PEABODY ENERGY CORP - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NUMBER 1-16463

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PEABODY ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

DELAWARE 13-4004153
(State or other jurisdiction of incorporation or (I.R.S. Employer Identification No.)
organization)

701 MARKET STREET, ST. LOUIS, MISSOURI 63101
(Address of principal executive offices) (Zip Code)

(314) 342-3400
Registrant's telephone number, including area code

SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act) Yes [X] No [ ]

Aggregate market value of the voting stock held by non-affiliates of the
Registrant, calculated using the closing price on June 28, 2002 of $28.30:
Common Stock, par value $0.01 per share, $873.3 million.

Number of shares outstanding of each of the Registrant's classes of Common
Stock, as of March 1, 2003: Common Stock, par value $0.01 per share, 52,423,512
shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Peabody Energy Corporation (the "Company") Annual Report
for the year ended December 31, 2002 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
6, 2003 (the "Company's 2003 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.
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CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

Some of the information included in this report 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:

- future outlook;

- anticipated capital expenditures;

- future cash flows and borrowings; and

- 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:

- growth in coal and power markets;

- coal's market share of electricity generation;

- timing of reductions in customer coal inventories;

- the pace and extent of the economic recovery and future economic
conditions;

- severity of weather;

- railroad and other transportation performance and costs;

- the ability to renew sales contracts upon expiration or renegotiation;

- the ability to successfully implement operating strategies;

- the effectiveness of our cost-cutting measures;

- regulatory and court decisions;

- future legislation;

- changes in postretirement benefit and pension obligations;

- credit, market and performance risk associated with our customers;

- modification or termination of our long-term coal supply agreements;

- reductions of purchases by major customers;

- risks inherent to mining, including geologic conditions or unforeseen
equipment problems;

- terrorist attacks or threats affecting our or our customers' operations;

- replacement of recoverable reserves;

- implementation of new accounting standards;

- inflationary trends, interest rates and access to capital markets and

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- other factors, including those discussed in "Legal Proceedings," set
forth in Item 3 of this report and the "Risks Related to Our Company"
section of "Management's Discussion and Analysis of Financial Condition
and Results of Operations," set forth in Item 7 of this report.

When considering these forward-looking statements, you should keep in mind
the cautionary statements in this report 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

1

Note: The words "we" or "our," as used in this report, refer to Peabody Energy
Corporation or its applicable subsidiary or subsidiaries.

PART I

ITEM 1. BUSINESS

OVERVIEW

We are the largest private-sector coal company in the world. During the
year ended December 31, 2002, we sold 197.9 million tons of coal. During this
period, we sold coal to more than 280 electricity generating and industrial
plants in 14 countries, and fueled the generation of more than 9% of all
electricity in the United States and 2% of all electricity in the world. At
December 31, 2002, we had 9.1 billion tons of proven and probable coal reserves.

We own, through our subsidiaries, majority interests in 33 coal operations
located throughout all major U.S. coal producing regions, with 73% of our U.S.
mining operations' coal sales during the year ended December 31, 2002 shipped
from the western United States and the remaining 27% 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 128.0 million tons
during 2002, representing a compounded annual growth rate of 11%. In the west,
we own and operate mines in Arizona, Colorado, Montana, New Mexico and Wyoming.
In the east, we own and operate mines in Illinois, Indiana, Kentucky and West
Virginia. We produced 78% of our sales volume for the year ended December 31,
2002 from non-union mines.

For the year ended December 31, 2002, 94% of our sales were to U.S.
electricity generators, 4% were to customers outside the United States and 2%
were to the U.S. industrial sector. Approximately 97% of our coal sales during
the year ended December 31, 2002 were under long-term contracts. Our sales
backlog, including backlog subject to price reopener and/or extension
provisions, approximated one billion tons as of December 31, 2002. The average
volume weighted remaining term of our long-term contracts is approximately 4.4
years, with remaining terms ranging from one to 18 years. As of December 31,
2002, we had approximately eight million tons and 75 million tons of expected
production unpriced for 2003 and 2004, respectively. We have the ability to
increase production by four to five million tons each quarter by running our
current operations at their full capacity.

In addition to our mining operations, we market, broker and trade coal and
emission allowances. Our total tons traded were 66.9 million for the year ended
December 31, 2002. Our other energy related businesses include coalbed methane
production, transportation services, third-party coal contract restructuring and
the development of coal-fueled 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. Peabody's first coal mine
was opened 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. Peabody Coal
Company was acquired by Kennecott Copper Company in 1968. The company was then
sold to Peabody Holding Company in 1977, which was formed by a consortium of
companies.

During the 1980s, Peabody grew through expansion and acquisition, opening
the North Antelope Mine in Wyoming's coal-rich Powder River Basin in 1983 and
the Rochelle Mine in 1985. In 1984, Peabody acquired the West Virginia coal
properties of ARMCO Steel and in 1987 purchased Eastern Associated Coal Corp.,
which included seven operating mines and substantial low sulfur coal reserves in
West Virginia.

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In July 1990, Peabody Holding Company was acquired by Hanson PLC, a
British-American industrial management company. From 1990 to 2002, Peabody's
business was redefined, as the company transformed itself into a more
productive, low-cost, low sulfur energy company, tripling its productivity and
reducing costs 42% while improving safety performance 66%.

In 1993, interests in three mines in New South Wales, Australia, were
acquired from Costain Group in anticipation of the growing Pacific Rim market
for coal. The properties included 100% ownership of the Ravensworth Mine, a 50%
interest in the Narama Mine and a 28.75% interest in the Warkworth Mine,
subsequently increased to 43.75%. We also subsequently developed a fourth mine,
Bengalla, which began shipments in early 1999. Peabody's interest in the
Bengalla joint venture was increased from 35% to 37% in 1998 and to 40% in 2000.
In 1993, the company also acquired the Lee Ranch Mine in New Mexico.

In 1994, Peabody purchased a one-third ownership in Black Beauty Coal
Company, Indiana's largest coal producer. The Caballo and Rawhide mines in
Wyoming's Powder River Basin also were purchased 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. Peabody's sales volume from
the Powder River Basin increased from 31 million tons in 1993 to 105 million
tons in 2002.

In February 1997, Hanson spun off its energy-related businesses into The
Energy Group PLC, which included Peabody Holding Company and Eastern Group, a
United Kingdom electricity distribution and generating company. The Energy Group
was a publicly traded company in the United Kingdom, and its American Depository
Receipts (ADRs) were publicly traded on the New York Stock Exchange. In May
1997, The Energy Group, through Peabody, purchased Citizens Power LLC, a leading
power marketer.

Peabody increased its 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 an additional 25% of Arclar Coal Company in 2000.

In May 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 and Citizens Power LLC.

In August 1999, Peabody purchased a 55% interest in the Moura Mine in
Queensland, Australia, which supplied a range of steam and metallurgical coals
to Asia-Pacific customers and operated a coalbed methane extraction operation.

In August 2000, Citizens Power, Peabody's subsidiary that marketed and
traded electric power and energy-related commodity risk management products, was
sold to Edison Mission Energy.

In January 2001, Peabody sold its Australian mining operations to Coal &
Allied, a 71%-owned subsidiary of Rio Tinto Limited for $455 million.

In April 2001, Peabody changed its name to Peabody Energy Corporation
("Peabody"), reflecting its position as a premier energy supplier. In May 2001,
Peabody completed an initial public offering of common stock, and the company's
shares began trading on the New York Stock Exchange under the ticker symbol
"BTU," the globally recognized symbol for energy.

In June 2002, Peabody acquired Beaver Dam Coal Company, a major holder of
coal reserves in Western Kentucky. In August 2002, Peabody acquired the Wilkie
Creek Coal Mine in Queensland, Australia, marking a return to Australian mining
operations. In September 2002, Peabody purchased the remaining 25% interest in
Arclar Company, LLC. Peabody's Black Beauty affiliate owns the remaining 75%
interest of Arclar.

In December 2002, Peabody contributed 120 million tons of coal reserves for
$72.5 million in cash and a 15% interest in Penn Virginia Resource Partners,
L.P. (NYSE: PVR), a publicly held master limited partnership.

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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.

(US MAP)

Within the United States, we conduct operations in the Powder River Basin,
Southwest, Appalachia and Midwest regions.

POWDER RIVER BASIN OPERATIONS

We control approximately 2.9 billion tons of coal reserves in the Powder
River Basin, the largest and fastest growing major U.S. coal-producing region.
Our subsidiaries, Powder River Coal Company and Caballo Coal Company, own and
manage three low sulfur, non-union surface mining complexes in Wyoming that sold
approximately 104.8 million tons of coal during the year ended December 31,
2002, 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 Railway and the Union Pacific
Railroad. The Rawhide Mine is serviced by the Burlington Northern Santa Fe
Railway.

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 8,300 to 8,900 Btu per pound.

Our subsidiary, Big Sky Coal Company, operates 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 Railway.

NORTH ANTELOPE/ROCHELLE

The North Antelope/Rochelle Mine is located 65 miles south of Gillette,
Wyoming. This mine is the largest in the United States, selling 75.4 million
tons during 2002. The North Antelope/Rochelle facility is capable of loading its
production in up to 2,000 railcars per day. 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

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States, using a dragline along with six truck-and-shovel fleets. We added a
second dragline at this mine in 2002 to improve productivity.

CABALLO

The Caballo Mine is located 20 miles south of Gillette, Wyoming. During
2002, it sold approximately 26.0 million tons of compliance coal (defined as
having sulfur dioxide content of 1.2 pounds or less per million Btu). 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.

RAWHIDE

The Rawhide Mine is located ten miles north of Gillette, Wyoming and uses
truck-and-shovel mining methods. Operations were suspended at the Rawhide mine
in 1999, but the mine reopened in January 2002 as a result of improved demand
for Powder River Basin coal. During 2002, it sold approximately 3.4 million tons
of compliance coal.

BIG SKY

The Big Sky Mine is located in the northern Powder River Basin near
Colstrip, Montana and uses dragline mining equipment. The mine sold 2.8 million
tons of medium sulfur coal during 2002. Coal is shipped by rail to several major
electricity 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 three mines in the western bituminous coal region -- two
in Arizona and one in Colorado. The Colorado mine, which is owned and managed by
Seneca Coal Company, and the Arizona mines, which are owned and managed by
Peabody Western Coal Company, supply primarily compliance coal under long-term
coal supply agreements to electricity generating stations in the region. In New
Mexico, we own and manage, through our Peabody Natural Resources Company
subsidiary, the Lee Ranch Mine, which mines and produces subbituminous medium
sulfur coal. Together, these four mines sold 21.0 million tons of coal during
2002.

BLACK MESA

The Black Mesa Mine, which is located on the Navajo Nation and Hopi Tribe
reservations in Arizona, uses two draglines and sold 4.6 million tons of coal
during 2002. 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 December 31, 2005. Hourly workers at this mine are members of the
United Mine Workers of America.

KAYENTA

The Kayenta Mine is adjacent to the Black Mesa Mine and uses four draglines
in three mining areas. It sold approximately 8.3 million tons of coal during
2002. 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.
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SENECA

The Seneca Mine near Hayden, Colorado shipped 1.8 million tons of
compliance coal during 2002, 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 MINE

The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 6.3
million tons of medium sulfur coal during 2002. Lee Ranch shipped the majority
of its coal to two customers in Arizona and New Mexico under coal supply
agreements extending until 2010 and 2014, respectively. Lee Ranch is a non-union
surface mine that uses a combination of dragline and truck-and-shovel mining
techniques.

