Group's Human Resource Capabilities Committee. Mr. Walcott holds an
MBA with high distinction from the Harvard Business School.
Richard A. Navarre became Executive Vice President and Chief Financial
Officer of our company in February 2001. Prior to that, he was Vice
President-Chief Financial Officer of our company since October 1999. Prior to
that, he was President of Peabody COALSALES Company from January 1998 to October
1999 and previously served as President of Peabody Energy Solutions, Inc. Prior
to his roles in sales and marketing, he was Vice President of Finance and served
as Vice President and Controller. He joined our company in 1993 as Director of
Financial Planning. Prior to joining us, Mr. Navarre was a senior manager with
KPMG Peat Marwick. Mr. Navarre is a member of the Trade and International
Affairs Committee and the Transportation Committee of the National Mining
Association. He is also a member of the NYMEX Coal Advisory Council. He also
serves on the Board of Advisors to the College of Business for Southern Illinois
University.
Fredrick D. Palmer became Executive Vice President-Legal and External
Affairs of our company in February 2001. He is responsible for our legal
affairs, state and federal government affairs, public relations and investor
relations. Prior to joining Peabody, he served for 15 years as chief executive
officer of Western Fuels Association, Inc. He most recently was of counsel in
the Washington, D.C. office of Shook Hardy & Bacon, a Kansas City-based law
firm. He received a BA and a JD from the University of Arizona.
Paul H. Vining became Executive Vice President-Sales and Trading of our
company in February 2001. Prior to that, he was President of Peabody COALSALES
Company from October 1999 to January 2001, and President of Peabody COALTRADE,
Inc. from March 1997 to October 1999, and Senior Vice President of Peabody
COALSALES Company from August 1995 to February 1997. Mr. Vining is a member of
the board of directors of the Coal Exporters Association.
Jeffery L. Klinger was named Vice President-Legal Services of our company
in May 1998. Prior to that, he had been our Vice President, Secretary and Chief
Legal Officer since October 1990. He served from 1986 to October 1990 as Eastern
Regional Counsel for Peabody Holding Company, from 1982 to 1986 as Director of
Legal and Public Affairs, Eastern Division of Peabody Coal Company and from 1978
to 1982 as Director of Legal and Public Affairs, Indiana Division of Peabody
Coal Company. He is a past President of the Indiana Coal Council and is
currently a trustee of the Energy and Mineral Law Foundation and a past
Treasurer and member of its Executive Committee. Mr. Klinger is also a member of
the National Mining Association's Legal Affairs Committee.
Sharon D. Fiehler has been Vice President of Human Resources of our company
since 1991, with executive responsibility for employee development, benefits,
compensation, employee relations and affirmative action programs. She joined
Peabody in 1981 as Manager-Salary Administration and has held a series of
employee relations, compensation and salaried benefits positions. Prior to
joining Peabody, Ms. Fiehler, who earned degrees in social work and psychology
and an MBA, was a personnel representative for Ford Motor Company. Ms. Fiehler
is a member of the National Mining Association's Human Resource Committee.
28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
In May 2001 we completed an initial public offering of our common stock and
sold 17.25 million shares to the public at an offering price of $28 per share.
Our net proceeds from the offering totaled $449.8 million. Our common stock is
listed on the New York Stock Exchange, under the symbol "BTU."
The table below sets forth the range of quarterly high and low sales prices
for our common stock on the New York Stock Exchange during the calendar quarters
indicated.
2001 HIGH LOW
---- ---
Second Quarter (from May 22, 2001) $38.05 $26.00
Third Quarter 32.00 22.20
Fourth Quarter 31.90 23.35
After completion of the offering, our authorized capital stock consisted of
(1) 150.0 million shares of common stock, par value $0.01 per share, of which
52.0 million shares of common stock are issued and outstanding, (2) 10.0 million
shares of preferred stock, par value $.01 per share, of which no shares are
issued and outstanding and (3) 40.0 million shares of series common stock, par
value $.01 per share, of which no shares are issued and outstanding. As of
February 15, 2002, there were approximately 243 holders of our common stock.
Dividend Policy
We paid dividends of $0.20 per share during the nine months ended December
31, 2001. The declaration and payment of dividends and the amount of dividends
will depend on our results of operations, financial condition, cash
requirements, future prospects, any limitations imposed by our debt instruments
and other factors deemed relevant by our board of directors. Our Senior Credit
Facility, as amended, allows us to pay annual dividends of up to the greater of
$25.0 million or 10% of consolidated EBITDA as defined in the facility. The
indentures governing our Senior Notes and Senior Subordinated Notes permit us to
pay annual dividends of up to the greater of 6% ($27.0 million) of the net
proceeds from our initial public offering, or additional amounts based on, among
other things, the sum of 50% of cumulative defined net income (since July 1,
1998) and 100% of the proceeds of our initial public offering. However, the
actual amount of any dividends will be determined by our board of directors.
Recent Sales of Unregistered Securities
We sold shares of and issued options for common stock and preferred stock
in the amounts, at the times, and for the aggregate amounts of consideration
listed below without registration under the Securities Act of 1933. Exemption
from registration under the Securities Act for each of the following sales is
claimed under Section 4(2) of the Securities Act because each of the
transactions were by the issuer and did not involve a public offering:
On March 31, 1999, we issued 72,164 shares of common stock to one of our
executives and 144,334 shares of common stock to eight executives of our
Citizens Power subsidiary in consideration for their services. Additionally, we
issued 826,986 options to purchase common stock at an exercise price of
$14.29 per share to our executives and other employees.
On July 1, 1999, we issued 52,675 options to purchase common stock at an
exercise price of $14.29 per share to our employees.
On January 1, 2000, we issued 6,300 shares of common stock to two
executives of our Citizens Power subsidiary in consideration for their services.
Additionally, we issued 320,461 options to purchase common stock at an exercise
price of $14.29 per share to our executives and to other employees.
On July 1, 2000, we issued 42,087 shares of common stock to three
executives in consideration for their services.(1) Additionally, we issued
398,929 options to purchase common stock at an exercise price of $14.29 per
share to our executives and other employees.
On October 1, 2000, we issued 49,350 shares of common stock at an exercise
price of $14.29 per share to our executives.
On December 29, 2000, we issued 83,255 shares of common stock to nine
executives in consideration for their services in exchange for other shares
previously issued to them.
On January 1, 2001, we issued 945,263 options to purchase common stock at
an exercise price of $14.29 per share to executives and to other employees.
On February 1, 2001, we issued 205,304 shares of common stock for an
aggregate consideration of $1,096,912 to 20 of our executives.
On February 12, 2001, we issued 63,000 options to purchase common stock at
an exercise price of $14.29 per share to one of our executives.
On April 9, 2001, we issued 11,466 shares of common stock for an aggregate
consideration of $61,261 to one of our executives.
--------
Notes: (1) These shares had been acquired by us from terminated employees.
Use of Proceeds
In connection with our initial public offering, the Securities and Exchange
Commission declared our Registration Statement on Form S-1 (File No. 333-55412)
relating to our common stock, $0.01 par value per share, effective on May 21,
2001. Lehman Brothers, Bear, Stearns & Co. Inc., Merrill Lynch & Co., Morgan
Stanley Dean Witter, UBS Warburg and A.G. Edwards & Sons, Inc. acted as
representatives of the underwriters for our initial public offering. We
completed the sale of all 17,250,000 shares of common stock registered under the
offering on May 22, 2001 and raised net proceeds of $449.8 million after
deducting total expenses of $33.2 million, comprised of the underwriters'
discounts and commissions of $27.2 million and other fees and expenses of $6.0
million. We did not make any direct or indirect payments to any of our
directors, officers or their associates under the offering; however, usual and
customary underwriting discounts and commissions were paid to Lehman Brothers
Inc. and Lehman Brothers International (Europe), each an affiliate of Lehman
Brothers Merchant Banking which beneficially owns 57% of our common stock.
We used the net proceeds from the offering to repay the remaining tranche B
term loan outstanding under the Senior Credit Facility of $125.0 million and
used $100.0 million to repay borrowings under our revolving credit facility that
were used to repay a portion of our 5% subordinated note. We also used $173.0
million of net proceeds to repurchase $80.0 million in principal amount of our
Senior Notes and $80.0 million in principal amount of our Senior Subordinated
Notes pursuant to a tender offer. In addition, we used $3.1 million and $12.7
million of proceeds to repurchase $2.9 million in principal amount of our Senior
Notes and $11.7 million in principal amount of our Senior Subordinated Notes,
respectively, in a private transaction. The remaining net proceeds were used for
the repayment of debt and for general corporate purposes. Except as described
above, none of the net proceeds from our initial public offering was used to
make direct or indirect payments to (1) any of our directors, officers or their
associates, (2) any person owning 10% or more of our equity securities, (3) any
of our affiliates or (4) any others.
ITEM 6. SELECTED FINANCIAL DATA.
The following table presents selected financial and other data about us and
our predecessor. We purchased our operating subsidiaries on May 19, 1998, and
prior to that date we had no substantial operations. The period ended March 31,
1999 is thus a full fiscal year, but includes results of operations only from
May 20, 1998. For periods prior to May 19, 1998, the results of operations are
for the operating subsidiaries acquired, which we refer to as our "predecessor
company" and which we include for comparative purposes.
In early 1999, we increased our equity interest in Black Beauty Coal
Company from 43.3% to 81.7%. Our results of operations include the consolidated
results of Black Beauty, effective January 1, 1999. Prior to that date, we
accounted for our investment in Black Beauty under the equity method, under
which we reflected our share of Black Beauty's results of operations as a
component of "Other revenues" in the consolidated statements of operations, and
our interest in Black Beauty's net assets within "Investments and other assets"
in the consolidated balance sheets.
In anticipation of the sale of Citizens Power, which occurred in August
2000, we classified Citizens Power as a discontinued operation as of March 31,
2000, and recorded an estimated loss on the sale of $78.3 million, net of income
taxes. We have adjusted our results of operations to reflect the classification
of Citizens Power as a discontinued operation for all periods presented.
On May 22, 2001, concurrent with our initial public offering, we converted
our Class A common stock and Class B common stock into a single class of common
stock, all on a one-for-one basis.
We have derived the selected historical financial data for our predecessor
for the year ended and as of March 31, 1998 and the period from April 1, 1998 to
May 19, 1998 and as of May 19, 1998, and the selected historical financial data
for our company for the period from May 20, 1998 to March 31, 1999 and as of
March 31, 1999, the years ended and as of March 31, 2000 and 2001 and the nine
months ended and as of December 31, 2001 from our predecessor company's and our
audited financial statements. You should read the following table in conjunction
with the financial statements, the related notes to those financial statements,
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations."
