Edgar Filing: PEABODY ENERGY CORP

FILED PURSUANT TO RULE NO. 424(b)(1)
REGISTRATION NO. 333-55412

PROSPECTUS

15,000,000 Shares

[LOGO OF PEABODY ENERGY CORP]

Peabody Energy Corporation

Common Stock

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This is our initial public offering of common stock. We are offering
15,000,000 shares of common stock. We are initially offering 12,000,000 shares
in the United States and Canada, and we are initially offering 3,000,000
shares outside the United States and Canada. No public market currently exists
for our shares.

Our shares have been authorized for listing on the New York Stock Exchange
under the symbol "BTU."

Investing in the shares involves risks. "Risk Factors" begin on page 10.

Per Share Total
--------- ------------

Public Offering Price.................................... $28.000 $420,000,000
Underwriting Discount.................................... $ 1.575 $ 23,625,000
Proceeds to Peabody ..................................... $26.425 $396,375,000

We have granted the underwriters a 30-day option to purchase up to
2,250,000 additional shares of common stock on the same terms and conditions
as set forth above to cover over-allotments, if any.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved these securities or determined if this
prospectus is accurate or complete. Any representation to the contrary is a
criminal offense.

Lehman Brothers, on behalf of the underwriters, expects to deliver the
shares on or about May 25, 2001.

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Lehman Brothers
Bear, Stearns International Limited
Merrill Lynch International
Morgan Stanley Dean Witter
UBS Warburg
Cazenove & Co.

May 21, 2001

TABLE OF CONTENTS

Page
----

Prospectus Summary....................................................... 1
Risk Factors............................................................. 10
Cautionary Notice Regarding
Forward-Looking Statements.............................................. 18
Use of Proceeds.......................................................... 19
Dividend Policy.......................................................... 19
Capitalization........................................................... 20
Dilution................................................................. 21
Unaudited Pro Forma Condensed Financial Information...................... 22
Selected Financial Data.................................................. 26
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 29
Coal Industry Overview................................................... 38
Business................................................................. 48

Page
----

Regulatory Matters......................................................... 68
Management................................................................. 74
Related Party Transactions................................................. 85
Principal Stockholders..................................................... 88
Description of Indebtedness................................................ 89
Description of Capital Stock............................................... 92
Shares Eligible for Future Sale............................................ 96
Certain U.S. Tax Consequences to Non-U.S. Holders.......................... 98
Underwriting............................................................... 100
Legal Matters.............................................................. 105
Experts.................................................................... 105
Where You Can Find Additional Information.................................. 105
Glossary of Selected Terms................................................. 106
Index to Financial Statements.............................................. F-1

You should rely only on the information contained in this prospectus. We
have not, and the underwriters have not, authorized any other person to provide
you with different information. If anyone provides you with different or
inconsistent information, you should not rely on it. We are not, and the
underwriters are not, making an offer to sell these securities in any
jurisdiction where an offer or sale is not permitted. You should assume that
the information appearing in this prospectus is accurate as of the date on the
front cover of this prospectus only. Our business, financial condition, results
of operations and prospects may have changed since that date.

Through and including June 15, 2001 (the 25th day after the date of this
prospectus), all dealers effecting transactions in our common stock, whether or
not participating in this offering, may be required to deliver a prospectus.
This is in addition to the dealers' obligation to deliver a prospectus when
acting as underwriters and with respect to their unsold allotments or
subscriptions.

PROSPECTUS SUMMARY

This summary may not contain all the information that may be important to
you. You should read the entire prospectus before making an investment
decision. References to years relate to calendar years, unless otherwise noted.
All information in this prospectus summary reflects the recent divestiture of
our Australian operations, unless otherwise noted. The estimates of our proven
and probable reserves included in this prospectus have been reviewed by
Marshall Miller & Associates. Because our industry is a technical one, we have
included a "Glossary of Selected Terms" that explains many of the terms we use
in this prospectus. You should carefully consider the information presented
under the heading "Risk Factors."

The Company

We are the largest private-sector coal company in the world. Our sales of
181.6 million tons of coal in the year ended March 31, 2001 accounted for more
than 16% of all U.S. coal sales and were more than 50% greater than the sales
of our closest competitor. During this period, we sold coal to more than 290
electric generating and industrial plants, fueling the generation of more than
9% of all electricity in the United States and 2.5% of all electricity in the
world. At March 1, 2001, we had 9.3 billion tons of proven and probable coal
reserves, approximately double the reserves of any other U.S. coal company. For
the year ended March 31, 2001, we generated pro forma total revenues of $2.4
billion and pro forma Adjusted EBITDA of $332.2 million.

We own majority interests in 34 coal operations located throughout all major
U.S. coal producing regions, with 66% of our fiscal year 2001 coal sales
shipped from the western United States and the remaining 34% from the eastern
United States. Most of our production in the western United States is low
sulfur coal from the Powder River Basin. Our overall western U.S. coal
production increased from 37.0 million tons in fiscal year 1990 to 119.7
million tons in fiscal year 2001, representing a compounded annual growth rate
of 11%. In the west, we own and operate mines in Arizona, Colorado, Montana,
New Mexico and Wyoming. In the east, we own and operate mines in Illinois,
Indiana, Kentucky and West Virginia. We produced 77% of our fiscal year 2001
sales volume from non-union mines.

For the year ended March 31, 2001, 93% of our sales were to U.S. electricity
generators, 3% were to the U.S. industrial sector and 4% were to customers
outside the United States. Approximately 85% of our fiscal year 2001 coal sales
were under long-term contracts. As of March 31, 2001, nearly one billion tons
of our future coal production were committed under long-term contracts, with
remaining terms ranging from one to 16 years and an average volume-weighted
remaining term of four years. As a result of recent significant improvements in
coal prices, we have added long-term contracts to our portfolio at favorable
prices. During the first four months of 2001, we entered into commitments to
sell four million tons of coal in 2001, 31 million tons of coal in 2002, 21
million tons of coal in 2003 and 19 million tons of coal in 2004, much of which
were at prices substantially above prior-year levels. Additionally, our
significant uncommitted future production positions us well to continue to
enter into favorably priced contracts. As of April 30, 2001, we had
approximately 37 million tons, 80 million tons and 111 million tons of expected
production available for sale at market-based prices in 2002, 2003 and 2004,
respectively.

We are also expanding in related energy businesses that include coal
trading, coalbed methane production, transportation-related services, third-
party coal contract restructuring and participation in the development of coal-
based generating plants.

Transformation of Peabody

We have grown significantly over the past decade and have transformed
ourselves from a largely high sulfur, high-cost coal company to a predominantly
low sulfur, low-cost coal producer, marketer and trader. To meet customer
demand for cleaner coal, we have increased our sales of low sulfur coal from
56% of our total volume in fiscal year 1990 to over 80% in fiscal year 2001. We
are also well positioned to continue selling higher sulfur coal to customers
that have invested in emissions control technology, buy emissions allowances or
blend higher sulfur coal with low sulfur coal. Our average cost per ton sold
decreased 43% from fiscal year 1990 to fiscal year 2001. The following chart
demonstrates our transformation:

Fiscal Year
-------------- Percent
1990 2001 Improvement
------ ------ -----------

Sales volume (million tons)......................... 93.3 181.6 95%
U.S. market share(/1/).............................. 9.1% 16.7% 84
Low sulfur sales volume (million tons).............. 52.6 146.3 178
Total coal reserves (billion tons)(/2/)............. 7.0 9.3 33
Low sulfur reserves (billion tons)(/2/)............. 2.5 4.4 76
Safety (incidents per 200,000 hours)................ 16.1 3.9 76
Productivity (tons per miner shift)................. 32.9 122.8 273
Average cost per ton sold(/3/)...................... $19.33 $11.05 43
Employees (approximate)............................. 10,700 6,100 43

--------
(1) Market share is calculated by dividing our U.S. sales volume by estimated
total demand for coal in the United States, as reported by the Energy
Information Administration.
(2) As of January 1, 1990 and as of March 1, 2001.
(3) Represents operating costs and expenses.

Market Opportunities

The U.S. coal industry continues to fuel more electricity generation than
all other energy sources combined. In 2000, coal-based plants generated an
estimated 51% of the nation's electricity, followed by nuclear (20%), gas-fired
(16%) and hydroelectric (8%) units. We believe that electricity deregulation
and the resulting competition for cost-efficient energy will strengthen demand
for coal. We also believe that U.S. and world coal consumption will continue to
increase as coal-based generating plants utilize their existing excess capacity
and as new coal-based plants are constructed. Coal is an attractive fuel for
electricity generation because it is:

. Abundant: Coal makes up more than 85% of fossil fuel reserves in the
United States. The nation has an estimated 250-year supply of coal,
based on current usage rates.

. Low-Cost: At an average delivered price of $1.20 per million British
thermal units, or Btu, coal's cost advantage over natural gas continued
to widen in 2000, during which the average delivered price of natural
gas was $4.22 per million Btu, and at times exceeded $10.00 per million
Btu. In 1999, 19 of the 25 lowest-cost major generating plants in the
United States were coal-based.

. Increasingly Clean: Aggregate pollution from U.S. coal-based plants has
declined significantly since 1970, even as coal consumption by
electricity generators has tripled.

Business Strengths

We believe our strengths will enable us to enhance our industry-leading
position and increase shareholder value.

. We are the world's largest private-sector producer and marketer of coal,
and the largest reserve holder of any U.S. coal company.

. We are the largest producer and marketer of low sulfur coal in the
world, with the number one position in the Southern Powder River Basin,
part of the fastest growing U.S. coal producing region.

. We have a large portfolio of long-term coal supply agreements and have
substantial future production available for sale at market prices.

. We are one of the most productive and lowest-cost providers of coal in
the United States.

. We serve a broad range of customers with mining operations located
throughout all major U.S. coal producing regions.

. We are a leader in reclamation management and have received numerous
state and national awards for our commitment to environmental
excellence.

. Our management team has a proven record of success and is incentivized
to maximize shareholder value.

While we strive to maintain these strengths, our industry and our company
are subject to risks that could adversely affect our business. For example, we
cannot assure you that in the future we will be able to sell coal as profitably
as at present. Additionally, our company and our customers are subject to
extensive governmental regulations that create significant costs and
restrictions and that could become more onerous in the future. For a more
complete discussion of the risks related to our company, you should read the
information presented under the heading "Risk Factors."

Business Strategy

To maximize shareholder value and enhance our position as a premier low-cost
energy provider, we seek to implement three core strategies:

. Expand to serve growth markets by pursuing strategic acquisitions,
developing our existing reserves and expanding in coal-related
businesses;

. Manage safe, low-cost, environmentally conscious operations by focusing
on regions where we can be a low-cost producer, aggressively reducing
our costs and remaining committed to safety and environmental
excellence; and

. Create innovative solutions to meet our customers' changing needs by
using our geographical diversity and superior market knowledge.

Confirming the depth of our strengths and the successful implementation of
our strategies, we were recently recognized as the world's best coal company at
the 2000 Financial Times Global Energy Awards by an international panel of
judges using the criteria of safety, environmental commitment, productivity,
market/technology innovation and shareholder value.

Recent Developments

Australian Operations

On January 29, 2001, we sold our Australian operations to a subsidiary of
Rio Tinto Limited for $446.8 million in cash, plus the assumption of all
liabilities, including $119.4 million of debt. We used proceeds from the sale
to repay $440.0 million of term loans under our senior credit facility. We
believe that the transaction maximized the value of our Australian operations.

Thoroughbred Energy Campus

On February 28, 2001, we filed an application with the State of Kentucky for
an air permit relating to a proposed coal-based electricity generation project
in western Kentucky. This project, the Thoroughbred Energy Campus, will be
located near Central City in Muhlenberg County. The proposed project would
consist of a five to six million ton per year underground coal mine that will
fuel a 1,500 megawatt generating plant constructed on approximately 4,500 acres
of property controlled by us. The generating station is being designed to
comply with all applicable state and federal regulatory emissions limits. The
Thoroughbred project is currently in a design development stage. We are engaged
in discussions with several prospective partners regarding the scope and
structure of the project, but we have not entered into any definitive
agreements. We currently intend to manage the initial permitting required for
the project and related mine operations and are seeking a partner to manage
plant construction, operations and power marketing.

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

Our principal executive offices are located at 701 Market Street, St. Louis,
Missouri 63101-1826, telephone (314) 342-3400.

The Offering

Common stock offered:
15,000,000 shares

Common stock outstanding after this 49,610,509 shares
offering:

Use of proceeds: We intend to use the net proceeds from
this offering to repay long-term debt.

Dividend policy:
We expect to pay quarterly dividends of
$0.10 per share on our common stock,
subject to the approval of our board of
directors and other matters discussed in
"Dividend Policy."

New York Stock Exchange symbol: BTU

Unless we indicate otherwise, all information in this prospectus reflects:

. the number of shares of our Class A common stock, Class B common stock
and preferred stock outstanding on March 31, 2001;

. the 1.4-for-one split of our Class A common stock, Class B common stock
and preferred stock prior to the completion of this offering;

. the conversion of our Class A common stock and Class B common stock and
the exchange and conversion of our preferred stock into a single class of
common stock, all on a one-for-one basis upon the completion of this
offering; and

. no exercise by the underwriters of the over-allotment option to purchase
up to 2,250,000 additional shares of common stock from us.

As of March 31, 2001, we had outstanding options to acquire 5,225,510 shares
of common stock at an exercise price of $14.29 per share.

Summary Financial Data

The following table presents summary 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 operations. The period ended March 31, 1999 is
thus a full fiscal year, but includes results of operations only from May 20,
1998. For the period prior to May 20, 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. Also, for comparative
purposes, we derived the "Total Fiscal Year 1999" column by adding the period
ended March 31, 1999 with our predecessor company results for the period ended
May 19, 1998. The effects of purchase accounting have not been reflected in the
results of our predecessor company.

In early 1999, we increased our equity interest in Black Beauty Coal Company
from 43.3% to 81.7%. Our results of operations include the consolidated results
of Black Beauty, effective January 1, 1999. Prior to that date, we accounted
for our investment in Black Beauty under the equity method, under which we
reflected our share of Black Beauty's results of operations as a component of
"Other revenues" in the statements of operations, and our interest in Black
Beauty's net assets within "Investments and other assets" in the balance
sheets.

In anticipation of the sale of Citizens Power, our power marketing
subsidiary, 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.

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. Results
of operations for the year ended March 31, 2001 included a pretax gain of
$171.7 million, or $124.2 million net of income taxes, from the sale of our
Australian operations.

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 we believe it is a useful indicator of our
ability to meet our 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.

We have derived the summary 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 summary historical financial data for our company for the period from May
20, 1998 to March 31, 1999 and as of March 31, 1999 and the years ended and as
of March 31, 2000 and 2001 from our predecessor company's and our audited
financial statements. The historical results are not necessarily indicative of
our future operating results. You should read the following table in
conjunction with the financial statements, which have been audited by Ernst &
Young LLP, independent auditors, and the notes to those statements appearing
elsewhere in this prospectus and "Management's Discussion and Analysis of
Financial Condition and Results of Operations."

Predecessor
Company May 20,
---------------- 1998 to Total Year Ended Year Ended
April 1, 1998 to March 31, Fiscal Year March 31, March 31,
May 19, 1998 1999 1999 2000 2001
---------------- ----------- ----------- ----------- -----------
(Dollars in thousands, except per share data)

Results of Operations Data:
Revenues:
Sales............................. $278,930 $ 1,970,957 $ 2,249,887 $ 2,610,991 $ 2,579,104
Other revenues.................... 11,728 85,875 97,603 99,509 90,588
-------- ----------- ----------- ----------- -----------
Total revenues.................. 290,658 2,056,832 2,347,490 2,710,500 2,669,692
Costs and expenses................ 281,333 1,899,788 2,181,121 2,517,263 2,327,853
-------- ----------- ----------- ----------- -----------
Operating profit................... $ 9,325 $ 157,044 $ 166,369 $ 193,237 $ 341,839
======== =========== =========== =========== ===========
Income (loss) from continuing
operations........................ $ 2,240 $ (5,433) $ (3,193) $ 118,570 $ 102,680
Income (loss) from discontinued
operations........................ (1,764) 6,442 4,678 (90,360) 12,925
Extraordinary loss from early
extinguishment of debt............ -- -- -- -- (8,545)
-------- ----------- ----------- ----------- -----------
Net income......................... $ 476 $ 1,009 $ 1,485 $ 28,210 $ 107,060
======== =========== =========== =========== ===========
Basic and diluted earnings (loss)
per Class A/B share from
continuing operations............. $ (0.16) $ 3.43 $ 2.97
Weighted average shares used in
calculating basic earnings (loss)
per Class A/B share............... 26,823,383 27,586,370 27,524,626

Other Data:
Tons sold (in millions):
United States..................... 20.9 147.7 168.6 179.2 181.6
Australia......................... 0.8 6.6 7.4 11.1 10.8
Adjusted EBITDA:
United States..................... $ 28,850 $ 279,588 $ 308,438 $ 361,209 $ 503,912
Australia......................... 5,991 56,638 62,629 81,810 78,895
Operating profit:
United States..................... 6,375 124,368 130,743 144,882 288,462
Australia......................... 2,950 32,676 35,626 48,355 53,377
Depreciation, depletion and
amortization:
United States..................... 22,475 155,220 177,695 216,327 215,450
Australia......................... 3,041 23,962 27,003 33,455 25,518
Net cash provided by (used in):
Operating activities.............. (28,157) 282,022 253,865 262,911 151,980
Investing activities.............. (21,550) (2,249,336) (2,270,886) (185,384) 388,462
Financing activities.............. 23,537 2,161,281 2,184,818 (205,181) (543,337)
Capital expenditures:
United States..................... 13,582 110,622 124,204 150,130 151,358
Australia......................... 7,292 63,898 71,190 28,624 35,702

Balance Sheet Data (at period end):
Total assets....................... $ 5,826,849 $ 5,209,487
Total debt......................... 2,076,166 1,405,621
Total stockholders' equity......... 508,426 631,238

Summary Pro Forma Financial Data

On January 29, 2001, we sold our Australian operations to a subsidiary of
Rio Tinto Limited for $446.8 million in cash plus the assumption of all
liabilities, including $119.4 million of debt. We incurred $15.0 million of
transaction costs in connection with this sale. The pretax gain on the sale of
our Australian operations was $171.7 million.

In anticipation of the sale of Citizens Power, which occurred in fiscal year
2001, 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.

The following unaudited pro forma financial data are based on the historical
presentation of our consolidated financial statements.

The unaudited pro forma results of operations data for the year ended March
31, 2001 give effect to:

. the sale of our Australian operations and the repayment of long-term
debt of $440.0 million as if it had occurred on April 1, 2000. However,
the gain on the sale of our Australian operations has been eliminated
from the results of operations data;

. the repayment of long-term debt of $105.0 million from the proceeds from
the sale of Citizens Power as if it had occurred on April 1, 2000; and

. the repayment of long-term debt of $365.0 million from the proceeds of
this offering as if it had occurred on April 1, 2000.

Pro forma basic and diluted earnings per share reflect the exchange and
conversion of our preferred shares into common shares and the increase in
common shares from this offering as if they had occurred on April 1, 2000.

The unaudited pro forma balance sheet data give effect to:

. the conversion of our Class A common stock and Class B common stock and
the exchange and conversion of our preferred stock into a single class
of common stock, all on a one-for-one basis upon the completion of the
offering as if they had occurred on March 31, 2001;

. the sale of 15.0 million shares of our common stock in this offering at
the public offering price of $28.00 per share as if it had occurred on
March 31, 2001; and

. the repayment of long-term debt of $365.0 million from the proceeds of
this offering as if it had occurred on March 31, 2001.

The summary unaudited pro forma financial data are intended for
informational purposes only and do not purport to be indicative of the results
that actually would have been obtained during the period presented and are not
necessarily indicative of operating results to be expected in future periods.
You should read the unaudited pro forma financial data in conjunction with the
financial statements and the related notes to those statements appearing
elsewhere in this prospectus and the information under "Unaudited Pro Forma
Condensed Financial Information," "Selected Financial Data" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

Year Ended March 31,
2001
------------------------
Historical Pro Forma
----------- -----------
(Dollars in thousands,
except per share data)

Results of Operations Data:
Revenues:
Sales............................................... $ 2,579,104 $ 2,388,902
Other revenues...................................... 90,588 42,292
----------- -----------
Total revenues..................................... 2,669,692 2,431,194
Costs and expenses:
Operating costs and expenses........................ 2,165,090 2,005,990
Depreciation, depletion and amortization............ 240,968 215,450
Selling and administrative expenses................. 99,267 97,809
Gain on sale of Australian operations............... (171,735) --
Net gain on property and equipment disposals........ (5,737) (4,782)
----------- -----------
Operating profit..................................... 341,839 116,727
Interest expense.................................... 197,686 115,299
Interest income..................................... (8,741) (7,962)
----------- -----------
Income before income taxes and minority interests.... 152,894 9,390
Income tax provision (benefit)...................... 42,690 (3,927)
Minority interests.................................. 7,524 7,524
----------- -----------
Income from continuing operations.................... $ 102,680 $ 5,793
=========== ===========
Basic and diluted earnings per Class A/B share from
continuing operations............................... $ 2.97 $ 0.12

Weighted average shares used in calculating basic
earnings per Class A/B share........................ 27,524,626 49,524,626

Other Data:
Tons sold (in millions).............................. 192.4 181.6
Adjusted EBITDA...................................... $ 582,807 $ 332,177
Capital expenditures................................. 187,060 151,358

Balance Sheet Data (at period end):
Total assets......................................... $ 5,209,487 $ 5,202,487
Total debt........................................... 1,405,621 1,040,621
Total stockholders' equity........................... 631,238 997,988

RISK FACTORS

An investment in our common stock involves risks. You should consider
carefully, in addition to the other information contained in this prospectus,
the following risk factors before deciding to purchase any common stock.

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 fiscal year 2001, 85% of our sales volume was sold
under long-term coal supply agreements. At March 31, 2001, our coal supply
agreements had remaining terms ranging from one to 16 years and an average
volume-weighted remaining term of four years.

Many of our coal supply agreements contain provisions that permit the
parties to adjust the contract price upward or downward at specified times. We
may adjust these contract prices based on inflation and/or changes in the
factors affecting the cost of producing coal, such as taxes, fees, royalties
and changes in the laws regulating the mining, production, sale or use of coal.
Failure of the parties to agree on a price under those provisions may allow
either party to terminate the contract. Over the last few years, several of our
coal supply agreements have been renegotiated, resulting in the contract prices
being closer to the then-current market prices, thus leading to a reduction in
the revenues from those contracts. We have also experienced a similar reduction
in coal prices in new long-term coal supply agreements replacing some of our
expiring contracts. Coal supply agreements also typically contain force majeure
provisions allowing temporary suspension of performance by us or the customer
during the duration of specified events beyond the control of the affected
party. Most coal supply agreements contain provisions requiring us to deliver
coal meeting quality thresholds for certain characteristics such as Btu, sulfur
content, ash content, grindability and ash fusion temperature. Failure to meet
these specifications could result in economic penalties, including price
adjustments, the rejection of deliveries or termination of the contracts.
Moreover, some of these agreements permit the customer to terminate the
contract if transportation costs, which our customers typically bear, increase
substantially. In addition, a majority of these contracts allow our customers
to terminate their contracts in the event of changes in regulations affecting
our industry that increase the price of coal beyond specified limits.

The operating profits we realize from coal sold under supply agreements
depend on a variety of factors. In addition, price adjustment and other
provisions may increase our exposure to short-term coal price volatility
provided by those contracts. If a substantial portion of our coal supply
agreements were modified or terminated, we could be materially adversely
affected to the extent that we are unable to find alternate buyers for our coal
at the same level of profitability. Some of our coal supply agreements are for
prices above current market prices. Although market prices for coal have
recently increased in most regions, we cannot predict whether the current
strength in the coal market will continue. As a result, we cannot assure you
that we will be able to replace existing long-term coal supply agreements at
the same prices or with similar profit margins when they expire. In addition,
two of our coal supply agreements are the subject of ongoing litigation and
arbitration.

The loss of, or significant reduction in, purchases by our largest customers
could adversely affect our revenues.

For fiscal year 2001, we derived 36% of our total coal revenues from sales
to our five largest customers. At March 31, 2001, we had 18 coal supply
agreements with these customers that expire at various times from 2001 to 2015.
We are currently discussing the extension of existing agreements or entering
into new long-term agreements with some of these customers, but we cannot
assure you that these negotiations will be successful

or that those customers will continue to purchase coal from us without long-
term coal supply agreements. If a number of these customers were to
significantly reduce their purchases of coal from us, or if we were unable to
sell coal to them on terms as favorable to us as the terms under our current
agreements, our financial condition and results of operations could suffer
materially.

Our financial performance could be adversely affected by our substantial debt.

Our financial performance could be affected by our substantial indebtedness.
As of March 31, 2001, on a pro forma basis after giving effect to this offering
and the use of proceeds, we would have had total indebtedness of $1,040.6
million. On the same pro forma basis, we would have had stockholders' equity of
$998.0 million. In addition, upon the consummation of this offering, we will
have total borrowing capacity under our and Black Beauty's revolving credit
facilities of $470.0 million. We may also incur additional indebtedness in the
future.

Our ability to pay principal and interest on our debt depends upon the
operating performance of our subsidiaries, which will be affected by, among
other things, prevailing economic conditions in the markets they serve, some of
which are beyond our control. We cannot assure you that our business will
generate sufficient cash flow from operations or that future borrowings will be
available under our revolving credit facilities or otherwise in an amount
sufficient to enable us to service our indebtedness or to fund our other
liquidity needs.

The degree to which we are leveraged could have important consequences to
you, including, but not limited to: (1) making it more difficult for us to pay
dividends and satisfy our debt obligations; (2) increasing our vulnerability to
general adverse economic and industry conditions; (3) requiring the dedication
of a substantial portion of our cash flow from operations to the payment of
principal of, and interest on, our indebtedness, thereby reducing the
availability of the cash flow to fund working capital, capital expenditures,
research and development or other general corporate uses; (4) limiting our
ability to obtain additional financing to fund future working capital, capital
expenditures, research and development or other general corporate requirements;
(5) limiting our flexibility in planning for, or reacting to, changes in our
business; and (6) placing us at a competitive disadvantage compared to less
leveraged competitors. In addition, our indebtedness subjects us to financial
and other restrictive covenants. Failure by us to comply with these covenants
could result in an event of default which, if not cured or waived, could have a
material adverse effect on us. Furthermore, substantially all of our assets
secure our indebtedness under our senior credit facility.

If transportation for our coal becomes unavailable or uneconomic for our
customers, our ability to sell coal would suffer.

Transportation costs represent a significant portion of the total cost of
coal, and as a result, the cost of transportation is a critical factor in a
customer's purchasing decision. Increases in transportation costs could make
coal a less competitive source of energy or could make some of our operations
less competitive than other sources of coal. Certain coal supply agreements
permit the customer to terminate the contract if the cost of transportation
increases by an amount ranging from 10% to 20% in any given 12-month period.

Coal producers depend upon rail, barge, trucking, overland conveyor and
other systems to deliver coal to markets. While U.S. coal customers typically
arrange and pay for transportation of coal from the mine to the point
of use, disruption of these transportation services because of weather-related
problems, strikes, lock-outs or other events could temporarily impair our
ability to supply coal to our customers and thus could adversely affect our
results of operations. For example, the high volume of coal shipped from all
Southern Powder River Basin mines could create temporary congestion on the rail
systems servicing that region.

Risks inherent to mining could increase the cost of operating our business.

Our mining operations are subject to conditions beyond our control that can
delay coal deliveries or increase the cost of mining at particular mines for
varying lengths of time. These conditions include weather and natural
disasters, unexpected maintenance problems, key equipment failures, variations
in coal seam thickness, variations in the amount of rock and soil overlying the
coal deposit, variations in rock and other natural materials and variations in
geologic conditions.

The government extensively regulates our mining operations, which imposes
significant costs on us, and future regulations could increase those costs or
limit our ability to produce coal.

General

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.