APPALACHIA OPERATIONS

We own and manage six wholly owned operating units and related facilities
in West Virginia. Our subsidiary, Pine Ridge Coal Company, owns and manages the
Big Mountain Operating Unit, and our subsidiary, Eastern Associated Coal Corp.,
owns and manages the remaining wholly owned facilities. During 2002, these
operations sold approximately 16.7 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. In addition to our wholly owned facilities, we own a 49%
interest in another underground mine in West Virginia.

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, and includes a small
amount of contract mine production from coal reserves we control. During 2002,
the Big Mountain Operating Unit sold approximately 1.2 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. During the fourth
quarter of 2002, we suspended operations of the unit in response to market
conditions. The mine was reopened in February 2003.

HARRIS OPERATING UNIT

The Harris Operating Unit consists of the Harris No. 1 Mine near Bald Knob,
West Virginia, which sold approximately 3.2 million tons of primarily
metallurgical product during 2002. 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 No.1 Mine, the Colony Bay Mine and
contract mining operations from coal reserves that we control. This preparation
plant shipped approximately 2.6 million tons of steam and metallurgical coal
sourced from the contract mines during 2002. Processed coal is loaded at the
plant site on the CSX railroad or transferred via conveyor to our Kopperston
loadout facility and loaded on the Norfolk Southern railroad.

WELLS OPERATING UNIT

The Wells Operating Unit, in Boone County, West Virginia, sold
approximately 3.9 million tons of metallurgical and steam coal during 2002. The
unit consists of the River's Edge Mine, contract mine production and the Wells
preparation plant, located near Wharton, West Virginia. Processed coal is loaded
on the CSX railroad. The River's Edge mine replaced the Lightfoot No. 2 Mine,
which depleted its economically recoverable reserves in the fourth quarter of
2002.

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FEDERAL NO. 2 MINE

The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining
equipment and shipped approximately 5.0 million tons of steam coal during 2002.
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, utilized 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. The mine produced 0.8
million tons in 2002, but production was suspended during the fourth quarter of
2002 in response to market conditions.

KANAWHA EAGLE COAL JOINT VENTURE

We have a 49% interest in Kanawha Eagle Coal, LLC, which owns and manages
an underground mine, preparation plant and barge-and-rail loading facilities
near Marmet, West Virginia. The mine is non-union and uses continuous mining
equipment. It shipped 1.5 million tons during 2002.

MIDWEST OPERATIONS

We operated seven wholly-owned mines in the midwestern United States during
2002, which collectively sold 7.3 million tons of coal. These operations include
five underground and two surface mines, along with three preparation plants and
three 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 to industrial customers that
generate their own power. Our Camp and Midwest operating units are owned and
managed by our Peabody Coal Company subsidiary.

CAMP OPERATING UNIT

The Camp Operating Unit, located near Morganfield, Kentucky, operated the
Camp No. 11 Mine, an underground mine, and a large preparation plant and barge
loading facility. The Camp No. 11 Mine sold 2.4 million tons of coal during 2002
before exhausting its economically recoverable reserves in December 2002. The
Camp No. 11 Mine used both longwall and continuous mining equipment. We sold
most of the Camp No. 11 production under contract to the Tennessee Valley
Authority. This mine's production will be replaced with production from the
Highland Operating Unit. Hourly workers at these operations were members of the
United Mine Workers of America.

HIGHLAND OPERATING UNIT

The Highland Operating Unit, which is owned and managed by our Highland
Mining Company subsidiary, is located near Waverly, Kentucky, and consists of
two underground mines. The Highland No. 11 Mine produced 0.6 million tons from
the No. 11 coal seam during 2002. The Highland No. 9 Mine is still in
development and is expected to operate from the No. 9 coal seam beginning in the
first quarter of 2003. Hourly workers at these operations are members of the
United Mine Workers of America.

MIDWEST OPERATING UNIT

The Midwest Operating Unit near Graham, Kentucky sold 1.4 million tons of
coal during 2002. In 2002, the unit included the Gibraltar surface mining
operation, which uses truck-and-shovel equipment, and the Gibraltar Highwall
Mine, which used continuous mining equipment. We sold coal from these mines
under contract to the Tennessee Valley Authority. The Gibraltar Highwall Mine
was closed in the

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summer of 2002 as the mine reached the end of its economically recoverable
reserves. Hourly workers at these operations are members of the United Mine
Workers of America.

PATRIOT COAL COMPANY

Our subsidiary, Patriot Coal Company, owns and manages Patriot, a surface
mine, and Freedom, an underground mine, in Henderson County, Kentucky, and sold
approximately 2.6 million tons of coal during 2002. The Big Run underground mine
in Ohio County, Kentucky began operations in the fourth quarter of 2002 and sold
approximately 0.3 million tons. The underground mines use 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.

In addition to the wholly-owned mines in our Midwest operating region, we
have an 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 producer in the Illinois
Basin, which currently manages eight active mines in Indiana and four active
mines in Illinois. Together with its equity affiliates, Black Beauty's
operations produced and sold 24.1 million tons of compliance, medium sulfur and
high sulfur steam coal during 2002. 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, holds the remaining minority interest.

Black Beauty's principal Indiana mines include Air Quality No. 1,
Farmersburg, Francisco and three mines near Somerville, Indiana. Air Quality No.
1 is an underground coal mine located near Monroe City, Indiana that shipped 1.8
million tons of compliance coal during 2002. Farmersburg is a surface mine
situated in Vigo and Sullivan counties in Indiana that sold 4.1 million tons of
medium sulfur coal during 2002. Francisco, a surface mine located in Gibson
county, Indiana, sold 2.4 million tons during 2002, and the three Somerville
surface mines, also located in Gibson county, shipped a total of 7.0 million
tons in fiscal year 2002.

During 2002, Black Beauty began production at a new underground mining
facility, the Vermilion Grove Mine, in east-central Illinois. Together with the
existing Riola No. 1 Mine, these operations sold 1.8 millions tons during 2002.
Black Beauty's remaining mines sold 2.7 million tons during 2002. All of Black
Beauty Coal Company's wholly-owned operations utilize non-union labor.

Black Beauty owns a 75% equity interest in Arclar Company, LLC, which
operates the Cottage Grove surface mine and Willow Lake underground mining
complex situated in Gallatin and Saline counties in southern Illinois. During
2002, these facilities sold 4.3 million tons of coal, primarily shipped by barge
to downriver utility plants. Black Beauty provides a contract workforce for the
Arclar surface operations; the workforce at the underground operations is
represented under non-UMWA labor agreements. The Willow Lake Mine began
operations during the first half of 2002. Willow Lake replaced Arclar's existing
operations at Eagle Valley and Big Ridge. Once it reaches full capacity, Willow
Lake is expected to produce about 3.5 million tons per year. In September 2002,
Peabody purchased the 25% interest in Arclar Company, LLC not owned by Black
Beauty for $14.9 million.

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 Somerville South mines and as contract operator for Black
Beauty at the Evansville River Terminal.

We are considering the acquisition of the 18.3% minority interest of Black
Beauty. In the event the acquisition is completed, we anticipate the continuing
involvement of the current minority interest owners in the day-to-day management
of the business.

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AUSTRALIAN MINING OPERATIONS -- WILKIE CREEK MINE

On August 22, 2002, we purchased the 1.4 million ton per year Wilkie Creek
Coal Mine and coal reserves in Queensland, Australia. From the acquisition date
to December 31, 2002, the mine sold 0.4 million tons. Evaluations are complete
with respect to 147 million tons of proven and probable reserves acquired
surrounding the Wilkie Creek Mine. We continue to evaluate other coal resources
that were obtained in this acquisition to finalize the estimate of our total
proven and probable reserves in Australia.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

On December 19, 2002, we formed an alliance with Penn Virginia Resource
Partners, L.P. (PVR) whereby we contributed 120 million tons of coal reserves in
exchange for $72.5 million in cash and 2.76 million units, or 15%, of the
publicly traded PVR master limited partnership. Our subsidiaries subsequently
leased the coal and will pay royalties as the coal is mined.

LONG-TERM COAL SUPPLY AGREEMENTS

We currently have a sales backlog of approximately one billion tons of
coal, and our coal supply agreements have remaining terms ranging from one to 18
years and an average volume-weighted remaining term of approximately 4.4 years.
For 2002, we sold 97% of our sales volume under long-term coal supply
agreements. In 2002, we sold coal to more than 280 electricity generating and
industrial plants in 14 countries. Our primary customer base is in the United
States. Two of our coal supply agreements are the subject of ongoing litigation
and arbitration.

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. As of December 31, 2002, we had approximately eight million tons and
75 million tons of expected production unpriced for 2003 and 2004, respectively.

Long-term contracts are attractive for regions where market prices are
expected to remain stable, for cost-plus arrangements serving captive
electricity generating plants and for the sale of high sulfur coal to "scrubbed"
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.

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 competitive bidding and extensive negotiations
with customers. Consequently, the terms of these contracts vary significantly in
many respects, including price adjustment features, price reopener terms, coal
quality requirements, quantity parameters, permitted sources of supply,
treatment of environmental constraints, extension options and force majeure,
termination and assignment provisions.

Each contract sets a base price. Some contracts provide for a predetermined
adjustment to base price at times specified in the agreement. Base prices may
also be adjusted quarterly, annually or at other periodic intervals for changes
in production costs and/or changes due to inflation or deflation. Changes in
production costs may be measured by defined formulas that may include actual
cost experience at the mine as part of the formula. The inflation/deflation
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 U.S.
Department of Commerce. In most cases, the components of the base price
represented by taxes, fees and royalties which are based on a percentage of the
selling price are also adjusted for any changes in the base price and passed
through to the customer. Some contracts allow the base price to be adjusted to
reflect the cost of capital.

Most contracts contain provisions to adjust the base price due to new
statutes, ordinances or regulations that impact our cost of performance of the
agreement. Additionally, some contracts contain language that allows for the
recovery of costs impacted by the modifications or changes in the
9

interpretation or application of any existing statute by local, state or federal
government authorities. Some agreements provide that if the parties fail to
agree on a price adjustment caused by cost increases due to changes in
applicable laws and regulations, the purchaser may terminate the agreement,
subject to the payment of liquidated damages.

Reopener provisions are present in many of our multi-year coal contracts.
These provisions may allow either party to commence a renegotiation of the
contract price at various intervals. In a limited number of agreements, if the
parties do not agree on a new price, the purchaser or seller has an option to
terminate the contract. 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. 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. Coal supply agreements typically stipulate procedures for quality
control, sampling and weighing. In the eastern U.S., approximately half of our
customers require that the coal is sampled and weighed at the destination,
whereas in the western U.S., samples and weights are usually taken at the
shipping source.

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.

SALES AND MARKETING

Our sales, trading 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 coal supply agreements by
acquiring rights to receive coal under a coal supply agreement, reselling that
coal, and supplying coal from other sources. As of December 31, 2002, we had 60
employees in our sales, marketing, trading and transportation operations,
including personnel dedicated to performing market research, contract
administration and risk/credit management activities.

TRANSPORTATION

Coal consumed domestically is usually sold at the mine, and transportation
costs are normally borne by the purchaser. Export coal is usually sold at the
loading port, with purchasers paying ocean freight. Producers usually pay
shipping costs from the mine to the port.

The majority of our sales volume is shipped by rail, but a portion of our
production is shipped by other modes of transportation. For example, coal from
our Highland 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

10

southern Nevada. Coal from the Seneca Mine in Colorado is transported by truck
to a nearby electricity generating plant. Other mines transport coal by rail and
barge or by rail and lake carrier on the Great Lakes. All coal from our southern
Powder River Basin mines in Wyoming is shipped by rail, and two competing
railroads, the Burlington Northern Santa Fe Railway and the Union Pacific
Railroad, serve our North Antelope/Rochelle and Caballo mines. The Rawhide Mine
is serviced by the Burlington Northern Santa Fe Railway. 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 have many long, established
relationships with our key suppliers, and do not believe that we are dependent
on any of our individual suppliers, except as noted below. The supplier base
providing mining materials has been relatively consistent in recent years,
although there has been some consolidation. Recent consolidation of suppliers of
explosives has limited the number of sources for these materials; however, we
are not dependent on any one supplier for explosives. Further, purchases of
certain underground mining equipment are concentrated with one principal
supplier; however, supplier competition continues to develop.