29
(Dollars in thousands, except share data)
Nine Months Period From
Ended Year Ended Year Ended May 20, 1998
December 31, March 31, March 31, Total Fiscal to
2001 2001 (1) 2000 (2) 1999 (3) March 31, 1999
------------ ----------- ------------ ------------- ---------------
RESULTS OF OPERATIONS DATA
Revenues
Sales $ 1,963,273 $ 2,579,104 $ 2,610,991 $ 2,249,887 $ 1,970,957
Other revenues 63,497 90,588 99,509 97,603 85,875
----------- ----------- ----------- ------------ ------------
Total revenues 2,026,770 2,669,692 2,710,500 2,347,490 2,056,832
Costs and expenses
Operating costs and expenses 1,677,426 2,165,090 2,178,664 1,887,846 1,643,718
Depreciation, depletion and amortization 174,587 240,968 249,782 204,698 179,182
Selling and administrative expenses 73,553 99,267 95,256 88,905 76,888
Gain on sale of Australian operations -- (171,735) -- -- --
Net gain on property and equipment disposals (14,327) (5,737) (6,439) (328) --
----------- ----------- ----------- ------------ ------------
Operating profit 115,531 341,839 193,237 166,369 157,044
Interest expense 88,686 197,686 205,056 180,327 176,105
Interest income (2,155) (8,741) (4,421) (20,194) (18,527)
----------- ----------- ----------- ------------ ------------
Income (loss) before income taxes and minority
interests 29,000 152,894 (7,398) 6,236 (534)
Income tax provision (benefit) 2,465 42,690 (141,522) 7,542 3,012
Minority interests 7,248 7,524 15,554 1,887 1,887
----------- ----------- ----------- ------------ ------------
Income (loss) from continuing operations 19,287 102,680 118,570 (3,193) (5,433)
Income (loss) from discontinued operations -- 12,925 (90,360) 4,678 6,442
----------- ----------- ----------- ------------ ------------
Income (loss) before extraordinary item 19,287 115,605 28,210 1,485 1,009
Extraordinary loss from early extinguishment of debt (28,970) (8,545) -- -- --
----------- ----------- ----------- ------------ ------------
Net income (loss) $ (9,683) $ 107,060 $ 28,210 $ 1,485 $ 1,009
=========== =========== =========== ============ ============
Basic earnings per share from continuing
operations $ 0.40
Diluted earnings per share from continuing
operations $ 0.38
Basic and diluted earnings (loss) per
Class A/B share from continuing operations $ 2.97 $ 3.43 $ (0.16)
Weighted average shares used in calculating basic
earnings (loss) per share 48,746,444 27,524,626 27,586,370 26,823,383
Weighted average shares used in calculating diluted
earnings (loss) per share 50,524,978 27,524,626 27,586,370 26,823,383
Dividends declared per share $ 0.20 -- -- --
OTHER DATA
Tons sold (in millions) 146.5 192.4 190.3 176.0 154.3
Adjusted EBITDA (4) $ 290,118 $ 582,807 $ 443,019 $ 371,067 $ 336,226
Net cash provided by (used in):
Operating activities 115,798 151,980 262,911 253,865 282,022
Investing activities (172,989) 388,462 (185,384) (2,270,886) (2,249,336)
Financing activities 33,090 (543,337) (205,181) 2,184,818 2,161,281
Depreciation, depletion and amortization 174,587 240,968 249,782 204,698 179,182
Capital expenditures 194,246 151,358 178,754 195,394 174,520
BALANCE SHEET DATA (AT PERIOD END)
Total assets $ 5,150,902 $ 5,209,487 $ 5,826,849 $ 7,023,931 $ 7,023,931
Total debt 1,031,067 1,405,621 2,076,166 2,542,379 2,542,379
Total stockholders' equity/invested capital 1,035,472 631,238 508,426 495,230 495,230
PREDECESSOR COMPANY
---------------------------
Period From
April 1, 1998 Year Ended
to March 31,
May 19, 1998 1998
------------- -----------
RESULTS OF OPERATIONS DATA
Revenues
Sales $ 278,930 $2,048,694
Other revenues 11,728 169,328
---------- ----------
Total revenues 290,658 2,218,022
Costs and expenses
Operating costs and expenses 244,128 1,695,216
Depreciation, depletion and amortization 25,516 200,169
Selling and administrative expenses 12,017 83,640
Gain on sale of Australian operations -- --
Net gain on property and equipment disposals (328) (21,815)
---------- ----------
Operating profit 9,325 260,812
Interest expense 4,222 33,410
Interest income (1,667) (14,543)
---------- ----------
Income (loss) before income taxes and minority
interests 6,770 241,945
Income tax provision (benefit) 4,530 83,050
Minority interests -- --
---------- ----------
Income (loss) from continuing operations 2,240 158,895
Income (loss) from discontinued operations (1,764) 1,441
---------- ----------
Income (loss) before extraordinary item 476 160,336
Extraordinary loss from early extinguishment of debt -- --
---------- ----------
Net income (loss) $ 476 $ 160,336
========== ==========
Basic earnings (loss) per share from continuing
operations
Diluted earnings (loss) per share from continuing
operations
Basic and diluted earnings (loss) per
Class A/B share from continuing operations
Weighted average shares used in calculating basic
earnings (loss) per share
Weighted average shares used in calculating diluted
earnings (loss) per share
Dividends declared per share
OTHER DATA
Tons sold (in millions) 21.7 167.5
Adjusted EBITDA (4) $ 34,841 $ 460,981
Net cash provided by (used in):
Operating activities (28,157) 187,852
Investing activities (21,550) (136,033)
Financing activities 23,537 (235,389)
Depreciation, depletion and amortization 25,516 200,169
Capital expenditures 20,874 165,514
BALANCE SHEET DATA (AT PERIOD END)
Total assets $6,406,587 $6,343,009
Total debt 633,562 602,276
Total stockholders' equity/invested capital 1,497,374 1,687,842
30
--------------
(1) Results of operations for the year ended March 31, 2001 included a $171.7
million pretax gain on the sale of our Australian operations.
(2) Results of operations for the year ended March 31, 2000 included a $144.0
million income tax benefit associated with an increase in the tax basis of
a subsidiary's assets due to a change in federal income tax regulations.
(3) For comparative purposes, we derived the "Total Fiscal 1999" column by
adding the period from May 20, 1998 to March 31, 1999 with our predecessor
company results for the period from April 1, 1998 to May 19, 1998. The
effects of purchase accounting have not been reflected in the results of
our predecessor company.
(4) Adjusted EBITDA is defined as income from continuing operations before
deducting net interest expense, income taxes, minority interests and
depreciation, depletion and amortization. Adjusted EBITDA is not a
substitute for operating income, net income and cash flow from operating
activities as determined in accordance with generally accepted accounting
principles as a measure of profitability or liquidity. Adjusted EBITDA is
presented as additional information because management believes it is a
useful indicator of our ability to meet debt service and capital
expenditure requirements. Because Adjusted EBITDA is not calculated
identically by all companies, our calculation may not be comparable to
similarly titled measures of other companies.
31
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
FISCAL YEAR CHANGE
In July 2001, we changed our fiscal year end from March 31 to December 31.
The change was first effective with respect to the nine months ended December
31, 2001. References to "fiscal year 2001" and "fiscal year 2000" refer to the
twelve months ended March 31, 2001 and March 31, 2000, respectively.
FACTORS AFFECTING COMPARABILITY
Sale of Australian Operations
In December 2000, we signed a share purchase agreement for the transfer of
the stock in two U.K. holding companies which, in turn, owned our Australian
subsidiaries, to a subsidiary of Rio Tinto Limited. Our Australian operations
consisted of interests in six coal mines, as well as a mining services operation
in Brisbane, Australia. The sale price was $446.8 million in cash, plus the
assumption of all liabilities. The sale closed on January 29, 2001.
Discontinued Operations
In August 2000, we sold Citizens Power, our subsidiary that marketed and
traded electric power and energy-related commodity risk management products, to
Edison Mission Energy. We classified Citizens Power as a discontinued operation
as of March 31, 2000, and recorded an estimated loss on the sale of $78.3
million, net of income taxes.
NINE MONTHS ENDED DECEMBER 31, 2001 COMPARED TO NINE MONTHS ENDED DECEMBER 31,
2000 (NOT PRESENTED HEREIN)
Sales. Sales for the nine months ended December 31, 2001 for the U.S.
operations (represents all of our operations, except for Australian operations
sold in January 2001) increased $219.1 million, to $1,963.3 million, a 12.6%
increase from the prior nine-month period. Improved sales volume in all mining
operating regions and price improvements in all regions except the Midwest,
where pricing remained level with the prior nine-month period, led the increase.
Additionally, sales from trading and brokerage activities increased as a result
of improved market liquidity and higher prices in the current nine-month period.
Sales volume for the U.S. operations was 146.5 million tons for the
current nine months, compared to 133.7 million tons for the prior nine-month
period, an increase of 9.6%. Higher sales volume at our Powder River Basin,
Southwest and Midwest operations led the increase, as our previous capital
investments in these regions allowed us to meet increased customer demand.
Overall U.S. operations' average sales price was 2.8% higher than the
prior nine-month period due to improved prices in the Appalachia and Powder
River Basin markets that were driven by strong customer demand in those regions.
The average pricing increase was slightly mitigated by sales mix, as the
Appalachia and Midwest regions' higher priced tons represented a lower
percentage of overall sales in the current nine months compared to the prior
nine-month period.
Total sales for the nine months ended December 31, 2001 increased $44.9
million, or 2.3%, from the prior nine-month period. Sales from Australian
operations included in the prior nine-month period were $174.2 million, from
sales volume of 9.8 million tons.
Powder River Basin sales increased $58.8 million, due to improved pricing
and volume from strong customer demand. Sales in the Midwest region increased
$35.0 million, led by improved operational performance and higher sales volume
at our Black Beauty operations. This improvement was partially offset by lower
production at the Camps operating unit related to equipment problems in the
current nine-month period, combined with the closure of the Camp No. 1 Mine in
October 2000. Appalachian sales increased $33.0 million, as a result of improved
demand-driven pricing. Sales in the Southwest region increased $28.1 million, as
we expanded production at the Lee Ranch Mine to meet new sales commitments, and
had higher demand at both of our Arizona mines. Finally, sales from brokerage
and trading activities increased $64.1 million, as sales volume increased as a
result of improved market liquidity and higher prices in the current year.
32
Other Revenues. Other revenues for the nine months ended December 31, 2001
for U.S. operations increased $40.9 million over the prior nine-month period.
The increase was primarily driven by higher revenues from trading and brokerage
operations, and $9.9 million in proceeds from the profitable monetization of
coal brokerage agreements with Enron. In addition, coal royalty income increased
$10.9 million, primarily due to two non-refundable advance coal royalties
received during the current year. Other revenues from Australian operations
included in the prior year period were $43.8 million.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense at U.S. operations increased $17.7 million in the nine
months ended December 31, 2001, as compared with the prior nine-month period.
Higher production volume in the current year, combined with $3.6 million of
additional depletion associated with the new coal royalty agreements discussed
above, and $2.0 million of depletion associated with coalbed methane operations
acquired early in 2001 led to the increase. Total depreciation, depletion and
amortization expense of $174.6 million decreased $5.6 million, as the nine
months ended December 31, 2000 included $23.3 million of expense from Australian
operations.
Selling and Administrative Expenses. Selling and administrative expenses
of $73.6 million increased $6.6 million compared to the nine months ended
December 31, 2000. Selling and administrative expenses associated with increased
volume, power plant development projects, higher insurance costs, and additional
costs associated with being a public company drove the increase.
Net Gain on Property and Equipment Disposals. Net gain on property and
equipment disposals increased $9.3 million, mainly due to gains on the sale of
certain idle coal reserves in the current nine-month period.
Operating Profit. Operating profit from U.S. operations increased $31.5
million, or 37.6%, for the nine months ended December 31, 2001. Overall
operating profit decreased $17.5 million, or 13.2%, compared to the prior
nine-month period, which included $49.0 million of operating profit from
Australian operations.
Operating profit from U.S. mining operations increased $17.0 million for
the nine months ended December 31, 2001, driven primarily by increased sales
prices, especially in Appalachia and the Powder River Basin. The profit increase
was achieved despite increased royalty and tax expense, increased energy-related
mining costs, and higher maintenance, repair, and overtime costs. Royalty and
tax expense, driven by higher sales prices, increased $20.5 million.
Energy-related mining costs, particularly explosives costs, increased $17.4
million. Finally, maintenance and repair costs and overtime costs increased in
most regions due to extended periods of producing at peak levels.
In the west, the Powder River Basin region's operating profit increased
$14.0 million over the prior nine-month period as higher volume and improved
prices overcame higher explosives, fuel and repair and maintenance costs. In the
Southwest region, operating profit was flat as higher sales volume was offset by
higher explosives and power costs.