Mine Safety and Health

Stringent safety and health standards have been in effect since Congress
enacted the Coal Mine Safety and Health 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 safety
and health affecting any segment of U.S. industry.

Black Lung

The Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits
Reform Act of 1977, as amended in 1981, require each coal mine operator to
secure payment of federal black lung benefits to claimants who are current and
former employees and to a trust fund for the payment of benefits and medical
expenses to claimants who last worked in the coal industry prior to July 1973.
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.

Coal Industry Retiree Health Benefit Act of 1992

Congress enacted the Coal Industry Retiree Health Benefit Act of 1992, also
known as the Coal Act, to provide for the funding of health benefits for
certain United Mine Workers of America retirees. The Coal Act established the
Combined Fund into which "signatory operators" and "related persons" are
obligated to pay annual premiums for beneficiaries. The Coal Act also created a
second benefit fund for miners who retired between July 1992 and September 1994
and whose former employers are no longer in business. Companies that are liable
under the Coal Act must pay premiums to the Combined Fund. Payments made by our
subsidiaries under the Coal Act totaled $4.1 million during fiscal year 2001.

Environmental Laws

We are subject to various federal and state environmental laws. These laws
require approval of many aspects of coal mining operations, and both federal
and state inspectors regularly visit our mines and other facilities to ensure
compliance.

Surface Mining Control and Reclamation Act. The Surface Mining Control and
Reclamation Act establishes mining and reclamation standards for all aspects of
surface mining, as well as many aspects of deep mining. The Surface Mining
Control and Reclamation Act and similar state statutes require operators, among
other things, to restore mined property in accordance with specified standards
and an approved reclamation plan. In addition, the Abandoned Mine Land Fund,
which is part of the Surface Mining Control and Reclamation Act, imposes a fee
on all current mining operations, the proceeds of which are used to restore
mines closed before 1977. The maximum tax is $0.35 per ton on surface-mined
coal and $0.15 per ton on deep-mined coal. The Surface Mining Control and
Reclamation Act also requires operators to meet comprehensive environmental
protection and reclamation standards during the course of, and upon completion
of, mining activities. A mine operator must submit a bond or otherwise secure
the performance of these reclamation obligations. Mine operators must receive
permits and permit renewals for surface mining operations from the Office of
Surface Mining Reclamation and Enforcement or, where state regulatory agencies
have adopted federally approved state programs under the act, the appropriate
state regulatory authority.

All states in which we have active mining operations have achieved primary
control of enforcement through approved state programs. Mining companies must
obtain numerous permits that strictly regulate environmental, health and safety
matters in connection with coal mining. Regulatory authorities exercise
considerable discretion in the timing of permit issuance. Also, private
individuals and the public at large have the right to comment on and otherwise
engage in the permitting process, including through intervention in the courts.
We cannot assure you that our permits will be renewed or granted in the future
or that permit issues will not adversely affect our operations.

As of March 31, 2001, our accruals relating to long-term reclamation costs,
mine-closing costs and other related liabilities totaled approximately $451.3
million. We incurred $4.1 million of operating expenses for the liability for
fiscal year 2001 and incurred related cash expense of $39.0 million.

The Clean Air Act. The Clean Air Act, the Clean Air Act Amendments and the
corresponding state laws that regulate the emissions of materials into the air
affect coal mining operations both directly and indirectly. The Clean Air Act's
permitting requirements and emission control requirements relating to
particulate matter, such as fugitive dust, including future regulation of fine
particulate matter, can directly affect coal mining and processing operations.
The Clean Air Act also indirectly affects coal mining operations by extensively
regulating the air emissions of sulfur dioxide and other compounds, including
nitrogen oxides, emitted by coal-based electric generating plants.

In July 1997, the Environmental Protection Agency, or EPA, adopted new, more
stringent National Ambient Air Quality Standards for very fine particulate
matter and ozone. 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, and could have a material adverse effect on
our financial condition and results of operations.

The Clean Air Act Amendments also require electricity generators that are
major sources of nitrogen oxide emissions in moderate or higher ozone non-
attainment areas to install reasonably available control technology for
nitrogen oxides, which are precursors of ozone. In addition, the EPA recently
announced final rules that would require 19 eastern states and Washington, D.C.
to make substantial reductions in nitrogen oxide emissions. Installation of
additional control measures required under those rules will make it more costly
to operate coal-based electric generating plants.

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. Future regulatory activity
may seek to reduce mercury emissions and these requirements, if enacted, could
result in reduced use of coal if electricity generators switch to other sources
of fuel.

Clean Water Act. The Clean Water Act of 1972 affects coal mining operations
by imposing restrictions on effluent discharge into water. Regular monitoring,
reporting requirements and performance standards are preconditions for the
issuance and renewal of permits governing the discharge of pollutants into
water.

Resource Conservation and Recovery Act. The Resource Conservation and
Recovery Act, or RCRA, which Congress enacted in 1976, affects coal mining
operations by imposing requirements for the treatment, storage and disposal of
hazardous wastes. Coal mining operations covered by the Surface Mining Control
and Reclamation Act permits are exempted from regulation under RCRA by statute.
We cannot, however, predict whether this exclusion will continue.

RCRA excludes certain large-volume wastes generated primarily from the
combustion of coal from being regulated as a hazardous waste pending a report
to Congress and a decision by the EPA either to regulate the coal combustion
wastes as a hazardous waste under RCRA or deem the regulation as unwarranted.
The EPA made its report to Congress in March 1999 and determined in May 2000
not to regulate coal wastes as a hazardous substance under RCRA. New
legislation that would regulate coal combustion waste as a hazardous waste
could cause a switch to other lower-ash fuels and reduce the amount of coal
used by electricity generators.

Federal and State Superfund Statutes. The Comprehensive Environmental
Response Compensation and Liability Act, or Superfund, and similar state laws
affect coal mining and hard rock operations by creating liability for
investigation and remediation in response to releases of hazardous substances
into the environment and for damages to natural resources. Under Superfund,
joint and several liability may be imposed on waste generators, site owners and
operators and others regardless of fault.

Environmental claims have been asserted against us at 18 sites in the United
States. Some of these claims are based on Superfund and on similar state
statutes. These claims are related to non-coal activities of our former
subsidiaries. We had an accrued liability of $48.0 million as of March 31, 2001
for these environmental claims. Our results of operations may be adversely
affected by the remediation costs at these or other sites, and our accrued
liability may not be adequate for these remediation costs.

Global Climate Change. The United States and over 160 other nations are
signatories to the 1992 Framework Convention on Climate Change, which is
intended to limit emissions of greenhouse gases, such as carbon dioxide. In
December 1997, in Kyoto, Japan, the signatories to the convention established a
binding set of emission targets for developed nations. Although the specific
emission targets vary from country to country, the United States would be
required to reduce emissions to 93% of 1990 levels over a five-year budget
period from 2008 through 2012. Although the United States has not ratified the
emission targets and no comprehensive regulations focusing on greenhouse gas
emissions are in place, these restrictions, whether through ratification of the
emission targets or other efforts to stabilize or reduce greenhouse gas
emissions, could adversely impact the price and demand for coal. According to
the Energy Information Administration's Emissions of Greenhouse Gases in the
United States 1999, coal accounts for 30% of greenhouse gas emissions in the
United States, and efforts to control greenhouse gas emissions could result in
reduced use of coal if electricity generators switch to sources of fuel with
lower carbon dioxide emissions.

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 $1,036.1 million as of March 31, 2001, of which
$62.0 million was a current liability. We have estimated these unfunded
obligations based on assumptions described in Note 14 to our audited financial
statements contained in this prospectus. If our assumptions do not materialize
as expected, cash expenditures and costs that we incur could be materially
higher. Moreover, we cannot assure you that regulatory changes will not
increase our obligations to provide these or additional benefits.

We are party to an agreement with the Pension Benefit Guaranty Corporation,
or the PBGC, and TXU Europe Limited, an affiliate of our former parent
corporation, under which we are required to make specified contributions to
three of our defined benefit pension plans and to maintain a $37.0 million
letter of credit in favor of the PBGC. If we or the PBGC gives notice of an
intent to terminate one or more of the covered pension plans in which
liabilities are not fully funded, or if we fail to maintain the letter of
credit, the PBGC may draw down on the letter of credit and use the proceeds to
satisfy liabilities under the Employee Retirement Income Security Act of 1974,
as amended. The PBGC, however, is required to first apply amounts received from
a $110.0 million guaranty in place from TXU Europe Limited in favor of the PBGC
before it draws on our letter of credit.

Our future success depends upon our ability to continue acquiring and
developing coal reserves that are economically recoverable.

Our recoverable reserves decline as we produce coal. We have not yet applied
for the permits required or developed the mines necessary to use all of our
reserves. Furthermore, we may not be able to mine all of our reserves as
profitably as we do at our current operations. Our future success depends upon
our conducting successful exploration and development activities or acquiring
properties containing economically recoverable reserves. Our current strategy
includes increasing our reserve base through acquisitions of government and
other leases and producing properties and continuing to use our existing
properties. The federal government also leases natural gas and coalbed methane
reserves in the west, including in the Powder River Basin. Some of these
natural gas and coalbed methane reserves are located on, or adjacent to, some
of our Powder River Basin reserves, potentially creating conflicting interests
between us and lessees of those interests. Other lessees' rights relating to
these mineral interests could prevent, delay or increase the cost of developing
our coal reserves. These lessees may also seek damages from us based on claims
that our coal mining operations impair their interests. Additionally, the
federal government limits the amount of federal land that may be leased by any
company to 150,000 acres nationwide. We currently lease or have applied to
lease a total of 64,805 acres from the federal government. The limit could
restrict our ability to lease additional federal lands.

We cannot assure you that our planned development and exploration projects
and acquisition activities will result in significant additional reserves or
that we will have continuing success developing additional mines. Most of our
mining operations are conducted on properties owned or leased by us. Because
title to most of our leased properties and mineral rights are not thoroughly
verified until a permit to mine the property is obtained, our right to mine
some of our reserves may be materially adversely affected if defects in title
or boundaries exist. In addition, in order to develop our reserves, we must
receive various governmental permits, as discussed in "Regulatory Matters"
below. We cannot predict whether we will continue to receive the permits
necessary for us to operate profitably in the future. We may not be able to
negotiate new leases from the government or from private parties or obtain
mining contracts for properties containing additional reserves or maintain our
leasehold interest in properties on which mining operations are not commenced
during the term of the lease. From time to time, we have experienced litigation
with lessors of our coal properties and with royalty holders.

If the coal industry experiences overcapacity in the future, our profitability
could be impaired.

During the mid-1970s and early 1980s, a growing coal market and increased
demand for coal attracted new investors to the coal industry, spurred the
development of new mines and resulted in added production capacity throughout
the industry, all of which led to increased competition and lower coal prices.
Recent increases in coal prices could similarly encourage the development of
expanded capacity by new or existing coal producers. Any overcapacity could
reduce coal prices in the future.

Our operating expenses could increase significantly if the price of fuel
increases.

Operating expenses at our mining locations are sensitive to changes in fuel
prices, particularly diesel fuel prices. We used 80.2 million gallons of diesel
fuel in fiscal year 2001, and our overall fuel expense was 41% higher
($24.2 million) than in fiscal year 2000. If fuel prices continue to increase,
our operating expenses could increase significantly.

Our financial condition could be negatively affected if we fail to maintain
satisfactory labor relations.

As of March 31, 2001, the United Mine Workers of America represented
approximately 37% of our employees, who produced 23% of our coal sales volume
in the United States during fiscal year 2001. Because of the higher labor costs
and the increased risk of strikes and other work-related stoppages that may be
associated with union operations in the coal industry, our non-unionized
competitors may have a competitive advantage in areas where they compete with
our unionized operations. If some or all of our current non-union operations
were to become unionized, we could incur an increased risk of work stoppages,
reduced productivity and higher labor costs. The ten-month United Mine Workers
of America strike in 1993 had a material adverse effect on us. Two of our
subsidiaries, Peabody Coal Company and Eastern Associated Coal Corp., operate
under a union contract that is in effect through December 31, 2002. The United
Mine Workers of America has indicated an interest in seeking early negotiations
for a new contract, although none of the parties are required to do so. Peabody
Western Coal Company operates under a union contract that is in effect through
September 1, 2005.

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 and to
satisfy other miscellaneous obligations. As of March 31, 2001, we had
outstanding surety bonds with third parties for post-mining reclamation
totaling $651.8 million. Furthermore, we have an additional $77.4 million of
surety bonds in place for our federal and state workers' compensation
obligations and other miscellaneous obligations. These bonds are typically
renewable on a yearly basis. We cannot assure you that surety bond issuers and
holders will continue to renew the bonds or refrain from demanding additional
collateral upon those renewals. Our failure to maintain, or inability to
acquire, surety bonds that are required by state and federal law would have a
material adverse effect on us. That failure could result from a variety of
factors including the following:

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

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

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

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 be special
purpose entities with credit ratings that are below investment grade.

One of our customers, Southern California Edison Company, had its credit
rating downgraded to non-investment grade as a result of the recent electricity
crisis in California. Southern California Edison, which owns 56% of the Mohave
Generating Station, and the other owners of the Mohave Generating Station have
a coal supply agreement that expires in 2005. In fiscal year 2001, we sold 4.8
million tons of coal to the Mohave Generating Station. The owners of the Mohave
Generating Station created a trust account in early 2001 to fund the payment of
coal under the coal supply agreement and have advised us of their obligation,
subject to certain

conditions, to cure any defaults of another owner. Our ability to continue to
receive payment from the Mohave Generating Station depends, in part, on the
creditworthiness of Southern California Edison. Failure to receive payment for
Southern California Edison's share of the Mohave Generating Station deliveries
could adversely affect our financial condition and results of operations. If
the creditworthiness of California utilities causes a general deterioration of
the creditworthiness of other utilities, our accounts receivable securitization
program could be adversely affected. On April 6, 2001, Pacific Gas and Electric
Company filed for Chapter 11 reorganization. We do not have any coal supply
agreements with that utility.

Lehman Brothers Merchant Banking controls us and may have conflicts of interest
with other stockholders in the future.

After the offering, Lehman Brothers Merchant Banking and its affiliates will
beneficially own 59% of our common stock, or 57% if the underwriters exercise
their over-allotment option in full. As a result, Lehman Brothers Merchant
Banking will continue to be able to control the election of our directors and
determine our corporate and management policies, including potential mergers or
acquisitions, asset sales and other significant corporate transactions. We
cannot assure you that the interests of Lehman Brothers Merchant Banking will
coincide with the interests of other holders of our common stock. We have
retained affiliates of Lehman Brothers Merchant Banking to perform advisory
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 in "Management" elsewhere in this prospectus, the
loss of a number of whom could have a material adverse effect on us. In
addition, as our business develops and expands, we believe that our future
success will depend greatly on our continued ability to attract and retain
highly skilled and qualified personnel. We cannot assure you that key personnel
will continue to be employed by us or that we will be able to attract and
retain qualified personnel in the future. We do not have "key person" life
insurance to cover our executive officers. Failure to retain or attract key
personnel could have a material adverse effect on us.

Risks Related To This Offering

There is no existing market for our common stock, and we do not know if one
will develop to provide you with adequate liquidity.

There has not been a public market for our common stock. We cannot predict
the extent to which investor interest in our company will lead to the
development of a trading market on the New York Stock Exchange or otherwise or
how liquid that market might become. The initial public offering price for the
shares was determined by negotiations between us and the representatives of the
underwriters and may not be indicative of prices that will prevail in the open
market following this offering.

If we or our existing stockholders sell additional shares of our common stock
after the offering, the market price of our common stock could decline.

The market price of our common stock could decline as a result of sales of a
large number of shares of common stock in the market after the offering or the
perception that such sales could occur. These sales, or the possibility that
these sales may occur, also might make it more difficult for us to sell equity
securities in the future at a time and at a price that we deem appropriate.

Sales of our common stock are restricted by lock-up agreements that our
directors, officers and all of our existing stockholders have entered into with
the underwriters and with us. The lock-up agreements restrict our directors,
officers and existing stockholders, subject to specified exceptions, from
selling or otherwise disposing of any shares for a period of 180 days after the
date of this prospectus without the prior written consent of

Lehman Brothers Inc. Lehman Brothers Inc. may, however, in its sole discretion
and without notice, release all or any portion of the shares from the
restrictions in the lock-up agreements.

After this offering, we will have approximately 49.6 million shares of
common stock outstanding. Of those shares, the 15.0 million shares we are
offering will be freely tradeable. The approximately 34.6 million shares that
were outstanding immediately prior to this offering will be eligible for resale
from time to time after the expiration of the 180-day lock-up period, subject
to contractual and Securities Act restrictions. Four million four hundred
thousand of those shares may be resold under Rule 144(k) without regard to
volume limitations and approximately 30.2 million shares may be sold subject to
the volume, manner of sale and other conditions of Rule 144. Lehman Brothers
Merchant Banking and its affiliates, which collectively own 29.4 million
shares, will have the ability to cause us to register the resale of its shares.

In addition, approximately 5.2 million shares are issuable upon the exercise
of presently outstanding stock options under our 1998 Stock Purchase and Option
Plan and approximately 2.5 million shares have been reserved for future
issuance under our Long-Term Equity Incentive Plan. Shares acquired upon the
exercise of vested options under our 1998 Stock Purchase and Option Plan for
Key Employees will first become eligible for resale on the second anniversary
of this offering. We also expect that any awards that will be granted under our
Long-Term Equity Incentive Plan will not begin to vest until at least one year
after the date of this offering. Within one year of this offering, we intend to
file a registration statement to register the sale of shares issuable upon the
exercise of all these stock options.

The book value of shares of common stock purchased in the offering will be
immediately diluted.

Investors who purchase common stock in the offering will suffer immediate
dilution of $9.50 per share in the pro forma as adjusted net tangible book
value per share. We also have a large number of outstanding stock options to
purchase common stock with exercise prices that are below the estimated initial
public offering price of the common stock. To the extent that these options are
exercised, there will be further dilution.

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 which could make it more difficult for stockholders to effect
certain corporate actions. 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.

CAUTIONARY NOTICE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes statements of our expectations, intentions, plans
and beliefs that constitute "forward-looking statements." These statements can
be found in "Prospectus Summary," "Management's Discussion and Analysis of
Financial Condition and Results of Operations," "Coal Industry Overview,"
"Business" and "Regulatory Matters," and can often be identified by forward-
looking words such as "expect," "anticipate," "believe," "goal," "plan,"
"intend," "estimate," "may" and "will" or similar words. You should be aware
that these statements are subject to known and unknown risks, uncertainties and
other factors, including those discussed in "Risk Factors," that could cause
actual results to differ materially from those suggested by the forward-looking
statements.

USE OF PROCEEDS

We will receive net proceeds from this offering of approximately $393.0
million, assuming no exercise of the underwriters' over-allotment option. We
intend to use approximately $125.0 million of the net proceeds to permanently
repay the tranche B term loan under our senior credit facility and $100.0
million to repay borrowings under our revolving credit facility. We borrowed
this $100.0 million on May 2, 2001 in order to repay a portion of our 5%
subordinated note, which matures in 2007. On May 8, 2001, we commenced an offer
to repurchase up to $80 million of our 8 7/8% senior notes due 2008 and up to
$80 million of our 9 5/8% senior subordinated notes due 2008 using the
remaining $168.0 million of proceeds.

As of March 31, 2001, the tranche B term loan accrued interest at an annual
rate of 7.19%, and is due to mature on June 30, 2006. Lehman Commercial Paper
Inc., an affiliate of Lehman Brothers Merchant Banking and Lehman Brothers
Inc., one of the underwriters of this offering, is a lender under our senior
credit facility and will receive a portion of the proceeds from the repayment
of the term loan.

DIVIDEND POLICY

We currently intend to declare and pay quarterly dividends of $0.10 per
share. The declaration and payment of dividends and the amount of dividends
will depend on our results of operations, financial condition, cash
requirements, future prospects, any limitations imposed by our debt instruments
and other factors deemed relevant by our board of directors. Our senior credit
facility, as amended, allows us to pay dividends of $25.0 million in fiscal
year 2002 and annual dividends in subsequent fiscal years equal to the greater
of $25.0 million or 10% of consolidated EBITDA as defined in the facility. The
indentures governing our senior notes and senior subordinated notes permit us
to pay annual dividends equal to 6% of our net proceeds from this offering,
plus additional amounts based on financial tests, although the actual amount of
any dividends will be determined by our board of directors.

CAPITALIZATION

The following table presents our capitalization as of March 31, 2001 (1) on
an actual basis and (2) on a pro forma as adjusted basis to reflect:

. the conversion of our Class A common stock and Class B common stock and
the exchange and conversion of our preferred stock into a single class
of common stock, all on a one-for-one basis upon the completion of this
offering;

. the sale of 15.0 million shares of our common stock in this offering at
the public offering price of $28.00 per share, net of estimated offering
expenses of $27.0 million; and

. the repayment of long-term debt of $365.0 million from the proceeds of
this offering.

You should read this table in conjunction with our financial statements and
the notes to those statements appearing elsewhere in this prospectus and
"Selected Financial Data," "Unaudited Pro Forma Condensed Financial
Information" and "Management's Discussion and Analysis of Financial Conditions
and Results of Operations."

As of March 31, 2001
-------------------------------------
Pro Forma
Actual Adjustments As Adjusted
-------- ----------- -----------
(Unaudited; in
millions)

Cash and cash equivalents............... $ 62.7 $ -- $ 62.7
======== ======= ========
Senior credit facility:
Revolving credit facility(/1/)........ $ -- $ -- $ --
Term loan facility.................... 125.0 (125.0) --
8 7/8% senior notes due 2008............ 399.1 (78.0) 321.1
9 5/8% senior subordinated notes due
2008................................... 498.9 (77.0) 421.9
Indebtedness of Black Beauty
subsidiary(/2/)........................ 211.0 -- 211.0
5% subordinated note(/3/)............... 169.9 (85.0) 84.9
Other long-term debt.................... 1.7 -- 1.7
-------- ------- --------
Total debt.......................... 1,405.6 (365.0) 1,040.6
Stockholders' equity:
Preferred stock....................... 0.1 (0.1) --
Class A common stock(/4/)............. 0.2 (0.2) --
Class B common stock.................. -- -- --
Common stock.......................... -- 0.3 0.3
-------- ------- --------
Total preferred and common stock.... 0.3 -- 0.3
Additional paid-in capital............ 498.2 393.0 891.2
Employee stock loans.................. (2.6) -- (2.6)
Accumulated other comprehensive loss.. (0.9) -- (0.9)
Retained earnings..................... 136.3 (26.2)(/5/) 110.1
Treasury stock........................ (0.1) -- (0.1)
-------- ------- --------
Total stockholders' equity.......... 631.2 366.8 998.0
-------- ------- --------
Total capitalization.............. $2,036.8 $ 1.8 $2,038.6
======== ======= ========

--------
(1) The revolving credit facility currently provides for maximum aggregate
borrowings of $200.0 million and letters of credit of up to $280.0 million.
Upon the consummation of this offering, the maximum aggregate borrowings
available under the revolving credit facility will increase from $200.0
million to $350.0 million. As of March 31, 2001, we had no loans
outstanding and letters of credit of $73.4 million outstanding under our
revolving credit facility. We borrowed $100.0 million under our revolving
credit facility on May 2, 2001 to fund the repurchase of a portion of our
5% subordinated note. We will repay those borrowings using proceeds from
this offering.
(2) A maximum of $120.0 million is available for borrowing under Black Beauty's
revolving credit facility. Black Beauty had $70.0 million of loans
outstanding under the revolving credit facility as of March 31, 2001.
(3) On May 2, 2001, we repaid $85.0 million carrying amount of the 5%
subordinated note. We funded this repayment with borrowings of $100.0
million under our revolving credit facility, which we will repay using
proceeds from this offering.
(4) The amount does not include 5,638,920 shares of common stock that have been
reserved for issuance under our 1998 stock purchase and option plan, under
which options for 5,225,510 shares were outstanding as of March 31, 2001.
(5) The amount reflects the after-tax impact of the write-off of a portion of
the debt issuance costs and the extraordinary item related to the early
extinguishment of long-term debt.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of
the common stock to be sold in this offering will exceed the net tangible book
value per share of common stock after the offering. Our pro forma net tangible
book value, after giving effect to the conversion of our Class A common stock
and Class B common stock and the exchange and conversion of our preferred stock
into a single class of common stock, all on a one-for-one basis, as of March
31, 2001, was $550.8 million, or $15.91 per share of outstanding common stock.
Pro forma net tangible book value per share is equal to the amount of our total
tangible assets (total assets less intangible assets) less total liabilities,
divided by the number of shares of our common stock outstanding as of March 31,
2001. After giving effect to the sale of the shares we are offering by this
prospectus at an initial public offering price of $28.00 per share and after
deducting underwriting discounts and the estimated offering expenses payable,
our pro forma as adjusted net tangible book value as of March 31, 2001 would
have been $917.6 million, or $18.50 per share of common stock. This represents
an immediate increase in net tangible book value of $2.59 per share to existing
stockholders and an immediate dilution in net tangible book value of $9.50 per
share to new investors. The following table illustrates this per share
dilution:

Per share
---------

Initial public offering price per share....................... $28.00
Pro forma net tangible book value per share before this
offering................................................... $15.91
Increase per share attributable to this offering............ 2.59
------
Adjusted pro forma net tangible book value per share after the
offering..................................................... 18.50
------
Dilution per share to new investors .......................... $ 9.50
======

The following table summarizes, on a pro forma as adjusted basis as of March
31, 2001, the total number of shares of common stock purchased from us, the
total consideration paid to us and the average price per share paid by existing
stockholders and by new investors purchasing shares in this offering:

Shares Purchased Total Consideration Average
------------------ -------------------- Price Per
Number Percent Amount Percent Share
---------- ------- ------------ ------- ---------

Existing stockholders......... 34,610,509 69.76% $495,162,602 54.11% $14.31
New investors ................ 15,000,000 30.24 420,000,000 45.89 28.00
---------- ------ ------------ ------
Total....................... 49,610,509 100.00% $915,162,602 100.00%
========== ====== ============ ======

The tables and calculations above assume no exercise of outstanding options.
As of March 31, 2001, there were 5,225,510 shares of our common stock reserved
for issuance upon exercise of outstanding options at an exercise price of
$14.29 per share. To the extent that these options are exercised, there will be
further dilution to new investors. See "Management--Stock Purchase and Option
Plan" and "Description of Capital Stock."

UNAUDITED PRO FORMA CONDENSED FINANCIAL INFORMATION

The following unaudited pro forma condensed financial statements are based
on the historical presentation of our consolidated financial statements. The
unaudited pro forma condensed statement of operations for the year ended March
31, 2001 gives effect to:

. the repayment of long-term debt of $105.0 million from the proceeds from
the sale of Citizens Power as if it had occurred on April 1, 2000; and

. the repayment of long-term debt of $365.0 million from the proceeds of
this offering as if it had occurred on April 1, 2000.

The unaudited pro forma condensed balance sheet gives effect to:

. the conversion of our Class A common stock and Class B common stock and
the exchange and conversion of our preferred stock into a single class
of common stock, all on a one-for-one basis upon the completion of the
offering as if they had occurred on March 31, 2001;

. the sale of 15.0 million shares of our common stock in this offering at
the public offering price of $28.00 per share as if it had occurred on
March 31, 2001; and

. the repayment of long-term debt of $365.0 million from the proceeds of
this offering as if it had occurred on March 31, 2001.

The unaudited pro forma condensed financial statements do not include
approximately $0.8 million of compensation cost related to stock options that
will vest upon completion of this offering.

The unaudited pro forma condensed financial statements are intended for
informational purposes only and do not purport to be indicative of the results
that actually would have been obtained during the period presented and are not
necessarily indicative of operating results to be expected in future periods.
You should read the unaudited pro forma condensed financial statements and
related notes in conjunction with the financial statements and the related
notes to those statements appearing elsewhere in this prospectus and the
information under "Selected Financial Data" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations."