TECHNICAL INNOVATION

We place great emphasis on the application of technical innovation to
improve new and existing equipment 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 was upgraded with new motors and digital controllers to
increase productivity. 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 electricity generating plant using advanced emissions reduction
technology funded primarily through the U.S. Department of Energy and operated
by an affiliate of Southern Company.

COMPETITION

The markets in which we sell our coal are highly competitive. According to
the Energy Information Administration's "Annual Coal Report 2001," the top 10
coal producers in the United States produced
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approximately 62% of total domestic coal in 2001. 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., Horizon Natural Resources,
Inc. and Massey Energy Company, which collectively accounted for approximately
40% of total U.S. coal production in 2001.

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 maximize our coal assets and land holdings for long-term growth, we
are developing coal-fueled generating projects in areas of the country where
electricity demand is strong and where there is access to land, water,
transmission lines and low-cost coal.

Peabody is continuing to progress on the permitting processes, transmission
access agreements and contractor-related activities for developing clean,
low-cost mine-mouth generating plants using our surface lands and coal reserves.
Because coal costs just a fraction of natural gas, mine-mouth generating plants
can provide low-cost electricity to satisfy growing baseload generation demand.
The plants will be designed to over-comply with all current clean air standards
using advanced emissions control technologies.

In 2002, Peabody achieved a major milestone in the development of the 1,500
megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky, when it
received the final air quality permit from the Commonwealth of Kentucky. Certain
environmental groups are challenging the air permit. In 2002, Peabody also
signed a transmission agreement and received its water withdrawal permit for the
1,500 megawatt Prairie State Energy Campus in Washington County, Illinois.

COALBED METHANE

Our subsidiary, Peabody Natural Gas, LLC, produces coalbed methane from its
operations located in the Southern Powder River Basin near our Caballo Mine. We
purchased these coalbed methane assets in January 2001 for approximately $10
million. We will continue to evaluate further development of this business
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. Our reclamation costs and mine-closing liabilities totaled approximately
$386.8 million as of December 31, 2002. Expense for the year ended December 31,
2002, the nine months ended December 31, 2001 and the fiscal year ended March
31, 2001 was $11.0 million, $9.6 million and $4.1 million, respectively. Our
method for accounting for reclamation activities changed on January 1, 2003 as a
result of the adoption of SFAS (Statement of Financial Accounting Standards) No.
143, "Accounting for Asset Retirement Obligations." The effects of the adoption
of SFAS No. 143 are discussed in the "Accounting Pronouncements Not Yet
Implemented" section of Item 7, "Management's Discussion and Analysis of
Financial Condition and Results of Operations," of this report.

12

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 $252.4
million as of December 31, 2002, $42.6 million of which was a current liability.
Expense for the year ended December 31, 2002, the nine months ended December 31,
2001 and the fiscal year ended March 31, 2001 was $55.4 million, $36.6 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 liabilities totaled
approximately $127.6 million as of December 31, 2002, $7.4 million of which was
a current liability. Expense for the year ended December 31, 2002, the nine
months ended December 31, 2001 and the fiscal year ended March 31, 2001 was $4.8
million, $3.0 million and $0.3 million, respectively.

Retiree Health Care. Consistent with SFAS 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 accrued 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 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 $1,031.7 million
as of December 31, 2002, $72.1 million of which was a current liability. Expense
for the year ended December 31, 2002, the nine months ended December 31, 2001
and the fiscal year ended March 31, 2001 was $74.4 million, $49.8 million and
$70.7 million, respectively. Obligations to the United Mine Workers of America
Combined Fund totaled $67.3 million as of December 31, 2002, $17.5 million of
which was a current liability. Expense for the year ended December 31, 2002 and
the nine months ended December 31, 2001 was $16.7 million and $3.3 million,
respectively. For the fiscal year ended March 31, 2001, income of $8.0 million
was recorded, primarily due to the withdrawal by the Social Security
Administration of certain beneficiaries previously assigned to us. The expense
recorded during the year ended December 31, 2002 reflects the expected
reassignment of these beneficiaries to us as a result of an adverse U.S. Supreme
Court decision in January 2003.

ELECTRICITY DEREGULATION

Congress enacted the Energy Policy Act of 1992 to stimulate competition in
electricity markets by giving 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. Some individual states are also proceeding with their own
deregulation initiatives.

The pace of deregulation differs significantly from state to state. As of
December 2002, 17 states and the District of Columbia had either enacted
legislation leading to the deregulation of the electricity market or issued a
regulatory order to implement retail access that would allow customers to choose
their own supplier of generation. Five states have delayed restructuring and 27
are not actively pursuing deregulation. In California, where supply and demand
imbalances created electricity supply shortages, the California Public Utilities
Commission suspended deregulation.

13

A possible consequence of deregulation is downward pressure on fuel prices.
However, because of coal's cost advantage and because some coal-fueled
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-fueled power plants are
operated at greater capacity.

EMPLOYEES

As of December 31, 2002, we and our subsidiaries had approximately 6,500
employees. As of December 31, 2002, the United Mine Workers of America
represented approximately 31% of our employees, who produced 19% of our coal
sales volume during the year ended December 31, 2002. An additional 4% of our
employees are represented by labor unions other than the United Mine Workers of
America. These employees produced 3% of our coal sales volume during the year
ended December 31, 2002. Relations with organized labor are important to our
success and we believe our relations with our 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 primarily 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.

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

14

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, as will the amounts of those awards. The
National Mining Association filed a lawsuit challenging these regulations, and
the U.S. District Court of the District of Columbia upheld the regulations. The
National Mining Association filed an appeal with the U.S. Court of Appeals for
the District of Columbia, but the regulations were upheld, with some exceptions
as to the retroactivity of the regulations.

COAL INDUSTRY RETIREE HEALTH BENEFIT ACT OF 1992

The Coal Industry Retiree Health Benefit Act of 1992 ("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 these funds. Annual payments made by certain of our subsidiaries
under the Coal Act totaled $11.1 million, $5.4 million and $4.2 million,
respectively, during the year ended December 31, 2002, nine months ended
December 31, 2001 and year ended March 31, 2001.

In 1995, in a case filed by the National Coal Association on behalf of its
members and others, a federal district court in Alabama ordered the Commissioner
of Social Security to recalculate the per-beneficiary premium which the Combined
Fund charges assigned operators. The Commissioner applied the recalculated
premium to all assigned operators. 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 premium calculation 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. In a decision dated December 16, 2002, the Court of Appeals for the
District of Columbia Circuit affirmed in part and reversed in part the lower
court's ruling and remanded the case for further proceedings. Among other
things, the Court of Appeals directed the Commissioner of Social Security to
void the agency's 1995 premium recalculation with respect to all assigned
operators except those that had been parties to the 1995 Alabama litigation,
including National Coal Association member companies. If the Combined Fund is
able to obtain a court decision that would retroactively assess the higher
premium rate to our subsidiaries, our

15

subsidiaries will be required to pay an additional premium to the Combined Fund
of approximately $5.7 million. In that event, the prospective annual premium
would also increase by approximately 10%.

ENVIRONMENTAL LAWS

We are subject to various federal, state and foreign environmental laws.
Some of these laws, discussed below, place many requirements on our coal mining
operations. Federal and state regulations require regular monitoring of our
mines and other facilities to ensure compliance.

SURFACE MINING CONTROL AND RECLAMATION ACT

The Surface Mining Control and Reclamation Act of 1977 (SMCRA), which is
administered by the Office of Surface Mining Reclamation and Enforcement (OSM),
establishes mining, environmental protection and reclamation standards for all
aspects of surface mining as well as many aspects of deep mining. Mine operators
must obtain SMCRA permits and permit renewals for mining operations from the
OSM. Where state regulatory agencies have adopted federal mining programs under
the act, the state becomes the regulatory authority. Except for Arizona, states
in which we have active mining operations have achieved primary control of
enforcement through federal authorization. In Arizona we mine on tribal lands
and are regulated by OSM because the tribes do not have SMCRA authorization.

SMCRA permit provisions include requirements for coal prospecting; mine
plan development; topsoil removal, storage and replacement; selective handling
of overburden materials; mine pit backfilling and grading; protection of the
hydrologic balance; subsidence control for underground mines; surface drainage
control; mine drainage and mine discharge control and treatment; and
re-vegetation.

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 SMCRA, 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 OSM's Applicant Violator System.

Once a permit application is prepared and submitted to the regulatory
agency, it goes through a completeness review and technical review. Public
notice of the proposed permit is given for a comment period before a permit can
be issued. Some SMCRA mine permits take over a year to prepare, depending on the
size and complexity of the mine and often take six months to two years to be
issued. 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.

Before a SMCRA permit is issued, a mine operator must submit a bond or
otherwise secure the performance of reclamation obligations. The Abandoned Mine
Land Fund, which is part of SMCRA, requires a fee on all coal produced. The
proceeds are used to reclaim mine lands closed prior to 1977 and to pay health
care benefit costs of orphan beneficiaries of the Combined Fund. The fee, which
partially expires on September 30, 2004, is $0.35 per ton on surface-mined coal
and $0.15 per ton on deep-mined coal. After that date, a fee will be assessed
each year to cover the expected health care benefit costs of the orphan
beneficiaries.

SMCRA stipulates compliance with many other major environmental programs.
These programs include the Clean Air Act; Clean Water Act; Resource Conservation
and Recovery Act (RCRA); Comprehensive Environmental Response, Compensation, and
Liability Acts (CERCLA) superfund and employee right-to-know provisions. Besides
OSM, other Federal regulatory agencies are involved in monitoring or permitting
specific aspects of mining operations. The U.S. Environmental Protection Agency

16

(EPA) is the lead agency for States or Tribes with no authorized programs under
the Clean Water Act, RCRA and CERCLA. The U.S. Army Corps of Engineers (COE)
regulates activities affecting navigable waters and the U.S. Bureau of Alcohol,
Tobacco and Firearms (ATF) regulates the use of explosive blasting.

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 comply with the requirements of the Surface
Mining Control and Reclamation Act and the state laws and regulations governing
mine reclamation.

On March 29, 2002, the U.S. District Court for the District of Columbia
issued a ruling on SMCRA Section 522(e) banning underground coal mining under
certain protected lands that were originally applicable only to surface coal
mining operations. The U.S. Department of Interior filed an appeal. If the
ruling is upheld, mining costs could increase and in some cases make portions of
coal reserves infeasible to mine.

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
10 micrometers in diameter or smaller. The Clean Air Act indirectly affects coal
mining operations by extensively regulating the air emissions of sulfur dioxide,
nitrogen oxides, mercury and other compounds 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 electricity generating customers are likely to be directly
affected when the revisions to the air quality standards are implemented by the
states. State and federal regulations relating to implementation of the new air
quality standards may restrict our ability to develop new mines or could require
us to modify our existing operations. The extent of the potential direct impact
of the new air quality standards on the coal industry will depend on the
policies and control strategies associated with the state implementation process
under the Clean Air Act, but could have a material adverse effect on our
financial condition and results of operations.

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 accurately predict 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
electricity 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 promulgated
the final rules that would require coal-burning power plants in 19 eastern
states and Washington, D.C. to make substantial reductions in nitrogen oxide
emissions beginning in May 2004. Installation of additional control

17

measures required under the final rules will make it more costly to operate
coal-based electricity generating plants.