In the east, the Appalachia region's operating profit increased $12.7
million due to strong sales prices, which overcame higher maintenance and
repairs and labor costs driven by certain production difficulties and severe
flooding in the current nine-month period. Operating profit in the Midwest
region declined $9.3 million compared to the prior nine-month period, as higher
sales volume and improved productivity at our Black Beauty operations were more
than offset by higher fuel and explosives costs at Black Beauty and production
and equipment problems at the Camps operating unit in the current nine-month
period.
Operating costs related to past mining activities were $9.8 million higher
in the current nine-month period, primarily due to a $10.0 million reduction of
our UMWA Combined Fund liability related to the withdrawal of certain
beneficiaries by the Social Security Administration in the prior year nine-month
period. Current period savings from prescription drug costs as a result of the
implementation of a mail order drug program were offset by an $8.0 million
reduction in the prior year of our liability for environmental cleanup-related
costs.
Operating profit from trading and brokerage operations increased $16.4
million over the prior nine-month period, as increased market volatility,
liquidity and improved sourcing flexibility provided product and price arbitrage
opportunities. The increase was achieved despite a $6.6 million charge related
to the Enron bankruptcy.
Operating profit also improved due to higher gains on the sale of coal
reserves and increased coal royalties, discussed above. Increased selling and
administrative costs decreased operating profit by $6.6 million.
Interest Expense. Interest expense for the nine months ended December 31,
2001 was $88.7 million, a $64.8 million decrease, or 42.2%, from the prior
nine-month period. The decrease was due to the significant long-term debt
repayments made since December 31, 2000. Utilizing proceeds from the sale of our
Australian operations, combined with proceeds from
33
our initial public offering in May 2001, we reduced long-term debt by $835
million from December 31, 2000 to December 31, 2001. We also benefited from a
decrease in our average borrowing rate on our variable rate debt in the nine
months ended December 31, 2001. Additionally, we entered into fixed to floating
rate interest rate swaps with notional amounts totaling $150.0 million in
October 2001, and realized interest savings of $0.6 million.
Interest Income. Interest income decreased $4.8 million, to $2.2 million,
for the nine months ended December 31, 2001. The decrease was mainly due to $3.6
million of interest income included in the prior nine-month period associated
with excise tax refunds for the period from January 1, 1994 to March 31, 1998.
Income Taxes. For the nine months ended December 31, 2001, income tax
expense was $2.5 million on income before income taxes and minority interests of
$29.0 million, compared to income tax expense of $3.7 million on a loss before
income taxes and minority interests of $13.4 million in the prior nine-month
period. Excluding the effect of Australian operating results included in the
prior nine-month period, there was an income tax benefit of $13.8 million on a
loss before income taxes and minority interests of $57.4 million.
Our consolidated tax position is impacted by the percentage depletion tax
deduction that creates an alternative minimum tax situation. The current year
tax situation reflects a reduction in our effective income tax rate from 25.0%
to 8.5%, primarily resulting from the impact of the allowance for percentage
depletion for tax purposes in relation to pre-tax income from continuing
operations.
Gain from Disposal of Discontinued Operations. During the nine months
ended December 31, 2000, we reduced our estimated loss on the sale of Citizens
Power by $11.8 million, net of income taxes. The reduction reflected a decrease
in the estimated operating losses of Citizens Power during the disposal period
due to higher income from electricity trading activities driven by increased
volatility and prices for electricity in the western U.S. power markets ($8.8
million) and higher estimated proceeds from the monetization of power contracts
as part of the wind-down of Citizens Power's operations ($3.0 million). Citizens
Power was classified as a discontinued operation effective March 31, 2000, and
the sale was completed during the fiscal year ended March 31, 2001.
Extraordinary Loss from Early Extinguishment of Debt. During the nine
months ended December 31, 2001, we recorded an extraordinary loss of $29.0
million, net of income taxes, which represented the excess of cash paid over the
carrying value of the debt retired and the write-off of debt issuance costs
associated with the debt retired.
FISCAL YEAR ENDED MARCH 31, 2001 COMPARED TO FISCAL YEAR ENDED MARCH 31, 2000
Sales. Sales decreased $31.9 million, or 1.2%, to $2,579.1 million for the
fiscal year 2001. Sales volume increased 2.1 million tons, or 1.1%, to 192.4
million tons in fiscal year 2001. The majority of the decline was the result of
$24.6 million of lower sales in Australia, due to the sale of our Australian
operations in January 2001. During the first nine months of fiscal year 2001,
average prices were 2.7% lower than the prior year's first nine months,
primarily due to a change in sales mix as higher-priced Midwest region volume
decreased in fiscal year 2001. However, this decrease was somewhat mitigated by
higher coal prices in the fourth quarter in nearly all operating regions, which
reduced the full year decline in average prices to only 1.0% compared to the
prior year. Sales from our U.S. operations decreased $7.3 million in fiscal year
2001, due to lower volumes in the Midwest region offset partially by slightly
higher volume in Appalachia, the Southwest region and at Black Beauty, and
improved pricing and volume in the Powder River Basin.
Sales in the Powder River region increased $44.9 million in fiscal year
2001, due to improved pricing and increased volume as a result of strong demand
for Powder River Basin coal. Sales in Appalachia improved by $42.3 million due
to higher volume from improved performance at our longwall operations in that
region. Black Beauty's sales increased $23.6 million due to the higher volumes
on contracts transitioned from our other mines, while sales in the Southwest
region improved $4.9 million due to slightly higher sales volume. Sales from
broker and trading activities increased $41.4 million, reflecting an increase in
volume over fiscal year 2000. These sales increases were more than offset by the
sales decrease in the Midwest region of $164.5 million from the closure and
suspension of three mines during fiscal year 2000 and the closure of another
mine early in the third quarter of fiscal year 2001.
Other Revenues. Other revenues decreased $8.9 million compared to the prior
year, to $90.6 million. Lower contract restructuring revenues and coal royalty
income in fiscal year 2001 were only partially offset by an increase in revenues
from engineering services for underground mining projects in Australia. Our
contract restructuring revenues typically arise from the negotiated termination
of our or a third party's existing coal supply agreement in exchange for a cash
payment.
34
Depreciation, Depletion and Amortization. Fiscal year 2001 depreciation,
depletion and amortization expense was $241.0 million, a decrease of $8.8
million compared to fiscal year 2000. The decrease was primarily due to $6.0
million of additional depletion associated with a new coal royalty agreement
entered into in fiscal year 2000.
Selling and Administrative Expenses. Selling and administrative expenses
increased $4.0 million in fiscal year 2001 to $99.3 million. This increase was
primarily related to $3.7 million of increased stock compensation expense in
fiscal year 2001 related to the grant of Class B common stock to management.
Gain on Sale of Australian Operations. On January 29, 2001, we sold our
Australian operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto
Limited. The selling price was $446.8 million, plus the assumption of all
liabilities, including $119.4 million of debt. We recorded a pretax gain of
$171.7 million on the sale.
Operating Profit. Fiscal year 2001 operating profit was $341.8 million, an
increase of $148.6 million compared to fiscal year 2000. Excluding the gain on
the sale of our Australian operations, operating profit was $170.1 million, a
decrease of $23.1 million from fiscal year 2000. Operating margin excluding the
gain on the sale of our Australian operations was 6.6% in fiscal year 2001, a
decrease from 7.4% in fiscal year 2000. A 41% increase in fuel prices decreased
operating margin by 1.0% and operating profit by $24.1 million in fiscal year
2001. At our U.S. mining operations, operating profit, excluding fuel cost
variances, remained stable in fiscal year 2001.
Operating profit in the Powder River Basin region increased $20.5 million
primarily due to higher pricing in fiscal year 2001, combined with slightly
improved sales volume. In the Southwest region, we realized increased operating
profit of $12.1 million as a result of improved productivity and higher sales
volume in fiscal year 2001. Offsetting these increases was a $40.0 million
decrease in the Midwest region associated with the closure and suspension of
three mines in fiscal year 2000 and the closure of another mine early in the
third quarter of fiscal year 2001. Black Beauty's operating profit decreased
$18.5 million due to lower contract restructuring revenues in fiscal year 2001,
higher operating costs caused by adverse geologic conditions encountered during
the first nine months of the year as we transitioned to new mining areas and
unfavorable weather conditions, which delayed production and transportation of
coal. Appalachia's operating profit decreased $6.5 million due to poor mining
conditions at certain underground operations and lower average pricing in the
first nine months of fiscal year 2001 due to contract expirations, partially
offset by improved performance at the region's longwall operations.
Fiscal year 2001 results also included a decrease in operating costs for an
$8.0 million reduction in our liabilities for environmental cleanup-related
costs based upon favorable experience and lower costs of $9.1 million related to
Black Lung excise tax refund credits on export shipments. Beginning in 1997, we
filed for a refund of these taxes on the basis that the tax was
unconstitutional. In May 2000, the Internal Revenue Service issued guidelines
for the refund of these taxes. We have filed a claim and expect to receive a
refund in the first half of calendar year 2002.
Operating costs also decreased $11.4 million in fiscal year 2001 due to the
reduction in our liability associated with the United Mine Workers of America
Combined Fund. The Coal Industry Retiree Health Benefit Act of 1992 established
the Combined Fund to provide for the funding of specified health benefits for
covered United Mine Workers of America retirees. Two of our subsidiaries filed a
lawsuit against the Social Security Administration asserting that it improperly
assigned certain beneficiaries to them. A federal District Court ruled in our
favor. Effective October 1, 2000, the Social Security Administration withdrew
the assignment to our subsidiaries of a specified number of beneficiaries,
resulting in a $11.4 million reduction in our liability.
Additionally, our Australian operations' operating profit increased $5.0
million in fiscal year 2001.
Interest Expense. Interest expense decreased $7.4 million to $197.7 million
in fiscal year 2001. The decrease was primarily due to a $7.7 million decrease
in interest expense in the fourth quarter resulting from the repayment of $455.0
million of term loans under our senior credit facilities during the quarter, and
the removal of $119.4 million of debt from our balance sheet as a result of the
sale of our Australian operations.
Interest Income. Interest income increased $4.3 million to $8.7 million in
fiscal year 2001, primarily as a result of the interest income recorded in
fiscal year 2001 associated with the Black Lung excise tax refunds.
Income Taxes. Fiscal year 2001 income tax expense was $42.7 million on
pretax income of $152.9 million, compared to an income tax benefit of $141.5
million on a pretax loss of $7.4 million in fiscal year 2000. Additionally, in
fiscal year 2000 we recorded a $144.0 million income tax benefit associated with
an increase in the tax basis of a subsidiary's assets due to a change in federal
income tax regulations.
35
Our consolidated tax position is impacted by the percentage depletion tax
deduction utilized by us and our U.S. subsidiaries that creates an alternative
minimum tax situation, and the positive contribution of our Australian
operations, which are taxed at a higher rate than our U.S. operations.
Additionally, in fiscal year 2001 we recorded a $47.5 million tax provision
related to the gain on sale of our Australian operations. Excluding the tax
provision related to the sale of our Australian operations, the income tax
benefit recorded on U.S. pretax losses exceeded the Australian income tax
expense in fiscal year 2001 by $4.8 million.
Minority Interests. In fiscal year 2001, minority interest expense
decreased $8.0 million to $7.5 million, due to lower fiscal year 2001 results at
our 81.7%-owned Black Beauty operations. As discussed above, Black Beauty's
results were affected by a contract restructuring gain in fiscal year 2000,
combined with higher mining costs due to poor geologic conditions and higher
fuel costs in fiscal year 2001.
Loss from Discontinued Operations. In fiscal year 2000, Citizens Power
incurred a loss from operations of $12.1 million. Citizens Power was classified
as a discontinued operation in March 2000.