Unaudited Pro Forma Condensed Statement of Operations

Year Ended March 31, 2001

Australian Pro Forma
Historical Operations(/1/) Adjustments As Adjusted
----------- --------------- ----------- -----------
(Dollars in thousands, except per share data)

Revenues:
Sales................. $ 2,579,104 $(190,202) $ -- $ 2,388,902
Other revenues........ 90,588 (48,296) -- 42,292
----------- --------- ----------- -----------
Total revenues...... 2,669,692 (238,498) -- 2,431,194
Costs and expenses:
Operating costs and
expenses............. 2,165,090 (159,100) -- 2,005,990
Depreciation,
depletion and
amortization......... 240,968 (25,518) -- 215,450
Selling and
administrative
expenses............. 99,267 (1,458) -- 97,809
Gain on sale of
Australian
operations........... (171,735) -- 171,735 (/1/) --
Net gain on property
and equipment
disposals............ (5,737) 955 -- (4,782)
----------- --------- ----------- -----------
Operating profit........ 341,839 (53,377) (171,735) 116,727
Interest expense...... 197,686 (6,446) (75,941)(/3/) 115,299
Interest income....... (8,741) 779 -- (7,962)
----------- --------- ----------- -----------
Income before income
taxes and minority
interests.............. 152,894 (47,710) (95,794) 9,390
Income tax provision
(benefit)............ 42,690 (18,111) (28,506)(/4/) (3,927)
Minority interests.... 7,524 -- -- 7,524
----------- --------- ----------- -----------
Income from continuing
operations............. $ 102,680 $ (29,599) $ (67,288) $ 5,793
=========== ========= =========== ===========
Basic and diluted
earnings per Class A/B
share from continuing
operations............. $ 2.97 $ 0.12
Weighted average shares
used in calculating
basic and diluted
earnings per Class A/B
share.................. 27,524,626 22,000,000 (/5/) 49,524,626
Other data:
Adjusted EBITDA(/2/).. $ 582,807 $ (78,895) $ (171,735) $ 332,177
Capital expenditures.. 187,060 (35,702) -- 151,358

See accompanying notes to unaudited pro forma condensed financial statements.

Unaudited Pro Forma Condensed Balance Sheet

As of March 31, 2001

Pro Forma
As
Historical Adjustments Adjusted
---------- ----------- ----------
(Dollars in thousands)

ASSETS
Current assets
Cash and cash equivalents............. $ 62,723 $ -- $ 62,723
Accounts receivable, net.............. 147,808 -- 147,808
Materials and supplies................ 38,733 -- 38,733
Coal inventory........................ 171,479 -- 171,479
Assets from coal and emission
allowance trading activities......... 172,330 -- 172,330
Deferred income taxes................. 12,226 -- 12,226
Other current assets.................. 24,656 -- 24,656
---------- --------- ----------
Total current assets................ 629,955 -- 629,955
Property, plant, equipment and mine
development, net....................... 4,322,639 -- 4,322,639
Investments and other assets............ 256,893 (7,000)(/6/) 249,893
---------- --------- ----------
Total assets........................ $5,209,487 $ (7,000) $5,202,487
========== ========= ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Short-term borrowings and current
maturities of long-term debt......... $ 36,305 $ -- $ 36,305
Income taxes payable.................. 491 -- 491
Liabilities from coal and emission
allowance trading activities......... 163,713 -- 163,713
Accounts payable and accrued
expenses............................. 576,476 -- 576,476
---------- --------- ----------
Total current liabilities........... 776,985 -- 776,985
Long-term debt, less current
maturities............................. 1,369,316 (365,000)(/7/) 1,004,316
Deferred income taxes................... 570,705 (8,750)(/8/) 561,955
Accrued reclamation and other
environmental liabilities.............. 447,713 -- 447,713
Workers' compensation obligations....... 210,780 -- 210,780
Accrued postretirement benefit costs.... 974,079 -- 974,079
Obligation to industry fund............. 52,172 -- 52,172
Other noncurrent liabilities............ 135,041 -- 135,041
---------- --------- ----------
Total liabilities................... 4,536,791 (373,750) 4,163,041
Minority interests...................... 41,458 -- 41,458
Stockholders' equity.................... 631,238 366,750 (/9/) 997,988
---------- --------- ----------
Total liabilities and stockholders'
equity............................. $5,209,487 $ (7,000) $5,202,487
========== ========= ==========

See accompanying notes to unaudited pro forma condensed financial statements.

Notes to Unaudited Pro Forma Condensed Financial Statements

(1) Represents the elimination of the historical accounts and the gain on
the sale of our Australian operations for fiscal year 2001.

(2) 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 we believe it is a useful indicator of our
ability to meet our 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.

(3) Represents the elimination of interest expense for the period, assuming
the following transactions occurred effective April 1, 2000:

. $440.0 million of net proceeds from the sale of the Australian operations
are used to repay a portion of the term loans outstanding under the
senior credit facility;

. $105.0 million of the proceeds from the sale of Citizens Power are used
to repay a portion of the term loans outstanding under the senior credit
facility;

. The net proceeds of $393.0 million from this offering are used to repay
the remaining $125.0 million of the term loans outstanding under the
senior credit facility, $85.0 million of our 5% subordinated note, $78.0
million of our senior notes and $77.0 million of our senior subordinated
notes; and

. $7.0 million of debt issuance costs are eliminated related to the early
extinguishment of debt, resulting in reduced amortization of debt
issuance costs.

The interest expense adjustment was calculated using the average interest
rate on term loans outstanding under our senior credit facility during the
periods presented, the imputed rate on the 5% subordinated note, and the stated
rates on the senior notes and the senior subordinated notes.

(4) Represents the net adjustment to income tax expense that is calculated
by applying the pro forma effective tax rate of 25% to the pro forma interest
expense adjustment and eliminating the $47.5 million tax provision related to
the sale of our Australian operations.

(5) Represents the exchange and conversion of our preferred shares into
common shares and the increase in common shares from this offering as if they
had occurred on April 1, 2000.

(6) Represents the write-off of a portion of debt issuance costs associated
with our senior credit facility, senior notes and senior subordinated notes,
resulting from the accelerated debt repayment. That write-off will be recorded
as an extraordinary item in the period in which we repay that debt.

(7) Represents the repayment of $125.0 million of term loans outstanding
under our senior credit facility, $85.0 million of our 5% subordinated note,
$78.0 million of our senior notes and $77.0 million of our senior subordinated
notes.

(8) Represents the reduction of deferred income taxes as a result of the
write-off of $7.0 million of debt issuance costs and a $28.0 million loss
related to the early extinguishment of our 5% subordinated note, our senior
notes and senior subordinated notes. This amount is calculated by applying the
pro forma effective tax rate of 25% to the $7.0 million adjustment and the
$28.0 million extraordinary item.

(9) Reflects the projected net increase in equity resulting from the $393.0
million of net proceeds from this offering, net of an after-tax extraordinary
loss of $26.2 million related to the early extinguishment of the remaining
$125.0 million of term loans outstanding under our senior credit facility,
$85.0 million of our 5% subordinated note, $78.0 million of our senior notes
and $77.0 million of our senior subordinated notes.

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 anticipation of the sale of Citizens Power, which occurred in August
2000, we classified Citizens Power as a discontinued operation as of March 31,
2000, and recorded an estimated loss on the sale of $78.3 million, net of
income taxes. We have adjusted our results of operations to reflect the
classification of Citizens Power as a discontinued operation for all periods
presented.

We have derived the selected historical financial data for our predecessor
for the year ended and as of September 30, 1996, the six months ended and as of
March 31, 1997, the year ended and as of March 31, 1998 and the period from
April 1, 1998 to May 19, 1998 and as of May 19, 1998, and the selected
historical financial data for our company for the period from May 20, 1998 to
March 31, 1999 and as of March 31, 1999 and the years ended and as of March 31,
2000 and 2001 from our predecessor company's and our audited financial
statements. The historical results are not necessarily indicative of our future
operating results. You should read the following table in conjunction with the
financial statements, which have been audited by Ernst & Young LLP, independent
auditors, and the notes to those statements appearing elsewhere in this
prospectus and "Management's Discussion and Analysis of Financial Condition and
Results of Operations."

(Dollars in thousands, except per share data)

Predecessor Company
-------------------------------------------------
Year Six Months May 20,
Ended Ended Year Ended April 1, 1998 to Total Year Ended Year Ended
September 30, March 31, March 31, 1998 to May March 31, Fiscal Year March 31, March 31,
1996 1997 1998 19, 1998 1999 1999(/1/) 2000(/2/) 2001(/3/)
------------- ---------- ---------- ----------- ----------- ----------- ---------- ----------

Results of Operations
Data:
Revenues:
Sales.................. $2,075,142 $1,000,419 $2,048,694 $ 278,930 $ 1,970,957 $ 2,249,887 $2,610,991 $2,579,104
Other revenues......... 118,444 63,674 169,328 11,728 85,875 97,603 99,509 90,588
---------- ---------- ---------- ----------- ----------- ----------- ---------- ----------
Total revenues....... 2,193,586 1,064,093 2,218,022 290,658 2,056,832 2,347,490 2,710,500 2,669,692
Costs and Expenses:
Operating costs and
expenses............... 1,693,543 822,938 1,695,216 244,128 1,643,718 1,887,846 2,178,664 2,165,090
Depreciation,
depletion and
amortization........... 197,853 101,730 200,169 25,516 179,182 204,698 249,782 240,968
Selling and
administrative
expenses............... 75,699 41,421 83,640 12,017 76,888 88,905 95,256 99,267
Impairment of long-
lived assets(/4/)...... 890,829 -- -- -- -- -- -- --
Gain on sale of
Australian
operations............. -- -- -- -- -- -- -- (171,735)
Net gain on property
and equipment
disposals.............. (13,042) (4,091) (21,815) (328) -- (328) (6,439) (5,737)
---------- ---------- ---------- ----------- ----------- ----------- ---------- ----------
Operating profit
(loss).................. (651,296) 102,095 260,812 9,325 157,044 166,369 193,237 341,839
Interest expense....... 62,526 24,700 33,410 4,222 176,105 180,327 205,056 197,686
Interest income........ (11,355) (8,590) (14,543) (1,667) (18,527) (20,194) (4,421) (8,741)
---------- ---------- ---------- ----------- ----------- ----------- ---------- ----------
Income (loss) before
income taxes and
minority interests...... (702,467) 85,985 241,945 6,770 (534) 6,236 (7,398) 152,894
Income tax provision
(benefit).............. (256,185) 27,553 83,050 4,530 3,012 7,542 (141,522) 42,690
Minority interests..... -- -- -- -- 1,887 1,887 15,554 7,524
---------- ---------- ---------- ----------- ----------- ----------- ---------- ----------
Income (loss) from
continuing operations... (446,282) 58,432 158,895 2,240 (5,433) (3,193) 118,570 102,680
Income (loss) from
discontinued
operations............. -- -- 1,441 (1,764) 6,442 4,678 (90,360) 12,925
---------- ---------- ---------- ----------- ----------- ----------- ---------- ----------
Income (loss) before
extraordinary item...... (446,282) 58,432 160,336 476 1,009 1,485 28,210 115,605
Extraordinary loss
from early
extinguishment of
debt................... -- -- -- -- -- -- -- (8,545)
---------- ---------- ---------- ----------- ----------- ----------- ---------- ----------
Net income (loss)....... $ (446,282) $ 58,432 $ 160,336 $ 476 $ 1,009 $ 1,485 $ 28,210 $ 107,060
========== ========== ========== =========== =========== =========== ========== ==========
Basic and diluted
earnings (loss) per
Class A/B share from
continuing operations... $ (0.16) $ 3.43 $ 2.97
Weighted average shares
used in calculating
basic and diluted
earnings (loss) per
Class A/B share......... 26,823,383 27,586,370 27,524,626
Other Data:
Tons sold (in
millions)............... 163.0 81.4 167.5 21.7 154.3 176.0 190.3 192.4
Adjusted EBITDA(/5/).... $ (453,443) $ 203,825 $ 460,981 $ 34,841 $ 336,226 $ 371,067 $ 443,019 $ 582,807
Net cash provided by
(used in):
Operating activities... 211,535 62,829 187,852 (28,157) 282,022 253,865 262,911 151,980
Investing activities... (105,640) (56,170) (136,033) (21,550) (2,249,336) (2,270,886) (185,384) 388,462
Financing activities... 15,987 94,178 (235,389) 23,537 2,161,281 2,184,818 (205,181) (543,337)
Depreciation, depletion
and amortization........ 197,853 101,730 200,169 25,516 179,182 204,698 249,782 240,968
Capital expenditures.... 152,106 76,460 165,514 20,874 174,520 195,394 178,754 187,060
Balance Sheet Data (at
period end):
Total assets............ $4,916,693 $5,025,812 $6,343,009 $ 6,406,587 $ 7,023,931 $ 7,023,931 $5,826,849 $5,209,487
Total debt.............. 456,867 321,723 602,276 633,562 2,542,379 2,542,379 2,076,166 1,405,621
Total stockholders'
equity/invested
capital................. 1,383,655 1,676,786 1,687,842 1,497,374 495,230 495,230 508,426 631,238

--------
(1) For comparative purposes, we derived the "Total Fiscal Year 1999" column by
adding the period from May 20, 1998 to March 31, 1999 with our predecessor
company results for the period from April 1, 1998 to May 19, 1998. The
effects of purchase accounting have not been reflected in the results of
our predecessor company.
(2) Results of operations for the year ended March 31, 2000 included a $144.0
million income tax benefit associated with an increase in the tax basis of
a subsidiary's assets due to a change in federal income tax regulations.
(3) Results of operations for the year ended March 31, 2001 included a $171.7
million pretax gain on the sale of our Australian operations.
(4) Results of operations for the year ended September 30, 1996 included a one-
time, non-cash charge of $890.8 million made pursuant to Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of."
(5) Adjusted EBITDA is defined as income from continuing operations before
deducting net interest expense, income taxes, minority interests and
depreciation, depletion and amortization. Adjusted EBITDA is not a
substitute for operating income, net income and cash flow from operating
activities as determined in accordance with generally accepted accounting
principles as a measure of profitability or liquidity. Adjusted EBITDA is
presented as additional information because management believes it is a
useful indicator of our ability to meet debt service and capital
expenditure requirements. Because Adjusted EBITDA is not calculated
identically by all companies, our calculation may not be comparable to
similarly titled measures of other companies.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

You should read the following discussion and analysis in conjunction with
"Selected Financial Data" and the financial statements and related notes
included elsewhere in this prospectus. The financial statements contained in
this prospectus for periods and dates prior to May 20, 1998 are of our
predecessor company.

Factors Affecting Comparability

Sale of Australian Operations

In December 2000, we signed a share purchase agreement for the transfer of
the stock in two U.K. holding companies which, in turn, owned our Australian
subsidiaries, to a subsidiary of Rio Tinto Limited. Our Australian operations
consisted of interests in six coal mines, as well as mining services in
Brisbane, Australia. The sale price was $446.8 million in cash, plus the
assumption of all liabilities including $119.4 million of debt. The sale closed
on January 29, 2001.

Discontinued Operations

In August 2000, we sold Citizens Power, our subsidiary that marketed and
traded electric power and energy-related commodity risk management products, to
Edison Mission Energy. We classified Citizens Power as a discontinued operation
as of March 31, 2000, and recorded an estimated loss on the sale of $78.3
million, net of income taxes. We have changed the presentation of our
historical results of operations and cash flows to reflect Citizens Power as a
discontinued operation for all periods presented. The fair value of the net
assets of Citizens Power is classified as a single line in the balance sheet
entitled "Net assets of discontinued operations" in fiscal year 2000 only.

Fiscal Year 2000 vs. Fiscal Year 1999

Effective January 1, 2000, our 81.7%-owned subsidiary, Black Beauty,
invested $6.6 million to obtain control of three of its midwestern coal mining
affiliates: Sugar Camp Coal, LLC, Arclar Coal Company, LLC and United Minerals
Company, LLC. Prior to fiscal year 2000, interests in these affiliates were
accounted for under the equity method and effective January 1, 2000, we
obtained decision-making control and began accounting for our 75% interest in
the affiliates on a consolidated basis. We have elected to consolidate these
affiliates as part of Black Beauty's results of operations effective April 1,
1999.

Fiscal year 2000 results also include the consolidated results of operations
for Black Beauty for 12 months compared to only three months in fiscal year
1999. We increased our ownership interest in Black Beauty from 43.3% to 81.7%
effective January 1, 1999. We accounted for our interest in Black Beauty under
the equity method from April 1 to December 31, 1998. As a result, prior to
January 1, 1999, our share of Black Beauty's results of operations was included
as a component of "Other revenues" in the statements of operations, and our
interest in Black Beauty's net assets was included within "Investments and
other assets" in the balance sheets.

The results of operations and cash flows for the period ended March 31, 1999
reflect the combination of our results from April 1, 1998 to March 31, 1999 (we
acquired our predecessor company effective May 20, 1998 and prior to that date
had no prior operations) and the results of the predecessor company for April
1, 1998 to May 19, 1998. In addition, the results of operations and cash flows
for the period ended March 31, 1999 may not be directly comparable to fiscal
year 2000 as a result of the effects of restatement of assets and liabilities
to their estimated fair market value in accordance with the application of
purchase accounting under Accounting Principles Board Opinion No. 16.

Fiscal Year Ended March 31, 2001 Compared to Fiscal Year Ended March 31, 2000

Sales. Sales decreased $31.9 million, or 1.2%, to $2,579.1 million for the
fiscal year 2001. Sales volume increased 2.1 million tons, or 1.1%, to 192.4
million tons in fiscal year 2001. The majority of the decline was the result of
$24.6 million of lower sales in Australia, due to the sale of our Australian
operations in January 2001. During the first nine months of fiscal year 2001,
average prices were 2.7% lower than the prior year's first nine months,
primarily due to a change in sales mix as higher-priced Midwest region volume
decreased in fiscal year 2001. However, this decrease was somewhat mitigated by
higher coal prices in the fourth quarter in nearly all operating regions, which
reduced the full year decline in average prices to only 1.0% compared to the
prior year. Sales from our U.S. operations decreased $7.3 million in fiscal
year 2001, due to lower volumes in the Midwest region offset partially by
slightly higher volume in Appalachia, the Southwest region and at Black Beauty,
and improved pricing and volume in the Powder River Basin.

Sales in the Powder River region increased $44.9 million in fiscal year
2001, due to improved pricing and increased volume as a result of strong demand
for Powder River Basin coal. Sales in Appalachia improved by $42.3 million due
to higher volume from improved performance at our longwall operations in that
region. Black Beauty's sales increased $23.6 million due to the higher volumes
on contracts transitioned from our other mines, while sales in the Southwest
region improved $4.9 million due to slightly higher sales volume. Sales from
broker and trading activities increased $41.4 million, reflecting an increase
in volume over fiscal year 2000. These sales increases were more than offset by
the sales decrease in the Midwest region of $164.5 million from the closure and
suspension of three mines during fiscal year 2000 and the closure of another
mine early in the third quarter of fiscal year 2001.

Other Revenues. Other revenues decreased $8.9 million compared to the prior
year, to $90.6 million. Lower contract restructuring revenues and coal royalty
income in fiscal year 2001 were only partially offset by an increase in
revenues from engineering services for underground mining projects in
Australia. Our contract restructuring revenues typically arise from the
negotiated termination of our or a third party's existing coal supply agreement
in exchange for a cash payment.

Depreciation, Depletion and Amortization. Fiscal year 2001 depreciation,
depletion and amortization expense was $241.0 million, a decrease of $8.8
million compared to fiscal year 2000. The decrease was primarily due to $6.0
million of additional depletion associated with a new coal royalty agreement
entered into in fiscal year 2000.

Selling and Administrative Expenses. Selling and administrative expenses
increased $4.0 million in fiscal year 2001 to $99.3 million. This increase was
primarily related to $3.7 million of increased stock compensation expense in
fiscal year 2001 related to the grant of Class B common stock to management.

Gain on Sale of Australian Operations. On January 29, 2001, we sold our
Australian operations to Coal & Allied, a 71%-owned subsidiary of Rio Tinto
Limited. The selling price was $446.8 million, plus the assumption of all
liabilities, including $119.4 million of debt. We recorded pretax gain of
$171.7 million on the sale.

Operating Profit. Fiscal year 2001 operating profit was $341.8 million, an
increase of $148.6 million compared to fiscal year 2000. Excluding the gain on
the sale of our Australian operations, operating profit was $170.1 million, a
decrease of $23.1 million from fiscal year 2000. Operating margin excluding the
gain on the sale of our Australian operations was 6.6% in fiscal year 2001, a
decrease from 7.4% in fiscal year 2000. A 41% increase in fuel prices in fiscal
year 2001 decreased operating margin by 1.0% and operating profit by $24.1
million in fiscal year 2001. At our U.S. mining operations, operating profit,
excluding fuel cost variances, remained stable in fiscal year 2001.

Operating profit in the Powder River Basin region increased $20.5 million
primarily due to higher pricing in fiscal year 2001, combined with slightly
improved sales volume. In the Southwest region, we realized increased operating
profit of $12.1 million as a result of improved productivity and higher sales
volume in fiscal

year 2001. Offsetting these increases was a $40.0 million decrease in the
Midwest region associated with the closure and suspension of three mines in
fiscal year 2000 and the closure of another mine early in the third quarter of
fiscal year 2001. Black Beauty's operating profit decreased $18.5 million due
to lower contract restructuring revenues in fiscal year 2001, higher operating
costs caused by adverse geologic conditions encountered during the first nine
months of the year as we transitioned to new mining areas and unfavorable
weather conditions, which delayed production and transportation of coal.
Appalachia's operating profit decreased $6.5 million due to poor mining
conditions at certain underground operations and lower average pricing in the
first nine months of fiscal year 2001 due to contract expirations, partially
offset by improved performance at the region's longwall operations.

Fiscal year 2001 results also included a decrease in operating costs for an
$8.0 million reduction in our liabilities for environmental cleanup-related
costs based upon favorable experience and lower costs of $9.1 million related
to Black Lung excise tax refund credits on export shipments. Beginning in 1997,
we filed for a refund of these taxes on the basis that the tax was
unconstitutional. In May 2000, the Internal Revenue Service issued guidelines
for the refund of these taxes. We have filed a claim and expect to receive a
refund in the first half of fiscal year 2002.

Operating costs also decreased $11.4 million in fiscal year 2001 due to the
reduction in our liability associated with the United Mine Workers of America
Combined Fund. The Coal Industry Retiree Health Benefit Act of 1992 established
the Combined Fund to provide for the funding of specified health benefits for
covered United Mine Workers of America retirees. Two of our subsidiaries filed
a lawsuit against the Social Security Administration asserting that it
improperly assigned certain beneficiaries to them. A federal District Court
ruled in our favor. Effective October 1, 2000, the Social Security
Administration withdrew the assignment to our subsidiaries of a specified
number of beneficiaries, resulting in a $11.4 million reduction in our
liability.

Additionally, our Australian operations' operating profit increased $5.0
million in fiscal year 2001.

Interest Expense. Interest expense decreased $7.4 million to $197.7 million
in fiscal year 2001. The decrease was primarily due to a $7.7 million decrease
in interest expense in the fourth quarter resulting from the repayment of
$455.0 million of term loans under our senior credit facilities during the
quarter, and the removal of $119.4 million of debt from our balance sheet as a
result of the sale of our Australian operations.

Interest Income. Interest income increased $4.3 million to $8.7 million in
fiscal year 2001, primarily as a result of the interest income recorded in the
current year associated with the Black Lung excise tax refunds.

Income Taxes. Fiscal year 2001 income tax expense was $42.7 million on
pretax income of $152.9 million, compared to an income tax benefit of $141.5
million on a pretax loss of $7.4 million in fiscal year 2000. Additionally, in
fiscal year 2000 we recorded a $144.0 million income tax benefit associated
with an increase in the tax basis of a subsidiary's assets due to a change in
federal income tax regulations.

Our consolidated tax position is impacted by the percentage depletion tax
deduction utilized by us and our U.S. subsidiaries that creates an alternative
minimum tax situation, and the positive contribution of our Australian
operations, which are taxed at a higher rate than our U.S. operations.
Additionally, in fiscal year 2001 we recorded a $47.5 million tax provision
related to the gain on sale of our Australian operations. Excluding the tax
provision related to the sale of our Australian operations, the income tax
benefit recorded on U.S. pretax losses exceeded the Australian income tax
expense in fiscal year 2001 by $4.8 million.

Minority Interests. In fiscal year 2001, minority interest expense decreased
$8.0 million to $7.5 million, due to lower fiscal year 2001 results at our
81.7%-owned Black Beauty operations. As discussed above, Black Beauty's results
were affected by a contract restructuring gain in fiscal year 2000, combined
with higher mining costs due to poor geologic conditions and higher fuel costs
in fiscal year 2001.

Loss from Discontinued Operations. In fiscal year 2000, Citizens Power
incurred a loss from operations of $12.1 million. Citizens Power was classified
as a discontinued operation in March 2000.

Gain from Disposal of Discontinued Operations. During fiscal year 2001, we
reduced our estimated net loss from the sale of Citizens Power by $12.9
million, net of income taxes. This reduction reflected a decrease in the
estimated operating losses of Citizens Power during the disposal period due to
higher income from electricity trading activities driven by increased
volatility and prices for electricity in the western U.S. power markets during
the first quarter ($8.8 million) and higher estimated proceeds from the
monetization of power contracts as part of the wind-up of our ownership of
Citizens Powers' operations ($4.1 million). We completed the sale of Citizens
Power in fiscal year 2001.

Extraordinary Loss from the Early Extinguishment of Debt. In the fourth
quarter of fiscal year 2001, we made optional prepayments of term loans under
our senior credit facilities. These prepayments were primarily funded with the
proceeds from the sale of our Australian operations. The prepayments resulted
in an extraordinary loss of $8.5 million, net of income taxes, due to the
write-off of costs related to the issuance of the debt repaid.

Fiscal Year Ended March 31, 2000 Compared to Total Fiscal Year 1999

Sales. For fiscal year 2000, sales increased $361.1 million, or 16.0%, to
$2.6 billion. Sales volume increased 8.1% over the prior year. The fiscal year
2000 results included an increase attributable to Black Beauty of $428.9
million, which was principally comprised of two amounts: the inclusion of Black
Beauty's results for an entire year ($264.1 million) and the consolidation of
Sugar Camp, Arclar and United Minerals on a retroactive basis ($164.8 million).
The average sales price per ton increased 7.4% in 2000 due to this inclusion of
sales of Black Beauty and its affiliates and higher prices in the Powder River
Basin. Sales in Australia increased $75.5 million over total fiscal year 1999.

Powder River Basin sales increased $13.1 million, due mainly to a continuing
improvement in pricing for the low sulfur coal in this region. Offsetting these
increases were declines in the Midwest and Appalachia markets of $68.1 million
and $53.8 million, respectively. Both regions were negatively impacted by mild
winter weather that increased customer coal stockpiles, causing lower demand
and pricing. Sales in the Midwest region declined primarily due to the closure
and suspension of three high sulfur mines in fiscal year 2000, while results in
Appalachia were hampered by price reductions for coal utilized by the export
metallurgical market, and operating difficulties related to longwall panel
development delays and adverse geological conditions. Brokerage and trading
revenues declined $33.5 million, mainly due to new contracts with lower prices
than expiring contracts.

Other Revenues. Other revenues improved $1.9 million compared to fiscal year
1999. This increase was primarily due to a $13.0 million gain from a contract
restructuring in which Black Beauty initiated the buyout of a customer's
contract in order to provide additional production capacity to meet a new long-
term coal supply agreement, and a $3.9 million gain on the settlement of a
contract dispute in the fourth quarter of fiscal year 2000, partially offset by
the exclusion of $7.5 million of equity income in affiliates subsequently
consolidated by Black Beauty as discussed above.

Selling and Administrative Expenses. Selling and administrative expenses
increased $6.4 million in fiscal year 2000 to $95.3 million. This increase was
the result of the inclusion of a full year of Black Beauty's operations,
compared to three months in fiscal year 1999 (an increase of $9.9 million) and
full year consolidation of Black Beauty affiliates previously mentioned,
partially offset by $13.1 million of compensation expense in fiscal year 1999
related to the grant of 992,276 shares of Class B common stock to management.