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. From 1990 to 1999, the EPA interpreted
the new source review criteria in a relatively consistent manner; however, the
EPA changed their interpretation during 1999. The Justice Department, on behalf
of the EPA, filed a number of lawsuits since November 1999, alleging that 10
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. At the end of 2002, the
EPA issued proposed new source review rules for sources that include electricity
generators. These new rules define routine maintenance, repair and replacement.
If these rules are finalized without material revisions, electricity generators
should be better able to make needed repairs and improvements to their plants
without the uncertainty of triggering cost-prohibitive environmental rules.

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. Under regulations issued
by the EPA in 1999, states are required to set a goal of restoring natural
visibility conditions in these Class I areas in their states by 2064 and to
explain their reasons to the extent they determine that this goal cannot be met.
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 dioxides and nitrogen
oxides.

The Clean Air Act Amendments require a study of electricity 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 electricity power generators. In February 2002, the President
proposed to cut electricity 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 has been translated into a
legislative proposal. In addition, similar emission reduction proposals have
been introduced in 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 dioxides, nitrogen oxides, mercury and carbon dioxide.

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In February 2003, seven states notified the EPA that they plan to sue the
agency to force it to set new source performance standards for utility emissions
of carbon dioxide and to tighten existing standards for sulfur dioxide and
particulate matter for utility emissions. In January 2003, three of these states
announced that they planned to seek a court order requiring the EPA to designate
carbon dioxide as a criteria pollutant and to issue a new National Ambient Air
Quality Standard for carbon dioxide. If these states file the lawsuits, are
successful in obtaining a court order and the EPA agrees to set emission
limitations for carbon dioxide and/or lower emission limitations for sulfur
dioxide and particulate matter, it could adversely affect the amount of coal our
customers would purchase from us.

CLEAN WATER ACT

The Clean Water Act of 1972 affects coal mining operations by establishing
in-stream water quality standards and treatment standards for waste water
discharge through the National Pollutant Discharge Elimination System (NPDES).
Regular monitoring, reporting requirements and performance standards are
requirements of NPDES permits that govern the discharge of pollutants into
water.

On May 8, 2002, the U.S. District Court for the Southern District of West
Virginia issued an injunction banning new Section 404 permits by the Huntington,
West Virginia Office of the Army Corp of Engineers (COE). Section 404 permits
are required for coal companies to place any material in streams for the purpose
of creating slurry ponds, water impoundments, refuse areas, valley fills or
other mining activities. The COE filed for an appeal of the Court's order with
the U.S. Court of Appeals for the Fourth Circuit. The COE Huntington office
issues permits for portions of Ohio, Kentucky and West Virginia where Peabody
mining operations are located. On January 29, 2003, the Fourth Circuit Court of
Appeals vacated the District Court's injunction.

Total Maximum Daily Load (TMDL) regulations established a process by which
states designate stream segments as impaired (not meeting present water quality
standards). Industrial dischargers, including coal mines, will be required to
meet new TMDL effluent standards for these stream segments. The adoption of new
TMDL effluent limitations for our coal mines could require more costly water
treatment and could adversely affect our coal production.

States are also adopting anti-degradation regulations in which a state
designates certain water bodies or streams as "high quality." These regulations
would prohibit the diminution of water quality in these streams. Waters
discharged from coal mines to high quality streams will be required to meet or
exceed new "high quality" standards. The designation of high quality streams at
our coal mines could require more costly water treatment and could aversely
affect our coal production.

RESOURCE CONSERVATION AND RECOVERY ACT

The Resource Conservation and Recovery Act (RCRA), which was enacted in
1976, affects coal mining operations by establishing requirements for the
treatment, storage and disposal of hazardous wastes. Coal mine wastes, such as
overburden and coal cleaning wastes, are exempted from hazardous waste
management.

Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous
waste regulation until the 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 high volume-low toxicity 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
mine-fill. The agency also concluded beneficial uses of these wastes, other than
for mine-filling, 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 electricity generators.
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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 liabilities may be imposed
on waste generators, site owners or 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 2001, 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 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 10 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
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

20

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 Securities and Exchange Commission (SEC). You may access
and read our SEC filings through our website, at www.peabodyenergy.com, or the
SEC's website, at www.sec.gov. 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 also request copies of our 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.

ITEM 2. PROPERTIES

COAL RESERVES

We had an estimated 9.1 billion tons of proven and probable coal reserves
as of December 31, 2002. An estimated 8.9 billion tons of our proven and
probable coal reserves are in the United States, and 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 regions.

- ---------------

(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

21

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, area extent, size, shape and depth of coalbeds are well
established.

Probable Reserves -- Reserve estimates in this category have a
moderate degree of geologic assurance. There are no sample and measurement
sites in areas of indicated coal. However, a single measurement can be used
to classify coal lying beyond measured as probable. Probable coal lies more
than one-quarter mile, but less than three quarters of a mile from a point
of thickness measurement. Further exploration is necessary to place
probable coal into the proven category.

In areas where geologic conditions indicate potential inconsistencies
related to coal reserves, we perform additional drilling to ensure the
continuity and mineability of the coal reserves. Consequently, sampling in those
areas involves drill holes that are spaced closer together than those distances
cited above.

We prepare our reserve estimates based on geological data assembled and
analyzed by our staff, which includes various geologists and engineers. We
periodically update our reserve estimates to reflect production of coal from the
reserves and new drilling or other data received. Accordingly, reserve estimates
will change from time to time to reflect mining activities, analysis of new
engineering and geological data, changes in reserve holdings, modification of
mining methods and other factors. We maintain reserve information, including the
quantity and quality (where available) of reserves as well as production rates,
surface ownership, lease payments and other information relating to our coal
reserve and land holdings, through a computerized land management system that we
developed.

Our reserve estimates are predicated on information obtained from our
extensive drilling program, which totals nearly 500,000 individual drill holes.
We compile data from individual drill holes in a computerized drill-hole system
from which the depth, thickness and, where core drilling is used, the quality of
the coal are determined. The density of the drill pattern determines whether the
reserves will be classified as proven or probable. The drill hole data are then
input into our computerized land management system, which overlays the
geological data with data on ownership or control of the mineral and surface
interests to determine the extent of our reserves in a given area. In addition,
we periodically engage independent mining and geological consultants to review
estimates of our coal reserves. The most recent of these reviews, which was
completed in March 2001, included a review of the procedures used by us to
prepare our internal estimates, verification of the accuracy of selected
property reserve estimates and retabulation of reserve groups according to
standard classifications of reliability. This study confirmed that we controlled
approximately 9.5 billion tons of proven and probable reserves as of April 1,
2000. After adjusting for acquisitions and production through December 31, 2002,
proven and probable reserves totaled 9.1 billion tons (see charts on page 24-25
of this report).

We have numerous federal coal leases that are administered by the U.S.
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 $3.00 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,
2002, we leased or had applied to lease 23,384 acres of federal land in
Colorado, 11,252 acres in Montana and 34,766 acres in Wyoming, for a total of
69,402 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.
22

Private coal leases normally have terms of between 10 and 20 years and
usually give us the right to renew the lease for a stated period or to maintain
the lease in force until the exhaustion of mineable and merchantable coal
contained on the relevant site. These private leases provide for royalties to be
paid to the lessor either as a fixed amount per ton or as a percentage of the
sales price. Many leases also require payment of a lease bonus or minimum
royalty, payable either at the time of execution of the lease or in periodic
installments.

The terms of 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.

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The following chart provides a summary, by mining complex, of production
for the year ended December 31, 2002, nine months ended December 31, 2001, and
fiscal year ended March 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)

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The following chart provides a summary of the amount of our proven and
probable coal reserves in each U.S. state and Australia, the predominant type of
coal mined in the applicable location, 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, 2002
(TONS IN MILLIONS)

25

- ---------------

(1) Assigned reserves represent recoverable coal reserves that we have committed
to mine at locations operating as of December 31, 2002. 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. The following table reflects the average moisture content
used in the determination of as-received Btu by region:

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.

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,

26

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%. On March 15, 2001, the court
allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted
seven claims including fraud and is seeking various remedies including
unspecified actual damages, punitive damages and reformation of its coal lease.

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. On
January 14, 2003, the Arizona District Court dismissed the lawsuit. Our
subsidiaries have filed an appeal of this decision with the Ninth Circuit Court
of Appeals.

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. 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. The
District of Columbia District Court denied our motion for a stay and we appealed
that ruling to the District of Columbia Court of Appeals. Oral argument on our
appeal is scheduled for April 14, 2003.

On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion
lawsuit involving the Navajo Nation and the United States. The Court rejected
the Navajo Nation's allegation that the U.S. breached its trust responsibilities
to the Tribe in approving the coal lease amendments and was liable for money
damages.

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 hearing was held in April 2002. On July 20, 2002, Peabody
Western received a favorable decision from the arbitrators. The decision
increased the price of coal by approximately $0.50 per ton from 1997 through
2001 and thereafter. As a result of the decision, we received pre-tax earnings
of approximately $22 million during the quarter ended September 30, 2002. The
exact impact of the ruling on the pricing of coal sales from January 1, 2002
forward will not be determined until Salt River completes a review of the
cumulative cost changes under the contract for the years 1997 through 2001.

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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. This ruling was subsequently
upheld on appeal. 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.

Peabody Western filed a motion to compel arbitration that 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. 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 that
was denied by the trial court on February 6, 2002.

Peabody Western reached a mediated settlement with the owners of the Mohave
Generating Station, which resulted in the recognition of $15.1 million in
pre-tax earnings during the quarter ended September 30, 2002. The settlement
provides for customer reimbursement of mine decommissioning and certain other
post-mining expenditures. The reimbursement commenced in January 2003 and
continues on a monthly basis through December 2005. All of the owners except one
exercised their option to prepay these reimbursements in 2002.

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CALIFORNIA PUBLIC UTILITIES COMMISSION PROCEEDINGS REGARDING THE FUTURE OF THE
MOHAVE GENERATING STATION

We have a long-term coal supply agreement with the owners of the Mohave
Generating Station that expires on December 31, 2005. There is a dispute with
the Hopi Tribe regarding the use of groundwater in the transportation of the
coal by pipeline to the Mohave plant. Also, Southern California Edison (the
majority owner and operator of the plant) is involved in a California Public
Utility Commission proceeding related to recovery of future capital expenditures
for new pollution abatement equipment for the station. As a result of these
issues, the owners of the Mohave Generating Station have announced that they
expect to idle the plant for at least 12 to 18 months beginning in 2006. We are
in active discussions to resolve the complex issues critical to the continuation
of the operation of the Mohave Generating Station and the renewal of the coal
supply agreement after December 31, 2005. There is no assurance that the issues
critical to the continued operation of the Mohave plant will be resolved. If
these issues are not resolved in a timely manner, the operation of the Mohave
plant will cease or be suspended beginning on December 31, 2005. The Mohave
plant is the sole customer of our Black Mesa Mine, which sold 4.6 million tons
of coal in 2002.

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 and on
January 15, 2003 the Court ruled against our subsidiaries and overturned the
Sixth Circuit's decision. As a result of the ruling, we recorded an after-tax
charge of approximately $10 million in 2002 and our subsidiaries will be
responsible for the health care premiums of the previously assigned defined
group of approximately 300 beneficiaries.

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 offer submitted by our
subsidiaries. Our subsidiaries are seeking specific performance of the
agreement, injunctive relief, declaratory judgment, and 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 and
the court's decision on the preliminary injunction was upheld on appeal. The
case is now in the discovery phase.

We are no longer 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.