Gain from Disposal of Discontinued Operations. During fiscal year 2001, we
reduced our estimated net loss from the sale of Citizens Power by $12.9 million,
net of income taxes. This reduction reflected a decrease in the estimated
operating losses of Citizens Power during the disposal period due to higher
income from electricity trading activities driven by increased volatility and
prices for electricity in the western U.S. power markets during the first
quarter ($8.8 million) and higher estimated proceeds from the monetization of
power contracts as part of the wind-up of our ownership of Citizens Powers'
operations ($4.1 million). We completed the sale of Citizens Power in fiscal
year 2001.
Extraordinary Loss from the Early Extinguishment of Debt. In the fourth
quarter of fiscal year 2001, we made optional prepayments of term loans under
our senior credit facilities. These prepayments were primarily funded with the
proceeds from the sale of our Australian operations. The prepayments resulted in
an extraordinary loss of $8.5 million, net of income taxes, due to the write-off
of costs related to the issuance of the debt repaid.
LONG-TERM COAL SUPPLY AGREEMENTS
Our strategy is to selectively renew, or enter into new, long-term supply
contracts when we can do so at prices we believe are favorable. During 2001,
prices for coal increased from prior year levels, particularly in the Powder
River Basin and in Appalachia, primarily due to increased prices for competing
fuels and increased demand for electricity. Late in 2001, coal prices began to
decline from the levels experienced earlier in 2001, due to a softer economy and
milder than normal winter weather. During calendar 2001, we signed contracts for
nearly 200 million tons of new business at higher prices than those realized in
calendar 2001. As of December 31, 2001 we had sales commitments for
approximately 93% of our calendar 2002 production which, as of March 1, 2002,
increased to 97% as a result of reduced production estimates for calendar 2002.
As of March 1, 2002, nearly 1 billion tons of our future coal production was
committed under long-term contracts.
Long-term contracts may be particularly attractive in regions where market
prices are expected to remain stable, particularly in cases such as high sulfur
coal that would otherwise not be in great demand or for sales under cost-plus
arrangements serving captive electricity generating plants. To the extent we do
not renew or replace expiring long-term coal supply agreements, our future sales
will be exposed to market fluctuations, including unexpected downturns in market
prices. Most of the contracts contain price adjustments for inflation and
changes in the laws regulating the mining, production, sale or use of coal.
LIQUIDITY AND CAPITAL RESOURCES
Cash provided by operating activities was $115.8 million in the nine months
ended December 31, 2001, an increase of $15.2 million over the prior nine-month
period. Cash flow in the prior year benefited from $25.0 million of proceeds
received related to our accounts receivable securitization program, while the
current nine-month period benefited from a $22.7 million federal income tax
refund. Cash from operations improved as a result of lower borrowing costs,
which overcame increased working capital cash uses in the current year. Cash
provided by operating activities was $152.0 million in the year ended March 31,
2001.
Net cash used in investing activities was $173.0 million for the nine
months ended December 31, 2001, compared to cash used in investing activities in
the prior nine month period of $31.7 million. The prior year period included
$85.6 million of proceeds related to the sale of Citizens Power and $34.7
million of cash used related to our Australian operations. Capital expenditures
increased $84.9 million, to $194.2 million, in the current nine-month period.
This increase was primarily due to higher investments in the Powder River Basin
and at our Black Beauty operations. Powder River Basin capital was used to
incrementally expand the operations, add new equipment, and reopen the Rawhide
mine. At our Black
36
Beauty operations, additional capital was used in the current year to complete
the addition of new mines to service long-term contracts and to purchase a
dragline to lower overburden removal costs. For the year ended March 31, 2001,
net cash provided by investing activities was $388.5 million. This included
$455.0 million from the sale of our Australian operations and $102.6 million
from discontinued operations.
Net cash provided by financing activities was $33.1 million for the nine
months ended December 31, 2001, an increase of $133.2 million over the prior
year period. We made debt payments of $458.8 million during the nine-month
period, principally from proceeds received from our initial public offering. The
prior year period reflects $132.3 million in debt repayments, principally made
using proceeds from our sale of Citizens Power. Finally, we paid $10.4 million
of dividends in the current nine-month period. Cash used in financing activities
was $543.3 million in the year ended March 31, 2001. This included net debt
payments of $568.6 million, sourced from the sale of our Australian operations
and Citizens Power.
The following table reflects our total indebtedness as of December 31, 2001
(in thousands):
December 31, 2001
-----------------
9.625% Senior Subordinated Notes
("Senior Subordinated Notes") due 2008 $ 391,390
8.875% Senior Notes ("Senior Notes") due 2008 316,413
5.0% Subordinated Note 90,026
Senior unsecured notes under various agreements 83,571
Unsecured revolving credit agreement 96,790
Other 52,877
----------
Total debt $1,031,067
==========
As of December 31, 2001, our revolving credit and letter of credit
borrowing facilities include the $480.0 million Revolving Credit Facility under
our Senior Credit Facility and Black Beauty's $120.0 million revolving credit
facility. These facilities total $600.0 million, and have a total of $470.0
million available for borrowing. Outstanding borrowings under Black Beauty's
revolving credit facility totaled $96.8 million. We were in compliance with the
restrictive covenants of all of our and our subsidiaries' debt agreements as of
December 31, 2001.
We have a $480.0 million Revolving Credit Facility that includes a
borrowing sub-limit of $350.0 million and a letter of credit sub-limit of $330.0
million. Our borrowing capacity increased from $200.0 million as a result of an
amendment to our Senior Credit Facility. The amendment, which became effective
at the time of the initial public offering, permits: the payment of annual cash
dividends up to the greater of $25.0 million or 10% of consolidated EBITDA,
as defined in the facility; other restricted payments subject to specified
limitations; and additional joint venture investments. In connection with the
amendment, we agreed to reduce the maximum permitted debt to EBITDA ratio and
increase the minimum required interest coverage ratio. All other terms and
conditions remained unchanged.
As of December 31, 2001, we had no borrowings outstanding under our
Revolving Credit Facility. Revolving loans under our Revolving Credit Facility
bear interest based on the Base Rate (as defined in the Senior Credit Facility),
or LIBOR (as defined in the Senior Credit Facility) at our option. The
applicable rate was 3.4% at December 31, 2001.
37
The following is a summary of commercial commitments available to us as of
December 31, 2001 (in thousands):
Expiration Per Year
----------------------------------------------------
Total Amounts Less than
Committed 1 Year 1 - 3 Years 4 - 5 Years Over 5 Years
------------- --------- ----------- ----------- ------------
Lines of Credit $470,000 - $470,000 - -
Standby Letters of Credit $330,000 - $330,000 - -
The indentures governing our Senior Notes and Senior Subordinated Notes
permit us and our Restricted Subsidiaries (as defined in the indentures) to
incur additional indebtedness, including secured indebtedness, subject to
certain limitations. In addition, the indentures limit our and our Restricted
Subsidiaries' ability to: lease, convey or otherwise dispose of all or
substantially all of our assets; issue specified types of capital stock; enter
into guarantees of indebtedness; incur liens; merge or consolidate with any
other person or enter into transactions with affiliates; and repurchase junior
securities or make specified types of investments. The indentures permit us to
pay annual dividends of up to the greater of 6% ($27.0 million) of the net
proceeds from our initial public offering, or additional amounts based on, among
other things, the sum of 50% of cumulative defined net income (since July 1,
1998) and 100% of the proceeds of our initial public offering. We expressly
reserve the right, at our sole discretion, from time to time, to purchase any
notes, in the open market or through privately negotiated transactions.
Black Beauty has a $120.0 million revolving credit facility which matures
on April 17, 2004. Black Beauty may elect one or a combination of interest rates
based on LIBOR or the corporate base rate plus a margin, which fluctuates based
on specified leverage ratios. The effective annual interest rate was 3.9% as of
December 31, 2001. Borrowings outstanding under the Black Beauty revolving
credit facility totaled $96.8 million at December 31, 2001. The revolving credit
facility contains customary restrictive covenants including limitations on
additional debt, investments and dividends.
Black Beauty's senior unsecured notes include $23.6 million of senior notes
and three series of notes with an aggregate principal amount of $60.0 million as
of December 31, 2001. The senior notes bear interest at 9.2%, payable quarterly,
and are pre-payable in whole or in part at any time, subject to certain
make-whole provisions. The three series of notes include Series A, B and C
notes, totaling $45.0 million, $5.0 million and $10.0 million, respectively. The
Series A notes bear interest at an annual rate of 7.5% and are due in November
2007. The Series B notes bear interest at an annual rate of 7.4% and are due in
November 2003. The Series C notes bear interest at an annual rate of 7.4% and
are due in November 2002. The senior unsecured notes contain customary
restrictive covenants including limitations on additional debt, investments and
dividends.
Subsidiaries of Black Beauty maintain borrowing facilities with banks and
other lenders with customary restrictive covenants. The aggregate amount of
outstanding indebtedness under those facilities totaled $52.9 million as of
December 31, 2001. The effective annual interest rate of this debt was 3.9% as
of December 31, 2001.
The Company has designated interest rate swaps with notional amounts
totaling $150.0 million as a fair value hedge of its Senior Notes. Under the
swaps, the Company pays a floating rate based upon the six-month LIBOR rate for
a period of seven years ending May 15, 2008. The applicable rate was 6.03% as of
December 31, 2001. The Company realized interest savings of $0.6 million from
the inception of the swaps on October 26, 2001 through December 31, 2001.
During calendar 2001, we repaid $835 million in debt. In January 2001, we
sold our Australian operations for $446.8 million. On May 22, 2001, we completed
an initial public offering of 17,250,000 shares of common stock. Net proceeds
from the offering were $449.8 million. We used substantially all of the proceeds
from the sale of our Australian operations and the initial public offering to
repay debt. Since March 31, 1999, we have reduced our total debt by over $1.5
billion.
During the nine months ended December 31, 2001, Moody's, Standard & Poor's
and Fitch reviewed our various debt ratings. Moody's upgraded our senior implied
rating to Ba2 from Ba3, our senior secured revolving credit facility to Ba1 from
Ba2, and our 9.625% Senior Subordinated Notes to B1 from B2. Standard & Poor's
upgraded our corporate credit
38
rating to BB from BB-, our 8.875% Senior Notes to BB from B+ and our 9.625%
Senior Subordinated Notes to B+ from B. Fitch upgraded our senior secured
revolving credit facility to BB+ from BB-, our 8.875% Senior Notes to BB from B+
and our 9.625% Senior Subordinated Notes to B+ from B-.
In March 2000, we established an accounts receivable securitization
program. Under the program, undivided interests in a pool of eligible trade
receivables that have been contributed to the Seller are sold, without recourse,
to a multi-seller, asset-backed commercial paper conduit ("Conduit"). Purchases
by the Conduit are financed with the sale of highly rated commercial paper. The
Company used proceeds from the sale of its accounts receivable to repay
long-term debt, effectively reducing its overall borrowing costs. The funding
cost of the securitization program was $4.5 million and $8.7 million for the
nine months ended December 31, 2001 and the year ended March 31, 2001,
respectively. The securitization program is currently scheduled to expire in
2007. Under the provisions of Statement of Financial Accounting Standards
("SFAS") No. 125, "Accounting for Transfers and Servicing of Financial Assets
and Extinguishments of Liabilities," (as amended by SFAS No. 140) the
securitization transactions have been recorded as sales, with those accounts
receivable sold to the Conduit removed from the consolidated balance sheet. The
amount of undivided interests in accounts receivable sold to the Conduit were
$140.0 million as of December 31, 2001 and March 31, 2001.