Operating Profit. Operating profit was $193.2 million for fiscal year 2000,
an increase of $26.8 million, or 16.1%. The impact of Black Beauty on fiscal
year 2000 results increased operating profit by $43.8 million, including a
$13.0 million gain from the Black Beauty contract restructuring previously
mentioned. We also had $12.8 million less stock compensation expense in fiscal
year 2000 than in fiscal year 1999.

Other regions showing year-over-year improvement were the Midwest ($15.0
million), Powder River Basin ($13.2 million) and Australia ($12.8 million). The
Midwest region improved over fiscal year 1999 as a result of lower reclamation
costs occurring from a change in permitting requirements in fiscal year 2000
($5.1 million), improved productivity and higher volume at the ongoing
Midwestern operations, partially offset by lower volumes due to the
closure/suspension of three mines in fiscal year 2000. Profit improved in the
Powder River Basin based upon higher pricing and higher demand for coal from
our lowest cost, most efficient operations. Our Australian operations also
reported higher profit.

Offsetting these increases were decreases in Appalachia ($32.1 million) and
the Southwest ($4.1 million). Profitability in Appalachia was directly impacted
by soft market conditions and higher costs as a result of longwall panel
development delays. The decline in the Southwest region was the result of
higher operating expenses, primarily as a result of higher repair and
maintenance expenses than in fiscal year 1999, offset partially by higher
volumes and a gain of $3.9 million from the settlement of a customer
contractual dispute. In addition, income from brokerage and trading activities
decreased $19.8 million, mainly as a result of lower volumes that were directly
related to contract expirations. Finally, we experienced higher costs for past
mining obligations due to the fiscal year 2000 cost of mine closure and
suspension in the Midwest region, and $14.0 million in higher administrative
costs as a result of the inclusion of Black Beauty and its affiliates.

Interest Expense. Interest expense for fiscal year 2000 was $205.1 million,
an increase of $24.8 million, or 13.8%. Fiscal year 1999 included acquisition-
related indebtedness from the May 19, 1998 acquisition of our predecessor
company forward. Also affecting fiscal year 2000 was the inclusion of $12.6
million of additional interest associated with the consolidation of Black
Beauty.

Interest Income. Interest income decreased $15.8 million from fiscal year
1999 to $4.4 million. The decrease was primarily attributable to interest
income from higher average cash balances held in fiscal year 1999 in
anticipation of the acquisition of an additional ownership interest in Black
Beauty that occurred late in fiscal year 1999.

Income Taxes. For fiscal year 2000, we recorded an income tax benefit of
$141.5 million on a pretax loss from continuing operations of $7.4 million,
compared to an income tax expense of $7.5 million on pretax income from
continuing operations of $6.2 million in fiscal year 1999. The fiscal year 2000
amount reflected a $144.0 million income tax benefit associated with an
election to treat Peabody Natural Resources Company, our subsidiary, as a
corporation rather than as a partnership for federal income tax purposes. This
election, which became available through a change in tax law that occurred in
December 1999, resulted in an increase in the tax basis in the entity's assets
and eliminated the necessity for a deferred tax liability that had reflected
the excess of the book basis in that subsidiary over the tax basis.

Our effective book income tax rate was primarily impacted by two factors:
the percentage depletion tax deduction used by us and our U.S. subsidiaries
that creates an alternative minimum tax situation and the level of contribution
by the Australian operations to the consolidated results of operations, which
is taxed at a higher rate than in the United States.

Loss From Discontinued Operations. In fiscal year 2000, our discontinued
operations reported a net loss of $12.1 million, compared to net income of $4.7
million in fiscal year 1999. The decrease was largely the result of a decline
in the number of utility contract restructuring transactions completed in
fiscal year 2000 compared to fiscal year 1999. In addition, fiscal year 2000
results included the estimated after-tax loss on disposal of Citizens Power of
$78.3 million.

Long-Term Coal Supply Agreements

As of March 31, 2001, nearly one billion tons of our future coal production
were committed under long-term contracts. Our strategy is to selectively renew,
or enter into new, long-term supply contracts when we can do so at favorable
prices. Long-term contracts may be particularly attractive in regions where
market prices are expected to remain stable, with respect to high sulfur coal
that would otherwise not be in great demand or for

sales under cost-plus arrangements serving captive electric generating plants.
Prices for coal have recently risen, particularly in the Powder River Basin and
in Appalachia, primarily due to increased prices for competing fuels and
increased demand for electricity. To the extent we do not renew or replace
expiring long-term coal supply agreements, our future sales will be exposed to
market fluctuations, including unexpected downturns in market prices. Most of
the contracts contain price adjustments for inflation and changes in the laws
regulating the mining, production, sale or use of coal. In the majority of
these contracts, the purchaser has the right to terminate the contract if the
price increases beyond certain limits, although we can usually decrease the
price in order to maintain the contract.

Liquidity and Capital Resources

Net cash provided by operating activities decreased by $110.9 million, to
$152.0 million, for fiscal year 2001. The decrease in net cash provided by
operating activities was primarily due to $60.0 million of lower proceeds from
the sale of accounts receivable in fiscal year 2001, combined with lower
operating cash flow from our Australian operations.

In March 2000, we established a five-year accounts receivable securitization
program under which we sell, without recourse, on an ongoing basis, undivided
interests in trade accounts receivable from our domestic subsidiaries other
than Black Beauty to a multi-seller, asset-backed commercial paper conduit. The
qualified pool of receivables included in the securitization program includes
customers with good credit ratings and is reduced for certain items, including
past due balances and specified concentration limits. The conduit's purchases
are financed with the sale of highly-rated commercial paper, allowing us to
lower our overall financing costs. The commercial paper is secured by high-
quality current trade receivables. The qualified pool of accounts receivable
subject to the program represented approximately 56% of our total accounts
receivable at March 31, 2001. Outstanding undivided interests totaled $100.0
million at March 31, 2000 and $140.0 million at March 31, 2001.

Net cash provided by investing activities was $388.5 million for fiscal year
2001, an increase of $573.9 million compared to fiscal year 2000. In fiscal
year 2001, we received $455.0 million in proceeds from the sale of our
Australian operations and $102.5 million in net proceeds from the sale of
Citizens Power, while fiscal year 2000 included higher expenditures for
acquisitions, partially offset by $32.9 million in proceeds from contract
restructurings.

Total capital expenditures for fiscal years 1999, 2000 and 2001 were $195.4
million, $178.8 million and $187.1 million, respectively. Of these capital
expenditures, $71.2 million, $28.6 million and $35.7 million relate to our
Australian operations. Our capital expenditures are primarily made to acquire
additional reserves and mining equipment. We currently estimate that our
capital expenditures for fiscal year 2002 will be $198.0 million and will
primarily be used to acquire additional coal reserves, develop existing
reserves, replace equipment and fund cost reduction initiatives. We had $94.4
million of future committed capital expenditures at March 31, 2001 that are
primarily related to acquiring additional Powder River Basin coal reserves and
mining equipment in fiscal year 2002. We anticipate funding these capital
expenditures through available cash and credit facilities.

Net cash used in financing activities was $543.3 million for fiscal year
2001, compared to $205.2 million in fiscal year 2000. We used the net proceeds
from the sales of Citizens Power and our Australian operations to repay $633.9
million of long-term debt during fiscal year 2001, an increase of $423.9
million in our debt repayments compared to fiscal year 2000.

Effective May 20, 1998, we paid The Energy Group PLC $2,003.5 million in
cash for P&L Coal Group. The acquisition was financed by a $480.0 million
equity contribution by Lehman Brothers Merchant Banking and affiliates and
borrowings of $1,523.5 million. We also entered into a $480.0 million senior
credit facility to provide for our working capital requirements following the
acquisition, with no initial borrowings related to financing the acquisition.

As of March 31, 2001, we had total indebtedness outstanding of $1,405.6
million that consisted of:

(In millions)

Term loans under our senior credit facility.................... $ 125.0
Senior notes .................................................. 399.1
Senior subordinated notes ..................................... 498.9
Indebtedness of Black Beauty subsidiary........................ 211.0
5.0% subordinated note......................................... 169.9
Other long-term debt........................................... 1.7
---------
$ 1,405.6
=========

The following table sets forth the mandatory repayments of our indebtedness
outstanding as of March 31, 2001:

Fiscal Year Senior Credit Facility 5.0% Subordinated Note Other Total
----------- ---------------------- ---------------------- -------- --------
(In millions)

2002.................... $ -- $ 20.0 $ 16.3 $ 36.3
2003.................... -- 20.0 37.7 57.7
2004.................... -- 20.0 50.2 70.2
2005.................... -- 20.0 85.6 105.6
2006.................... -- 20.0 7.9 27.9
2007 and thereafter..... 125.0 120.0 862.9 1,107.9
------- ------ -------- --------
$ 125.0 $220.0 $1,060.6 $1,405.6
======= ====== ======== ========

Our senior credit facility includes a revolving credit facility that
currently provides for aggregate borrowings of up to $200.0 million and letters
of credit of up to $280.0 million. The revolving credit facility commitment
matures in fiscal year 2005. As of March 31, 2001, we had no borrowings
outstanding under the revolving credit facility. Revolving loans under the
revolving credit facility bear interest based on the base rate (as defined in
the senior credit facility), or LIBOR (as defined in the senior credit
facility) at our option. As of March 31, 2001, we had $73.4 million of letters
of credit outstanding under the revolving credit facility.

The revolving credit facility and related term loan facility also currently
contain restrictions and limitations including, but not limited to, financial
covenants that require us to maintain and achieve certain levels of financial
performance and prohibit the payment of cash dividends and similar restricted
payments.

The indentures governing the senior notes and senior subordinated notes
permit us and our restricted subsidiaries to incur additional indebtedness,
including secured indebtedness, subject to certain limitations. In addition,
the indentures limit our ability to:

.pay dividends or make other distributions;

.lease, convey or otherwise dispose of all or substantially all of our
assets;

.issue specified types of capital stock;

.enter into guarantees of indebtedness;

.incur liens;

.restrict our subsidiaries' ability to make dividend payments;

.merge or consolidate with any other person or enter into transactions with
affiliates; and

.repurchase junior securities or make specified types of investments.

As of March 31, 2001, Black Beauty maintained a $100.0 million revolving
credit facility that matures on February 28, 2002. Black Beauty may elect one
or a combination of interest rates based on LIBOR or the corporate base rate
plus a margin, which fluctuates based on specified leverage ratios. Borrowings
outstanding under the Black Beauty revolving credit agreement totaled $70.0
million at March 31, 2001. The revolving credit facility contains customary
restrictive covenants, including limitations on additional debt, investments
and dividends. In addition, Black Beauty's ability to pay dividends is subject
to certain financial tests.

Black Beauty's senior unsecured notes include $31.4 million of senior notes
and three series of notes with an aggregate principal amount of $60.0 million
as of March 31, 2001. The senior notes bear interest at 9.2%, payable
quarterly, and are prepayable in whole or in part at any time, subject to
certain make-whole provisions. The three series of notes include Series A, B
and C notes, totaling $45.0 million, $5.0 million and $10.0 million,
respectively. The Series A notes bear interest at an annual rate of 7.5% and
are due in fiscal year 2008. The Series B notes bear interest at an annual rate
of 7.4% and are due in fiscal year 2004. The Series C notes bear interest at an
annual rate of 7.4% and are due in fiscal year 2003. The senior unsecured notes
contain customary restrictive covenants, including limitations on additional
debt, investments and dividends.

As of March 31, 2001, the revolving and working capital borrowing facilities
referred to above totaled $300.0 million, and borrowings thereunder totaled
$70.0 million. We were in compliance with the restrictive debt covenants of all
of our debt agreements as of March 31, 2001.

Subsidiaries of Black Beauty maintain borrowing facilities with banks and
other lenders with customary restrictive covenants. The aggregate amount of
outstanding indebtedness under those facilities totaled $47.8 million as of
March 31, 2001.

On January 29, 2001, we received $455.0 million in cash, prior to post-
closing adjustments of $8.2 million, from the sale of our Australian
operations. Using these proceeds, we repaid the remaining $110.0 million of the
tranche A term loan and $345.0 million of the tranche B term loan outstanding
under our senior credit facility. After giving effect to those repayments, we
had no tranche A term loans outstanding and $125.0 million of tranche B term
loans outstanding.

In connection with this offering, we anticipate applying $125.0 million of
proceeds to the repayment of the remaining tranche B term loan outstanding
under the senior credit facility and $100.0 million to repay borrowings under
our revolving credit facility, which we incurred on May 2, 2001 in connection
with the repayment of a portion of the 5% subordinated note. We also intend to
use proceeds from this offering to repurchase a portion of our senior notes and
our senior subordinated notes.

We have received the approval from a sufficient number of our lenders to
amend our senior credit facility. The amendment, which will be effective upon
the consummation of this offering, will permit the payment of cash dividends
and other restricted payments subject to specified limitations, increase the
amount available for borrowing under the revolving credit facility from $200.0
million to $350.0 million and permit additional joint venture investments. In
connection with the amendment, we agreed to reduce the maximum permitted debt
to EBITDA ratio and increase the minimum required interest coverage ratio. We
paid an amendment fee of $1.4 million to a group of over 100 lenders who
consented to the amendment. Lehman Commercial Paper Inc., an affiliate of
Lehman Brothers, received $0.06 million of that credit facility amendment fee.
All other terms and conditions remain unchanged.

Black Beauty replaced its $100.0 million revolving credit facility with a
new $120.0 million revolving credit facility on April 16, 2001. The new
facility contains substantially similar restrictive covenants and matures on
April 17, 2004. Borrowings outstanding under the $100.0 million revolving
credit facility on April 16, 2001 were refinanced under the new $120.0 million
revolving credit facility.

Certain Liabilities

We have significant long-term liabilities relating to mine reclamation,
work-related injuries and illnesses, pensions and retiree health care. Accruals
for these liabilities reflect U.S. coal industry and generally accepted
accounting principles. Our operations and the operations of our predecessor
subject us to liability for the

investigation and remediation of releases of hazardous substances into the
environment and for damages to natural resources under Superfund and similar
state laws. The majority of our existing liabilities relate to our past
operations, which had more mines and employees than we currently have. Our
aggregate cash payments for these liabilities for fiscal year 2001 were $149.0
million.

In connection with the sale of Citizens Power, we have indemnified the buyer
from certain losses resulting from specified power contracts and guarantees. No
claims have been asserted against us under this indemnity.

Recent Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 133, "Accounting for Derivative Instruments
and Hedging Activities." Statement of Financial Accounting Standards No. 133
(as amended by Statement of Financial Accounting Standards Nos. 137 and 138)
requires the recognition of all derivatives as assets or liabilities within the
balance sheet and requires both the derivatives and the underlying exposure to
be recorded at fair value. Any gain or loss resulting from changes in fair
value will be recorded as part of the results of operations, or as a component
of comprehensive income or loss, depending upon the intended use of the
derivative. The effective date of Statement of Financial Accounting Standards
No. 133 is for all fiscal quarters of fiscal years beginning after June 15,
2000 (effective April 1, 2001 for us). We do not anticipate that the adoption
of Statement of Financial Accounting Standards No. 133 will have a material
effect on our financial condition or results of operations, subject to new or
revised implementation guidelines issued by the Derivatives Implementation
Group.

Quantitative and Qualitative Disclosures About Market Risk

Trading Activities

We market and trade coal and emission allowances. These activities give rise
to market risk, which represents the potential loss that can be caused by a
change in the market value of a particular commitment. We actively measure,
monitor and attempt to control market risks to ensure compliance with
management policies. For example, we have policies in place that limit the
amount of total exposure we may assume at any point in time.

We account for coal and emission allowance trading using the fair value
method, which requires us to reflect financial instruments with third parties,
such as forwards, futures, options and swaps, at market value in our
consolidated financial statements.

Non-trading Activities

We manage our commodity price risk for non-trading purposes through the use
of long-term coal supply agreements, rather than through the use of derivative
instruments. We sold approximately 85% of our sales volume under long-term coal
supply agreements during fiscal year 2001. Over the next few years, we
anticipate that an increasing portion of our coal sales will be made at then-
current market prices rather than under long-term coal supply agreements. As a
result, our revenues will be increasingly affected by fluctuations in the price
of coal.

Some of the products used in our mining activities, such as diesel fuel, are
subject to price volatility. We use forward contracts to manage the volatility
related to this exposure.

We have exposure to changes in interest rates due to our existing level of
indebtedness. As of March 31, 2001, we had $1,161.1 million of fixed-rate
borrowings and approximately $244.5 million of variable-rate borrowings
outstanding. A one percentage point increase in interest rates would result in
an annualized increase to interest expense of approximately $2.4 million on our
variable-rate borrowings. With respect to our fixed-rate borrowings, a 1%
increase in interest rates would result in a $61.3 million decrease in the fair
value of these borrowings.

COAL INDUSTRY OVERVIEW

We obtained the information provided in this "Coal Industry Overview"
regarding future coal consumption and future coal market prices from the Energy
Information Administration, the independent statistical and analytical agency
within the U.S. Department of Energy, as well as Energy Ventures Analysis, Inc.
and Resource Data International, Inc., private market research firms. The
Energy Information Administration bases its forecasts on assumptions about,
among other things, trends in various economic sectors (residential,
transportation, industrial, etc.), economic growth rates, technological
improvements and demand for other energy sources. The Energy Information
Administration's Annual Energy Outlook 2001, International Energy Outlook 2000
and World Energy Outlook 2000 more fully describe these assumptions. Neither
Resource Data International nor Energy Ventures Analysis, Inc. describes the
assumptions upon which they base their projections.

Introduction

Coal is one of the world's most abundant, efficient and affordable natural
resources, used primarily to provide fuel for the generation of electricity.
According to the International Energy Agency, in 1997, coal provided 26% of the
world's primary energy supply and was responsible for approximately 44% of the
world's power generation. Coal's share of electricity generation in the United
States was an estimated 51% in 2000.

The United States is the second largest coal producer in the world, exceeded
only by China. Other leading coal producers include Australia, India and South
Africa. The United States has the largest coal reserves in the world, with an
estimated 250 years of supply based on current usage rates. U.S. coal reserves
are more plentiful than U.S. oil or natural gas reserves, with coal
representing more than 85% of the nation's fossil fuel reserves.

United States coal production has nearly doubled during the past 30 years.
In 2000, total U.S. coal production was estimated to be 1.1 billion tons.
Approximately 62% of U.S. coal is produced by surface mining methods, while the
remaining 38% is produced by underground mining methods.

The U.S. coal industry operates under a highly developed regulatory regime
that governs all mining and mine safety activities, including land reclamation,
which requires mined lands to be restored to a condition equal to or better
than that existing before mining. Coal mining in the United States has become a
relatively safe occupation, relying on sophisticated technology and a skilled
work force to become one of the safest, most productive coal industries in the
world.

In recent years, the coal industry has experienced significant gains in
mining productivity, changes in air quality laws, growth in coal consumption
and industry consolidation. According to the Energy Information Administration,
the number of operating mines declined 50% over the past ten years, while
overall coal production increased approximately 6% over that period. During the
same period, average coal mine productivity nearly doubled due to changes in
work practices, new technologies and an increase in production in the Powder
River Basin coal region, where thick, easily accessible coal seams result in
high productivity. The overall productivity gains contributed to stability in
coal prices during the 1990s. Recent increases in the price of natural gas and
other energy commodities, however, have resulted in the price of coal
increasing in most regions where we operate. A notable industry trend has been
the shift to low sulfur coal production, particularly in the Powder River
Basin, driven by the significant regulatory restrictions on sulfur dioxide
emissions from coal-based electric generating plants.

Coal Markets

Resource Data International estimates that approximately 1.1 billion tons of
coal were consumed in the United States in 2000 and expects domestic
consumption to grow at a rate of 0.4% per year from 2000 through 2015. Demand
from domestic electricity generators, currently accounting for more than 90% of
domestic

consumption, is projected to increase to more than one billion tons by 2015.
Overall, coal use at coke plants and steel mills is projected to decrease.

Projected U.S. Coal Consumption

2000P 2005P 2010P 2015P
----- ----- ----- -----
(Tons in millions)
Sector
------

Electricity generators.................................. 928 984 996 1,012
Industrial.............................................. 73 73 72 72
Coke plants/steel mills................................. 28 24 20 19
----- ----- ----- -----
Total domestic........................................ 1,029 1,081 1,088 1,103
Export.................................................. 59 62 63 61
----- ----- ----- -----
Total................................................. 1,088 1,143 1,151 1,164
===== ===== ===== =====

--------
Source: Resource Data International, Outlook for Coal 2000.

The U.S. coal industry's principal customers are electricity generators.
According to Resource Data International, these electricity generators are
expected to require more coal in order to meet the growing demand for
electricity. Coal-based generation is used in most cases to meet baseload
requirements, so coal use generally grows at the pace of electricity growth. In
the aggregate, coal-based plants currently utilize approximately 70% of their
capacity, although the optimal sustainable capacity utilization is 85% for a
typical plant, and most can run at higher rates for short periods. An increase
from 70% capacity utilization to 85% capacity utilization would translate into
approximately 200 million tons of additional annual coal consumption. By 2010,
coal-based plants would have to run at approximately 82% of capacity to meet
expected demand for electricity, assuming that all the same plants were running
at today's efficiency levels and that market share remains constant. Gas-fired
electricity generation, which is used primarily for intermediate and peak-load
demand, is anticipated to gain market share at the expense of nuclear
generation or where peak-load capacity is needed.

As the table below indicates, coal generated an estimated 51% of the
electricity in the United States in 2000.

Electricity Fuel Sources Comparison(/1/)

1990 1995 2000P
---- ---- -----

Coal............................................................ 53% 51% 51%
Nuclear......................................................... 19 20 20
Hydro........................................................... 10 9 8
Natural Gas..................................................... 13 15 16
Other........................................................... 5 5 5
--- --- ---
Total......................................................... 100% 100% 100%
=== === ===

--------
Source: Energy Information Administration Monthly Energy Review, December 2000.
(1) Based on net generation

Regional Coal Markets

Over the past several years, largely as a result of sulfur dioxide emissions
limitations mandated by the Clean Air Act, demand has shifted toward lower
sulfur coal. In 1995, Phase I of the Clean Air Act required high sulfur coal
plants to reduce their emissions of sulfur dioxide to 2.5 pounds or less of
sulfur dioxide per million Btu. As a result of a significant switch to very low
sulfur Powder River Basin coal, manyPhase I-affected plants overcomplied with
the sulfur dioxide requirements, creating a surplus of emission

allowances that could be traded within a market for sulfur dioxide emissions
credits. In 2000, Phase II of the Clean Air Act tightened restrictions on
sulfur dioxide emissions from 2.5 pounds or less to 1.2 pounds or less of
sulfur dioxide per million Btu. Surplus emission credits from Phase I allow
some generators to delay retrofitting old plants with scrubbers. Eventually,
owners of these plants will have to retrofit or switch to Phase II compliance
coal, including Southern Powder River Basin or other low sulfur coal. The
following table indicates the historical and projected shift to Powder River
Basin coal.

U.S. Coal Demand by Production Region

Historical Projected
---------- -----------------------
1996 2000 2005 2010 2015
---------- ----- ----- ----- -----
(Tons in millions)

Southern Powder River Basin.............. 253 322 367 387 409
Northern Powder River Basin.............. 37 41 43 44 44
Other Western United States.............. 101 120 109 106 113
Northern Appalachia...................... 155 144 146 145 139
Central/Southern Appalachia.............. 310 280 300 304 308
Illinois Basin........................... 116 93 86 82 76
Lignite.................................. 90 86 89 80 71
Other.................................... 11 2 3 3 4
----- ----- ----- ----- -----
Total.................................. 1,073 1,088 1,143 1,151 1,164
===== ===== ===== ===== =====

--------
Source: Resource Data International, Outlook for Coal & Competing Fuels, Winter
1996-1997 and Outlook for Coal 2000.

Coal Characteristics

There are four types of coal: lignite, subbituminous, bituminous and
anthracite. Each has characteristics that make it more or less suitable for
different end uses. In general, coal of all geological composition is
characterized by end use as either "steam coal" or "metallurgical coal,"
sometimes known as "met coal." Steam coal is used by electricity generators and
by industrial facilities to produce steam, electricity or both. Metallurgical
coal is refined into coking coal, which is used in the production of steel.
Heat value and sulfur content, the most important coal characteristics,
determine the best end use of particular types of coal.

Heat Value

The heat value of coal is commonly measured in Btu per pound of coal. A Btu
is the amount of heat needed to raise one pound of water one degree Fahrenheit.
Coal found in the eastern and midwestern regions of the United States tends to
have a heat content ranging from 10,000 to 15,000 Btu per pound. Most coal
found in the western United States ranges from 8,000 to 10,000 Btu per pound.
The weight of moisture in coal, as sold, is included in references to Btu per
pound of coal in this prospectus, unless otherwise indicated.

Lignite is a brownish-black coal with a heat content that generally ranges
from 4,500 to 8,500 Btu per pound. Major lignite operations are located in
Louisiana, Montana, North Dakota and Texas. Lignite is used almost exclusively
in power plants located adjacent to or near these mines because any
transportation costs, coupled with mining costs, would render its use
uneconomical. We do not have any lignite reserves.

Subbituminous coal is a black coal with a heat content that ranges from
8,000 to 12,000 Btu per pound. Most subbituminous reserves are located in
Alaska, Colorado, Montana, New Mexico, Washington and Wyoming. Subbituminous
coal is used almost exclusively by electricity generators and some industrial
consumers. We have extensive subbituminous reserves in the Powder River Basin
of Wyoming.

Bituminous coal is a "soft" black coal with a heat content that ranges from
9,500 to 15,000 Btu per pound. This coal is located primarily in Appalachia,
Arizona, the Midwest, Colorado and Utah, and is the type most commonly used for
electricity generation in the United States. Bituminous coal is also used for
industrial

steam purposes and is used in steel production. All of our reserves in Arizona,
Colorado, Illinois, Indiana, Kentucky and West Virginia are categorized as
bituminous coal.

Anthracite is a "hard" coal with a heat content that can be as high as
15,000 Btu per pound. A limited amount of anthracite deposits is located
primarily in the Appalachian region of Pennsylvania. Anthracite is used
primarily for industrial and home heating purposes. We do not have any
anthracite reserves.

Sulfur Content

Sulfur content can vary from seam to seam and sometimes within each seam.
Coal combustion produces sulfur dioxide, the amount of which varies depending
on the chemical composition and the concentration of sulfur in the coal. Low
sulfur coal has a variety of definitions, but we use it in this prospectus to
refer to coal with a sulfur content of 1.0% or less by weight. Compliance coal
refers to coal with a sulfur content of less than 1.2 pounds per million Btu.
The strict emissions standards of the Clean Air Act have increased demand for
low sulfur coal. We expect continued high demand for low sulfur coal as
electricity generators meet the current Phase II requirements of the Clean Air
Act Amendments (1.2 pounds or less of sulfur dioxide per million Btu). U.S.
sulfur dioxide emissions from electricity generation have decreased 25% from
1989 levels, while U.S. coal consumption has increased 17% during the same
period.

Subbituminous coal typically has a lower sulfur content than bituminous
coal, but some bituminous coal in Colorado, eastern Kentucky, southern West
Virginia and Utah also has a low sulfur content.

Plants equipped with sulfur-reduction technology, known as "scrubbers,"
which reduce sulfur dioxide emissions by 50% to 95%, can use higher sulfur
coal. Plants without scrubbers can use medium and high sulfur coal by
purchasing emission allowances on the open market or blending that coal with
low sulfur coal. Each allowance permits the user to emit a ton of sulfur
dioxide. Some older coal-based plants have been retrofitted with scrubbers. Any
new coal-based generation built in the United States will likely use clean coal
technologies to remove the majority of sulfur dioxide, nitrogen oxide and
particulate matter emissions.

Other

Ash is the inorganic residue remaining after the combustion of coal. As with
sulfur content, ash content varies from seam to seam. Ash content is an
important characteristic of coal because electric generating plants must handle
and dispose of ash following combustion.

Moisture content of coal varies by the type of coal, the region where it is
mined and the location of coal within a seam. In general, high moisture content
decreases the heat value and increases the weight of the coal, thereby making
it more expensive to transport. Moisture content in coal, as sold, can range
from approximately 5% to 30% of the coal's weight.