29

WEST VIRGINIA FLOODING LITIGATION

Three of our subsidiaries have been named in four separate complaints filed
in Boone, Kanawha and Wyoming Counties, West Virginia. These cases collectively
include 622 plaintiffs who are seeking damages for property damage and personal
injuries arising out of flooding that occurred in southern West Virginia in July
of 2001. The plaintiffs have sued coal, timber, railroad and land companies
under the theory that mining, construction of haul roads and removal of timber
caused natural surface waters to be diverted in an unnatural way, thereby
causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that
these four cases, along with over 10 additional flood damage cases not involving
our subsidiaries, be handled pursuant to the Court's Mass Litigation rules. As a
result of this ruling, the cases have been transferred to the Circuit Court of
Raleigh County in West Virginia to be handled by a panel consisting of three
circuit court judges. They will, among other things, determine whether the
individual cases should be consolidated or returned to their original circuit
courts.

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.

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 and other potentially responsible parties are
currently involved in environmental investigation, litigation or remediation at
11 sites.

These 11 sites were formerly owned or operated by Gold Fields or Gold
Fields' predecessors, associated companies and its former parent company. The
Environmental Protection Agency has placed two of these sites on the National
Priorities List, promulgated pursuant to Superfund, and one of the sites is on a
similar state priority list. There are a number of additional sites in the
United States that were previously owned or operated by such companies that
could give rise to environmental proceedings in which Gold Fields could incur
liabilities.

Where the sites were identified, independent environmental consultants were
employed in 1997 in order to assess the estimated total amount of the liability
per site and the proportion of those liabilities that Gold Fields is likely to
bear. The available information on which to base this review was very limited
since all of the sites except for two sites (on which no remediation is
currently taking place) are no longer owned by Gold Fields. Independent
environmental consultants conducted another assessment in 2002. We have accrued
liabilities of $42.1 million as of December 31, 2002 for the environmental
liabilities described above relating to Gold Fields that are included as part of
"other noncurrent 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.

30

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, 2002.

ITEM 4A. EXECUTIVE OFFICERS OF THE COMPANY

Set forth below are the names, ages as of February 28, 2003 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.

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 Based Generation
Stakeholders Group and Co-Chairman of the National Mining Association's
Sustainable Development and Health Care Reforms Committees. He has previously
served as Chairman of the National Mining Association, the Coal Industry
Advisory Board of the International Energy Agency, the Center for Energy and
Economic Development, and the Co-Chairman of the Coal Utilization Research
Council. He is also a director of U.S. Bank, N.A.

Richard M. Whiting became Executive Vice President -- Sales, Marketing and
Trading in October 2002. Previously, Mr. Whiting served as President and Chief
Operating Officer of the Company and President of Peabody COALSALES Company. 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 a member of the Board of Directors of Penn
Virginia Resource GP, LLC, the general partner of Penn Virginia Resource
Partners, L.P. He is Chairman of the Bituminous Coal Operators' Association,
Chairman of the National Mining Association's Safety and Health Committee and is
a member of the Visiting Committee of West Virginia University College of
Engineering and Mineral Resources.

31

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 1987 to 1998, he was a
Senior Vice President and a director with The Boston Consulting Group where he
served a variety of clients in strategy and operational assignments. He joined
Boston Consulting Group in 1981, and was 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. 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 serves on the Board of Advisors to the College of
Business for Southern Illinois University -- Carbondale. He is a member of
Financial Executives International and the NYMEX Coal Advisory Council.

Fredrick D. Palmer became Executive Vice President -- Legal and External
Affairs of our company in February 2001. He is responsible for our legal and
governmental affairs. Prior to joining Peabody, he served for 15 years as chief
executive officer and five years as general counsel of Western Fuels
Association, Inc. For a short period in 2001, he also 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.

Sharon D. Fiehler has been Executive Vice President of Human Resources and
Administration of our company since April 2002, with executive responsibility
for information services, 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 the chair of the
Benefits Committee of the Bituminous Coal Operators' Association and is a member
of the National Mining Association's Human Resource Committee.

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.

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."

32

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.

As of February 28, 2003, our authorized capital stock consisted of (1)
150.0 million shares of common stock, par value $0.01 per share, of which 52.4
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 26, 2003, there were approximately 124 holders of record of our common
stock.

On April 5, 2002, certain of our shareholders, including our largest
shareholder, Lehman Brothers Merchant Banking Partners II L.P. and affiliates
(collectively "Lehman Brothers"), sold 9,000,000 shares of common stock in a
secondary offering. The selling shareholders received all net proceeds. We did
not sell any shares through the offering.

The underwriters of the secondary offering were granted the right to
purchase up to an additional 1,100,000 shares of common stock to cover
over-allotments. The underwriters exercised the over-allotment option, and on
May 8, 2002, purchased an additional 148,000 shares. Lehman Brothers sold, in
the aggregate, 8,155,000 shares in the offering, and their beneficial ownership
of our outstanding common stock declined from 57% to 41% immediately following
the offering.

On July 23, 2002, our Board of Directors adopted a preferred share purchase
rights plan (the "Rights Plan"). In connection with the Rights Plan, the Board
of Directors declared a dividend of one preferred share purchase right (a
"Right") for each outstanding share of our common stock, par value $0.01 per
share. The Rights dividend was payable on August 12, 2002 to the stockholders of
record on that date. The description and terms of the Rights are set forth in an
Agreement, dated as of July 24, 2002, between us and EquiServe Trust Company,
N.A., as Rights Agent.

The Rights have certain anti-takeover effects. The Rights will cause
substantial dilution to a person or group that attempts to acquire us on terms
not approved by our Board of Directors, except pursuant to any offer conditioned
on a substantial number of Rights being acquired. The Rights should not
interfere with any merger or other business combination approved by the Board of
Directors since we may redeem the Rights at a redemption price of $0.001 per
Right prior to the time that a person or group has acquired beneficial ownership
of 15% or more of our common stock. In addition, the Board of Directors is
authorized to reduce the 15% threshold to not less than 10%.

DIVIDEND POLICY

We paid quarterly dividends totaling $0.40 per share during the year ended
December 31, 2002 and $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.

33

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, our
Board of Directors will determine the actual amount of any dividends.

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 was by the issuer and did not involve a public offering:

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.

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 in consideration for their services.

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 in
consideration for their services.

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 in
consideration for his services.

On April 9, 2001, we issued 11,466 shares of common stock for an
aggregate consideration of $61,261 to one of our executives in
consideration for his services.

From May 22, 2001 through December 31, 2001, we issued 67,066 shares
of common stock as a result of the exercise of options. During 2002, we
issued 291,203 shares of common stock as a result of the exercise of
options. All of these options were exercised at a price of $14.29 per
share.

- ---------------

(1) These shares had been acquired by us from terminated employees.

34

EQUITY COMPENSATION PLAN INFORMATION

As required by Item 201(d) of Regulation S-K, the table below provides
information regarding our equity compensation plans as of December 31, 2002:

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 ("Black Beauty") 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.

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.

We have derived the selected historical financial data for our predecessor
for 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, the nine months ended and as of December 31, 2001 and
the year ended and as of December 31, 2002 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

35

statements, and "Management's Discussion and Analysis of Financial Condition and
Results of Operations."

- ---------------

(1) Results of operations for the year ended December 31, 2002 included an
income tax benefit of $40.0 million. This benefit results primarily from
significant tax benefits realized as a result of utilizing net operating
loss carryforwards to offset taxable gains recognized in connection with the
Penn

36

Virginia and landfill sale transactions (discussed in Item 7 of this
report). Utilization of the loss carryforwards required the reduction of a
previously recorded valuation allowance that had reduced the book value of
the loss carryforwards. In 2002, due to a change in accounting principle
discussed in Note 1 to our consolidated financial statements, we began
recording revenues related to all coal trading activities on a net basis in
"Other revenues," and all prior period amounts were reclassified. Had our
physically settled trading transactions been recorded on a gross basis,
total revenues and operating costs would have been $161.9 million, $88.8
million and $41.6 million higher for the year ended December 31, 2002, the
nine months ended December 31, 2001 and the year ended March 31, 2001,
respectively.

(2) Results of operations for the year ended March 31, 2001 included a $171.7
million pretax gain on the sale of our Peabody Resources Limited operations
in Australia. Capital expenditures of $151.4 million for this period do not
include Peabody Resources Limited capital expenditures.

(3) 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.

(4) 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.

(5) Adjusted EBITDA is defined as income from continuing operations before
deducting net interest expense, income taxes, minority interests and
depreciation, depletion and amortization. Adjusted EBITDA is not a
substitute for operating income, net income and cash flow from operating
activities as determined in accordance with generally accepted accounting
principles as a measure of profitability or liquidity. Adjusted EBITDA is
presented as additional information because management believes it is a
useful indicator of our ability to meet debt service and capital expenditure
requirements. Because Adjusted EBITDA is not calculated identically by all
companies, our calculation may not be comparable to similarly titled
measures of other companies.

ITEM 7. 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.

FACTORS AFFECTING COMPARABILITY

SALE OF PEABODY RESOURCES LIMITED OPERATIONS

In December 2000, we signed a share purchase agreement for the sale of the
stock in two U.K. holding companies which, in turn, owned our Peabody Resources
Limited subsidiaries in Australia, to a subsidiary of Rio Tinto Limited. These
operations consisted of interests in six coal mines, as well as a mining
services operation in Brisbane, Australia. The sale price was $455.0 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.

37

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

Our subsidiaries have significant long-term liabilities for postretirement
benefit costs, workers' compensation obligations and defined benefit pension
plans. Detailed information related to these liabilities is included in the
notes to our consolidated financial statements. Liabilities for postretirement
benefit costs and workers' compensation obligations are not funded. Our pension
obligations are funded in accordance with the provisions of federal law.

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.

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 differ materially from our current estimates.
Moreover, regulatory changes could increase our obligation to satisfy these or
additional obligations. Expense for the year ended December 31, 2002 for these
liabilities totaled $134.6 million, while payments were $143.9 million.

RECLAMATION

Our subsidiaries 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. Expense related to reclamation liabilities for the year
ended December 31, 2002 was $11.0 million, and payments totaled $21.4 million.

Our method for accounting for reclamation activities changed on January 1,
2003 as a result of the adoption of SFAS No. 143, "Accounting for Asset
Retirement Obligations." The estimated effect of the adoption of SFAS No. 143 is
discussed in the "Accounting Pronouncements Not Yet Implemented" section of Item
7 of this report, below.

38

TRADING ACTIVITIES

We engage in the buying and selling of coal and emission allowances in
over-the-counter markets. During 2002, accounting requirements related to our
trading activities changed due to the rescission of Emerging Issues Task Force
(EITF) Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities." Contracts we entered into after October 25, 2002
were only accounted for on a fair value basis if they met the SFAS No. 133
definition of a derivative. This accounting change is discussed in Note 1 to our
consolidated financial statements.

To establish fair values for our trading contracts, 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.

Eighty-nine percent of the contracts in our trading portfolio as of
December 31, 2002 were valued utilizing prices from over-the-counter market
sources. The remaining 11% 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, 2002, the timing of trading portfolio contract
expirations is as follows:

YEAR ENDED DECEMBER 31, 2002 COMPARED TO YEAR ENDED DECEMBER 31, 2001 (NOT
PRESENTED HEREIN)

Sales. Sales for the year ended December 31, 2002 increased $115.8
million, or 4.6%, to $2,630.4 million. U.S. sales increased $121.9 million, a
4.9% increase from the prior year. Pricing increases in all regions drove the
sales increase. Our average sales price was 5.6% higher than the prior year. The
average price increase was impacted by higher priced contracts signed in 2001
and a $27.7 million increase in sales related to a favorable arbitration ruling
that resulted in a retroactive price increase on our Navajo station coal supply
agreement. This ruling is discussed in detail in Note 24 to our consolidated
financial statements. The pricing increase was partially mitigated by sales mix,
as higher priced tons in the Appalachia and Midwest regions represented a lower
percentage of overall sales in the current year compared to the prior year.