The following is a summary of our significant contractual obligations as of
December 31, 2001 (in thousands):
Payments Due by Year
---------------------------------------------------------
After 5
Less than 1 Year 1-3 Years 4-5 Years Years
---------------- --------- --------- --------
Long-term debt $ 46,499 $198,613 $ 35,549 $750,406
Capital lease obligations 895 869 579 53
Operating leases 65,511 113,821 80,964 72,610
Unconditional purchase obligations 136,688 - - -
Coal reserve obligations 36,725 26,118 24,818 32,454
-------- -------- -------- --------
Total contractual cash obligations $286,318 $339,421 $141,910 $855,523
======== ======== ======== ========
Additionally, we have long-term liabilities relating to retiree health
care, work-related injuries and illnesses, defined benefit pension plans and
mine reclamation and end of mine closure costs. The following is the estimated
spending related to these items as of December 31, 2001 (in thousands):
Payments Due by Year
-------------------------------------------
Less than 1 Year 1-3 Years 4-5 Years
---------------- --------- ---------
$190,600 $413,200 $373,300
We had $136.7 million of committed capital expenditures at December 31,
2001, that are primarily related to acquiring additional coal reserves and
mining equipment in 2002. Total capital expenditures for calendar year 2002 are
expected to range from $165 million to $195 million, and have been and will be
primarily used to acquire additional low sulfur coal reserves, develop existing
reserves, replace or add equipment and fund cost reduction initiatives. We
anticipate funding these capital expenditures through operating cash flow. In
addition, cash requirements to fund employee related and reclamation liabilities
included above are expected to be funded from operating cash flow, along with
obligations related to long-term debt, capital and operating leases and coal
reserves. We believe the risk of generating lower than anticipated operating
cash flow in 2002 is reduced by our high level of sales commitments (97% of 2002
planned production) and lower expected borrowing costs as a result of our
significant debt reductions.
CRITICAL ACCOUNTING POLICIES
Our discussion and analysis of our financial condition, results of
operations, liquidity and capital resources is based upon our financial
statements, which have been prepared in accordance with accounting principles
generally accepted in the United States. Generally accepted accounting
principles require that we make estimates and judgments that affect the reported
amounts of assets, liabilities, revenues and expenses, and related disclosure of
contingent assets and liabilities. On an on-going basis, we evaluate our
estimates. We base our estimates on historical experience and on various other
assumptions that we believe are reasonable under the circumstances, the results
of which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources. Actual results
may differ from these estimates.
Employee Related Liabilities
We have significant long-term liabilities relating to retiree health care,
work-related injuries and illnesses and defined pension plans. Detailed
information related to these liabilities is included in the notes to our
consolidated financial statements. Retiree health care and work-related injuries
are not funded. Pension obligations are funded in accordance with the provisions
of federal law.
39
Each of these liabilities are actuarially determined and we use various
actuarial assumptions, including the discount rate and future cost trends, to
estimate the costs and obligations for these items.
Our discount rate is based on a hypothetical portfolio of currently
available, high-quality debt instruments ("AA" or better rating under either
Moody's or Standard & Poor's) whose maturity dates match the expected payments.
We assumed a discount rate of 7.4% and 7.85% to determine the obligations at
December 31, 2001 and March 31, 2001, respectively.
We make assumptions related to future trends for medical care costs in the
estimates of retiree health care and work-related injuries and illnesses
obligations. In addition, we make assumptions related to future compensation
increases and rates of return on plan assets in the estimates of pension
obligations.
If our assumptions do not materialize as expected, actual cash
expenditures and costs that we incur could be materially different than
currently estimated. Moreover, regulatory changes could increase our obligation
to satisfy these or additional obligations.
Payments related to these liabilities totaled $100.5 million for the nine
months ended December 31, 2001.
Reclamation
We have significant long-term liabilities relating to mine reclamation and
end of mine closure costs. Liabilities are recorded for the estimated costs to
reclaim land as the acreage is disturbed during the ongoing surface mining
process. The estimated costs to reclaim support acreage and perform other
functions at both surface and underground mines are recorded ratably over the
lives of the mines. Reclamation liabilities are not funded.
The liability is determined on a by-mine basis and we use various
assumptions, including estimates of disturbed acreage as determined from
engineering data and the costs to reclaim the disturbed acreage.
If our assumptions do not materialize as expected, actual cash
expenditures and costs that we incur could be materially different than
currently estimated. Moreover, regulatory changes could increase our obligation
to perform reclamation and mine closing activities.
Payments related to reclamation liabilities totaled $20.7 million for the
nine months ended December 31, 2001.
Trading Activities
We engage in the buying and selling of coal and emission allowances in
over-the-counter markets. Purchases and sales of commodities on a forward basis
are marked-to-market and carried at fair value in the consolidated financial
statements, with changes in that fair value recorded in earnings in the period
they occur.
For transactions that take place in over-the-counter markets, we use
bid/ask price quotations obtained from multiple, independent third party brokers
to value coal and emission allowance positions. Prices from these sources are
then averaged to obtain trading position values. We would experience difficulty
in valuing our market positions if the number of third party brokers should
decrease or market liquidity is reduced.
Seventy-six percent of the contracts in our trading portfolio as of
December 31, 2001 were valued utilizing prices from over-the-counter market
sources. The remaining 24% of our contracts were valued based on
over-the-counter market source prices adjusted for differences in coal quality
and content, as well as contract duration.
As of December 31, 2001, the timing of trading portfolio contract
expirations are as follows:
Year of Expiration Percentage of Portfolio
------------------ -----------------------
2002 75%
2003 3%
2004 18%
2005 3%
2006 1%
---
100%
===
40
At December 31, 2001, 89% of our credit exposure related to coal and
emission allowance trading activities is with counterparties that are investment
grade.
RECENT ACCOUNTING PRONOUNCEMENTS
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." SFAS No. 143 addresses accounting and reporting for
obligations associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. This statement is effective for fiscal years
beginning after June 15, 2002 (effective January 1, 2003 for the Company). The
Company is currently assessing the impact of this new standard.
In July 2001, the FASB issued SFAS No. 144, "Impairment or Disposal of
Long-Lived Assets," which is effective for fiscal years beginning after December
15, 2001 (effective January 1, 2002 for the Company). The provisions of this
statement provide a single accounting model for impairment of long-lived assets.
We do not anticipate the adoption of SFAS No. 144 will have a material effect on
our financial condition or results of operations.
RISK FACTORS
IF A SUBSTANTIAL PORTION OF OUR LONG-TERM COAL SUPPLY AGREEMENTS TERMINATE, OUR
REVENUES AND OPERATING PROFITS COULD SUFFER IF WE WERE UNABLE TO FIND ALTERNATE
BUYERS WILLING TO PURCHASE OUR COAL ON COMPARABLE TERMS TO THOSE IN OUR
CONTRACTS.
A substantial portion of our sales are made under coal supply agreements,
which are important to the stability and profitability of our operations. The
execution of a satisfactory coal supply agreement is frequently the basis on
which we undertake the development of coal reserves required to be supplied
under the contract. For the nine months ended December 31, 2001, 83% of our
sales volume was sold under long-term coal supply agreements. At December 31,
2001, our coal supply agreements had remaining terms ranging from one to 14
years and an average volume-weighted remaining term of approximately four years.
Many of our coal supply agreements contain provisions that permit the
parties to adjust the contract price upward or downward at specified times. We
may adjust these contract prices based on inflation and/or changes in the
factors affecting the cost of producing coal, such as taxes, fees, royalties and
changes in the laws regulating the mining, production, sale or use of coal.
Failure of the parties to agree on a price under those provisions may allow
either party to terminate the contract. In past years, several of our coal
supply agreements have been renegotiated, resulting in the contract prices being
closer to the then-current market prices, thus leading to a reduction in the
revenues from those contracts. We have also experienced a similar reduction in
coal prices in new long-term coal supply agreements replacing some of our
expiring contracts. Coal supply agreements also typically contain force majeure
provisions allowing temporary suspension of performance by us or the customer
during the duration of specified events beyond the control of the affected
party. Most coal supply agreements contain provisions requiring us to deliver
coal meeting quality thresholds for certain characteristics such as Btu, sulfur
content, ash content, grindability and ash fusion temperature. Failure to meet
these specifications could result in economic penalties, including price
adjustments, the rejection of deliveries or termination of the contracts.
Moreover, some of these agreements permit the customer to terminate the contract
if transportation costs, which our customers typically bear, increase
substantially. In addition, a majority of these contracts allow our customers to
terminate their contracts in the event of changes in regulations affecting our
industry that increase the price of coal beyond specified limits.
The operating profits we realize from coal sold under supply agreements
depend on a variety of factors. In addition, price adjustment and other
provisions may increase our exposure to short-term coal price volatility
provided by those contracts. If a substantial portion of our coal supply
agreements were modified or terminated, we could be materially adversely
affected to the extent that we are unable to find alternate buyers for our coal
at the same level of profitability. Some of our coal supply agreements are for
prices above current market prices. Although market prices for coal increased in
most regions in 2001, we cannot predict whether the strength in the coal market
will continue. As a result, we cannot assure you that we will be able to replace
existing long-term coal supply agreements at the same prices or with similar
profit margins when they expire. In addition, three of our coal supply
agreements are the subject of ongoing litigation and arbitration.
THE LOSS OF, OR SIGNIFICANT REDUCTION IN, PURCHASES BY OUR LARGEST CUSTOMERS
COULD ADVERSELY AFFECT OUR REVENUES.
For the nine months ended December 31, 2001, we derived 33% of our total
coal revenues from sales to our five largest customers. At December 31, 2001, we
had 20 coal supply agreements with these customers that expire at various times
from 2002 to 2015. We are currently discussing the extension of existing
agreements or entering into new long-term agreements
41
with some of these customers, but these negotiations may not be successful and
those customers may not continue to purchase coal from us under long-term coal
supply agreements. If a number of these customers were to significantly reduce
their purchases of coal from us, or if we were unable to sell coal to them on
terms as favorable to us as the terms under our current agreements, our
financial condition and results of operations could suffer materially.
OUR FINANCIAL PERFORMANCE COULD BE ADVERSELY AFFECTED BY OUR SUBSTANTIAL DEBT.
Our financial performance could be affected by our substantial
indebtedness. As of December 31, 2001, we had total indebtedness of $1,031.1
million. We currently have total borrowing capacity under our and Black Beauty's
revolving credit facilities of $470.0 million. We may also incur additional
indebtedness in the future.
Our ability to pay principal and interest on our debt depends upon the
operating performance of our subsidiaries, which will be affected by, among
other things, prevailing economic conditions in the markets they serve, some of
which are beyond our control. Our business may not generate sufficient cash flow
from operations and future borrowings may not be available under our revolving
credit facilities or otherwise in an amount sufficient to enable us to service
our indebtedness or to fund our other liquidity needs.
The degree to which we are leveraged could have important consequences,
including, but not limited to: (1) making it more difficult for us to pay
dividends and satisfy our debt obligations; (2) increasing our vulnerability to
general adverse economic and industry conditions; (3) requiring the dedication
of a substantial portion of our cash flow from operations to the payment of
principal of, and interest on, our indebtedness, thereby reducing the
availability of the cash flow to fund working capital, capital expenditures,
research and development or other general corporate uses; (4) limiting our
ability to obtain additional financing to fund future working capital, capital
expenditures, research and development or other general corporate requirements;
(5) limiting our flexibility in planning for, or reacting to, changes in our
business; and (6) placing us at a competitive disadvantage compared to less
leveraged competitors. In addition, our indebtedness subjects us to financial
and other restrictive covenants. Failure by us to comply with these covenants
could result in an event of default which, if not cured or waived, could have a
material adverse effect on us. Furthermore, substantially all of our assets
secure our indebtedness under our Senior Credit Facility.
IF TRANSPORTATION FOR OUR COAL BECOMES UNAVAILABLE OR UNECONOMIC FOR OUR
CUSTOMERS, OUR ABILITY TO SELL COAL COULD SUFFER.
Transportation costs represent a significant portion of the total cost of
coal, and as a result, the cost of transportation is a critical factor in a
customer's purchasing decision. Increases in transportation costs could make
coal a less competitive source of energy or could make some of our operations
less competitive than other sources of coal. Certain coal supply agreements
permit the customer to terminate the contract if the cost of transportation
increases by an amount ranging from 10% to 20% in any given 12-month period.