When some types of coal are super-heated in the absence of oxygen, they form
a hard, dry, caking form of coal called coke. Steel production uses coke as a
fuel and reducing agent to smelt iron ore in a blast furnace.

Coal Mining Techniques

Coal mining operations commonly use four distinct techniques to extract coal
from the ground. The most appropriate technique is determined by coal seam
characteristics such as location and recoverable reserve base. Drill hole data
are used initially to define the size, depth and quality of the coal reserve
area before committing to a specific extraction technique. All coal mining
techniques rely heavily on technology; consequently, technological improvements
have resulted in increased productivity. The four most common mining techniques
are continuous mining, longwall mining, truck-and-shovel mining and dragline
mining.

It is generally easier to mine coal seams that are thick and located close
to the surface than thin underground seams. Typically, coal mining operations
will begin at the part of the coal seam that is easiest and most economical to
mine. In the coal industry, this characteristic is referred to as "low ratio."
As the seam is

mined, it becomes more difficult and expensive to mine because the seam either
becomes thinner or protrudes more deeply into the earth, requiring removal of
more material over the seam, known as the "overburden." For example, many seams
of coal in the midwest are five to 10 feet thick and located hundreds of feet
below the surface. In contrast, seams in the Powder River Basin of Wyoming may
be 80 feet thick and located only 50 feet below the surface.

Once the raw coal is mined, it is often crushed, sized and washed in
preparation plants where the product consistency and heat content are improved.
This process involves crushing the coal to the required size, removing
impurities and, where necessary, blending it with other coal to match customer
specifications.

Continuous Mining

Continuous mining is an underground mining method in which main airways and
transportation entries are developed and remote-controlled continuous miners
extract coal from "rooms," leaving "pillars" to support the roof. Shuttle cars
transport coal from the face to a conveyor belt for transport to the surface.
This method is often used to mine smaller coal blocks or thin seams and seam
recovery is typically approximately 50%. Productivity for continuous mining
averages 25 to 50 tons per miner shift.

Longwall Mining

Longwall mining is an underground mining method that uses hydraulic jacks or
shields, varying from five feet to 12 feet in height, to support the roof of
the mine while a mobile-cutting sheerer advances through the coal. Chain belts
then move the coal to a standard deep mine conveyer system for delivery to the
surface. Continuous mining is used to develop access to long rectangular panels
of coal, which are then mined with longwall equipment, allowing controlled
subsidence behind the advancing machinery. Longwall mining is highly
productive, but it is effective only for large blocks of medium to thick coal
seams. High capital costs associated with longwall mining demand a large,
contiguous reserve base. Seam recovery using longwall mining is typically 70%,
and productivity averages 48 to 80 tons per miner shift.

Truck-and-Shovel Mining

Truck-and-shovel mining is an open-cast method that uses large electric-
powered shovels to remove overburden, which is used to backfill pits after coal
removal. Shovels load coal in haul trucks for transportation to the preparation
plant or rail loadout. Seam recovery using the truck-and-shovel method is
typically 90%. Productivity depends on equipment, geological composition and
the ratio of overburden to coal. Productivity varies between 250 to 400 tons
per miner shift in the Powder River Basin to 30 to 80 tons per miner shift in
eastern U.S. regions.

Dragline Mining

Dragline mining is an open-cast method that uses large capacity electric-
powered draglines to remove overburden to expose the coal seams. Shovels load
coal in haul trucks for transportation to the preparation plant and then to the
rail loadout. Truck capacity can range from 80 to 400 tons per load. Seam
recovery using the dragline method is typically 90% or more and productivity
levels are similar to those for truck-and-shovel mining.

Technology

Coal mining technology is continually evolving, improving, among other
things, underground mining systems and larger earth-moving equipment for
surface mines. For example, longwall mining technology has increased the
average recovery of coal from large blocks of underground coal from 50% to 70%.
At larger surface mines, haul trucks have capacities of 240 to 400 tons, which
is nearly double the maximum capacity of the largest haul trucks used a decade
ago. This increase in capacity, along with larger shovels and draglines, has

increased overall mine productivity. According to National Mining Association
data, overall coal mine productivity, measured in tons produced per miner
shift, increased 101% from 1986 to 1997.

Coal Regions

Coal is mined from coalfields throughout the United States, with the major
production centers located in the Powder River Basin, Central Appalachia,
Northern Appalachia, the Illinois Basin and in other western coalfields. We
operate mines in all of these major coal-producing regions.

Powder River Basin

The Powder River Basin contains some of the most attractive coal reserves in
the world. The Powder River Basin covers more than 12,000 square miles in
northeastern Wyoming and 7,000 square miles in southeastern Montana.
Demonstrated coal reserves total approximately 188 billion tons. Within the
Powder River Basin, there are various qualities of subbituminous coal, with
current production of subbituminous coal ranging from 8,300 Btu per pound to
9,200 Btu per pound and from 0.5% sulfur to 0.3% sulfur. The mines located just
north and south of Gillette, Wyoming are categorized as Southern Powder River
Basin mines. The coal in the Southern Powder River Basin is ranked as
subbituminous with an extremely low sulfur content.

Production in the Southern Powder River Basin has increased from
approximately seven million tons in 1970 to approximately 322 million tons in
2000, and coal production in the Powder River Basin now accounts for
approximately 30% of U.S. coal consumption by volume. The Southern Powder River
Basin has grown into the largest coal supply region in the United States. From
1990 to 2000, the region's compounded annual production growth rate was 7.0%
compared to an overall compounded annual production growth rate of 0.5% for the
total U.S. coal industry. The Southern Powder River Basin markets more than 95%
of its coal to U.S. electricity generators, principally in this region between
the Rocky Mountains and the Appalachian Mountains. We have three active mining
operations in the Powder River Basin: one in Montana and two in northeastern
Wyoming.

Central/Southern Appalachia

Central/Southern Appalachia contains coalfields in eastern Kentucky,
southwestern Virginia and central and southern West Virginia. Production in
Central/Southern Appalachia has decreased from approximately 305 million tons
in 1996 to approximately 213 million tons in 2000. Production declined in all
major sections of Central/Southern Appalachia except for southern West
Virginia, which has grown due to the expansion of more economically attractive
surface mines. The region has experienced significant consolidation in the past
several years due to modest demand growth and strong competition from western
coal. Central/Southern Appalachian operators market approximately 67% of their
coal to electricity generators, principally in the southeastern United States.
Central/Southern Appalachia also sells extensively to the export market and
industrial customers. The coal of Central/Southern Appalachia has an average
heat content of 12,500 Btu per pound and is generally low sulfur. We operate
five coal operations in southern West Virginia producing low sulfur steam and
metallurgical coal.

Northern Appalachia

High and medium sulfur coal is found in the Northern Appalachian coalfields
of western Pennsylvania, southeastern Ohio and northern West Virginia. Demand
for coal from this region has in recent years been, and is expected to remain,
relatively stable. Production in the region was approximately 140 million tons
in 2000. Much of the production in this region is concentrated in a few highly
productive longwall mining operations in southeastern Pennsylvania and northern
West Virginia. Despite its sulfur content of 1.5% to 2.0%, which is considered
medium sulfur coal, coal from the Pittsburgh seam produced from these mines is
considered attractive to electricity generators because of its high heat
content of approximately 13,000 Btu per pound. We operate one mine in this
region.

Illinois Basin

The Illinois Basin consists of approximately 48,000 square miles throughout
Illinois, southern Indiana and western Kentucky. There has been significant
consolidation among coal producers in the Illinois Basin over the past several
years. The Illinois Basin is a declining production center due to the region's
relatively high sulfur coal and competition from lower sulfur western coal.
Production in the Illinois Basin peaked at 141 million tons in 1990. Since
1990, production has decreased by over 36% due to displacement by lower sulfur,
lower-cost coal. Illinois Basin coal is sold primarily to local customers.
Demonstrated reserves total an estimated 135 billion tons of bituminous coal.
Approximately 16 coal seams have been identified in this region. Current
production quality ranges from 9,000 to 12,700 Btu per pound and 0.8% to 4.5%
sulfur, with production averaging approximately 11,400 Btu per pound and 2.5%
sulfur. We have extensive reserves and five active mining operations in the
Illinois Basin coal region, all located in western Kentucky. In addition, we
own an 81.7% interest in Black Beauty, Indiana's largest coal producer. Black
Beauty has 16 active mines in this region.

Western Bituminous Coal Regions

The western bituminous coal regions include the Hanna Basin in Wyoming, the
Uinta Basin of northwestern Colorado and Utah, the Four Corners Region in New
Mexico and Arizona and the Raton Basin in southern Colorado. These regions
produce high-quality, low sulfur steam coal for selected markets in these
regions, for export through West Coast ports and for shipment to some
midwestern customers. Production in these regions has increased from
104 million tons in 1996 to 109 million tons in 2000. We have extensive
reserves and four operating mines in these regions.

Lignite Production Regions

Lignite is mined in North Dakota, Texas and Louisiana. We do not have any
lignite reserves.

Coal Prices

Coal prices vary dramatically by region and are determined by a number of
factors. The two principal components of the delivered price of coal are the
price of coal at the mine, which is influenced by mine operating costs and coal
quality, and the cost of transporting coal from the mine to the point of use.
Electricity generators purchase coal on the basis of its delivered cost per
million Btu.

Price at the Mine

The price of coal at the mine is influenced by geological characteristics
such as seam thickness, overburden ratios and depth of underground reserves.
Powder River Basin coal is relatively inexpensive to mine, at $3 to $5 per ton,
based on our estimates, because the seams are thick and are typically located
close to the surface, enabling mining companies to use open-pit mining methods.
The large capital costs associated with truck-and-shovel and dragline mining (a
dragline can cost up to $50 million and a truck-and-shovel spread can cost up
to $20 million) are amortized over millions of tons of coal produced. Powder
River Basin mines are highly productive and require less labor than underground
mines, thus reducing the labor component of mining costs. By contrast, eastern
U.S. coal is more expensive to mine (at $15 to $30 per ton, based on our
estimates) than western coal, because of thinner coal seams and thicker
overburden. Underground mining, prevalent in the eastern United States, has
higher labor costs than surface mining, including costs for labor benefits and
health care, and high capital costs, including modern mining equipment and
construction of extensive ventilation systems.

In addition to the cost of mine operations, the price of coal at the mine is
also a function of quality characteristics such as heat value and sulfur, ash
and moisture content. Metallurgical coal has higher carbon and lower ash
content and is usually priced $4 to $10 per ton higher than steam coal produced
in the same regions. Higher prices are paid for special coking coal with low
volatility characteristics.

Transportation Costs

Coal used for domestic consumption is generally sold free on board at the
mine and the purchaser normally bears the transportation costs. Export coal,
however, is usually sold at the loading port, and coal producers are
responsible for shipment to the export coal-loading facility and the buyer pays
the ocean freight.

Most electricity generators arrange long-term shipping contracts with rail
or barge companies to assure stable delivered costs. Transportation can be a
large component of the buyer's cost. Although the customer pays the freight,
transportation cost is still important to coal mining companies because the
customer may choose a supplier largely based on the cost of transportation.
According to the National Mining Association, in 1997, more than 70% of all
U.S. coal was shipped by rail or barge. Trucks and overland conveyors haul coal
over shorter distances, while lake carriers and ocean vessels move coal to
export markets. Some domestic coal is shipped over the Great Lakes. Railroads
move more coal than any other product, and in 1999, coal accounted for 22% of
total U.S. rail freight revenue and more than 44% of total freight tonnage.
Most coal mines are served by a single rail company, but much of the Powder
River Basin is served by two competing rail carriers, the Burlington Northern &
Santa Fe and the Union Pacific. Rail competition in this major coal-producing
region is important because rail costs constitute up to 75% of the delivered
cost of Powder River Basin coal in remote markets.

As indicated in the chart below, steam coal prices in the major regions in
which we compete ranged from $3.60 to $23.25 per ton in 2000, depending upon
the quality and source region of the coal. The following table summarizes
historical steam coal prices at the mine by supply region.

Historical Steam Coal Prices
(Nominal dollars per ton, free on board at mine)

Pounds
Sulfur
Btu Dioxide Historical
Per Per Million ---------------------------
Region/Basin Pound Btu 1997 1998 1999 2000
------------ ------ ----------- ------ ------ ------ ------

Southern Powder River Basin..... 8,800 0.5 $ 4.26 $ 4.63 $ 4.59 $ 4.55
Southern Powder River Basin..... 8,500 0.8 3.39 3.51 3.64 3.60
Central Appalachia.............. 12,500 1.5 23.55 24.07 23.20 23.25
Northern Appalachia............. 13,300 3.5 24.32 23.52 21.17 22.50
Western Kentucky................ 11,200 5.0 21.00 21.11 20.79 21.25
Indiana......................... 11,000 5.0 16.32 16.24 16.42 17.00

--------
Source: Energy Ventures Analysis, Inc., February 2001.

According to Energy Ventures Analysis, Inc., prices in April 2001 for
representative 8,800 Btu Powder River Basin coal and 12,500 Btu Central
Appalachian coal were approximately $12.50 per ton and $44.00 per ton,
respectively. Moreover, we expect prices to remain above their historical
levels due to several factors, including the high cost of competing fuels such
as natural gas, higher electricity demand and the availability of excess coal-
based electricity generation capacity.

Coal's Competitive Position

Cost Comparison of Fuel Types

Coal generated an estimated 51% of U.S. electricity in 2000. Coal attained
this dominant market share because of its relative low cost and its
availability throughout the United States. The cost of fuel is the largest
variable cost involved in electricity generation. The Energy Information
Administration estimated the relative cost of coal versus other electric
generating fuels as follows:

Average U.S. Energy Prices (including cost of transportation)
(Cost per million Btu)

Electric Generation by Fuel Type 1990 1995 2000E 2001P 2002P
-------------------------------- ----- ----- ----- ----- -----

Coal.............................................. $1.46 $1.32 $1.20 $1.20 $1.19
Oil............................................... 3.32 2.59 4.22 4.03 3.87
Natural Gas....................................... 2.32 1.98 4.22 5.22 5.02

--------
Source: Energy Information Administration, Annual Energy Outlook 2000 and 1999
Annual Energy Review.

During 2000, the price of natural gas more than quadrupled, which increase
is not fully reflected in the above table.

In addition to fuel, electricity generators incur other variable and fixed
costs in electricity production. On average, the total cost per megawatt-hour
of coal-based electricity generation is less expensive than for electricity
generated from natural gas or nuclear power. According to Resource Data
International, 19 of the 25 major electric generation plants with the lowest
operating costs in the United States in 1999 were coal-based. Hydroelectric
power is inexpensive but is limited geographically, and there are few suitable
sites for new hydroelectric dams. Moreover, because coal-based electric
generating plants, on average, are operating below maximum capacity, these
plants can increase their electricity generation without substantial
incremental capital costs, thus improving coal's overall cost competitiveness.
The following table illustrates the relative total cost of coal-based
generation relative to other electric generating sources.

Average Total Generating Costs(/1/)

1990 1995 1999
------ ------ ------

Coal....................................................... $20.06 $18.73 $17.62
Nuclear.................................................... 22.36 20.02 17.95
Hydro...................................................... 3.04 3.68 3.94
Natural Gas................................................ 28.84 25.84 30.57

--------
Source: Resource Data International Power Dat, FERC Form 1 Data.
(1) Average annual generating costs per megawatt-hour produced for all U.S.
electric generating plants; costs include fuel and operation and
maintenance, but exclude depreciation.

Deregulation of the Electricity Generation Industry

In October 1992, Congress enacted the Energy Policy Act of 1992. To
stimulate competition in the electricity market, that legislation gave
wholesale suppliers access to the transmission lines of U.S. electricity
generators. In April 1996, the Federal Energy Regulatory Commission issued the
first of a series of orders establishing rules providing for open access to
electricity transmission systems. The federal government is currently exploring
a number of options concerning utility deregulation. Individual states are also
proceeding with their own deregulation initiatives.

The pace of deregulation differs significantly from state to state. To date,
23 states and Washington, D.C. have enacted programs leading to the
deregulation of the electricity market; 19 other states are considering

similar programs. Due to the uncertainty around the timing and implementation
of deregulation, it is difficult to predict the impact on individual
electricity generators. This uncertainty has increased due to the recent energy
crisis in California, where market inefficiencies and supply and demand
imbalances have created electricity supply shortages. The crisis has slowed
deregulation activity in other states and at the federal level.

If ultimately implemented, full-scale deregulation of the power industry is
expected to enable both industrial and residential customers to shop for the
lowest-cost supply of power and the best service available. This fundamental
change in the power industry is expected to compel electricity generators to be
more aggressive in developing and defending market share, to be more focused on
their pricing and cost structures and to be more flexible in reacting to
changes in the market.

A possible consequence of deregulation is downward pressure on fuel prices.
However, because of coal's cost advantage and because some coal-based
generating facilities are underutilized in the current regulated electricity
market, we believe that additional coal demand would arise as electricity
markets are deregulated if the most efficient coal-based power plants are
operated at greater capacity.

BUSINESS

All information in "Business" reflects the recent divestiture of our
Australian operations.

We are the largest private-sector coal company in the world. Our sales of
181.6 million tons of coal in fiscal year 2001 accounted for more than 16% of
all U.S. coal sales and were more than 50% greater than the sales of our
closest competitor. We own majority interests in 34 coal operations located
throughout all major U.S. coal producing regions, with 66% of our coal sales in
fiscal year 2001 shipped from the western United States and the remaining 34%
from the eastern United States. Most of our production in the western United
States is low sulfur coal from the Powder River Basin. Our overall western U.S.
coal production increased from 37.0 million tons in fiscal year 1990 to 119.7
million tons in fiscal year 2001, representing a compounded annual growth rate
of 11%.

Transformation of Peabody

Fiscal Year
-------------- Percent
1990 2001 Improvement
------ ------ -----------

Market Opportunities

The U.S. coal industry continues to fuel more electricity generation than
all other energy sources combined. In 2000, coal-based plants generated an
estimated 51% of the nation's electricity, followed by nuclear (20%), gas-
fired (16%) and hydroelectric (8%) units. We believe that electricity
deregulation and the resulting competition for cost-efficient energy will
strengthen demand for coal. We also believe that U.S. and world coal
consumption will continue to grow as coal-based generating plants utilize
their excess capacity and new coal-based plants are constructed. Coal is an
attractive fuel for electricity generation because it is:

. Abundant: Coal makes up more than 85% of fossil fuel reserves in the
United States. The nation has an estimated 250-year supply of coal,
based on current usage rates.

. Low-Cost: At an average delivered price of $1.20 per million Btu, coal's
cost advantage over natural gas continued to widen in 2000, during which
the average delivered price of natural gas was $4.22 per million Btu,
and at times exceeded $10.00 per million Btu. In 1999, 19 of the 25
lowest-cost major generating plants in the United States were coal-
based.

. Increasingly Clean: Aggregate pollution from U.S. coal-based plants has
declined significantly since 1970, even as the amount of coal used for
electricity generation has tripled.

Business Strengths

We believe our strengths will enable us to enhance our industry-leading
position and increase shareholder value.

We are the world's largest private-sector producer and marketer of coal,
and the largest reserve holder of any U.S. coal company. In 2001, our U.S.
market share was over 16% and our sales volume was more than 50% greater than
that of our closest competitor. Our reserve base of 9.3 billion tons of proven
and probable coal reserves is the largest of any U.S. coal producer, and we
believe that we have significant expansion opportunities in areas adjacent to
our existing reserves. Based on current production rates, we believe our
reserves could last for more than 50 years.

We are the largest producer and marketer of low sulfur coal in the world,
with the number one position in the Southern Powder River Basin, part of the
fastest growing U.S. coal producing region. As of March 1, 2001, 4.4 billion
tons of our proven and probable coal reserves were low in sulfur, which is
substantially greater than the low sulfur reserves of any of our competitors.
During fiscal year 2001, we were the largest seller of low sulfur coal in the
United States, selling 146.3 million tons of low sulfur coal, which was 81% of
our total sales volume for that period. More than half of our total sales
volume comes from the Southern Powder River Basin, where we have a 30% market
share. The Southern Powder River Basin has very low sulfur coal and has
experienced a 24% increase in production volume, from 261 million tons in 1996
to 323 million tons in 2000, compared to stable total U.S. production volumes
during that period. The increased demand for low sulfur coal has been driven
primarily by the Clean Air Act Amendments of 1990, which place limits on
sulfur dioxide and other emissions from coal-based power plants. To date, the
majority of affected electricity generators have chosen to convert to low
sulfur coal rather than install scrubbers to reduce sulfur dioxide emissions
from high sulfur coal.

We have a large portfolio of long-term coal supply agreements and have
substantial future production available for sale at market prices. We have a
large portfolio of coal supply agreements that provides us with reliable
revenues. As of March 31, 2001, nearly one billion tons of our future coal
production were committed under these contracts. During the first four months
of 2001, we entered into commitments to sell four million tons of coal in
2001, 31 million tons of coal in 2002, 21 million tons of coal in 2003 and 19
million tons of coal in 2004, much of which were at prices substantially above
prior-year levels. We also have a significant amount of production that will
be available for sale in the future, which could enable us to benefit from
anticipated favorable market prices for coal. As of April 30, 2001, we had
approximately 37 million tons, 80 million tons and 111 million tons of
expected production available for sale at market-based prices in 2002, 2003
and 2004, respectively.

We are one of the most productive and lowest-cost providers of coal in the
United States. Through a shift to lower-cost operations, economies of scale,
investments in advanced production technologies and centralized purchasing,
information technology systems, marketing programs and land management
functions, we are able to

achieve operating and corporate efficiencies. From fiscal year 1990 to fiscal
year 2001, we increased our sales volume from 93.3 million tons to 181.6
million tons, while reducing the number of employees in our operations from
approximately 10,700 to approximately 6,100. During this period, we also
increased our average productivity, in terms of coal production per miner
shift, by 273%.

We serve a broad range of customers with mining operations located
throughout all major U.S. coal producing regions. We own majority interests in
34 active coal operations in the United States, selling coal to more than 290
electric generating and industrial plants in the United States. We supply coal
to customers in 12 countries. In fiscal year 2001, approximately 66% of our
sales volume came from the western United States and 34% came from the eastern
United States. Because of the geographical mix of our reserves and production,
we can source coal from multiple regions, giving us greater flexibility to meet
the needs of our customers and reduce their transportation costs. Our
geographical diversity also enables us to capitalize on opportunities to
remarket and trade coal.

We are a leader in reclamation management and have received numerous state
and national awards for our commitment to environmental excellence. We have a
long-standing commitment to protecting the environment. We consistently restore
mined lands to a condition as good as, or better than, their condition prior to
mining. As a result of our efforts, we have received more than 30 state and
national reclamation awards over the past five years. In 2000, we received an
unprecedented six of 12 Department of Interior reclamation excellence awards
given to U.S. mining companies.

Our management team has a proven record of success and is incentivized to
maximize shareholder value. Our management team has a proven record of
increasing productivity and reducing costs, making strategic acquisitions,
meeting financial commitments and developing and maintaining strong customer
relationships. Our senior executives, who have an average of 19 years of
experience in the coal industry and 14 years of experience with our company,
have transformed us into a predominantly low sulfur, low-cost coal company. Our
senior management and employees are meaningfully invested in our performance
through their 15.7% fully-diluted ownership of our company (before this
offering), which gives them an ongoing stake in the creation of shareholder
value.

Business Strategy

To maximize shareholder value and enhance our position as a premier low-cost
energy provider, we seek to implement three core strategies:

Expand to serve growth markets. We have a proven record as a transaction-
oriented company and an industry consolidator. During the 1990s, we
completed 15 acquisitions, significantly expanding our presence in the fast-
growing Powder River Basin and acquiring low-cost, lower sulfur operations
and reserves throughout other regions of the United States.
We intend to:

. Pursue strategic acquisitions, as well as synergistic acquisitions
in our core operating regions where we can use our skills, existing
assets, coal supply contracts and customer relationships;

. Develop our existing reserve base to serve attractive markets, while
actively maintaining a blend of long-term sales contracts and
uncommitted production to provide earnings stability and position us
to benefit from improving market conditions; and

. Expand our activities in high-growth coal-related businesses,
including coal trading, coalbed methane production and the
development of new coal-based generation capacity.

Manage safe, low-cost, environmentally conscious operations. In the past
decade, we have lowered our average cost per ton, increased labor
productivity, improved our safety performance and earned recognition as a
leader in environmental management.

We intend to:

. focus our capital investments in regions where we can be a low-cost
producer;

. continuously reduce our costs using larger, more efficient mining
equipment, optimizing process flows and leveraging our economies of
scale through centralized administrative functions;

. implement innovative employee practices, including improved labor
flexibility and performance-based incentives;

. improve upon our strong safety record; and

. remain committed to environmental excellence through superior
reclamation practices.

Create innovative solutions to meet customers' changing needs. Our
geographically diverse asset portfolio and superior market knowledge enable
us to provide customized products, services and solutions to our customer
network of more than 290 electric generating and industrial plants in 12
countries and 37 states.

We intend to:

. use our geographically diverse asset portfolio to flexibly meet
customers' changing needs by offering multiple coal products from
various points of origin;

. capitalize on our extensive customer relationships, superior market
knowledge and ability to access coal produced by both us and third
parties to maximize revenue opportunities across multiple markets;
and

. expand our coal trading and provide customized services, including
third-party coal contract restructuring and transportation
logistical support.

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

We were incorporated in Delaware in 1998, at which time we acquired our
operating companies, whose predecessors date from 1883.

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.

[GRAPHIC APPEARS HERE]

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

Powder River Basin Operations

We control approximately 3.0 billion tons of coal reserves in the Southern
Powder River Basin, the largest and fastest growing major U.S. coal-producing
region. We own and manage two active low sulfur, non-union surface mining
complexes in Wyoming that sold approximately 99.2 million tons of coal during
fiscal year 2001, or approximately 50% of our total coal sales. The North
Antelope/Rochelle and Caballo mines are serviced by both major western
railroads, the Burlington Northern & Santa Fe and the Union Pacific.

Our Wyoming Powder River Basin reserves are classified as surface mineable,
subbituminous coal with seam thickness varying from 70 to 105 feet. The sulfur
content of the coal in current production ranges from 0.2% to 0.4% and the heat
value ranges from 8,500 to 8,900 Btu per pound.

We also operate the Big Sky Mine in Montana in the Northern Powder River
Basin. Coal is shipped from this mine to customers in the upper Midwest by the
Burlington Northern & Santa Fe railroad.

North Antelope/Rochelle

The North Antelope/Rochelle Mine is located 65 miles south of Gillette,
Wyoming. This mine is the largest and most productive in the United States,
selling 73.1 million tons during fiscal year 2001. The North Antelope/Rochelle
Mine produces premium quality coal with a sulfur content averaging 0.2% and a
heat value

ranging from 8,500 to 8,900 Btu per pound. The North Antelope/Rochelle Mine
produces the lowest sulfur coal in the United States, using a dragline along
with six truck-and-shovel fleets. We are adding a second dragline in 2002 to
improve productivity.

Caballo

The Caballo Mine is located 20 miles south of Gillette, Wyoming. During
fiscal year 2001, it sold approximately 26.1 million tons of compliance coal.
Caballo is a truck-and-shovel operation with a coal handling system that
includes two 12,000-ton silos and two 11,000-ton silos.

Big Sky

The Big Sky Mine is located in the northern end of the Powder River Basin
near Colstrip, Montana, and uses dragline mining equipment. The mine sold 1.7
million tons of medium sulfur coal during fiscal year 2001. Coal is shipped by
rail to several major electric generating customers in the upper midwestern
United States. This mine is near the exhaustion of its economically recoverable
reserves, and we may close it in the next several years, depending upon market
and mining conditions. Hourly workers at the Big Sky Mine are members of the
United Mine Workers of America.

Southwest Operations

We own and manage four mines in the western bituminous coal region, two in
Arizona, one in each of Colorado and New Mexico. The Colorado and Arizona mines
supply primarily compliance coal and the New Mexico mine supplies medium sulfur
coal under long-term coal supply agreements to electricity generating stations
in the region. Together, these mines sold 19.7 million tons of coal during
fiscal year 2001.