U.S. mining and broker operations' sales volume for the year ended December
31, 2002 was 183.5 million tons, which was 2.2 million tons below the prior
year. We had lower sales volume at our Appalachia and Midwest operations, driven
by soft market demand as a result of mild weather early in the year, a slower
U.S. economy and more aggressive management of coal stockpile levels by
customers. Volume decreases at our eastern operations more than offset a 1.4
million ton increase in sales volume at our western operations.

Powder River Basin sales increased $130.3 million, due to improved pricing
and slightly higher volume in the current year, driven by continued strong
customer demand. Sales in the Southwest region were $33.9 million higher than
the prior year, primarily due to the effect of the arbitration ruling previously
discussed, combined with slightly higher pricing and volume. Appalachia region
sales increased $7.7 million, as higher pricing offset lower volume from softer
demand, which resulted in suspension of the Big Mountain Mine twice during the
year and the Colony Bay Mine during the fourth quarter. Midwest region sales
decreased $31.0 million, as higher prices were more than offset by lower volume
due to

39

geologic problems at the Camp No. 11 Mine and delays in the startup of two new
mines in the region, combined with softer coal demand in the current year.
Finally, sales from coal brokerage activities decreased $20.3 million due to a
change in sales mix and slightly lower volume.

Sales from our Australian mining operations decreased $6.1 million compared
to the prior year. The current year includes $9.9 million of sales related to
the Wilkie Creek mining operations purchased in 2002, while the prior year
included $16.0 million of sales from our Peabody Resources Limited operations
that were sold in January 2001.

Other Revenues. Other revenues for the year ended December 31, 2002
decreased $7.9 million from the prior year, to $86.7 million. The current year
included a $15.1 million gain from a mediated settlement related to the Mohave
generating station coal supply agreement. This settlement is discussed in detail
in Note 24 to our consolidated financial statements. Revenues from trading
operations increased $9.0 million, primarily due to $10.0 million related to a
forward sale that will settle during 2003 and 2004. These improvements were
offset by significantly lower coal royalty revenues. Other revenues in the prior
year included higher coal royalties of $12.0 million, primarily due to two
non-refundable advance royalties, $9.9 million related to the monetization of
coal brokerage agreements that had increased in value due to favorable market
conditions and $4.5 million of mining services revenues from our Peabody
Resources Limited operations.

Selling and Administrative Expenses. Selling and administrative expenses
of $101.4 million for the year ended December 31, 2002 were $4.5 million lower
than the prior year, due to the reduction of corporate expenses in response to
difficult market conditions in the current year, combined with stock
compensation charges recorded in the prior year related in part to our initial
public offering.

Gain on Sale of Peabody Resources Limited Operations. On January 29, 2001,
we sold our Peabody Resources Limited operations to Coal & Allied, a 71%-owned
subsidiary of Rio Tinto Limited. The selling price was $455.0 million, plus the
assumption of all liabilities. We recorded a pretax gain of $171.7 million on
the sale ($124.2 million after taxes).

Net Gain on Property and Equipment Disposals. Net gain on property and
equipment disposals of $15.8 million was $0.8 million higher than the prior
year. The current year included a $10.1 million gain related to the sale of a
landfill site that we developed and permitted using idle assets to serve Los
Angeles County. The prior year included a $6.4 million gain on the sale of
certain idle coal reserves and other reserve and equipment sales.

Operating Profit. Excluding the effect of the $171.7 million gain on sale
of our Peabody Resources Limited operations, operating profit increased $21.1
million, or 13.8%, to $173.7 million. Operating profit from U.S. operations
increased $22.6 million, or 15.3%, to $170.9 million for the year ended December
31, 2002. The increase at the U.S. operations was driven by higher operating
profit of $75.8 million from U.S. mining operations (excluding operating costs
related to post-mining activities and net gains on property disposals) as a
result of higher overall pricing due to contracts signed in 2001, combined with
the effects of the Navajo station arbitration ruling and Mohave station mediated
settlement, which increased operating profit by $37.1 million.

In the west, the Powder River Basin region's operating profit increased
$31.5 million as improved prices and higher volume overcame higher royalty and
tax expenses associated with improved prices, higher repair and maintenance
costs and higher fixed costs associated with running mines at lower than
anticipated capacity in the current year. The Southwest region's operating
profit increased $21.6 million as the $37.1 million increase related to the
Navajo arbitration ruling and Mohave mediated settlement was partially offset by
higher truck, dragline and shovel maintenance and repairs expense. In addition,
two outages of the Southwest region's coal transportation pipeline contributed
to higher costs in the current year.

In the east, both regions' profits were negatively impacted by running
mines at lower than anticipated capacity in the current year and charges in the
fourth quarter related to the suspension of two mines in Appalachia due to lower
than anticipated demand and the early closure of the Camp No. 11 Mine in the

40

Midwest due to geologic difficulties. Despite these issues, operating profit in
the Midwest region increased $12.1 million compared to the prior year, as lower
overall sales levels in the region and geologic difficulties at the Camp No. 11
mine were more than offset by improved pricing and lower fuel and maintenance
and repair costs at Black Beauty. The Appalachia region's operating profit
increased $10.6 million due to strong sales price improvement, which overcame
higher per ton mining costs due to lower than planned production volume, the
mine suspensions previously mentioned and production difficulties at the Harris
Mine's longwall.

Operating profit from trading and brokerage operations increased $7.3
million over the prior year, primarily due to the $10.0 million transaction
discussed above in "Other Revenues." Our trading volume increased to 66.9
million tons in 2002 from 53.7 million tons traded in the prior year.

Operating costs related to post-mining activities were $36.2 million higher
in the year ended December 31, 2002, primarily due to $14.1 million of higher
excise tax refunds in the prior year and a $17.2 million charge in the current
year related to an adverse U.S. Supreme Court decision which assigned us
responsibility for the health care premiums of certain beneficiaries previously
withdrawn by the Social Security Administration as a result of a prior U.S.
Circuit Court of Appeals decision. The remainder of the year-over-year increase
related primarily to higher retiree healthcare costs.

U.S. operations' operating profit was also affected by lower coal royalty
income of $12.8 million and lower results from other commercial activities of
$7.3 million.

The current year also included $2.8 million from our Wilkie Creek
operations in Australia, while the prior year included operating profit of $4.3
million from Peabody Resources Limited operations prior to their sale in January
2001.

Interest Expense. Interest expense for 2002 was $102.5 million, a decrease
of $30.5 million, or 22.9%, from the prior year. The decrease in borrowing cost
was due to the significant long-term debt repayments made during 2001, and lower
short-term interest rates in the current year. Utilizing proceeds from the sale
of our Peabody Resources Limited operations in January 2001 and our initial
public offering in May 2001, we reduced long-term debt by approximately $0.8
billion during 2001. As of December 31, 2002, our debt totaled approximately
$1.0 billion.

Interest Income. Interest income increased $3.7 million, to $7.6 million,
for 2002. The current year included $4.6 million in interest income received
related to excise tax refunds, while the prior year included interest earned on
cash received from the sale of our Peabody Resources Limited operations in
January 2001.

Income Taxes. For 2002, we had an income tax benefit of $40.0 million on
income before income taxes and minority interests of $78.8 million, compared to
income tax expense of $41.5 million on income before income taxes and minority
interests of $195.3 million in the prior year. Overall, our effective tax rate
is sensitive to the benefit of the percentage depletion tax deduction relative
to our annual profitability, as well as our ability to utilize our existing net
operating loss carryforwards of over $500 million available for federal income
tax purposes. In the prior year, the provision was affected by the sale of our
Peabody Resources Limited operations. In 2002, our tax provision reflected
significant tax benefits realized as a result of utilizing net operating loss
carryforwards to offset taxable gains recognized in connection with the Penn
Virginia (discussed in Item 2 of this report) and landfill sale transactions.
Utilization of these net operating loss carryforwards allowed for the reduction
of a previously recorded valuation allowance that had reduced the carrying value
of our net operating loss carryforward tax benefits.

Gain from Disposal of Discontinued Operations. During the year ended
December 31, 2001, we reduced our loss on the sale of Citizens Power by $1.2
million.

Extraordinary Loss from Early Extinguishment of Debt. During the year
ended December 31, 2001, we repaid debt using proceeds from the sale of our
Australian operations and our initial public offering. We recorded an
extraordinary loss of $37.5 million, net of income taxes, which represented the
excess of

41

cash paid over the carrying value of the debt retired and the write-off of debt
issuance costs associated with the debt retired.

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 $153.8 million, to $1,869.3 million, a 9.0%
increase from the prior year 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 year nine-month period, led
the increase.

Sales volume for the U.S. operations was 146.5 million tons for the nine
months ended December 31, 2001, compared to 133.7 million tons for the prior
year 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
year 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 nine months ended December 31, 2001 compared to the prior
year nine-month period.

Total sales for the nine months ended December 31, 2001 decreased $20.4
million, or 1.1%, from the prior nine-month period, as the prior period included
$174.2 million in sales from our Peabody Resources Limited operations, 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 nine
months ended December 31, 2001, 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.

Other Revenues. Other revenues for the nine months ended December 31, 2001
for U.S. operations increased $45.2 million over the prior year 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 nine months ended December 31, 2001. Other
revenues from Peabody Resources Limited operations included in the prior
nine-month 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 year nine-month
period. Higher production volume, 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 in the nine months ended December 31, 2001 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.

42

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 nine months ended December 31, 2001.

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 year
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, 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, 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 nine months ended December 31, 2001.

Operating costs related to post-mining activities were $9.8 million higher
in the nine months ended December 31, 2001, 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. In the nine months ended December 31, 2001, 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 nine-month
period of our liability for environmental cleanup-related costs.

Operating profit from trading and brokerage operations increased $16.4
million, 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 in the
nine months ended December 31, 2001.

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 year
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 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

43

year 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 year nine-
month period. Excluding the effect of Australian operating results included in
the prior year 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.

Overall, our effective tax rate is sensitive to the benefit of the
percentage depletion tax deduction relative to our annual profitability, as well
as our ability to utilize our existing net operating loss carryforwards. Income
taxes for the nine months ended December 31, 2001 reflected 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.

LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities was $231.2 million for the year ended
December 31, 2002, an increase of $58.7 million, or 34% from the year ended
December 31, 2001. Income before taxes and minority interests (excluding the
gain on sale of Peabody Resources Limited operations included in the prior year)
was $55.2 million higher than the prior year. Working capital cash usages were
$22.8 million higher in 2002, while reclamation, workers' compensation and
retiree healthcare spending was $26.5 million lower in 2002.

Net cash used in investing activities was $144.1 million for 2002, compared
to cash provided by investing activities of $247.2 million in the prior year.
The prior year included $455.0 million of proceeds from the sale of our Peabody
Resources Limited operations, and $16.9 million of proceeds related to the sale
of Citizens Power. Capital expenditures decreased $27.7 million, to $208.6
million, in 2002. These capital expenditures were primarily for the replacement
of mining equipment, the expansion of capacity at certain mines and projects to
improve the efficiency of mining operations. Proceeds from property and
equipment disposals increased $110.7 million to $125.4 million; proceeds in the
current year included $72.5 million received related to our contribution of
reserves to Penn Virginia and $27.7 million related to the landfill sale.
Finally, 2002 included higher acquisition expenditures of $38.1 million. The
2002 acquisitions are discussed in detail in the notes to our consolidated
financial statements.