Coal producers depend upon rail, barge, trucking, overland conveyor and
other systems to deliver coal to markets. While U.S. coal customers typically
arrange and pay for transportation of coal from the mine to the point of use,
disruption of these transportation services because of weather-related problems,
strikes, lock-outs or other events could temporarily impair our ability to
supply coal to our customers and thus could adversely affect our results of
operations. For example, the high volume of coal shipped from all Southern
Powder River Basin mines could create temporary congestion on the rail systems
servicing that region.
RISKS INHERENT TO MINING COULD INCREASE THE COST OF OPERATING OUR BUSINESS.
Our mining operations are subject to conditions beyond our control that can
delay coal deliveries or increase the cost of mining at particular mines for
varying lengths of time. These conditions include weather and natural disasters,
unexpected maintenance problems, key equipment failures, variations in coal seam
thickness, variations in the amount of rock and soil overlying the coal deposit,
variations in rock and other natural materials and variations in geologic
conditions.
THE GOVERNMENT EXTENSIVELY REGULATES OUR MINING OPERATIONS, WHICH IMPOSES
SIGNIFICANT COSTS ON US, AND FUTURE REGULATIONS COULD INCREASE THOSE COSTS OR
LIMIT OUR ABILITY TO PRODUCE COAL.
Federal, state and local authorities regulate the coal mining industry with
respect to matters such as employee health and safety, permitting and licensing
requirements, air quality standards, water pollution, plant and wildlife
protection, reclamation and restoration of mining properties after mining is
completed, the discharge of materials into the environment, surface subsidence
from underground mining and the effects that mining has on groundwater quality
and availability. In addition, significant legislation mandating specified
benefits for retired coal miners affects our industry. Numerous governmental
permits and approvals are required for mining operations. We are required to
prepare and present to federal,
42
state or local authorities data pertaining to the effect or impact that any
proposed exploration for or production of coal may have upon the environment.
The costs, liabilities and requirements associated with these regulations may be
costly and time-consuming and may delay commencement or continuation of
exploration or production operations. The possibility exists that new
legislation and/or regulations and orders may be adopted that may materially
adversely affect our mining operations, our cost structure and/or our customers'
ability to use coal. New legislation or administrative regulations (or judicial
interpretations of existing laws and regulations), including proposals related
to the protection of the environment that would further regulate and tax the
coal industry, may also require us or our customers to change operations
significantly or incur increased costs. The majority of our coal supply
agreements contain provisions that allow a purchaser to terminate its contract
if legislation is passed that either restricts the use or type of coal
permissible at the purchaser's plant or results in specified increases in the
cost of coal or its use. These factors and legislation, if enacted, could have a
material adverse effect on our financial condition and results of operations.
In addition, the United States and over 160 other nations are signatories
to the 1992 Framework Convention on Climate Change, which is intended to limit
emissions of greenhouse gases, such as carbon dioxide. In December 1997, in
Kyoto, Japan, the signatories to the convention established a binding set of
emission targets for developed nations. Although the specific emission targets
vary from country to country, the United States would be required to reduce
emissions to 93% of 1990 levels over a five-year budget period from 2008 through
2012. Although the United States has not ratified the emission targets and no
comprehensive regulations focusing on greenhouse gas emissions are in place,
these restrictions, whether through ratification of the emission targets or
other efforts to stabilize or reduce greenhouse gas emissions, could adversely
impact the price and demand for coal. According to the Energy Information
Administration's Emissions of Greenhouse Gases in the United States 2000, coal
accounts for 32% of greenhouse gas emissions in the United States, and efforts
to control greenhouse gas emissions could result in reduced use of coal if
electricity generators switch to sources of fuel with lower carbon dioxide
emissions. Further developments in connection with the Kyoto Protocol could have
a material adverse effect on our financial condition or results of operations.
OUR EXPENDITURES FOR POSTRETIREMENT BENEFIT AND PENSION OBLIGATIONS COULD BE
MATERIALLY HIGHER THAN WE HAVE PREDICTED IF OUR UNDERLYING ASSUMPTIONS PROVE TO
BE INCORRECT.
We provide postretirement health and life insurance benefits to eligible
union and non-union employees. We calculated the total accumulated
postretirement benefit obligation under Statement of Financial Accounting
Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions," which we estimate had a present value of $1,032.5 million as of
December 31, 2001, $70.4 million of which was a current liability. We have
estimated these unfunded obligations based on assumptions described in Note 18
to our audited financial statements. If our assumptions do not materialize as
expected, cash expenditures and costs that we incur could be materially higher.
Moreover, regulatory changes could increase our obligations to provide these or
additional benefits.
We are party to an agreement with the Pension Benefit Guaranty Corporation,
or the PBGC, and TXU Europe Limited, an affiliate of our former parent
corporation, under which we are required to make specified contributions to
three of our defined benefit pension plans and to maintain a $37.0 million
letter of credit in favor of the PBGC. If we or the PBGC gives notice of an
intent to terminate one or more of the covered pension plans in which
liabilities are not fully funded, or if we fail to maintain the letter of
credit, the PBGC may draw down on the letter of credit and use the proceeds to
satisfy liabilities under the Employee Retirement Income Security Act of 1974,
as amended. The PBGC, however, is required to first apply amounts received from
a $110.0 million guaranty in place from TXU Europe Limited in favor of the PBGC
before it draws on our letter of credit.
OUR FUTURE SUCCESS DEPENDS UPON OUR ABILITY TO CONTINUE ACQUIRING AND DEVELOPING
COAL RESERVES THAT ARE ECONOMICALLY RECOVERABLE.
Our recoverable reserves decline as we produce coal. We have not yet
applied for the permits required or developed the mines necessary to use all of
our reserves. Furthermore, we may not be able to mine all of our reserves as
profitably as we do at our current operations. Our future success depends upon
our conducting successful exploration and development activities or acquiring
properties containing economically recoverable reserves. Our current strategy
includes increasing our reserve base through acquisitions of government and
other leases and producing properties and continuing to use our existing
properties. The federal government also leases natural gas and coalbed methane
reserves in the west, including in the Powder River Basin. Some of these natural
gas and coalbed methane reserves are located on, or adjacent to, some of our
Powder River Basin reserves, potentially creating conflicting interests between
us and lessees of those interests. Other lessees' rights relating to these
mineral interests could prevent, delay or increase the cost of developing our
coal reserves. These lessees may also seek damages from us based on claims that
our coal mining operations impair their interests. Additionally, the federal
government limits the amount of federal land that may be leased by any company
to 150,000 acres
43
nationwide. As of December 31, 2001, we leased or have applied to lease a total
of 66,796 acres from the federal government. The limit could restrict our
ability to lease additional federal lands.
Our planned development and exploration projects and acquisition activities
may not result in significant additional reserves and we may not have continuing
success developing additional mines. Most of our mining operations are conducted
on properties owned or leased by us. Because title to most of our leased
properties and mineral rights are not thoroughly verified until a permit to mine
the property is obtained, our right to mine some of our reserves may be
materially adversely affected if defects in title or boundaries exist. In
addition, in order to develop our reserves, we must receive various governmental
permits, as discussed in Part I, Item 1 of this report under "Regulatory
Matters." We cannot predict whether we will continue to receive the permits
necessary for us to operate profitably in the future. We may not be able to
negotiate new leases from the government or from private parties or obtain
mining contracts for properties containing additional reserves or maintain our
leasehold interest in properties on which mining operations are not commenced
during the term of the lease. From time to time, we have experienced litigation
with lessors of our coal properties and with royalty holders.
IF THE COAL INDUSTRY EXPERIENCES OVERCAPACITY IN THE FUTURE, OUR PROFITABILITY
COULD BE IMPAIRED.
During the mid-1970s and early 1980s, a growing coal market and increased
demand for coal attracted new investors to the coal industry, spurred the
development of new mines and resulted in added production capacity throughout
the industry, all of which led to increased competition and lower coal prices.
Recent increases in coal prices could similarly encourage the development of
expanded capacity by new or existing coal producers. Any overcapacity could
reduce coal prices in the future.
OUR FINANCIAL CONDITION COULD BE NEGATIVELY AFFECTED IF WE FAIL
TO MAINTAIN SATISFACTORY LABOR RELATIONS.
As of December 31, 2001, the United Mine Workers of America represented
approximately 35% of our employees, who produced 21% of our coal sales volume in
the United States during the nine months ended December 31, 2001. Because of the
higher labor costs and the increased risk of strikes and other work-related
stoppages that may be associated with union operations in the coal industry, our
non-unionized competitors may have a competitive advantage in areas where they
compete with our unionized operations. If some or all of our current non-union
operations were to become unionized, we could incur an increased risk of work
stoppages, reduced productivity and higher labor costs. The ten-month United
Mine Workers of America strike in 1993 had a material adverse effect on us. Two
of our subsidiaries, Peabody Coal Company and Eastern Associated Coal Corp.,
operate under a union contract that is in effect through December 31, 2006.
Peabody Western Coal Company operates under a union contract that is in effect
through September 1, 2005.
OUR OPERATIONS COULD BE ADVERSELY AFFECTED IF WE FAIL TO MAINTAIN REQUIRED
SURETY BONDS.
Federal and state laws require bonds to secure our obligations to reclaim
lands used for mining, to pay federal and state workers' compensation, to secure
coal lease obligations, and to satisfy other miscellaneous obligations. As of
December 31, 2001, we had outstanding surety bonds with third parties for
post-mining reclamation totaling $684.9 million. Furthermore, we have an
additional $223.7 million of surety bonds in place for workers' compensation and
retiree health care obligations and $111.6 million of surety bonds securing
coal leases. These bonds are typically renewable on a yearly basis. Surety bond
issuers and holders may not continue to renew the bonds or refrain from
demanding additional collateral upon those renewals. Our failure to maintain, or
inability to acquire, surety bonds that are required by state and federal law
would have a material adverse effect on us. That failure could result from a
variety of factors including the following:
o lack of availability, higher expense or unfavorable market terms of
new surety bonds;
o restrictions on the availability of collateral for current and future
third-party surety bond issuers under the terms of our indentures or
Senior Credit Facility; and
o the exercise by third-party surety bond issuers of their right to
refuse to renew the surety.
LEHMAN BROTHERS MERCHANT BANKING CONTROLS US AND MAY HAVE CONFLICTS OF INTEREST
WITH OTHER STOCKHOLDERS IN THE FUTURE.
Lehman Brothers Merchant Banking owns 57% of our common stock. Lehman
Brothers Merchant Banking will continue to be able to control the election of
our directors and determine our corporate and management policies and actions,
including potential mergers or acquisitions, asset sales and other significant
corporate transactions. The interests of Lehman Brothers Merchant Banking may
not coincide with the interests of other holders of our common stock. We have
retained
44
affiliates of Lehman Brothers Merchant Banking to perform advisory and financing
services for us in the past, and may continue to do so in the future.
OUR ABILITY TO OPERATE OUR COMPANY EFFECTIVELY COULD BE IMPAIRED IF WE LOSE KEY
PERSONNEL.
We manage our business with a number of key personnel, in particular the
executive officers discussed previously in Part I, Item 4A. The loss of a number
of key personnel could have a material adverse effect on us. In addition, as our
business develops and expands, we believe that our future success will depend
greatly on our continued ability to attract and retain highly skilled and
qualified personnel. We cannot assure you that key personnel will continue to be
employed by us or that we will be able to attract and retain qualified personnel
in the future. We do not have "key person" life insurance to cover our executive
officers. Failure to retain or attract key personnel could have a material
adverse effect on us.