Black Mesa

The Black Mesa Mine, which is located on the Navajo Nation and Hopi Tribe
reservations in Arizona, uses two draglines and sold 4.8 million tons of coal
during fiscal year 2001. The Black Mesa Mine coal is crushed, mixed with water
and then transported 273 miles through the underground Black Mesa Pipeline
(which is owned by a third party) to the Mohave Generating Station near
Laughlin, Nevada, operated and partially owned by Southern California Edison.
The mine and the pipeline were designed to deliver coal exclusively to the
plant, which has no other source of coal. The Mohave Generating Station coal
supply agreement extends until 2005, with the customer's option to extend the
term up to an additional 15 years, subject to agreement on specified terms.
Hourly workers at this mine are members of the United Mine Workers of America.

Kayenta

The Kayenta Mine is adjacent to the Black Mesa Mine and uses three draglines
in three mining areas. It sold approximately 8.0 million tons of coal during
fiscal year 2001. The Kayenta Mine coal is crushed, then carried 17 miles by
conveyor belt to storage silos where it is loaded on to a private rail line and
transported 83 miles to the Navajo Generating Station, operated by the Salt
River Project near Page, Arizona. The mine and the railroad were designed to
deliver coal exclusively to the power plant, which has no other source of coal.
The Navajo coal supply agreement extends until 2011. Hourly workers at this
mine are members of the United Mine Workers of America.

Seneca

The Seneca Mine near Hayden, Colorado shipped 1.6 million tons of compliance
coal during fiscal year 2001, operating with two draglines in two separate
mining areas. The mine's coal is hauled by truck to the nearby Hayden
Generating Station, operated by the Public Service of Colorado, under a coal
supply agreement that extends until 2011. Hourly workers at this mine are
members of the United Mine Workers of America.

Lee Ranch Coal Company

The Lee Ranch Mine, located near Grants, New Mexico, sold approximately 5.3
million tons of medium sulfur coal during fiscal year 2001. Lee Ranch shipped
the majority of its coal to two customers in Arizona and New Mexico under coal
supply agreements extending until 2010 and 2014, respectively. Lee Ranch is a
non-union surface mine that uses a combination of dragline and truck-and-shovel
mining techniques. Lee Ranch is currently expanding its annual production
capacity by approximately 2.0 million tons that we plan to sell under long-term
agreements to two new customers.

Appalachia Operations

We own and manage five operating units and related facilities in West
Virginia. During fiscal year 2001, these operations sold approximately 18.5
million tons of compliance, medium sulfur and high sulfur steam and
metallurgical coal to customers in the United States and abroad. Hourly workers
at these operations are members of the United Mine Workers of America.

Big Mountain/White's Branch Operating Unit

The Big Mountain/White's Branch Operating Unit is based near Prenter, West
Virginia. In August 2000, we closed the Robin Hood No. 9 Mine after depleting
its mineable reserves and the White's Branch Mine began production. During
fiscal year 2001, the Big Mountain No. 16, Robin Hood No. 9 and White's Branch
mines sold approximately 2.4 million tons of steam coal. Big Mountain No. 16
and White's Branch are underground mines using continuous mining equipment.
Processed coal is loaded on the CSX railroad.

Harris Operating Unit

The Harris Operating Unit consists of the Harris No. 1 Mine near Bald Knob,
West Virginia, which sold approximately 4.2 million tons of compliance coal
during fiscal year 2001. This mine uses both longwall and continuous mining
equipment.

Rocklick Operating Unit and Contract Mines

The Rocklick preparation plant, located near Wharton, West Virginia,
processes coal produced by the Harris Mine and contract mining companies from
coal reserves that we control. This preparation plant shipped approximately 7.7
million tons of steam and metallurgical coal during fiscal year 2001, including
4.2 million tons related to the Harris Operating Unit. Processed coal is loaded
at the plant site on the CSX railroad or transferred via conveyor to our
Kopperston loadout facility and loaded on the Norfolk Southern railroad.

Wells Operating Unit

The Wells Operating Unit, in Boone County, West Virginia, sold approximately
3.7 million tons of metallurgical and steam coal during fiscal year 2001. The
unit consists of the Lightfoot No. 2 Mine, contract mines and the Wells
Preparation Plant, located near Wharton, West Virginia. The mine uses
continuous mining equipment to produce coal from reserves we own. Processed
coal is loaded on the CSX railroad.

Federal No. 2 Mine

The Federal No. 2 Mine, near Fairview, West Virginia, uses longwall mining
equipment and shipped approximately 4.8 million tons of steam coal during
fiscal year 2001. Coal shipped from the Federal No. 2 Mine has a sulfur content
only slightly above that of medium sulfur coal and has an above average heating
content. As a result, it is more marketable than some other medium sulfur
coals. The CSX and Norfolk Southern railroads jointly serve the mine.

Kanawha Eagle Coal Joint Venture

We have a minority interest in Kanawha Eagle Coal, LLC, which owns a deep
mine, a preparation plant and barge-and-rail loading facilities near Marmet,
West Virginia. The union-free mine uses continuous mining equipment and shipped
1.1 million tons during fiscal year 2001.

Midwest Operations

We own and operate five mines in the midwestern United States, which
collectively sold 8.8 million tons of coal during fiscal year 2001. Our midwest
operations include three underground and two surface mines, along with five
preparation plants and four barge loading facilities, located in western
Kentucky, southern Illinois and southwestern Indiana. We ship coal from these
mines primarily to electricity generators in the midwestern United States, and
we sell some coal to industrial customers that generate their own power. Some
of our hourly workers in this region are members of the United Mine Workers of
America; however, some of our mines in this region operate union-free.

We control 16 additional mines in the midwestern United States through our
81.7% joint venture interest in Black Beauty, as discussed below.

Black Beauty Coal Company

We own 81.7% of Black Beauty, the largest coal company in the Midwest
region, which operates ten mines in Indiana and also has interests in one mine
in east-central Illinois, four mines in southern Illinois and one mine in
western Kentucky. Together these operations sold 22.9 million tons of
compliance, medium sulfur and high sulfur steam coal during fiscal year 2001.
We purchased a one-third interest in Black Beauty in 1994, and increased our
interest to 43.3% in 1998 and 81.7% in 1999. Black Beauty Resources, Inc.,
owned by certain members of Black Beauty's management team, owns the remaining
interest.

Black Beauty's principal mines include Air Quality No. 1, Farmersburg,
Francisco and two mines in Somerville, Indiana. Air Quality No. 1 is an
underground coal mine located near Monroe City, Indiana that shipped 1.7
million tons of compliance coal during fiscal year 2001. Farmersburg is a
surface mine in Vigo and Sullivan counties in Indiana that sold 4.1 million
tons of medium sulfur coal during fiscal year 2001. Francisco, located in
Gibson county, Indiana, sold 2.2 million tons during fiscal year 2001 and the
two Somerville mines, also located in Gibson county, shipped a total of 4.8
million tons in fiscal year 2001. All of Black Beauty's mines operate union-
free.

Black Beauty owns a 75%-equity interest in Sugar Camp Coal, LLC, a 5.0
million-ton per year complex comprised of two surface mines, Wildcat Hills and
Cottage Grove, and one underground mine, Eagle Valley, located in southern
Illinois. Sugar Camp also owns Arclar Coal Company, which operates one
underground mine, Big Ridge, in southern Illinois that currently sells 1.8
million tons per year. The contract work forces at Eagle Valley and Big Ridge
are both represented under non-UMWA labor agreements.

Camp Operating Unit

The Camp Operating Unit, located near Morganfield, Kentucky, currently
operates the Camp No. 11 Mine, an underground mine, and a large preparation and
barge loading facility. The Camp No. 1 Mine exhausted its economically
recoverable reserves and ceased operations in October 2000. Together, these
operations sold 5.4 million tons of coal during fiscal year 2001. The Camp No.
11 Mine uses both longwall and continuous mining equipment. We sell most of the
production under contract to the Tennessee Valley Authority.

Midwest Operating Unit

The Midwest Operating Unit near Graham, Kentucky sold 1.3 million tons of
coal during fiscal year 2001. The unit currently includes the Gibraltar surface
mining operation, which uses truck-and-shovel equipment, and the Gibraltar
Highwall Mine, which uses continuous mining equipment. The unit used to include
the Martwick mine; however in November 2000, the Martwick Mine exhausted its
economically recoverable reserves and ceased operations, and the Gibraltar
Highwall mine began operations to replace the production. We sell coal from
these mines under contract to the Tennessee Valley Authority.

Patriot Coal Company

Patriot Coal Company operates Patriot, a surface mine, and Freedom, an
underground mine, in Henderson County, Kentucky, and sold approximately 2.1
million tons of coal during fiscal year 2001. The underground mine uses
continuous mining equipment, and the surface mine uses truck-and-shovel
equipment. Patriot Coal Company also operates a preparation plant and a dock.
These mines operate union-free.

Properties

Coal Reserves

We had an estimated 9.3 billion tons of proven and probable coal reserves as
of March 1, 2001, of which approximately 41% is compliance coal and 59% is non-
compliance coal. We own approximately 45% of these reserves and lease the
remaining 55%. Compliance coal is defined by Phase II of the Clean Air Act as
coal having sulfur dioxide content of 1.2 pounds or less per million Btu.
Electricity generators are able to use coal that exceeds these specifications
by using emissions reduction technology, using emissions allowance credits or
blending higher sulfur coal with lower sulfur coal.

Below is a table summarizing the locations and reserves of our major
operating units.

Proven and
Probable Reserves
as of
March 1, 2001(/1/)
------------------
Owned Leased Total
Operating Regions Locations Tons Tons Tons
----------------- --------- ----- ------ -----
(Tons in millions)

Powder River Basin Wyoming and Montana................ 190 3,147 3,337
Southwest Arizona, Colorado and New Mexico... 672 583 1,255
Appalachia West Virginia...................... 310 413 723
Midwest Illinois, Indiana and Kentucky..... 3,030 1,001 4,031
----- ----- -----
Total............................................... 4,202 5,144 9,346
===== ===== =====

--------
(1) Reserves have been adjusted to take into account estimated losses involved
in producing a saleable product.

Proven and probable coal reserves are classified as follows:

Proven Reserves--Reserve estimates in this category have the highest
degree of geologic assurance. Proven coal lies within one-quarter mile of a
valid point of measurement or point of observation (such as exploratory
drill holes or previously mined areas) supporting such measurements. The
sites for thickness measurement are so closely spaced, and the geologic
character is so well defined, that the average thickness, areal extent,
size, shape and depth of coalbeds are well established.

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

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

We prepare our reserve estimates based on geological data assembled and
analyzed by our staff, which includes various geologists and engineers. We
periodically update our reserve estimates to reflect production of coal from
the reserves and new drilling or other data received. Accordingly, reserve
estimates will change from

time to time to reflect mining activities, analysis of new engineering and
geological data, changes in reserve holdings, modification of mining methods
and other factors. We maintain reserve information, including the quantity and
quality (where available) of reserves as well as production rates, surface
ownership, lease payments and other information relating to our coal reserve
and land holdings, through a computerized land management system that we
developed.

Our reserve estimates are predicated on information obtained from our
extensive drilling program, which totals nearly 500,000 individual drill holes.
We compile data from individual drill holes in a computerized drill-hole system
from which the depth, thickness and, where core drilling is used, the quality
of the coal are determined. The density of the drill pattern determines whether
the reserves will be classified as proven or probable. The drill hole data are
then input into our computerized land management system, which overlays the
geological data with data on ownership or control of the mineral and surface
interests to determine the extent of our reserves in a given area. In addition,
we periodically engage independent mining and geological consultants to review
estimates of our coal reserves. The most recent of these reviews, which was
completed in March 2001, included a review of the procedures used by us to
prepare our internal estimates, verification of the accuracy of selected
property reserve estimates and retabulation of reserve groups according to
standard classifications of reliability. This study, completed by Marshall
Miller & Associates, confirmed that we controlled approximately 9.5 billion
tons of proven and probable reserves as of April 1, 2000. After adjusting for
production through March 1, 2001, proven and probable reserves totalled 9.3
billion tons.

We have numerous federal coal leases that are administered by the Department
of the Interior under the Federal Coal Leasing Amendments Act of 1976. These
leases cover our principal reserves in Wyoming and other reserves in Montana
and Colorado. Each of these leases continues indefinitely, provided there is
diligent development of the property and continued operation of the related
mine or mines. The Bureau of Land Management has asserted the right to adjust
the terms and conditions of these leases, including rent and royalties, after
the first 20 years of their term and at 10-year intervals thereafter. Annual
rents under our federal coal leases are now set at $3.08 per acre. Production
royalties on federal leases are set by statute at 12.5% of the gross proceeds
of coal mined and sold for surface-mined coal and 8% for underground-mined
coal. The federal government limits by statute the amount of federal land that
may be leased by any company and its affiliates at any time to 75,000 acres in
any one state and 150,000 acres nationwide. As of March 31, 2001, we leased or
applied to lease 23,386 acres of federal land in Colorado, 11,252 acres in
Montana, 30,167 acres in Wyoming for a total of 64,805 nationwide.

Similar provisions govern three coal leases with the Navajo and Hopi Indian
tribes. These leases cover coal contained in 65,000 acres of land in northern
Arizona lying within the boundaries of the Navajo Nation and Hopi Indian
reservations. We also lease coal-mining properties from various state
governments.

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

The terms of our private leases are normally extended by active production
on or near the end of the lease term. Leases containing undeveloped reserves
may expire or these leases may be renewed periodically. With a portfolio of
approximately 9.3 billion tons, we believe that we have sufficient reserves to
replace capacity from depleting mines for the foreseeable future and that our
reserve base is one of our strengths. We believe that the current level of
production at our major mines is sustainable.

Consistent with industry practice, we conduct only limited investigation of
title to our coal properties prior to leasing. Title to lands and reserves of
the lessors or grantors and the boundaries of our leased properties are not
completely verified until we prepare to mine those reserves.

The following chart provides a summary, by mining complex, of production for
fiscal years 1999, 2000 and 2001, tonnage of coal reserves that is assigned to
our operating mines, our property interest in those reserves and other
characteristics of the facilities.

Production and Assigned Reserves (/1/)
(Tons in millions)

Production Sulfur Content(/2/)
----------------------------- --------------------------------------------
greater than
less than 1.2 to greater than
1.2 pounds 2.5 pounds 2.5 pounds As-
sulfur dioxide sulfur dioxide sulfur dioxide received
Fiscal Fiscal Fiscal per per per Btu per
Mining Complex Year 1999 Year 2000 Year 2001 Type of Coal million Btu million Btu million Btu pound(/3/)
-------------- --------- --------- --------- ------------------- -------------- -------------- -------------- ----------

Northern
Appalachia:
Federal No. 2... 4.8 4.2 4.7 Steam -- -- 54.5 13,375
----- ----- ----- ------- ----- -----
Northern
Appalachia...... 4.8 4.2 4.7 -- -- 54.5
Southern
Appalachia:
Big
Mountain/White's
Branch.......... 1.9 2.1 2.0 Steam 22.4 9.1 -- 12,319
Harris.......... 3.6 3.2 3.9 Steam/Metallurgical 22.1 1.7 -- 13,550
Rocklick........ 3.8 3.3 3.2 Steam/Metallurgical 19.3 8.4 -- 12,900
Wells........... 2.8 2.0 1.6 Steam/Metallurgical 16.9 5.8 -- 13,630
----- ----- ----- ------- ----- -----
Southern
Appalachia...... 12.1 10.5 10.7 80.7 25.0 --
Midwest:
Camp(/4/)....... 6.4 6.4 5.4 Steam -- -- 129.2 11,525
Hawthorn(/5/)... 3.1 2.1 -- Steam N/A N/A N/A N/A
Lynnville(/6/).. 3.0 2.2 -- Steam N/A N/A N/A N/A
Marissa(/7/).... 4.2 2.3 -- Steam N/A N/A N/A N/A
Midwest......... 1.2 1.2 1.2 Steam -- -- 2.5 10,166
Patriot......... 1.6 1.9 2.0 Steam -- -- 51.3 10,600
Black Beauty:
Air Quality No.
1............... 1.7 1.8 1.7 Steam 58.3 -- -- 11,164
Riola No.
1(/8/).......... -- 0.4 1.0 Steam -- -- 11.6 10,553
Cedar
Creek(/9/)...... 0.3 -- -- Steam N/A N/A N/A N/A
Sugar
Ridge(/10/)..... -- -- 0.1 Steam -- 0.9 -- 11,616
Francisco....... 2.9 2.8 2.2 Steam -- -- 13.9 11,513
Eel(/11/)....... 0.2 -- -- Steam N/A N/A N/A N/A
Columbia........ 1.0 0.7 0.8 Steam -- 0.2 -- 11,519
Discovery(/12/).. 0.6 0.6 0.3 Steam -- -- 2.3 10,660
Farmersburg..... 3.2 3.5 4.1 Steam -- 27.0 -- 10,814
Birdwell/Miller
Creek........... 1.6 1.4 0.9 Steam -- -- 2.9 11,591
Somerville
Central(/13/)... -- -- 2.0 Steam -- -- 17.8 11,124
Somerville
North........... 1.9 2.0 2.8 Steam -- -- 5.8 11,119
Viking.......... 1.3 1.3 1.0 Steam -- -- 1.6 11,675
Sugar Camp
Coal............ 3.6 5.6 5.0 Steam -- -- 17.5 12,148
West
Fork(/14/)...... 0.5 0.5 0.2 Steam N/A N/A N/A N/A
Lyons(/15/)..... 0.1 -- -- Steam N/A N/A N/A N/A
Deanefield...... -- 0.4 0.8 Steam -- -- 3.3 11,120
----- ----- ----- ------- ----- -----
Midwest......... 38.3 37.0 31.5 58.3 28.1 259.7
Powder River
Basin:
Big Sky......... 3.1 2.4 1.7 Steam -- 33.1 28.6 8,800
North
Antelope/Rochelle.. 66.6 68.3 72.3 Steam 1,507.3 -- -- 8,750
Caballo......... 26.9 26.1 25.6 Steam 850.0 95.3 -- 8,500
Rawhide(/16/)... 3.3 -- -- Steam N/A N/A N/A N/A
----- ----- ----- ------- ----- -----
Powder River
Basin........... 99.9 96.9 99.6 2,357.3 128.4 28.6
Southwest:
Black Mesa...... 4.4 4.5 4.9 Steam 91.5 2.6 -- 10,671
Kayenta......... 6.9 7.6 8.5 Steam 253.4 80.4 -- 10,717
Lee Ranch....... 5.0 4.9 5.2 Steam -- 176.6 -- 9,200
Seneca.......... 1.6 1.4 1.5 Steam 15.7 -- -- 10,408
----- ----- ----- ------- ----- -----
Southwest....... 17.8 18.5 20.1 360.6 259.6 --
----- ----- ----- ------- ----- -----
Total............ 173.0 167.1 166.6 2,856.9 441.1 342.8
===== ===== ===== ======= ===== =====

As of March 1, 2001
---------------------------------------------------
Assigned
Proven and
Mining Complex Probable Reserves Owned Leased Surface Underground
-------------- ----------------- ----- ------- ------- -----------

Northern
Appalachia:
Federal No. 2... 54.5 54.5 -- -- 54.5
----------------- ----- ------- ------- -----------
Northern
Appalachia...... 54.5 54.5 -- -- 54.5
Southern
Appalachia:
Big
Mountain/White's
Branch.......... 31.5 -- 31.5 -- 31.5
Harris.......... 23.8 -- 23.8 -- 23.8
Rocklick........ 27.7 -- 27.7 -- 27.7
Wells........... 22.7 -- 22.7 -- 22.7
----------------- ----- ------- ------- -----------
Southern
Appalachia...... 105.7 -- 105.7 -- 105.7
Midwest:
Camp(/4/)....... 129.2 2.8 126.4 -- 129.2
Hawthorn(/5/)... N/A N/A N/A N/A N/A
Lynnville(/6/).. N/A N/A N/A N/A N/A
Marissa(/7/).... N/A N/A N/A N/A N/A
Midwest......... 2.5 1.7 0.8 2.0 0.5
Patriot......... 51.3 -- 51.3 3.2 48.1
Black Beauty:
Air Quality No.
1............... 58.3 0.5 57.8 -- 58.3
Riola No.
1(/8/).......... 11.6 -- 11.6 -- 11.6
Cedar
Creek(/9/)...... N/A N/A N/A N/A N/A
Sugar
Ridge(/10/)..... 0.9 -- 0.9 -- 0.9
Francisco....... 13.9 3.2 10.7 13.9 --
Eel(/11/)....... N/A N/A N/A N/A N/A
Columbia........ 0.2 -- 0.2 0.2 --
Discovery(/12/).. 2.3 0.1 2.2 -- 2.3
Farmersburg..... 27.0 23.5 3.5 27.0 --
Birdwell/Miller
Creek........... 2.9 -- 2.9 2.9 --
Somerville
Central(/13/)... 17.8 17.7 0.1 17.8 --
Somerville
North........... 5.8 5.8 -- 5.8 --
Viking.......... 1.6 -- 1.6 1.6 --
Sugar Camp
Coal............ 17.5 9.1 8.4 4.2 13.3
West
Fork(/14/)...... N/A N/A N/A N/A N/A
Lyons(/15/)..... N/A N/A N/A N/A N/A
Deanefield...... 3.3 -- 3.3 3.3 --
----------------- ----- ------- ------- -----------
Midwest......... 346.1 64.4 281.7 81.9 264.2
Powder River
Basin:
Big Sky......... 61.7 -- 61.7 61.7 --
North
Antelope/Rochelle.. 1,507.3 -- 1,507.3 1,507.3 --
Caballo......... 945.3 -- 945.3 945.3 --
Rawhide(/16/)... N/A N/A N/A N/A N/A
----------------- ----- ------- ------- -----------
Powder River
Basin........... 2,514.3 -- 2,514.3 2,514.3 --
Southwest:
Black Mesa...... 94.1 -- 94.1 94.1 --
Kayenta......... 333.8 -- 333.8 333.8 --
Lee Ranch....... 176.6 174.9 1.7 176.6 --
Seneca.......... 15.7 1.3 14.4 15.7 --
----------------- ----- ------- ------- -----------
Southwest....... 620.2 176.2 444.0 620.2 --
----------------- ----- ------- ------- -----------
Total............ 3,640.8 295.1 3,345.7 3,216.4 424.4
================= ===== ======= ======= ===========

The following chart provides a summary of the amount of our proven and
probable coal reserves in each state, the predominant type of coal mined in
the applicable state, our property interest in the reserves and other
characteristics of the facilities.

Assigned and Unassigned Proven and Probable Coal Reserves(/1/)
As of March 1, 2001

(Tons in millions)

Total Tons Proven and
------------------- Probable Type of
Location Assigned Unassigned Reserves Proven Probable Coal
----------------- -------- ---------- ---------- ------- -------- -------------

Northern Appalachia:
West Virginia... 54.5 -- 54.5 33.2 21.3 Steam
------- ------- ------- ------- -------
Northern
Appalachia...... 54.5 -- 54.5 33.2 21.3
Southern
Appalachia:
Ohio............ -- 78.1 78.1 55.1 23.0 Steam
Steam/
West Virginia... 105.7 484.6 590.3 414.8 175.5 Metallurgical
------- ------- ------- ------- -------
Southern
Appalachia...... 105.7 562.7 668.4 469.9 198.5
Midwest:
Illinois........ -- 2,202.8 2,202.8 1,041.6 1,161.2 Steam
Indiana......... -- 333.7 333.7 213.2 120.5 Steam
Kentucky........ 183.3 866.6 1,049.9 625.4 424.5 Steam
Black Beauty
Coal Company
(Illinois,
Indiana,
Kentucky)....... 162.8 270.6 433.4 182.2 251.2 Steam
Missouri........ -- 11.9 11.9 10.7 1.2 Steam
------- ------- ------- ------- -------
Midwest......... 346.1 3,685.6 4,031.7 2,073.1 1,958.6
Powder River Basin:
Montana......... 61.8 301.4 363.2 334.9 28.3 Steam
Wyoming......... 2,452.5 521.7 2,974.1 2,837.5 136.6 Steam
------- ------- ------- ------- -------
Powder River
Basin........... 2,514.3 823.1 3,337.3 3,172.4 164.9
Southwest:
Arizona......... 427.9 -- 427.9 427.9 -- Steam
Colorado........ 15.8 136.3 152.1 125.4 26.7 Steam
New Mexico...... 176.6 493.9 670.5 209.0 461.5 Steam
Utah............ -- 3.6 3.6 -- 3.6 Steam
------- ------- ------- ------- -------
Southwest....... 620.3 633.8 1,254.1 762.3 491.8
------- ------- ------- ------- -------
Total Proven and
Probable......... 3,640.8 5,705.2 9,346.0 6,510.9 2,835.1
======= ======= ======= ======= =======

Sulfur Content(/2/)
------------------------------------------------
less than greater than greater than
1.2 pounds 1.2 to 2.5 pounds 2.5 pounds
sulfur dioxide sulfur dioxide sulfur dioxide As-Received Reserve Control Mining Method
per per per Btu per --------------- -------------------
Location million Btu million Btu million Btu pound(/17/) Owned Leased Surface Underground
--------------------- -------------- ------------------ -------------- ----------- ------- ------- ------- -----------

Northern Appalachia:
West Virginia... -- -- 54.5 13,540 54.5 -- -- 54.5
-------------- ------------------ -------------- ------- ------- ------- -----------
Northern
Appalachia...... -- -- 54.5 54.5 -- -- 54.5
Southern Appalachia:
Ohio............ -- -- 78.1 11,160 78.1 -- 0.1 78.0
West Virginia... 311.8 249.6 28.9 12,170 177.3 413.0 40.9 549.4
-------------- ------------------ -------------- ------- ------- ------- -----------
Southern
Appalachia...... 311.8 249.6 107.0 255.4 413.0 41.0 627.4
Midwest:
Illinois........ 4.9 65.6 2,132.3 10,520 2,171.8 31.0 53.3 2,149.5
Indiana......... 0.1 3.7 329.9 10,380 274.7 59.0 101.6 232.1
Kentucky........ 0.2 0.3 1,049.4 10,990 396.6 653.3 113.0 936.9
Black Beauty
Coal Company
(Illinois,
Indiana,
Kentucky)....... 62.4 47.6 323.4 11,190 175.3 258.1 112.1 321.3
Missouri........ -- -- 11.9 10,141 11.8 0.1 11.9 --
-------------- ------------------ -------------- ------- ------- ------- -----------
Midwest......... 67.6 117.2 3,846.9 3,030.2 1,001.5 391.9 3,639.8
Powder River Basin:
Montana......... 43.7 179.0 140.5 8,710 189.1 174.1 363.2 --
Wyoming......... 2,792.5 173.8 7.8 8,440 1.0 2,973.1 2,974.1 --
-------------- ------------------ -------------- ------- ------- ------- -----------
Powder River
Basin........... 2,836.2 352.8 148.3 190.1 3,147.2 3,337.3 --
Southwest:
Arizona......... 344.8 83.1 -- 10,510 -- 427.9 427.9 --
Colorado........ 42.8 108.7 0.6 10,430 3.6 148.5 17.3 134.8
New Mexico...... 214.5 406.0 50.0 9,510 664.4 6.1 670.5 --
Utah............ 3.6 -- -- 10,430 3.6 -- -- 3.6
-------------- ------------------ -------------- ------- ------- ------- -----------
Southwest....... 605.7 597.8 50.6 671.6 582.5 1,115.7 138.4
-------------- ------------------ -------------- ------- ------- ------- -----------
Total Proven and
Probable......... 3,821.3 1,317.4 4,207.3 4,201.8 5,144.2 4,885.9 4,460.1
============== ================== ============== ======= ======= ======= ===========

--------
(1) Assigned reserves represent recoverable coal reserves that we have
committed to mine at locations operating as of March 1, 2001. Unassigned
reserves represent coal at suspended locations and coal that has not been
committed, and that would require new mine development, mining equipment
or plant facilities before operations could begin on the property.
(2) Compliance coal is defined by Phase II of the Clean Air Act as coal having
sulfur dioxide content of 1.2 pounds or less per million Btu. Non-
compliance coal is defined as coal having sulfur dioxide content in excess
of this standard. Electricity generators are able to use coal that exceeds
these specifications by using emissions reduction technology, using
emissions allowance credits or blending higher sulfur coal with lower
sulfur coal.
(3) As-received Btu per pound includes the weight of moisture in the coal on
an as-sold basis.
(4) The Camp No. 1 mine at the Camp operating unit was closed in October 2000.
(5) Production at the Hawthorn mine has been suspended since December 1999.
(6) Production at the Lynnville mine has been suspended since December 1999.
(7) The Marissa mine was closed in October 1999.
(8) The Riola No. 1 mine was acquired in October 1999.
(9) The Cedar Creek mine was closed in July 1998.
(10) The Sugar Ridge mine opened in December 2000.
(11) The Eel mine was closed in July 1998.
(12) The Discovery mine was temporarily idled from April 2000 to July 2000.
(13) The Somerville Central mine opened in March 2000.
(14) The West Fork mine closed in August 2000.
(15) The Lyons mine closed in September 1998.
(16) The Rawhide mine operated at reduced production during fiscal year 1999
and suspended production in March 1999.
(17) As-received Btu per pound includes the weight of moisture in the coal on
an as sold basis. The following table reflects the average moisture
content used in the determination of as-received Btu for the region:

Northern Appalachia................................................. 6.0%
Southern Appalachia................................................. 7.0%
Midwest:
Illinois.......................................................... 14.0%
Indiana........................................................... 15.0%
Kentucky.......................................................... 12.5%
Black Beauty Coal Company......................................... 14.5%
Missouri.......................................................... 12.0%
Powder River Basin:
Montana........................................................... 26.5%
Wyoming........................................................... 27.5%
Southwest:
Arizona........................................................... 13.0%
Colorado.......................................................... 14.0%
New Mexico........................................................ 15.5%
Utah.............................................................. 15.5%

Resource Development

We hold approximately 9.3 billion tons of proven and probable coal reserves.
Our Resource Development group constantly reviews this reserve base for
opportunities to generate revenues through the sale of non-strategic coal
reserves and surface land. In addition, we generate revenue through royalties
from coal reserves leased to third parties and farm income from surface land
under third party contracts. The Resource Development group is also actively
pursuing opportunities in the area of coalbed methane extraction in the United
States through a new subsidiary, Peabody Natural Gas, LLC. In January 2001, we
purchased the coalbed methane assets of JN Exploration & Production Limited
Partnership for approximately $10 million.