Net cash used by financing activities was $54.8 million for 2002, compared
with cash used in financing activities of $414.1 million in the prior year. The
prior year included $449.8 million of net proceeds from our initial public
offering. Net debt repayments were $842.9 million higher in 2001, principally as
a result of the usage of proceeds received from the sale of our Peabody
Resources Limited operations and our initial public offering to repay debt. We
also received a $19.9 million dividend in 2001

44

from our Peabody Resources Limited operations. In addition, we increased
dividends paid to our shareholders by $10.5 million in 2002.

The following table reflects our total indebtedness as of December 31, 2002
(in thousands):

As of December 31, 2002, our revolving credit and letter of credit
borrowing facilities included the $480.0 million Revolving Credit Facility under
our Senior Credit Facility and Black Beauty's $140.0 million revolving credit
facility. The Revolving Credit Facility has a borrowing sub-limit of $350.0
million and a letter of credit sub-limit of $330.0 million. Together, these
facilities total $620.0 million, and had a total of $316.6 million available for
borrowing as of December 31, 2002. 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 2.9% at December 31, 2002.

Black Beauty has a $140.0 million revolving credit facility that 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 3.0% as of
December 31, 2002. The revolving credit facility contains customary restrictive
covenants including limitations on additional debt, investments and dividends.

As of December 31, 2002, we had borrowings of $116.6 million outstanding
under the Black Beauty revolving credit facility and no borrowings outstanding
under our Revolving Credit Facility.

The following is a summary of commercial commitments available to us under
our Revolving Credit Facility and Black Beauty's revolving credit facility as of
December 31, 2002 (in thousands):

As of December 31, 2002, we have issued letters of credit totaling $186.8
million under our Revolving Credit Facility, leaving $143.2 million of letter of
credit capacity available under the Revolving Credit Facility.

We are considering the acquisition of the 18.3% minority interest of Black
Beauty. Should we complete this acquisition, we anticipate funding it from our
available borrowing capacity.

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

45

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.

On February 27, 2003, we commenced a tender offer to purchase for cash any
and all of our outstanding Senior Notes and Senior Subordinated Notes. The
tender offer or any redemption of notes on May 15, 2003 will be conditioned upon
obtaining sufficient proceeds from the refinancing initiatives announced in
February 2003. These initiatives include a new $600 million revolving credit
facility and a new $600 million bank term loan, and issuance of other senior
debt in the amount of $500 million. We intend to use a portion of the net
proceeds from these financings to fund the purchase of the senior notes and the
senior subordinated notes in connection with the tender offer. We intend to call
for redemption on May 15, 2003, in accordance with the applicable indenture, all
notes that remain outstanding after the tender offer, at the redemption price of
104.438% of the principal amount with respect to the Senior Notes and at the
redemption price of 104.813% of the principal amount with respect to the Senior
Subordinated Notes, plus interest accrued and unpaid up to but not including,
the redemption date.

We have designated interest rate swaps with notional amounts totaling
$150.0 million as a fair value hedge of our Senior Notes. Under the swaps, we
pay a floating rate based upon the six-month LIBOR rate for a period of seven
years ending May 15, 2008. The applicable rate was 5.41% as of December 31,
2002. We realized interest savings of $4.2 million related to the swaps during
2002.

During the year, Fitch Ratings, Inc. affirmed its investment-grade BBB
rating on the corporate senior unsecured notes and unsecured bank revolver of
Black Beauty. On October 2, 2002, Moody's assigned us an SGL-1 liquidity rating.
Under Moody's rating system, SGL-1 means "very good" liquidity. Moody's SGL
ratings, an assessment of liquidity, are used to supplement the current Moody's
credit ratings for companies rated from "Ba1" to "C." In January 2003, Standard
& Poor's announced that it assigned its BB+ rating to our Senior Credit
Facility. The agency also affirmed its BB corporate credit rating and its stable
outlook.

CONTRACTUAL OBLIGATIONS

The following is a summary of our significant contractual obligations as of
December 31, 2002 (in thousands):

Additionally, we have long-term liabilities relating to retiree health care
(postretirement benefits and multi-employer benefit plans), 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, 2002 (in thousands):

We had $56.8 million of committed capital expenditures at December 31,
2002. Total capital expenditures for 2003 are expected to range from $175
million to $200 million, and have been and will be

46

primarily used to develop existing reserves, replace or add equipment, acquire
additional low sulfur or other strategic coal reserves 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 2003 is reduced by our high level of sales
commitments (95% of 2003 planned production) and recent efforts to improve our
operating cost structure.

OFF-BALANCE SHEET ARRANGEMENTS

In the normal course of business, we are a party to certain off-balance
sheet arrangements. These arrangements include guarantees, indemnifications,
financial instruments with off-balance sheet risk, such as bank letters of
credit and performance or surety bonds and our $140.0 million accounts
receivable securitization. Liabilities related to these arrangements are not
reflected in our consolidated balance sheets, and we do not expect any material
adverse effects on our financial condition, results of operations or cash flows
to result from these off-balance sheet arrangements.

We use surety bonds to secure our reclamation, workers' compensation,
postretirement benefits and coal lease obligations. As of December 31, 2002, we
had outstanding surety bonds with third parties for post-mining reclamation
totaling $622.6 million. We had an additional $164.4 million of surety bonds in
place for workers' compensation and retiree healthcare obligations and $69.0
million of surety bonds securing coal leases. Recently, surety bond costs have
increased, while the market terms of surety bonds have generally become less
favorable to us. To the extent that surety bonds become unavailable, we would
seek to secure our obligations with letters of credit, cash deposits or other
suitable forms of collateral.

We have guaranteed $14.9 million of debt of an affiliate in which we have a
49% equity investment, as described in Note 22 to our consolidated financial
statements. We maintain letters of credit totaling $223.8 million to secure
lease, workers' compensation, postretirement benefits, and other obligations, as
discussed in Notes 11, 15, 17 and 22, respectively, to our consolidated
financial statements. Our remaining guarantees and indemnifications are
discussed in Note 22 to our consolidated financial statements.

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. We
used proceeds from the sale of our accounts receivable to repay long-term debt,
effectively reducing our overall borrowing costs. The funding cost of the
securitization program was $3.3 million for the year ended December 31, 2002.
The securitization program is currently scheduled to expire in 2007. Under the
provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities," the securitization transactions have
been recorded as sales, with those accounts receivable sold to the Conduit
removed from our consolidated balance sheet. The amount of undivided interests
in accounts receivable sold to the Conduit were $136.4 million as of December
31, 2002. A detailed description of our $140.0 million accounts receivable
securitization is included in Note 5 to our consolidated financial statements.

ACCOUNTING PRONOUNCEMENTS NOT YET IMPLEMENTED

In June 2001, the Financial Accounting Standards Board (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 Peabody), and primarily changes the manner in which we
recognize expense for final reclamation of acreage disturbed during the mining
process.

Based on recent industry implementation guidance, we anticipate recording a
cumulative gain of approximately $10 million to $15 million, net of income
taxes, upon adoption of SFAS No. 143. Beginning

47

with 2003, we expect depreciation and accretion expense of approximately $10
million to $15 million in addition to the $11.0 million of expense recorded for
final reclamation for the year ended December 31, 2002. Future changes to
implementation guidance, if any, could result in changes to these anticipated
impacts.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections," which is effective January 1, 2003 for Peabody. As a result of
SFAS No. 145, gains or losses on debt extinguishment previously reported as
extraordinary items will be presented as a component of results from continuing
operations unless the extinguishment meets the criteria for classification as an
extraordinary item in Accounting Principles Board Opinion No. 30. On February
27, 2003, we commenced a tender offer to purchase for cash any and all of our
outstanding Senior Notes and Senior Subordinated Notes. The tender offer or any
redemption of notes on May 15, 2003 will be conditioned upon obtaining
sufficient proceeds from the refinancing initiatives announced in February 2003.
These initiatives include a new $600 million revolving credit facility and a new
$600 million bank term loan, and issuance of other senior debt in the amount of
$500 million. Any charges incurred pursuant to the extinguishment of our
existing debt as a result of the refinancing will impact our results from
continuing operations.

On October 25, 2002, the EITF rescinded EITF Issue No. 98-10 "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities." The
effects of the rescission on the Company's accounting for coal and emission
allowance trading activities are discussed in Note 1 to our consolidated
financial statements. As a result of the rescission, energy trading contracts we
entered into after October 25, 2002 are evaluated under SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The effect of
the rescission on non-derivative energy trading contracts entered into prior to
October 25, 2002 will be recorded as a cumulative effect of a change in
accounting principle in the first quarter of 2003. We anticipate we will record
a cumulative effect loss of $15 to $20 million, net of income taxes, to reverse
the net unrealized gains on non-derivative energy trading contracts recorded
prior to December 31, 2002. These non-derivative energy trading contracts will
settle in 2003 and 2004.

In November 2002, the FASB issued Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others" (FIN 45). The disclosure requirements of
FIN 45 are effective for our 2002 consolidated financial statements. For
applicable guarantees issued after January 1, 2003, FIN 45 requires that a
guarantor recognize a liability for the fair value of the obligation undertaken
in issuing the guarantee. We do not believe that the accounting requirements of
FIN 45 will have a material effect on our financial condition or results of
operations.

In January 2003, FASB issued Interpretation No. 46, "Consolidation of
Variable Interest Entities" (FIN 46), which requires the consolidation of
variable interest entities, as defined. FIN 46 is applicable to financial
statements to be issued after 2002; however, disclosures are required currently
if any variable interest entities are expected to be consolidated. We do not
believe that any entities will be consolidated as a result of FIN 46.

RISKS RELATING TO OUR COMPANY

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 year ended December 31, 2002, 97% of our sales
volume was sold under long-term coal supply agreements. At December 31, 2002,
our coal supply agreements had remaining terms ranging from one to 18 years and
an average volume-weighted remaining term of approximately 4.4 years.

48

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. In a
limited number of contracts, failure of the parties to agree on a price under
those provisions may allow either party to terminate the contract. We sometimes
experience a 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, some 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, market prices for coal decreased in most regions in 2002.
As a result, we cannot predict the future strength of the coal market and cannot
assure you that we will be able to replace existing long-term coal supply
agreements at the same prices or with similar profit margins when they expire.
In addition, two of our coal supply agreements are the subject of ongoing
litigation and arbitration, as discussed in Item 3 of this report.

THE LOSS OF, OR SIGNIFICANT REDUCTION IN, PURCHASES BY OUR LARGEST CUSTOMERS
COULD ADVERSELY AFFECT OUR REVENUES.

For the year ended December 31, 2002, we derived 28% of our total coal
revenues from sales to our five largest customers. At December 31, 2002, we had
31 coal supply agreements with these customers that expire at various times from
2003 to 2015. We are currently discussing the extension of existing agreements
or entering into new long-term agreements with some of these customers, but
these negotiations may not be successful and those customers may not continue to
purchase coal from us under long-term coal supply agreements. If a number of
these customers were to significantly reduce their purchases of coal from us, or
if we were unable to sell coal to them on terms as favorable to us as the terms
under our current agreements, our financial condition and results of operations
could suffer materially.