TERRORIST ATTACKS AND THREATS, ESCALATION OF MILITARY ACTIVITY IN RESPONSE TO
SUCH ATTACKS OR ACTS OF WAR MAY NEGATIVELY AFFECT OUR BUSINESS, FINANCIAL
CONDITION, AND RESULTS OF OPERATIONS.
Terrorist attacks and threats, escalation of military activity in response
to such attacks or acts of war may negatively affect our business, financial
condition and results of operations. Our business is affected by general
economic conditions, fluctuations in consumer confidence and spending, and
market liquidity, which can decline as a result of numerous factors outside of
our control, such as terrorist attacks and acts of war. Recent terrorist attacks
in the United States, as well as future events occurring in response to, or in
connection with, the attacks, including future terrorist attacks against United
States targets, rumors or threats of war, actual conflicts involving the United
States or its allies, or military or trade disruptions affecting our customers,
may materially adversely affect our operations. As a result, there could be
delays or losses in transportation and deliveries of coal to our customers,
decreased sales of our coal and extension of time for payment of accounts
receivable from our customers. Strategic targets such as energy-related assets
may be at greater risk of future terrorist attacks than other targets in the
United States. In addition, disruption or significant increases in energy prices
could result in government-imposed price controls. It is possible that any, or a
combination, of these occurrences could have a material adverse effect on our
business, financial condition and results of operations.
OUR ABILITY TO COLLECT PAYMENTS FROM OUR CUSTOMERS COULD BE IMPAIRED IF THEIR
CREDITWORTHINESS DETERIORATES.
Our ability to receive payment for coal sold and delivered depends on the
continued creditworthiness of our customers. Our customer base is changing with
deregulation as utilities sell their power plants to their non-regulated
affiliates or third parties. These new power plant owners may have credit
ratings that are below investment grade. One of our customers, Southern
California Edison Company, had its credit rating downgraded to non- investment
grade as a result of the electricity crisis in California in 2001. Southern
California Edison, which owns 56% of the Mohave Generating Station, and the
other owners of the Mohave Generating Station have a coal supply agreement that
expires in 2005. For fiscal year 2001 and the nine months ended December 31,
2001, we sold 4.8 million and 3.6 million tons of coal, respectively, to the
Mohave Generating Station. The owners of the Mohave Generating Station created a
trust account in early 2001 to fund the payment of coal under the coal supply
agreement and have advised us of their obligation, subject to certain
conditions, to cure any defaults of another owner. Our ability to continue to
receive payment from the Mohave Generating Station depends, in part, on the
creditworthiness of Southern California Edison. Failure to receive payment for
Southern California Edison's share of the Mohave Generating Station deliveries
could adversely affect our financial condition and results of operations. If the
creditworthiness of California utilities causes a general deterioration of the
creditworthiness of other utilities, our accounts receivable securitization
program could be adversely affected.
On April 6, 2001, Pacific Gas and Electric Company filed for Chapter 11
reorganization. We do not have any coal supply agreements with that utility.
One of our trading counterparties, Enron North America, filed for
bankruptcy in December 2001. At December 31, 2001, we recorded a $6.6 million
pre-tax charge for trades with Enron North America. Subsequent to Enron's
bankruptcy, the creditworthiness of other trading counterparties has
deteriorated. If deterioration of the creditworthiness of other counterparties
continues, we could be adversely affected.
45
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
Trading Activities
We market and trade coal and emission allowances. These activities give
rise to market risk, which represents the potential loss that can be caused by a
change in the market value of a particular commitment. We actively measure,
monitor and adjust traded position levels to remain within market risk limits
prescribed by management. For example, we have policies in place that limit the
amount of total exposure we may assume at any point in time.
We account for coal and emission allowance trading using the fair value
method, which requires us to reflect financial instruments with third parties,
such as forwards, futures, options and swaps, at market value in the
consolidated financial statements.
We perform a value at risk analysis of our trading portfolio, which
includes over-the-counter and brokerage trading of coal and emission allowances.
Our value at risk model is based on the industry standard risk-metrics
variance/co-variance approach. This captures our exposure related to both option
and forward positions. Our value at risk model assumes a fifteen-day holding
period and a 95% confidence interval.
The use of value at risk allows management to aggregate market risks
across products in the portfolio, compare risk on a consistent basis and
identify the drivers of risk. Due to the subjectivity in the choice of the
liquidation period, reliance on historical data to calibrate the models and the
inherent limitations in the value at risk methodology, including the use of
delta/gamma adjustments related to options, we perform regular stress, back
testing and scenario analysis to estimate the impacts of market changes on the
value of the portfolio. The results of these analyses are used to supplement the
value at risk methodology and identify additional market related risks.
During the nine months ended December 31, 2001, the low, high and average
values at risk for our coal trading portfolio were $0.7 million, $5.0 million
and $1.8 million, respectively. Our emission allowance value at risk averaged
$0.1 million during the nine months ended December 31, 2001, and did not exceed
$0.6 million during that period. Seventy-five percent of our trading positions
will settle in calendar 2002.
The Company also monitors other types of risk associated with its coal and
emission allowance trading activities, including market liquidity, counterparty
nonperformance and position valuation.
Non-trading Activities
We manage our commodity price risk for non-trading purposes through the
use of long-term coal supply agreements, rather than through the use of
derivative instruments. We sold 83% of our sales volume under long-term coal
supply agreements during the nine months ended December 31, 2001. We have sales
commitments for 97% of our calendar 2002 production.
Some of the products used in our mining activities, such as diesel fuel,
are subject to price volatility. We, through our suppliers, utilize forward
contracts to manage the exposure related to this volatility.
We have exposure to changes in interest rates due to our existing level of
indebtedness. As of December 31, 2001, after taking into consideration the
effects of interest rate swaps, we had $729.0 million of fixed-rate borrowings
and $302.1 million of variable-rate borrowings outstanding. A one percentage
point increase in interest rates would result in an annualized increase to
interest expense of $3.0 million on our variable-rate borrowings. With respect
to our fixed-rate borrowings, a one percentage point increase in interest rates
would result in a $41.0 million decrease in the fair value of these borrowings.
46
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See Part IV, Item 14 of this report for the information required by this
Item.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information required by Item 401 of Regulation S-K is included under
the caption "Election of Directors" in the Company's 2002 Proxy Statement and in
Part I, Item 4A of this report under the caption "Executive Officers of the
Company." Such information is incorporated herein by reference. The information
required by Item 405 of Regulation S-K is included under the caption "Section
16(a) Beneficial Ownership Reporting Compliance" in the Company's 2002 Proxy
Statement and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The information required by Item 402 of Regulation S-K is included under
the caption "Executive Compensation" in the Company's 2002 Proxy Statement and
is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information required by Item 403 of Regulation S-K is included under
the caption "Ownership of Company Securities" in the Company's 2002 Proxy
Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information required by Item 404 of Regulation S-K is included under
the caption "Related Party Transactions" in the Company's 2002 Proxy Statement
and is incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) Financial Statements
(1) The following consolidated financial statements of Peabody Energy
Corporation included in the Company's December 31, 2001 Annual Report to
Stockholders are incorporated by reference:
Report of Independent Auditors
Consolidated Statements of Operations--Nine Months Ended December 31,
2001, and the years ended March 31, 2001 and March 31, 2000
Consolidated Balance Sheets--December 31, 2001 and March 31, 2001
Consolidated Statements of Changes in Stockholders' Equity--Nine Months
Ended December 31, 2001, and the years ended March 31, 2001 and March 31,
2000
Consolidated Statements of Cash Flows--Nine Months Ended December 31,
2001, and the years ended March 31, 2001 and March 31, 2000
Notes to Consolidated Financial Statements
(2) Financial Statement Schedule.
The following financial statement schedule of Peabody Energy
Corporation is included in Item 14, along with the report of independent
auditors thereon, at the pages indicated:
Page
----
Report of Independent Auditors on Financial Statement Schedule F-1
Valuation and Qualifying Accounts F-2
47
All other schedules for which provision is made in the applicable accounting
regulation of the Securities and Exchange Commission are not required under the
related instructions or are inapplicable and, therefore, have been omitted.
(3) Exhibits.
See Exhibit Index hereto.
(b) Reports on Form 8-K.
We filed no reports on Form 8-K during the quarter ended December 31, 2001.
48
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PEABODY ENERGY CORPORATION
/s/ Irl F. Engelhardt
------------------------------------
Irl F. Engelhardt
Chairman and Chief Executive Officer
Date: March 12, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons, on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Irl F. Engelhardt
-------------------------------------------
Irl F. Engelhardt Chairman, Chief Executive Officer and Director March 12, 2002
(principal executive officer)
/s/ Richard M. Whiting
-------------------------------------------
Richard M. Whiting President, Chief Operating Officer and Director March 12, 2002
/s/ Richard A. Navarre
-------------------------------------------
Richard A. Navarre Executive Vice President and Chief Financial Officer March 12, 2002
(principal financial and accounting officer)
/s/ Henry E. Lentz
-------------------------------------------
Henry E. Lentz Vice President, Assistant Secretary and Director March 12, 2002
/s/ Bernard J. Duroc-Danner
-------------------------------------------
Bernard J. Duroc-Danner Director March 12, 2002
/s/ Roger H. Goodspeed
-------------------------------------------
Roger H. Goodspeed Director March 12, 2002
/s/ Felix P. Herlihy
-------------------------------------------
Felix P. Herlihy Director March 12, 2002
/s/ William E. James
-------------------------------------------
William E. James Director March 12, 2002
/s/ William C. Rusnack
-------------------------------------------
William C. Rusnack Director March 12, 2002
/s/ James R. Schlesinger
-------------------------------------------
James R. Schlesinger Director March 12, 2002
/s/ Blanche M. Touhill
-------------------------------------------
Blanche M. Touhill Director March 12, 2002
/s/ Alan H. Washkowitz
-------------------------------------------
Alan H. Washkowitz Director March 12, 2002
49
REPORT OF INDEPENDENT AUDITORS
Board of Directors
Peabody Energy Corporation
We have audited the consolidated financial statements of Peabody Energy
Corporation (the Company) as of December 31, 2001 and March 31, 2001, and for
the nine months ended December 31, 2001 and the years ended March 31, 2001 and
2000, and have issued our report thereon dated January 19, 2002. Our audits also
included the financial statement schedule listed in Item 14(a). This schedule is
the responsibility of the Company's management. Our responsibility is to express
an opinion based on our audits. In our opinion, the financial statement schedule
referred to above, when considered in relation to the basic financial statements
taken as a whole, presents fairly in all material respects the information set
forth therein.
/s/ Ernst & Young LLP
St. Louis, Missouri
January 19, 2002
F-1
PEABODY ENERGY CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(In thousands) Balance at Charged to Balance
Beginning Costs and at End
Description of Period Expenses Deductions(1) Other of Period
----------- ---------- ---------- ------------- -------- ----------
NINE MONTHS ENDED DECEMBER 31, 2001
Reserves deducted from asset accounts:
Land and coal interests $ 13,184 $ (275) $ - $ (73) $ 12,836
Reserve for materials and supplies 11,562 - (1,689) 20 9,893
Allowance for doubtful accounts 1,213 283 - - 1,496
YEAR ENDED MARCH 31, 2001
Reserves deducted from asset accounts:
Land and coal interests $ 13,199 $ 605 $ - $ (620)(2) $ 13,184
Reserve for materials and supplies 12,400 - (2,672) 1,834 (2) 11,562
Allowance for doubtful accounts 1,233 - (20) - 1,213
YEAR ENDED MARCH 31, 2000
Reserves deducted from asset accounts:
Land and coal interests $ 54,277 $ 2,179 $(40,541) $ (2,716)(2)(3) $ 13,199
Reserve for materials and supplies 16,558 - (4,748) 590 (2) 12,400
Allowance for doubtful accounts 177 1,213 (157) - 1,233
(1) Reserves utilized, unless otherwise indicated.
(2) Balances transferred from other accounts.