Long-Term Coal Supply Agreements

We currently have coal supply agreements to sell nearly one billion tons of
coal, with remaining terms ranging from one to 16 years and an average volume-
weighted remaining term of four years. For fiscal year 2001, we sold 85% of our
sales volume under coal supply agreements. During fiscal year 2001, we sold
coal to more than 290 electric generators and industrial plants in
12 countries.

We expect to continue selling a significant portion of our coal under long-
term supply agreements. Our strategy is to selectively renew, or enter into
new, long-term supply contracts when we can do so at favorable prices. Long-
term contracts may be particularly attractive in regions where market prices
are expected to remain stable, with respect to high sulfur coal that would
otherwise not be in great demand or for sales under cost-plus arrangements
serving captive power plants. Prices for coal have recently risen, particularly
in the Powder River Basin and in Appalachia, primarily due to increased prices
for competing fuels and increased demand for electricity.

Typically, customers enter into coal supply agreements to secure reliable
sources of coal at predictable prices, while we seek stable sources of revenue
to support the investments required to open, expand and maintain or improve
productivity at the mines needed to supply these contracts. The terms of coal
supply agreements result from bidding and extensive negotiations with
customers. Consequently, the terms of these contracts typically vary
significantly in many respects, including price adjustment features, price
reopener terms, coal quality requirements, quantity parameters, flexibility and
adjustment mechanics, permitted sources of supply, treatment of environmental
constraints, extension options and force majeure, termination and assignment
provisions.

Each contract sets a base price. Base prices are often adjusted at quarterly
or annual intervals for changes due to inflation and/or changes in actual costs
such as taxes, fees and royalties. The inflation adjustments are measured by
public indices, the most common of which is the implicit price deflator for the
gross domestic product as published by the Department of Commerce. In addition,
most of the contracts contain price adjustments for changes in the laws
regulating the mining, production, sale or use of coal. In the majority of
these contracts, the purchaser has the right to terminate the contract if the
price increases beyond certain limits, although we can usually decrease the
price in order to maintain the contract.

Price adjustment provisions are present in most of our long-term coal
contracts greater than three years in duration. These provisions allow either
party to commence a renegotiation of the contract price at various intervals.
If the parties do not agree on a new price, the purchaser or seller often has
an option to terminate the contract. Some agreements provide that if the
parties fail to agree on a price adjustment caused by cost increases due to
changes in applicable law and regulations, the purchaser may terminate the
agreement, subject to the payment of liquidated damages. Under some contracts,
we have the right to match lower prices offered to our customers by other
suppliers.

Quality and volumes for the coal are stipulated in coal supply agreements,
and in some instances buyers have the option to vary annual or monthly volumes
if necessary. Variations to the quality and volumes of coal may lead to
adjustments in the contract price. Coal supply agreements typically stipulate
procedures for quality control, sampling and weighing. Most coal supply
agreements contain provisions requiring us to deliver coal

within certain ranges for specific coal characteristics such as heat content
(Btu), sulfur, ash, grindability and ash fusion temperature. Failure to meet
these specifications can result in economic penalties, suspension or
cancellation of shipments or termination of the contracts.

Contract provisions in some cases set out mechanisms for temporary
reductions or delays in coal volumes in the event of a force majeure, including
events such as strikes, adverse mining conditions or serious transportation
problems that affect the seller or unanticipated plant outages that may affect
the buyer. More recent contracts stipulate that this tonnage can be made up by
mutual agreement or at the discretion of the buyer. Buyers often negotiate
similar clauses covering changes in environmental laws. We often negotiate the
right to supply coal that complies with a new environmental requirement to
avoid contract termination. Coal supply agreements typically contain
termination clauses if either party fails to comply with the terms and
conditions of the contract, although most termination provisions provide the
opportunity to cure defaults.

In some of our contracts, we have a right of substitution, allowing us to
provide coal from different mines as long as the replacement coal meets quality
specifications and will be sold at the same delivered cost. Contracts usually
contain specified sampling locations: in the eastern United States,
approximately 50% of customers require that the coal is sampled and weighed at
the destination, whereas in the western United States, samples are usually
taken at the shipping source.

Sales and Marketing

Our sales and marketing operations include Peabody COALSALES and Peabody
COALTRADE. Through these entities, we sell coal produced by our diverse
portfolio of operations, broker coal sales of other coal producers, both as
principal and agent, trade coal and emissions allowances, and provide
transportation-related services. We also restructure third-party coal supply
agreements by acquiring a customer's right to receive coal from another coal
company under a coal supply agreement, reselling that coal, and supplying that
customer with coal from our own operations. As of March 31, 2001, we had 67
employees in our sales and marketing operations, including personnel dedicated
to performing market research, contract administration and risk management
activities.

Transportation

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

The majority of our sales volume is shipped by rail, but a portion of our
production is shipped by other modes of transportation. For example, coal from
our Camp operating unit in Kentucky is shipped by barge to the Tennessee Valley
Authority's Cumberland plant in Tennessee. Coal from our Black Mesa Mine in
Arizona is transported by a 273-mile coal-water pipeline to the Mohave
Generating Station in southern Nevada. Coal from the Seneca Mine in Colorado is
transported by truck to a nearby electric generating plant. Other mines
transport coal by rail and barge or by rail and lake carrier on the Great
Lakes. All coal from our Powder River Basin mines is shipped by rail, and two
competing railroads, the Burlington Northern & Santa Fe and the Union Pacific,
serve our two Southern Powder River Basin mines. Approximately 8,000 unit
trains are loaded each year to accommodate the coal shipped by these mines. A
unit train generally consists of 100 to 140 cars, each of which can hold 100 to
120 tons of coal.

Our transportation department manages the loading of trains and barges. We
believe we enjoy good relationships with the rail carriers and barge companies
due, in part, to our modern coal-loading facilities and the experience of our
transportation coordinators.

Suppliers

The main types of goods we purchase are mining equipment and replacement
parts, explosives, fuel, tires and lubricants. We also purchase coal from third
parties to satisfy some of our customer contracts. The supplier

base providing these goods has been relatively consistent in recent years and
we have many long established relationships with our key suppliers. We do not
believe that we are dependent on any of our individual suppliers.

Technical Innovation

We place great emphasis on the application of technical innovation to
improve the mining process. This research and development effort is typically
undertaken and funded by equipment manufacturers using our input and expertise.
Our engineering staff and purchasing departments work with manufacturers to
design and produce equipment that we believe will add value to the business.
For example, we worked with a manufacturer to design larger trucks to haul
overburden and coal at various mines throughout our company. In Wyoming, we
were the first coal company to use the current, state-of-the-art 400-ton haul
trucks. We have worked with our underground equipment suppliers to develop
higher horsepower continuous mining machines, which mine the coal more
effectively, and at a lower cost per ton. We have also assisted them in the
development of a continuous haulage machine, which can be operated by one
person as opposed to the standard four-person requirement. We are the largest
user of advanced coal quality analyzers among coal producers, according to the
manufacturer of this sophisticated equipment. These analyzers allow continuous
analysis of certain coal quality parameters such as sulfur content. Their use
helps ensure consistent product quality and helps customers meet stringent air
emission requirements. We also use global positioning satellite technology
extensively in our larger surface mining operations to ensure proper mine
layout. As a result of these efforts, many of our mines have become among the
most productive in the industry. We also support the Power Systems Development
Facility, a highly efficient electric generating plant using advanced emissions
reduction technology funded primarily through the Department of Energy and
operated by an affiliate of Southern Company.

Coalbed Methane

Peabody Natural Gas, LLC is evaluating the potential for coalbed methane
development within our coal reserves. In addition, we purchased coalbed methane
assets near our Caballo Mine in Wyoming in January 2001 for approximately $10
million. We currently intend to expand this business line through acquisitions
and development of our own reserves.

Competition

The markets in which we sell our coal are highly competitive. The top 10
coal producers in the United States produce approximately 64% of total domestic
coal, although there are approximately 730 coal producers in the United States.
Our principal competitors are other large coal producers, including Arch Coal,
Inc., Kennecott Energy Co., a subsidiary of Rio Tinto, RAG AG, CONSOL Energy
Inc., AEI Resources, Inc. and Massey Energy Company, which collectively
accounted for approximately 41% of total U.S. coal production in 2000.

A number of factors beyond our control affect the markets in which we sell
our coal. Continued demand for our coal and the prices obtained by us depend
primarily on the coal consumption patterns of the electricity industries in the
United States, the availability, location, cost of transportation and price of
competing coal and other electricity generation and fuel supply sources such as
natural gas, oil, nuclear and hydroelectric. Coal consumption patterns are
affected primarily by the demand for electricity, environmental and other
governmental regulations and technological developments. We compete on the
basis of coal quality, delivered price, customer service and support and
reliability.

Certain Liabilities

We have significant long-term liabilities for reclamation, work-related
injuries and illnesses, pensions and retiree health care. In addition, labor
contracts with the United Mine Workers of America and voluntary arrangements
with non-union employees include long-term benefits, notably health care
coverage for retired and future retirees and their dependents. We provide
reserves for a substantial portion of these obligations. The majority of our
existing liabilities relate to our past operations, which had more mines and
employees than we currently have.

Reclamation. Reclamation liabilities primarily represent the future costs to
restore surface lands to productivity levels equal to or greater than pre-
mining conditions, as required by the Surface Mining Control and Reclamation
Act. We also record other related liabilities, such as water treatment and
environmental costs. Our long-term reclamation costs, mine-closing and other
related liabilities totaled approximately $451.3 million as of March 31, 2001,
$3.6 million of which was a current liability. Expense for fiscal year 2001 was
$4.1 million.

Workers' Compensation. These liabilities represent the actuarial estimates
for compensable, work-related injuries (traumatic claims) and occupational
disease, primarily black lung disease (pneumoconiosis). The Federal Black Lung
Benefits Act requires employers to pay black lung awards to former employees
who filed claims after June 1973. These liabilities totaled approximately
$244.3 million as of March 31, 2001, $33.6 million of which was a current
liability. Expense for fiscal year 2001 was $41.4 million.

Pension-Related Provisions. Pension-related costs represent the actuarially-
estimated cost of pension benefits. Annual contributions to the pension plans
are determined by consulting actuaries based on the Employee Retirement Income
Security Act minimum funding standards and an agreement with the Pension
Benefit Guaranty Corporation. Pension-related liabilities totaled approximately
$10.7 million as of March 31, 2001, $8.1 million of which was a current
liability.

Retiree Health Care. Consistent with Statement of Financial Accounting
Standards No. 106, we record a liability representing the estimated cost of
providing retiree health care benefits to current retirees and active employees
who will retire in the future. Provisions for active employees represent the
amount recognized to date, based on their service to date; additional amounts
are provided periodically so that the total liability is accrued when the
employee retires.

A second category of retiree health care obligations represents the
liability for future contributions to the United Mine Workers of America
Combined Fund created by federal law in 1992. This multiemployer fund provides
health care benefits to a closed group of former employees who retired prior to
1976; no new retirees will be added to this group. The liability is subject to
increases or decreases in per capita health care costs, offset by the mortality
curve in this aging population of beneficiaries.

Our retiree health care liabilities totaled approximately $1,036.1 million
as of March 31, 2001, $62.0 million of which was a current liability. Expense
for fiscal year 2001 was $70.7 million. Obligations to the United Mine Workers
of America Combined Fund totaled $57.8 million as of March 31, 2001, $5.6
million of which was a current liability. Income for fiscal year 2001 was $8.0
million.

Employees

As of March 31, 2001, we and our subsidiaries had approximately 6,100
employees. Approximately 37% of our employees are affiliated with organized
labor unions, which accounted for approximately 23% of the tons we sold in the
United States during fiscal year 2001. Relations with organized labor are
important to our success and we believe our relations with employees are
satisfactory. Hourly workers at our mines in Arizona, Colorado and Montana are
represented by the United Mine Workers of America under the Western Surface
Agreement, which was ratified in 2000 and is effective through September 1,
2005. Our union labor east of the Mississippi River is also represented by the
United Mine Workers of America and is subject to the National Bituminous Coal
Wage Agreement, which is effective through December 31, 2002.

Legal Proceedings

From time to time, we are involved in legal proceedings arising in the
ordinary course of business. We believe we have recorded adequate reserves for
these liabilities and that there is no individual case pending that is likely
to have a material adverse effect on our financial condition or results of
operations. We discuss our significant legal proceedings below.

Navajo Nation

On June 18, 1999, the Navajo Nation served our subsidiaries, Peabody Holding
Company, Inc., Peabody Coal Company and Peabody Western Coal Company, with a
complaint that had been filed in the U. S. District Court for the District of
Columbia. Other defendants in the litigation are two customers, one current
employee and one former employee. The Navajo Nation has alleged 16 claims,
including Civil Racketeer Influenced and Corrupt Organizations Act, or RICO,
violations and fraud and tortious interference with contractual relationships.
The complaint alleges that the defendants jointly participated in unlawful
activity to obtain favorable coal lease amendments. Plaintiff also alleges that
defendants interfered with the fiduciary relationship between the United States
and the Navajo Nation. The plaintiff is seeking various remedies including
actual damages of at least $600 million, which could be trebled under the RICO
counts, punitive damages of at least $1 billion, a determination that Peabody
Western Coal Company's two coal leases for the Kayenta and Black Mesa mines
have terminated due to our breach of these leases and a reformation of the two
coal leases to adjust the royalty rate to 20%. All defendants have filed
motions to dismiss the complaint. On March 15, 2001, the court denied the
Peabody defendants' motions to dismiss.

In March 2000, the Hopi Tribe filed a motion to intervene in this lawsuit.
The Hopi Tribe has alleged seven claims, including fraud. The Hopi Tribe is
seeking various remedies, including unspecified actual and punitive damages,
reformation of its coal lease and a termination of the coal lease. On March 15,
2001, the court granted the Hopi Tribe's motion. On April 17, 2001, we filed a
motion to dismiss the Hopi complaint.

While the outcome of litigation is subject to uncertainties, based on our
preliminary evaluation of the issues and the potential impact on us, we believe
this matter will be resolved without a material adverse effect on our financial
condition or results of operations.

Salt River Project Agricultural Improvement and Power District--Price Review

In May 1997, Salt River Project Agricultural Improvement and Power District,
or Salt River, acting for all owners of the Navajo Generating Station,
exercised their contractual option to review certain cumulative cost changes
during a five-year period from 1992 to 1996. Peabody Western sells
approximately 7 to 8 million tons of coal per year to the owners of the Navajo
Generation Station under a long-term contract. In July 1999, Salt River
notified Peabody Western that it believed the owners were entitled to a price
decrease of $1.92 per ton as a result of the review. Salt River also claimed
entitlement to a retroactive price adjustment to January 1997 and that an
overbilling of $50.5 million had occurred during the same five-year period. In
October 1999, Peabody Western notified Salt River that it believed it was
entitled to a $2.00 per ton price increase as a result of the review. The
parties were unable to settle the dispute and Peabody Western filed a demand
for arbitration in September 2000. The arbitration panel has been selected and
the hearing is scheduled to start on October 29, 2001.

On February 12, 2001 in a related action, Salt River, again acting for all
owners of the Navajo Generating Station, filed a lawsuit against Peabody
Western in the Superior Court in Maricopa County in Arizona. This lawsuit seeks
to compel arbitration of issues that Peabody Western does not believe are
subject to arbitration, namely, (1) the effective date of any price change
resulting from the resolution of the price review arbitration discussed above
and (2) the validity of Salt River's $50.5 million claim for alleged
overcharges by Peabody Western for the period from 1992 through 1996 (the five-
year period that was the subject of the price review). If the court declines to
compel arbitration of these issues, the lawsuit alternatively requests that the
court find in favor of Salt River on these issues. We have removed this matter
to the U.S. District Court for the District of Arizona.

While the outcome of arbitration and litigation is subject to uncertainties,
based on our preliminary evaluation of the issues and the potential impact on
us, we believe that the matter will be resolved without a material adverse
effect on our financial condition or results of operations.

Salt River Project Agricultural Improvement and Power District--Mine Closing
and Retiree Health Care

Salt River and the other owners of the Navajo Generating Station filed a
lawsuit on September 27, 1996 in the Superior Court of Maricopa County in
Arizona seeking a declaratory judgment that certain costs relating to final
reclamation, environmental monitoring work and mine decommissioning and costs
primarily relating to retiree health care benefits are not recoverable by our
subsidiary, Peabody Western Coal Company, under the terms of a coal supply
agreement dated February 18, 1977. The contract expires in 2011.

Peabody Western filed a motion to compel arbitration of these claims, which
was granted in part by the trial court. Specifically, the trial court ruled
that the mine decommissioning costs were subject to arbitration but that the
retiree health care costs were not subject to arbitration. Peabody Western
appealed and the Arizona Court of Appeals affirmed the trial court's order.
Peabody Western filed a petition for review with the Arizona Supreme Court.
That petition was denied on September 24, 1998. As a result, Peabody Western,
Salt River and the other owners of the Navajo Generating Station will arbitrate
the mine decommissioning costs issue and will litigate the retiree health care
costs issue.

While the outcome of litigation and arbitration is subject to uncertainties,
based on our preliminary evaluation of the issues and the potential impact on
us, and based on outcomes in similar proceedings, we believe that the matter
will be resolved without a material adverse effect on our financial condition
or results of operations.

Southern California Edison Company

In response to a demand for arbitration by one of our subsidiaries, Peabody
Western, Southern California Edison and the other owners of the Mohave
Generating Station filed a lawsuit on June 20, 1996 in the Superior Court of
Maricopa County, Arizona. The lawsuit sought a declaratory judgment that mine
decommissioning costs and retiree health care costs are not recoverable by
Peabody Western under the terms of a coal supply agreement dated May 26, 1976.
The contract expires in 2005.

Peabody Western filed a motion to compel arbitration which was granted by
the trial court. Southern California Edison appealed this order to the Arizona
Court of Appeals, which denied its appeal. Southern California Edison then
appealed the order to the Arizona Supreme Court which remanded the case to the
Arizona Court of Appeals and ordered the appellate court to determine whether
the trial court was correct in determining that Peabody Western's claims are
arbitrable. The Arizona Court of Appeals ruled that neither mine
decommissioning costs nor retiree health care costs are to be arbitrated and
that both issues should be resolved in litigation. The matter has been remanded
back to the Superior Court of Maricopa County, Arizona, where a trial has been
set for September 11, 2001. Peabody Western answered the complaint and asserted
counterclaims. The court then permitted Southern California Edison to amend its
complaint to add a claim of overcharges of at least $19.2 million by Peabody
Western. The court also ruled that the claim for the overcharges and for
damages resulting from the September 2001 trial would be tried separately,
following the resolution of the September 2001 trial.

While the outcome of litigation is subject to uncertainties, based on our
preliminary evaluation of the issues and the potential impact on us, and based
on outcomes in similar proceedings, we believe that the matter will be resolved
without a material adverse effect on our financial condition or results of
operations. We had a receivable on our balance sheet at March 31, 2001 for the
mine closing costs associated with the Salt River and Southern California
Edison matters of $81.5 million.

Social Security Administration

In 1999, Eastern Associated Coal Corp. and Peabody Coal Company filed a
lawsuit in the U.S. District Court for the Western District of Kentucky against
the Social Security Administration asserting that the Social Security
Administration had improperly assigned, under the Coal Act, certain
beneficiaries to us. Subsequently, Peabody Coal and Eastern Associated moved
for summary judgment on this claim. Summary judgment was granted and in 2000,
the Social Security Administration filed an appeal of the district court's
decision with the

U.S. Court of Appeals for the Sixth Circuit. The matter has been briefed. The
Sixth Circuit Court ruled against the Social Security Administration on the
same issue in the case of Dixie Fuel v. Apfel which it decided in 1999.
Accordingly, we believe that the matter will be resolved without a material
adverse effect on our financial condition or results of operations.

Environmental

Federal and State Superfund Statutes. Superfund and similar state laws
create liability for investigation and remediation in response to releases of
hazardous substances in the environment and for damages to natural resources.
Under that legislation and many state Superfund statutes, joint and several
liability may be imposed on waste generators, site owners and operators and
others regardless of fault.

Our subsidiary, Gold Fields Mining Corporation, its predecessors and its
former parent company are or may become parties to environmental proceedings
that have commenced or may commence in the United States in relation to certain
sites previously owned or operated by those entities or companies associated
with them. We have agreed to indemnify Gold Fields' former parent company for
any environmental claims resulting from any activities, operations or
conditions that occurred prior to the sale of Gold Fields to us. Gold Fields is
currently involved in environmental investigation or remediation at nine sites
and is a defendant in litigation with private parties involving two additional
sites.

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

Where the sites were identified, independent environmental consultants were
employed in 1997 in order to assess the estimated total amount of the liability
per site and the proportion of those liabilities that Gold Fields is likely to
bear. The available information on which to base this review was very limited
since all of the sites except for two sites (on which no remediation is
currently taking place) are no longer owned by Gold Fields. Independent
environmental consultants conducted another assessment in 2000. We have accrued
liabilities of $48.0 million as of March 31, 2001 for the environmental
liabilities described above relating to Gold Fields that are included as part
of the overall provision for reclamation and environmental liabilities in our
consolidated financial statements. Significant uncertainty exists as to whether
these claims will be pursued against Gold Fields in all cases, and where they
are pursued, the amount of the eventual costs and liabilities, which could be
greater or less than this provision. We believe that the remaining amount of
the provision is adequate to cover these environmental liabilities.

Although waste substances generated by coal mining and processing are
generally not regarded as hazardous substances for the purposes of Superfund
and similar legislation, some products used by coal companies in operations,
such as chemicals, and the disposal of these products are governed by the
statute. Thus, coal mines currently or previously owned or operated by us, and
sites to which we have sent waste materials, may be subject to liability under
Superfund and similar state laws.

REGULATORY MATTERS

Federal, state and local authorities regulate the U.S. coal mining industry
with respect to matters such as employee health and safety, permitting and
licensing requirements, air quality standards, water pollution, plant and
wildlife protection, the reclamation and restoration of mining properties after
mining has been completed, the discharge of materials into the environment,
surface subsidence from underground mining and the effects of mining on
groundwater quality and availability. In addition, the industry is affected by
significant legislation mandating certain benefits for current and retired coal
miners. Numerous federal, state and local governmental permits and approvals
are required for mining operations. We believe that we have obtained all
permits currently required to conduct our present mining operations. We may be
required to prepare and present to federal, state or local authorities data
pertaining to the effect or impact that a proposed exploration for or
production of coal may have on the environment. These requirements could prove
costly and time-consuming, and could delay commencing or continuing exploration
or production operations. Future legislation and administrative regulations may
emphasize the protection of the environment and, as a consequence, our
activities may be more closely regulated. Such legislation and regulations, as
well as future interpretations and more rigorous enforcement of existing laws,
may require substantial increases in equipment and operating costs to us and
delays, interruptions or a termination of operations, the extent of which we
cannot predict.

We endeavor to conduct our mining operations in compliance with all
applicable federal, state and local laws and regulations. However, because of
extensive and comprehensive regulatory requirements, violations during mining
operations occur from time to time in the industry. None of the violations to
date or the monetary penalties assessed upon us has been material.

Mine Safety and Health

Stringent health and safety standards have been in effect since Congress
enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety
and Health Act of 1977 significantly expanded the enforcement of safety and
health standards and imposed safety and health standards on all aspects of
mining operations.

Most of the states in which we operate have state programs for mine safety
and health regulation and enforcement. Collectively, federal and state safety
and health regulation in the coal mining industry is perhaps the most
comprehensive and pervasive system for protection of employee health and safety
affecting any segment of U.S. industry. While regulation has a significant
effect on our operating costs, our U.S. competitors are subject to the same
degree of regulation.

Our goal is to achieve excellent safety and health performance. We measure
our success in this area primarily through the use of accident frequency rates.
We believe that a superior safety and health regime is inherently tied to
achieving our productivity and financial goals. We seek to implement this goal
by: training employees in safe work practices; openly communicating with
employees; establishing, following and improving safety standards; involving
employees in establishing safety standards; and recording, reporting and
investigating all accidents, incidents and losses to avoid reoccurrence.

Black Lung

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung
Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must
secure payment of federal black lung benefits to claimants who are current and
former employees and to a trust fund for the payment of benefits and medical
expenses to claimants who last worked in the coal industry prior to July 1,
1973. Less than 7% of the miners currently seeking federal black lung benefits
are awarded these benefits by the federal government. The trust fund is funded
by an excise tax on production of up to $1.10 per ton for deep-mined coal and
up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of
the gross sales price. This tax is passed on to the purchaser under many of our
coal supply agreements.

In December 2000, the Department of Labor issued new amendments to the
regulations implementing the federal black lung laws that, among other things,
establish a presumption in favor of a claimant's treating physician and limit a
coal operator's ability to introduce medical evidence regarding the claimant's
medical condition. Industry reports anticipate that the number of claimants who
are awarded benefits will increase significantly as will the amounts of those
awards. The National Mining Association has filed a lawsuit challenging these
regulations. The U.S. District Court of the District of Columbia issued a
preliminary injunction staying the effectiveness of the new rules. A trial on
the merits is set for June 5, 2001.

Coal Industry Retiree Health Benefit Act of 1992

The Coal Act provides for the funding of health benefits for certain United
Mine Workers of America retirees. The Coal Act established the Combined Fund
into which "signatory operators" and "related persons" are obligated to pay
annual premiums for beneficiaries. The Coal Act also created a second benefit
fund for miners who retired between July 21, 1992 and September 30, 1994 and
whose former employers are no longer in business. Companies that are liable
under the Coal Act must pay premiums to the Combined Fund. Annual payments made
by certain of our subsidiaries under the Coal Act totaled $5.1 million and $4.1
million, respectively, during fiscal years 2000 and 2001.