In addition, we sold 4.6 million tons of coal to the Mohave Generating
Station in 2002. We have a long-term coal supply agreement with the owners of
the Mohave Generating Station that expires on December 31, 2005. There is a
dispute with the Hopi Tribe regarding the use of groundwater in the
transportation of coal by pipeline to the Mohave Generating Station. Also,
Southern California Edison (the majority owner and operator of the plant) is
involved in a California Public Utility Commission proceeding related to
recovery of future capital expenditures for new pollution abatement equipment
for the station. As a result of these issues, the owners of the Mohave
Generating Station have announced that they expect to idle the plant for at
least 12 to 18 months beginning in 2006. We are in active discussions to resolve
the complex issues critical to the continuation of the operation of the Mohave
Generating Station and the renewal of the coal supply agreement after December
31, 2005. There is no assurance that the issues critical to the continued
operation of the Mohave Generating Station will be resolved. The Mohave
Generating Station is the sole customer of our Black Mesa Mine, which produces
and sells 4.5 to

49

5 million tons of coal per year. If we are unable to renew the coal supply
agreement with the Mohave Generating Station, our financial condition and
results of operations could be adversely affected after 2005.

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, 2002, we had total indebtedness of $1,029.2
million. We currently have total borrowing capacity under our and Black Beauty's
revolving credit facilities of $490.0 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,
except for the assets of Black Beauty Coal Company and its affiliates, 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.

50

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, 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 U.S. 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 of and demand for coal. According to the Energy
Information Administration's Emissions of Greenhouse Gases in the United States
2001, 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 regulations or other
limits on carbon dioxide emissions 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 $1,031.7 million as of
December 31, 2002, $72.1 million of which was a current liability. We have
estimated these unfunded obligations based on assumptions described in the notes
to our consolidated 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 two
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 give notice of an intent to
terminate one or more of the

51

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. On November 19,
2002 TXU Europe Limited was placed under the administration process in the
United Kingdom (a process similar to bankruptcy proceedings in the United
States). As a result of these proceedings, TXU Europe Limited may be liquidated
or otherwise reorganized in such a way as to relieve it of its obligations under
its guaranty.

In addition, certain of our subsidiaries participate in two multi-employer
pension funds and have an obligation to contribute to a multi-employer defined
contribution benefit fund. Contributions to these funds could increase as a
result of future collective bargaining with the United Mine Workers of America,
a shrinking contribution base as a result of the insolvency of other coal
companies who currently contribute, lower than expected returns on pension fund
assets, higher medical and drug costs or other funding deficiencies. Certain of
our subsidiaries are statutorily obligated to contribute to the 1992 Fund under
the Coal Act. Contributions to this fund could increase as a result of a
shrinking contribution base and increasing beneficiaries due to the insolvency
of other coal companies who currently contribute, higher medical and drug costs
or other funding deficiencies.

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 nationwide. As of December 31, 2002, we leased or had applied
to lease a total of 69,402 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. 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

52

prices. Similarly, an increase in future coal prices could 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, 2002, the United Mine Workers of America represented
approximately 31% of our employees, who produced 19% of our coal sales volume
during 2002. An additional 4% of our employees are represented by labor unions
other than the United Mine Workers of America. These employees produced 3% of
our coal sales volume during 2002. 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, 2002, we had outstanding surety bonds with third parties for
post-mining reclamation totaling $622.6 million. Furthermore, we had an
additional $164.4 million of surety bonds in place for workers' compensation and
retiree healthcare obligations and $69.0 million of surety bonds securing coal
leases. These bonds are typically renewable on a yearly basis. It has become
increasingly difficult for us to secure new surety bonds or renew bonds without
the posting of partial collateral. In addition, surety bond costs have increased
while the market terms of surety bonds have generally become less favorable to
us. Surety bond issuers and holders may not continue to renew the bonds or may
demand additional collateral upon those renewals. Our failure to maintain, or
inability to acquire, surety bonds that are required by state and federal law
would have a material adverse effect on us. That failure could result from a
variety of factors including the following:

- lack of availability, higher expense or unfavorable market terms of new
surety bonds;

- restrictions on the availability of collateral for current and future
third-party surety bond issuers under the terms of our indentures or
senior credit facility; and

- the exercise by third-party surety bond issuers of their right to refuse
to renew the surety.

LEHMAN BROTHERS MERCHANT BANKING HAS SIGNIFICANT INFLUENCE ON ALL STOCKHOLDER
VOTES AND MAY HAVE CONFLICTS OF INTEREST WITH OTHER STOCKHOLDERS IN THE
FUTURE.

At December 31, 2002, Lehman Brothers Merchant Banking and its affiliates
beneficially owned approximately 41% of our common stock. As a result, Lehman
Brothers Merchant Banking will effectively continue to be able to influence 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 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 of this report. 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

53

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. Future terrorist attacks
against U.S. 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. In addition, the creditworthiness of
certain of our customers and trading counterparties has deteriorated due to
lower than anticipated demand for energy and lower volume and volatility in the
traded energy markets in 2002.

If deterioration of the creditworthiness of other electric power generator
customers or trading counterparties continues, our $140.0 million accounts
receivable securitization program and our business could be adversely affected.

OUR CERTIFICATE OF INCORPORATION AND BY-LAWS INCLUDE PROVISIONS THAT MAY
DISCOURAGE A TAKEOVER ATTEMPT.

Provisions contained in our certificate of incorporation and by-laws and
Delaware law could make it more difficult for a third party to acquire us, even
if doing so might be beneficial to our stockholders. Provisions of our by-laws
and certificate of incorporation impose various procedural and other
requirements that could make it more difficult for stockholders to effect
certain corporate actions. For example, a change of control of our company may
be delayed or deterred as a result of the stockholders' rights plan adopted by
our board of directors. These provisions could limit the price that certain
investors might be willing to pay in the future for shares of our common stock
and may have the effect of delaying or preventing a change in control.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

TRADING ACTIVITIES

TRADING ACTIVITIES

We market and trade coal and emission allowances. These activities give
rise to commodity price 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 risk limits

54

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 our
consolidated financial statements. Our policy for accounting for coal and
emission allowance trading activities is described in Note 1 to our consolidated
financial statements.

We perform a value at risk analysis on our trading portfolio, which
includes over-the-counter and brokerage trading of coal and emission allowances.
The use of value at risk allows us to quantify in dollars, on a daily basis, the
price risk inherent in our trading portfolio. 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 15-day holding period and a 95% one-tailed confidence
interval.

The use of value at risk allows management to aggregate pricing 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 year ended December 31, 2002, the low, high, and average values
at risk for our coal trading portfolio were $0.3 million, $3.9 million, and $1.7
million, respectively. Our emission allowance value at risk during the year
ended December 31, 2002 never exceeded $0.2 million. Forty-eight percent of the
value of our trading portfolio is scheduled to be realized by the end of 2003,
and 91% of the value of our trading portfolio is scheduled to be realized by the
end of 2004.

We also monitor other types of risk associated with our coal and emission
allowance trading activities, including credit, market liquidity and
counterparty nonperformance.

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 97% of our sales volume under long-term coal supply
agreements during 2002. We have sales commitments for 95% of our 2003
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, 2002, after taking into consideration the
effects of interest rate swaps, we had $721.5 million of fixed-rate borrowings
and $307.7 million of variable-rate borrowings outstanding. A one percent
increase in interest rates would result in an annualized increase to interest
expense of $3.1 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 $34.4 million decrease in the fair value of these borrowings.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

See Part IV, Item 15 of this report for the information required by this
Item.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

55

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 2003 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 2003 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 2003 Proxy Statement and
is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The information required by Item 403 of Regulation S-K is included under
the caption "Ownership of Company Securities" in the Company's 2003 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 2003 Proxy Statement
and is incorporated herein by reference.

ITEM 14. CONTROLS AND PROCEDURES

The Chief Executive Officer and Executive Vice President and Chief
Financial Officer have evaluated our disclosure controls and procedures within
90 days of the filing of this report and have concluded that there are no
significant deficiencies or material weaknesses. There have been no significant
changes in our internal controls or in other factors subsequent to the date of
our most recent evaluation that could significantly affect these controls.

There have been no significant changes in the Corporation's internal
controls or in other factors that could significantly affect internal controls
subsequent to December 31, 2002.

PART IV

ITEM 15. 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, 2002 Annual Report to
Stockholders are incorporated by reference:

Report of Independent Auditors

Consolidated Statements of Operations -- Year Ended December 31, 2002, Nine
Months Ended December 31, 2001 and the Year Ended March 31, 2001

Consolidated Balance Sheets -- December 31, 2002 and December 31, 2001

Consolidated Statements of Changes in Stockholders' Equity -- Year Ended
December 31, 2002, Nine Months Ended December 31, 2001 and the Year Ended
March 31, 2001

Consolidated Statements of Cash Flows -- Year Ended December 31, 2002, Nine
Months Ended December 31, 2001 and the Year Ended March 31, 2001

Notes to Consolidated Financial Statements

56

(2) Financial Statement Schedule

The following financial statement schedule of Peabody Energy Corporation is
included in Item 15, along with the report of independent auditors thereon, at
the pages indicated:

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

On October 17, 2002, we filed a Form 8-K under Item 5, Other Events
and Regulation FD Disclosure, concerning Adjusted EBITDA and earnings per
share for the quarter ended September 30, 2002 and revised guidance on
Adjusted EBITDA and earnings per share for the year ended December 31,
2002.

On December 23, 2002, we filed a Form 8-K under Item 5, Other Events
and Regulation FD Disclosure, concerning our exchange of coal reserves for
$72.5 million in cash and 2.76 million units of Penn Virginia Resource
Partners, L.P., a publicly-held master limited partnership.

On January 17, 2003, we filed a Form 8-K under Item 5, Other Events
and Regulation FD Disclosure, announcing two events, an adverse U.S.
Supreme Court ruling and the recognition of certain income tax benefits,
that impacted our earnings in the fourth quarter of 2002.

On January 31, 2003, we filed a Form 8-K under Item 9, Regulation FD
Disclosure, concerning our calendar year and fourth quarter 2002 earnings,
and our 2003 forecast.

On February 27, 2003, we filed a Form 8-K under Item 5, Other Events
and Regulation FD Disclosure, announcing that we had commenced a tender
offer to purchase for cash any and all of our outstanding 8 7/8% Senior
Notes due 2008 and 9 5/8% Senior Subordinated Notes due 2008.

57

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 7, 2003

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.

58

CERTIFICATION

I, Irl F. Engelhardt, certify that:

1. I have reviewed this annual report on Form 10-K of Peabody Energy
Corporation ("the registrant");

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

IRL F. ENGELHARDT
--------------------------------------
Irl F. Engelhardt,
Chief Executive Officer

Date: March 7, 2003

59

CERTIFICATION

I, Richard A. Navarre, certify that:

1. I have reviewed this annual report on Form 10-K of Peabody Energy
Corporation ("the registrant");

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;

(b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing
date of this annual report (the "Evaluation Date"); and

(c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal controls;
and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

RICHARD A. NAVARRE
--------------------------------------
Richard A. Navarre
Executive Vice President and Chief
Financial Officer

Date: March 7, 2003

60

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, 2002 and 2001, and for the year
ended December 31, 2002, the nine months ended December 31, 2001 and the year
ended March 31, 2001, and have issued our report thereon dated January 18, 2003.
Our audits also included the financial statement schedule listed in Item 15(a).
This schedule is the responsibility of the Company's management. Our
responsibility is to express an opinion based on our audits. In our opinion, the
financial statement schedule referred to above, when considered in relation to
the basic financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.

ERNST & YOUNG LLP

St. Louis, Missouri
January 18, 2003

F-1

PEABODY ENERGY CORPORATION

SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS

- ---------------

(1) Reserves utilized, unless otherwise indicated.

(2) Balances transferred from other accounts.

F-2

EXHIBIT INDEX

The exhibits below are numbered in accordance with the Exhibit Table of
Item 601 of Regulation S-K.

- ---------------

* These exhibits constitute all management contracts, compensatory plans and
arrangements required to be filed as an exhibit to this form pursuant to Item
15(c) of this report.

+ Filed herewith.