(3) Balances transferred as part of asset contribution to joint venture.
F-2
EXHIBIT INDEX
The exhibits below are numbered in accordance with the Exhibit Table of Item 601
of Regulation S-K.
Exhibit
No. Description of Exhibit
--- ----------------------
3.1 Third Amended and Restated Certificate of Incorporation of the Registrant (Incorporated by reference to Exhibit 3.1 of the
Registrant's Form S-1 Registration Statement No. 333-55412).
3.2 Amended and restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.2 of the Company's Form S-1
Registration Statement No. 333-55412).
4.1 Senior Note Indenture dated as of May 18, 1998 between the Registrant and State Street Bank and Trust Company, as Senior
Note Trustee (Incorporated by reference to Exhibit 4.1 of the Registrant's Form S-4 Registration Statement No. 333-59073).
4.2 Senior Subordinated Note Indenture dated as of May 18, 1998 between the Registrant and State Street Bank and Trust
Company, as Senior Subordinated Note Trustee (Incorporated by reference to Exhibit 4.2 of the Registrant's Form S-4
Registration Statement No. 333-59073).
4.3 First Supplemental Senior Note Indenture dated as of May 19, 1998 among the Guaranteeing Subsidiary (as defined therein),
the Registrant the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust
Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.3 of the Registrant's Form S-4 Registration
Statement No. 333-59073).
4.4 First Supplemental Senior Subordinated Note Indenture dated as of May 19, 1998 among the Guaranteeing Subsidiary (as
defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated
Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to
Exhibit 4.4 of the Registrant's Form S-4 Registration Statement No. 333-59073).
4.5 Notation of Senior Subsidiary Guarantee dated as of May 19, 1998 among the Senior Note Guarantors (as defined in the
Senior Note Indenture) (Incorporated by reference to Exhibit 4.5 of the Registrant's Form S-4 Registration Statement No.
333-59073).
4.6 Notation of Subordinated Subsidiary Guarantee dated as of May 19, 1998 among the Senior Subordinated Note Guarantors (as
defined in the Senior Subordinated Note Indenture) (Incorporated by reference to Exhibit 4.6 of the Registrant's Form S-4
Registration Statement No. 333-59073).
4.7 Senior Note Registration Rights Agreement dated as of May 18, 1998 between the Registrant and Lehman Brothers Inc.
(Incorporated by reference to Exhibit 4.7 of the Registrant's Form S-4 Registration Statement No. 333-59073).
4.8 Senior Subordinated Note Registration Rights Agreement dated as of May 18, 1998 between the Registrant and Lehman Brothers
Inc. (Incorporated by reference to Exhibit 4.8 of the Registrant's Form S-4 Registration Statement No. 333-59073).
4.9 Second Supplemental Senior Note Indenture dated as of December 31, 1998 among the Guaranteeing Subsidiary (as defined
therein), the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank
and Trust Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.9 of the Registrant's Form 10-Q for the
quarter ended December 31, 1999).
4.10 Second Supplemental Senior Subordinated Note Indenture dated as of December 31, 1998 among the Guaranteeing Subsidiary (as
defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated
Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to
Exhibit 4.10 of the Registrant's Form 10-Q for the quarter ended December 31, 1999).
4.11 Third Supplemental Senior Note Indenture dated as of June 30, 1999 among the Guaranteeing Subsidiary (as defined therein),
the Registrant, the other Senior Note Guarantors (as defined in the Senior Note Indenture) and State Street Bank and Trust
Company, as Senior Note Trustee (Incorporated by reference to Exhibit 4.11 of the Registrant's Form 10-Q for the quarter
ended December 31, 1999).
4.12 Third Supplemental Senior Subordinated Note Indenture dated as of June 30, 1999 among the Guaranteeing Subsidiary (as
defined therein), the Registrant, the other Senior Subordinated Note Guarantors (as defined in the Senior Subordinated
Note Indenture) and State Street Bank and Trust Company, as Senior Subordinated Note Trustee (Incorporated by reference to
Exhibit 4.12 of the Registrant's Form 10-Q for the quarter ended December 31, 1999).
1
Exhibit
No. Description of Exhibit
--- ----------------------
4.13 Specimen of stock certificate representing the Registrant's common stock, $.01 par value. (Incorporated by reference
to Exhibit 4.13 of the Registrant's Form S-1 Registration Statement No. 333-55412).
4.14 Stockholders' Agreement dated as of May 19, 1998 among the Registrant, Lehman Brothers Merchant Banking Partners II L.P.,
Lehman Brothers Offshore Investment Partners II L.P., LB I Group Inc., Lehman Brothers Capital Partners III, L.P., Lehman
Brothers Capital Partners IV, L.P., Lehman Brothers MBG Partners 1998 (A) L.P. and certain members of the Registrant's
management. (Incorporated by reference to Exhibit 4.14 of the Registrant's Form S-1 Registration Statement No. 333-55412).
4.15 Stockholders' Agreement dated as of July 23, 1998 among the Registrant, Lehman Brothers Merchant Banking Partners II L.P.,
Lehman Brothers Offshore Investment Partners II L.P., LB I Group Inc., Lehman Brothers Capital Partners III, L.P., Lehman
Brothers Capital Partners IV, L.P., Lehman Brothers MBG Partners 1998 (A) L.P., Co-Investment Partners, L.P., The Mutual
Life Insurance Company of New York and Finlayson Investments Pte Ltd. (Incorporated by reference to Exhibit 4.15 of the
Registrant's Form S-1 Registration Statement No. 333-55412).
4.16 Registration Rights Agreement, dated as of December 2001, among the Registrant, Lehman Brothers Merchant Banking Partners
II L.P., Lehman Brothers Offshore Investment Partners II L.P., LB I Group, Inc., Lehman Brothers Capital Partners III
L.P., Lehman Brothers Capital Partners IV L.P., Lehman Brothers MBG Partners (A) L.P., Lehman Brothers MBG Partners (B)
L.P. and Lehman MBG Partners (C) L.P.
10.1 Amended and Restated Credit Agreement dated as of June 9, 1998 among the Registrant, as Borrower, Lehman Brothers Inc., as
Arranger, Lehman Commercial Paper Inc., as Syndication Agent, Documentation Agent, and Administrative Agent, and the
lenders party thereto (Incorporated by reference to Exhibit 10.1 of the Registrant's Form S-4 Registration Statement No.
333-59073).
10.2 Guarantee and Collateral Agreement dated as of May 14, 1997 made by the Guarantors, in favor of Lehman Commercial Paper,
Inc., as Administrative Agent for the banks and other financial institutions (Incorporated by reference to Exhibit 10.2 of
the Registrant's Form S-4 Registration Statement No. 333-59073).
10.3 Federal Coal Lease WYW0321779: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.3 of the Registrant's
Form S-4 Registration Statement No. 333-59073).
10.4 Federal Coal Lease WYW119554: North Antelope/Rochelle Mine (Incorporated by reference to Exhibit 10.4 of the Registrant's
Form S-4 Registration Statement No. 333-59073).
10.5 Federal Coal Lease WYW5036: Rawhide Mine (Incorporated by reference to Exhibit 10.5 of the Registrant's Form S-4
Registration Statement No. 333-59073).
10.6 Federal Coal Lease WYW3397: Caballo Mine (Incorporated by reference to Exhibit 10.6 of the Registrant's Form S-4
Registration Statement No. 333-59073).
10.7 Federal Coal Lease WYW83394: Caballo Mine (Incorporated by reference to Exhibit 10.7 of the Registrant's Form S-4
Registration Statement No. 333-59073).
10.8 Federal Coal Lease WYW136142 (Incorporated by reference to Exhibit 10.8 of Amendment No. 1 of the Registrant's Form S-4
Registration Statement No. 333-59073).
10.9 Royalty Prepayment Agreement by and among Peabody Natural Resources Company, Gallo Finance Company and Chaco Energy
Company, dated September 30, 1998 (Incorporated by reference to Exhibit 10.9 of the Registrant's Form 10-Q for the second
quarter ended September 30, 1998).
10.10* 1998 Stock Purchase and Option Plan for Key Employees of the Registrant (Incorporated by reference to Exhibit 10.10 of the
Registrant's Form 10-Q for the third quarter ended December 1998).
10.11* Employment Agreement between Irl F. Engelhardt and the Registrant dated May 19, 1998 (Incorporated by reference to Exhibit
10.11 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.12* Employment Agreement between Richard M. Whiting and the Registrant dated May 19, 1998 (Incorporated by reference to
Exhibit 10.12 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.13* Employment Agreement between Richard A. Navarre and the Registrant dated May 19, 1998 (Incorporated by reference to
Exhibit 10.13 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.14* Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated May 19, 1998 (Incorporated by reference to
Exhibit 10.14 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.15* Employment Agreement between Paul H. Vining and the Registrant dated July 1, 2000 (Incorporated by reference to Exhibit
10.19 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.16 Amendment No. 1 to Credit Agreement dated as of April 30, 2001 among the Registrant, as Borrower, Lehman Brothers Inc., as
Arranger, Lehman Commercial Paper Inc., as Syndication Agent, Bank of America National Trust & Savings Association and The
Fuji Bank, Limited, as Documentation Agents, Bank One, NA, as Administrative Agent, and the lenders party thereto
(Incorporated by reference to Exhibit 10.20 of the Registrant's Form S-1 Registration Statement No. 333-55412).
2
Exhibit
No. Description of Exhibit
--- ----------------------
10.17* First Amendment to the Employment Agreement between Irl F. Engelhardt and the Registrant dated as of May 10, 2001
(Incorporated by reference to Exhibit 10.21 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.18* First Amendment to the Employment Agreement between Richard M. Whiting and the Registrant dated as of May 10, 2001
(Incorporated by reference to Exhibit 10.22 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.19* First Amendment to the Employment Agreement between Richard A. Navarre and the Registrant dated as of May 10, 2001
(Incorporated by reference to Exhibit 10.23 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.20* First Amendment to the Employment Agreement between Roger B. Walcott, Jr. and the Registrant dated as of May 10, 2001
(Incorporated by reference to Exhibit 10.24 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.21* First Amendment to the Employment Agreement between Paul H. Vining and the Registrant dated as of May 10, 2001
(Incorporated by reference to Exhibit 10.25 of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.22* Form of First Amendment to Stockholders' Agreement dated as of May 19, 1998 (Incorporated by reference to Exhibit 10.26
of the Registrant's Form S-1 Registration Statement No. 333-55412).
10.23* Form of Long-Term Equity Incentive Plan (Incorporated by reference to Exhibit 10.27 of the Registrant's Form S-1
Registration Statement No. 333-55412).
10.24* Form of 2001 Employee Stock Purchase Plan (Incorporated by reference to Exhibit 10.28 of the Registrant's Form S-1
Registration Statement No. 333-55412).
10.25* Form of Equity Incentive Plan for Non-Employee Directors (Incorporated by reference to Exhibit 10.29 of the Registrant's
Form S-1 Registration Statement No. 333-55412).
10.26* Form of Amendment to the Non-Qualified Stock Option Agreement (Incorporated by reference to Exhibit 10.30 of the
Registrant's Form S-1 Registration Statement No. 333-55412).
10.27* Peabody Energy Corporation Deferred Compensation Plan (Incorporated by reference to Exhibit 10.30 of the Registrant's
Form 10-Q for the quarter ended September 30, 2001).
10.28 Receivables Purchase Agreement as of February 20, 2002, by and among Seller, the Registrant, Market Street Funding
Corporation, and PNC Bank, National Association, as Administrator.
13 Portions of the Company's Annual Report to Stockholders for the nine months ended December 31, 2001.
21 List of Subsidiaries.
23 Consent of Ernst & Young LLP, Independent Auditors.
* These exhibits constitute all management contracts, compensatory plans
and arrangements required to be filed as an exhibit to this form pursuant to
Item 14(c) of this report.
3