In October 1998, the Combined Fund sent a premium notice to all assigned
operators subject to the fund that included retroactive death benefit and
health benefit premiums dating back to February 1, 1993. On November 13, 1998,
10 employers, including two of our subsidiaries, Peabody Coal Company and
Eastern Associated Coal Corp., challenged the fund's retroactive rebilling in a
lawsuit filed in the Northern District Court of Alabama. If we are successful
in this litigation, we will be eligible for a $1.0 million credit as a
reduction to future premiums.

In 1996, the Combined Fund sued the Social Security Administration in the
District of Columbia seeking a declaration that the Social Security
Administration's original calculation of the per-beneficiary premium was
proper. Certain coal companies, but not our subsidiaries, intervened in the
lawsuit. On February 25, 2000, the federal District Court ruled in favor of the
Combined Fund. The Combined Fund has obtained an amended order and the
intervenor coal companies have appealed the court's decision. If this decision
is upheld on appeal, our subsidiaries will be required to pay an additional
premium to the Combined Fund of approximately $2.4 million.

Environmental Laws

We are subject to various federal, state and foreign environmental laws.
These laws require approval of many aspects of coal mining operations, and both
federal and state inspectors regularly visit our mines and other facilities to
ensure compliance.

Surface Mining Control and Reclamation Act

The Surface Mining Control and Reclamation Act, which is administered by the
Office of Surface Mining Reclamation and Enforcement, establishes mining,
environmental protection and reclamation standards for all aspects of surface
mining as well as many aspects of deep mining. The Surface Mining Control and
Reclamation Act and similar state statutes require, among other things, the
restoration of mined property in accordance with specified standards and an
approved reclamation plan. In addition, the Abandoned Mine Land Fund, which is
part of the Surface Mining Control and Reclamation Act, imposes a fee on all
current mining operations, the proceeds of which are used to restore mines
closed before 1977. The maximum tax is $0.35 per ton on surface-mined coal and
$0.15 per ton on deep-mined coal.

A mine operator must submit a bond or otherwise secure the performance of
these reclamation obligations. Mine operators must receive permits and permit
renewals for surface mining operations from the Office of Surface Mining
Reclamation and Enforcement or, where state regulatory agencies have adopted
federally approved state programs under the act, the appropriate state
regulatory authority. We accrue for the liability associated with all end-of-
mine reclamation on a ratable basis as the coal reserve is being mined.

All states in which we have active mining operations have achieved primary
control of enforcement through approved state programs. Although we do not
anticipate significant permit issuance or renewal problems, we cannot assure
you that our permits will be renewed or granted in the future or that permit
issues will not adversely affect operations. Under previous regulations of the
act, responsibility for any coal operator currently in violation of the act
could be imputed to other companies deemed, according to regulations, to "own
or control" the coal operator. Sanctions included being blocked from receiving
new permits and rescission or suspension of existing permits. Because of a
recent federal court action invalidating these ownership and control
regulations, the scope and potential impact of the "ownership and control"
requirements on us are unclear. The Office of Surface Mining Reclamation and
Enforcement has responded to the court action by promulgating interim
regulations, which more narrowly apply the ownership and control standards to
coal companies. Although the federal action could have, by analogy, a
precedential effect on state regulations dealing with "ownership and control,"
which are in many instances similar to the invalidated federal regulations, it
is not certain what impact the federal court decision will have on these state
regulations.

West Virginia Mountaintop Mining

On October 20, 1999, the U.S. District Court for the Southern District of
West Virginia issued a permanent injunction against the West Virginia
Department of Environmental Protection in a mountaintop-mining lawsuit. As
interpreted by the Director of the Department of Environmental Protection, the
injunction prohibits the Department from approving any new permits that would
authorize the placement of excess soil in intermittent and perennial streams
for the primary purpose of waste (overburden) disposal. The Department also
interpreted the injunction to affect certain existing coal refuse ponds,
sediment ponds and mountaintop-mining operations.

The Department has filed an appeal of the decision with the U.S. Court of
Appeals for the Fourth Circuit. On October 29, 1999, the District Court issued
a stay of its decision pending a resolution of the appeal. In April 2001, the
Fourth Circuit overturned the District Court decision regarding the
intermittent and perennial stream issue.

The Clean Air Act

The Clean Air Act, the Clean Air Act Amendments and the corresponding state
laws that regulate the emissions of materials into the air, affect coal mining
operations both directly and indirectly. Direct impacts on coal mining and
processing operations may occur through Clean Air Act permitting requirements
and/or emission control requirements relating to particulate matter, such as
fugitive dust, including future regulation of fine particulate matter measuring
ten micrometers in diameter or smaller. The Clean Air Act indirectly affects
coal mining operations by extensively regulating the air emissions of sulfur
dioxide and other compounds, including nitrogen oxides, emitted by coal-based
electricity generating plants.

In July 1997, the EPA adopted new, more stringent National Ambient Air
Quality Standards for very fine particulate matter and ozone. As a result, some
states will be required to change their existing implementation plans to attain
and maintain compliance with the new air quality standards. Our mining
operations and electric generating customers are likely to be directly affected
when the revisions to the air quality standards are implemented by the states.
State and federal regulations relating to implementation of the new air quality
standards may restrict our ability to develop new mines or could require us to
modify our existing operations. The extent of the potential direct impact of
the new air quality standards on the coal industry will depend on the policies
and control strategies associated with the state implementation process under
the Clean Air Act, but could have a material adverse effect on our financial
condition and results of operations. The Court of Appeals for the District of
Columbia issued an opinion in May 1999 limiting the manner in which the EPA can
enforce these standards. After a request by the federal government for a
rehearing by the Court of Appeals was denied, the Supreme Court agreed in
January 2000 to review the case. On February 27, 2001, the Supreme Court found
in favor of the EPA in material part and remanded the case to the Court of
Appeals. Implementation of the fine particulate National Ambient Air Quality
Standards will occur, if at all, after the Court of Appeals disposes of any
preserved challenges to the standards and the EPA develops a new implementation
policy. The effect of this decision on us and our customers is unknown at this
time.

Title IV of the Clean Air Act Amendments places limits on sulfur dioxide
emissions from electric power generation plants. The limits set baseline
emission standards for these facilities. Reductions in emissions occurred in
Phase I in 1995 and in Phase II in 2000 and apply to all coal-based power
plants. The affected electricity generators have been able to meet these
requirements by, among other ways, switching to lower sulfur fuels, installing
pollution control devices, such as scrubbers, reducing electricity generating
levels or purchasing sulfur dioxide emission allowances. Emission sources
receive these sulfur dioxide emission allowances, which can be traded or sold
to allow other units to emit higher levels of sulfur dioxide. We cannot
ascertain the effect of these provisions of the Clean Air Act Amendments on us
at this time. We believe that implementation of Phase II has resulted in a
downward pressure on the price of higher sulfur coal, as additional coal-based
electric generating plants have complied with the restrictions of Title IV.

The Clean Air Act Amendments also require electricity generators that
currently are major sources of nitrogen oxides in moderate or higher ozone non-
attainment areas to install reasonably available control technology for
nitrogen oxides, which are precursors of ozone. In addition, the EPA recently
announced the final rules that would require 19 eastern states and Washington,
D.C. to make substantial reductions in nitrogen oxide emissions. Installation
of additional control measures required under the final rules will make it more
costly to operate coal-based electric generating plants.

In accordance with Section 126 of the Clean Air Act, eight northeastern
states filed petitions requesting the EPA to make findings and require
decreases in nitrogen oxide emissions from certain sources in certain upwind
states that might contribute to ozone nonattainment in the petitioning states.
The EPA has granted four of the eight petitions finding that certain sources
are contributing to ozone non-attainment in certain of the petitioning states
and the EPA has proposed levels of nitrogen oxide control for the named
sources. Our customers are among the named sources and, implementation of the
requirement to install control equipment could impact the amount of coal
supplied to those customers if they decide to switch to other sources of fuel,
which would result in lower emission of nitrogen oxides. A coalition of 40
electricity generators and power companies petitioned the U.S. Court of Appeals
for the District of Columbia to review the EPA's decision to grant the four
petitions. On May 15, 2001, the Court of Appeals substantially upheld the EPA's
ruling, but remanded for reconsideration the EPA's decision to regulate certain
cogeneration facilities and the EPA's use of certain projections regarding
future growth in setting the nitrogen oxide emission limitations.

The Clean Air Act Amendments provisions for new source review require
electricity generators to install the best available control technology if they
make a major modification to a facility that results in an increase in its
potential to emit regulated pollutants. The Justice Department on behalf of the
EPA filed a number of lawsuits since November 1999, alleging that ten
electricity generators violated the new source review provisions of the Clean
Air Act Amendments at power plants in the midwestern and southern United
States. The EPA issued an administrative order alleging similar violations by
the Tennessee Valley Authority, affecting seven plants and notices of violation
for an additional eight plants owned by the affected electricity generators.
Three electricity generators have reached settlements with the Justice
Department requiring the installation of additional control equipment on
selected generating units. If the remaining electricity generators are found to
be in violation, they could be subject to civil penalties and be required to
install the required control equipment or cease operations. Our customers are
among the named electricity generators and if found not to be in compliance,
the fines and requirements to install additional control equipment could
adversely affect the amount of coal they would burn if the plant operating
costs were to increase to the point that the plants were operated less
frequently.

The Clean Air Act Amendments set a national goal for the prevention of any
future, and the remedying of any existing, impairment of visibility in 156
national parks and wildlife areas across the country. Visibility in these areas
is to be returned to natural conditions by 2064 through plans that must be
developed by the states. The state plans may require the application of "Best
Available Retrofit Technology" after 2010 on sources found to be contributing
to visibility impairment of regional haze in these areas. The control
technology requirements could cause our customers to install equipment to
control sulfur dioxide and nitrogen oxide emissions. The requirement to install
control equipment could affect the amount of coal supplied to those customers
if they decide to switch to other sources of fuel to lower emission of sulfur
oxides and nitrogen oxides.

In addition, the Clean Air Act Amendments require a study of electric
generating plant emissions of certain toxic substances, including mercury, and
direct the EPA to regulate these substances, if warranted. In December 2000,
the EPA decided that mercury air emissions from power plants should be
regulated. The EPA will propose regulations by December 2003 and will issue
final regulations by December 2004. It is a possibility that future regulatory
activity may seek to reduce mercury emissions and these requirements, if
adopted, could result in reduced use of coal if electricity generators switch
to other sources of fuel.

Clean Water Act

The Clean Water Act of 1972 affects coal mining operations by imposing
restrictions on effluent discharge into water. Regular monitoring, reporting
requirements and performance standards are preconditions for the issuance and
renewal of permits governing the discharge of pollutants into water.

Resource Conservation and Recovery Act

RCRA imposes requirements for the treatment, storage and disposal of
hazardous wastes. Coal mining operations covered by the Surface Mining Control
and Reclamation Act permits are exempted from regulation under RCRA by statute.
We cannot, however, predict whether this exclusion will continue.

RCRA excludes certain large-volume wastes generated primarily from the
combustion of coal from being regulated as a hazardous waste pending a report
to Congress and a decision by the EPA either to regulate the coal combustion
wastes as a hazardous waste under RCRA or deem the regulation as unwarranted.
The EPA made its report to Congress in March 1999 and determined in May 2000
not to regulate coal waste as a hazardous substance under RCRA. Any requirement
to regulate coal combustion waste as a hazardous waste could cause a switch to
other lower ash fuels and reduce the amount of coal used by electric
generators.

Federal and State Superfund Statutes

Superfund and similar state laws affect coal mining and hard rock operations
by creating liability for investigation and remediation in response to releases
of hazardous substances into the environment and for damages to natural
resources. Under Superfund, joint and several liability may be imposed on waste
generators, site owners and operators and others regardless of fault.

Global Climate Change

The United States, Australia and over 160 other nations are signatories to
the 1992 Framework Convention on Climate Change, which is intended to limit
emissions of greenhouse gases, such as carbon dioxide. In December 1997, in
Kyoto, Japan, the signatories to the convention established a binding set of
emission targets for developed nations. Although the specific emission targets
vary from country to country, the United States would be required to reduce
emissions to 93% of 1990 levels over a five-year budget period from 2008
through 2012. Although the United States has not ratified the emission targets
and no comprehensive regulations focusing on greenhouse gas emissions are in
place, these restrictions, whether through ratification of the emission targets
or other efforts to stabilize or reduce greenhouse gas emissions, could
adversely affect the price and demand for coal. According to the Energy
Information Administration's Emissions of Greenhouse Gases in the United States
1999, coal accounts for 30% of greenhouse gas emissions in the United States,
and efforts to control greenhouse gas emissions could result in reduced use of
coal if electric generators switch to lower carbon sources of fuel. In March
2001, President Bush reiterated his opposition to the Kyoto Protocol and
further stated that he did not believe that the government should impose
mandatory carbon dioxide emission reductions on power plants.

Permitting

Mining companies must obtain numerous permits that impose strict regulations
on various environmental and safety matters in connection with coal mining.
These provisions include requirements for coal prospecting;

mine plan development; topsoil removal, storage and replacement; selective
handling of overburden materials; mine pit backfilling and grading; protection
of the hydrologic balance; subsidence control for underground mines; surface
drainage control; mine drainage and mine discharge control and treatment; and
revegetation.

We must obtain permits from applicable state regulatory authorities before
we begin to mine reserves. The mining permit application process is initiated
by collecting baseline data to adequately characterize the pre-mine
environmental condition of the permit area. This work includes surveys of
cultural resources, soils, vegetation, wildlife, assessment of surface and
ground water hydrology, climatology and wetlands. In conducting this work, we
collect geologic data to define and model the soil and rock structures and coal
that we will mine. We develop mine and reclamation plans by utilizing this
geologic data and incorporating elements of the environmental data. The mine
and reclamation plan incorporates the provisions of the Surface Mining Control
and Reclamation Act, the state programs and the complementary environmental
programs that impact coal mining. Also included in the permit application are
documents defining ownership and agreements pertaining to coal, minerals, oil
and gas, water rights, rights of way, and surface land and documents required
of the Office of Surface Mining's Applicant Violator System.

Once a permit application is prepared and submitted to the regulatory
agency, it goes through a completeness review, technical review and public
notice and comment period before it can be approved. Some Surface Mining
Control and Reclamation Act mine permits can take over a year to prepare,
depending on the size and complexity of the mine and often take six months to
sometimes two years to receive approval. Regulatory authorities have
considerable discretion in the timing of the permit issuance and the public has
rights to comment on and otherwise engage in the permitting process, including
through intervention in the courts.

We do not believe there are any substantial matters that pose a risk to
maintaining our existing mining permits or hinder our ability to acquire future
mining permits. It is our policy to ensure that our operations are in full
compliance with the requirements of the Surface Mining Control and Reclamation
Act and the state laws and regulations governing mine reclamation.

MANAGEMENT

Directors and Executive Officers

Set forth below are the names, ages as of March 31, 2001 and current
positions with us and our subsidiaries of our executive officers and directors.
Directors are elected at the annual meeting of stockholders. Executive officers
are appointed by, and hold office at, the discretion of the directors.

Name Age Position
---- --- --------

Irl F. Engelhardt....... 54 Chairman, Chief Executive Officer and Director
Richard M. Whiting...... 46 President, Chief Operating Officer and Director
Roger B. Walcott, Jr.... 45 Executive Vice President-Corporate Development
Richard A. Navarre...... 40 Executive Vice President and Chief Financial Officer
Fredrick D. Palmer...... 56 Executive Vice President-Legal and External Affairs and Secretary
Paul H. Vining.......... 46 Executive Vice President-Sales and Trading
Jeffery L. Klinger...... 54 Vice President-Legal Services and Assistant Secretary
Sharon D. Fiehler....... 44 Vice President-Human Resources
Roger H. Goodspeed...... 50 Director
Henry E. Lentz.......... 56 Director
Alan H. Washkowitz...... 60 Director

Irl F. Engelhardt served as our President and Chief Executive Officer from
1990 to 1995 and our Chairman and Chief Executive Officer since 1993, and has
been a director since June 1998. Since joining our company in 1979, he has held
various officer level positions in the executive, sales, business development
and administrative areas, including serving as Chairman of Peabody Resources
Ltd. (Australia) and Chairman of Citizens Power. Mr. Engelhardt also served as
Co-Chief Executive Officer and executive director of The Energy Group from
February 1997 to May 1998, Chairman of Cornerstone Construction & Materials,
Inc. from September 1994 to May 1995 and Chairman of Suburban Propane Company
from May 1995 to February 1996. He also served as a director and Group Vice
President of Hanson Industries from 1995 to 1996. Mr. Engelhardt is Co-Chairman
of the Coal Utilization Research Council, Co-Chairman of the Coal Based
Generators Stakeholders Group and past Chairman of the National Mining
Association and the Coal Industry Advisory Board of the International Energy
Agency. He is also a director of Firstar Bank, N.A. (formerly Mercantile Bank
of St. Louis, N.A.).

Richard M. Whiting was promoted to President and Chief Operating Officer of
our company in January 1998 and has been a director since June 1998. He served
as President of Peabody COALSALES Company from June 1992 to January 1998. Since
joining our company in 1976, Mr. Whiting has held a number of operations, sales
and engineering positions both at the corporate offices and at field locations.
From 1989 to 1990, Mr. Whiting served as Vice President of Engineering and
Operations Support. Mr. Whiting is currently Chairman of the Bituminous Coal
Operators' Association, Chairman of the National Mining Association's Safety
and Health Committee and a member of the National Coal Council.

Roger B. Walcott, Jr. became Executive Vice President-Corporate Development
of our company in February 2001. Prior to that, he was Executive Vice President
of our company since June 1998. From 1981 to 1998, he was a Senior Vice
President and a director with The Boston Consulting Group where he served a
variety of clients in strategy and operational assignments. He was also
Chairman of The Boston Consulting Group's Human Resource Capabilities
Committee. Mr. Walcott holds an MBA with high distinction from the Harvard
Business School.

Richard A. Navarre became Executive Vice President and Chief Financial
Officer of our company in February 2001. Prior to that, he was Vice President-
Chief Financial Officer of our company since October 1999. Prior to that, he
was President of Peabody COALSALES Company from January 1998 to October 1999
and previously served as President of Peabody Energy Solutions, Inc. Prior to
his roles in sales and marketing, he was Vice President of Finance and served
as our Vice President and Controller. He joined our company in

1993 as Director of Financial Planning. Prior to joining us, Mr. Navarre was a
senior manager with KPMG Peat Marwick. Mr. Navarre is a member of the Trade and
International Affairs Committee and the Transportation Committee of the
National Mining Association. He is also a member of the NYMEX Coal Advisory
Council. He also serves on the Board of Advisors to the College of Business for
Southern Illinois University.

Fredrick D. Palmer became Executive Vice President-Legal and External
Affairs of our company in February 2001. He is responsible for our legal
affairs, state and federal government affairs, public relations and investor
relations. Prior to joining Peabody, he served for 15 years as chief executive
officer of Western Fuels Association, Inc. He most recently was of counsel in
the Washington, D.C. office of Shook Hardy & Bacon, a Kansas City-based law
firm. He received a BA and a JD from the University of Arizona.

Paul H. Vining became Executive Vice President-Sales and Trading of our
company in February 2001. Prior to that, he was President of Peabody COALSALES
Company from October 1999 to January 2001, and President of Peabody COALTRADE,
Inc. from March 1997 to October 1999, and Senior Vice President of Peabody
COALSALES Company from August 1995 to February 1997. Mr. Vining is a member of
the board of directors of the Coal Exporters Association.

Jeffery L. Klinger was named Vice President-Legal Services of our company in
May 1998. Prior to that, he had been our Vice President, Secretary and Chief
Legal Officer since October 1990. From 1986 to October 1990, he served as
Eastern Regional Counsel for Peabody Holding Company and from 1982 to 1986 as
Director of Legal and Public Affairs, Eastern Division of Peabody Coal Company
and joined Peabody as Director of Legal and Public Affairs, Indiana Division of
Peabody Coal Company from 1978 to 1982. He is a past President of the Indiana
Coal Council and is currently a trustee of the Energy and Mineral Law
Foundation and a past Treasurer and member of their Executive Committee. Mr.
Klinger is also a member of the National Mining Association's Legal Affairs
Committee.

Sharon D. Fiehler has been Vice President of Human Resources of our company
since 1991, with executive responsibility for employee development, benefits,
compensation, employee relations and affirmative action programs. She joined
Peabody in 1981 as Manager-Salary Administration and has held a series of
employee relations, compensation and salaried benefits positions. Prior to
joining Peabody, Ms. Fiehler, who earned degrees in social work and psychology
and an MBA, was a personnel representative for Ford Motor Company. Ms. Fiehler
is a member of the National Mining Association's Human Resource Committee.

Roger H. Goodspeed became a director of our company in May 1998. He is also
a Managing Director of Lehman Brothers. He joined Lehman Brothers in 1974 and
became a Managing Director in 1984. During his tenure at Lehman Brothers, he
has served in management positions for several different groups. In 1994, he
became the original Chairman of Citizens Lehman Power, an electric power
marketing joint venture 50%-owned by Lehman Brothers, and continued in that
role until the joint venture was sold to The Energy Group in 1997 and changed
its name to Citizens Power. Mr. Goodspeed received an MBA from the Anderson
School at the University of California, Los Angeles.

Henry E. Lentz became a director of our company in February 1998. He is also
a Managing Director of Lehman Brothers and a principal of the firm's Merchant
Banking Group. Mr. Lentz joined Lehman Brothers in 1971 and became a Managing
Director in 1976. In 1988, Mr. Lentz left Lehman Brothers to serve as Vice
Chairman of Wasserstein Perella Group, Inc. In 1993, he returned to Lehman
Brothers as a Managing Director and, prior to joining the Merchant Banking
Group, served as head of the firm's worldwide energy practice. Mr. Lentz is
currently a director of Rowan Companies, Inc. and Consort Holdings plc. Mr.
Lentz holds an MBA, with honors, from the Wharton School of the University of
Pennsylvania.

Alan H. Washkowitz became a director of our company in May 1998. He is also
a Managing Director of Lehman Brothers and the head of the firm's Merchant
Banking Group, responsible for the oversight of Lehman Brothers Merchant
Banking Partners II L.P. Mr. Washkowitz joined Kuhn Loeb & Co. in 1968 and
became a general partner of Lehman Brothers in 1978 when it acquired Kuhn Loeb
& Co. Prior to joining the Merchant

Banking Group, Mr. Washkowitz headed Lehman Brothers' Financial Restructuring
Group. He is currently a director of CP Kelco ApS, L-3 Communications
Corporation, K&F Industries, Inc. and McBride plc. Mr. Washkowitz holds an MBA
from Harvard University and a JD from Columbia University.

Our board of directors is currently comprised of five directors, and we
expect to add two independent members to our board of directors within three
months and a third independent member to our board of directors within 12
months after the consummation of this offering. In addition, we expect that as
long as Lehman Brothers Merchant Banking controls us, they will add additional
members to our board of directors so that Lehman Brothers Merchant Banking will
continue to control a majority of our board of directors. In accordance with
the terms of our certificate of incorporation, the board of directors will be
divided into three classes, each serving staggered three-year terms: Class I,
whose initial term will expire at the annual meeting of stockholders held in
2002; Class II, whose initial term will expire at the annual meeting of
stockholders in 2003; and Class III, whose initial term will expire at the
annual meeting of stockholders in 2004. As a result, only one class of
directors will be elected at each annual meeting of our stockholders, with the
other classes continuing for the remainder of their respective terms. Roger
Goodspeed has been designated as a Class I director; Messrs. Whiting and Lentz
have been designated as Class II directors; and Messrs. Engelhardt and
Washkowitz have been designated as Class III directors. In addition, our
certificate of incorporation and by-laws provide that directors may be removed
only for cause and only upon the affirmative vote of holders of at least 75% of
the voting power of all the outstanding shares of stock entitled to vote
generally in the election of directors, voting together as a single class.
There are no family relationships among any of our directors and executive
officers.

Committees of our Board of Directors

The standing committees of our board of directors will consist of an audit
committee, a compensation committee and an executive committee.

Audit Committee

The principal duties of our audit committee are as follows:

. to recommend the firm of independent outside auditors for appointment by
the board of directors;

. to meet with our financial management, internal audit management and
independent outside auditors to review matters relating to our internal
accounting controls, internal audit program, accounting practices and
procedures, the scope and procedures of the outside audit, the
independence of the outside auditors and other matters relating to our
financial condition;

. to review our annual report to stockholders, proxy materials and annual
report on Form 10-K for filing with the SEC; and

. to report to the board of directors periodically any recommendations the
audit committee may have with respect to the foregoing matters.

The audit committee has the power to investigate any matter brought to its
attention within the scope of its duties and to retain counsel for this purpose
where appropriate.

We plan to appoint two members of the audit committee within three months
following this offering and the third member within 12 months after the
consummation of this offering.

Compensation Committee

The principal duties of the compensation committee are as follows:

. to review key employee compensation policies, plans and programs;

. to monitor performance and compensation of our employee-directors,
officers and other key employees;

. to prepare recommendations and periodic reports to the board of directors
concerning these matters; and

. to function as the committee which administers the annual and long-term
incentive programs referred to in "Executive Compensation" below.

The members of the compensation committee are Messrs. Lentz and Washkowitz.

Executive Committee

When our board of directors is not in session, the executive committee will
have all of the power and authority as delegated by the board of directors,
except with respect to:

. amending our certificate of incorporation and by-laws;

. adopting an agreement of merger or consolidation;

. recommending to our stockholders the sale, lease or exchange of all or
substantially all of our property and assets;

. recommending to our stockholders a dissolution of our company or a
revocation of any dissolution;

. declaring a dividend; and

. issuing stock.

The members of the executive committee are Messrs. Engelhardt, Lentz and
Washkowitz.

Compensation Committee Interlocks and Insider Participation

None of our executive officers has served as a director or member of the
compensation committee, or other committee serving an equivalent function, of
any entity of which an executive officer is expected to serve as a member of
our compensation committee.

Executive Compensation

The following table sets forth the annual compensation for our chief
executive officer and the four most highly compensated executive officers (the
named executive officers, other than the chief executive officer) for their
services to our company during fiscal years 2001, 2000 and 1999.

Summary Compensation Table

Annual
Compensation Long-Term Compensation
----------------- ---------------------------------------------
Restricted Securities
Stock Underlying LTIP All Other
Name and Principal Fiscal Salary Bonus Award(s) Options/SARs Payments Compensation
Position Year ($) ($) (#)(/1/) (#)(/2/)($)(/3/) ($)(/4/)
------------------ ------ ------- --------- ---------- ------------ -------- ------------

Irl F. Engelhardt....... 2001 700,000 1,050,000 -- 64,019 -- 56,434
Chairman, Chief
Executive Officer 2000 700,000 875,000 -- -- -- 51,525
and Director 1999 681,264 700,000 216,495 699,797 441,240 23,998

Richard M. Whiting...... 2001 400,000 600,000 -- 22,696 -- 31,630
President, Chief
Operating Officer 2000 400,000 500,000 -- -- -- 28,662
and Director 1999 385,834 400,000 72,164 251,759 168,051 12,238

Roger B. Walcott, Jr. .. 2001 350,000 525,000 -- 22,696 -- 27,530
Executive Vice
President-- 2000 350,000 437,500 72,164 -- -- 24,955
Corporate Development 1999 291,667 350,000 -- 251,759 -- 8,374

Richard A. Navarre...... 2001 250,000 406,250 -- 55,084 -- 19,615
Executive Vice
President and 2000 233,750 343,750 -- -- -- 17,203
Chief Financial Officer 1999 220,000 220,000 54,124 188,863 45,030 6,824

Paul H. Vining.......... 2001 262,500 517,624 36,971 148,698 -- 20,820
Executive Vice
President-- 2000 208,120 293,540 9,936 76,861 -- 15,536
Sales and Trading 1999 190,000 172,765 7,217 49,000 -- 5,962

--------
(1) Represents number of shares of common stock granted to executives as of May
19, 1998. In addition, shares purchased by Mr. Walcott on May 19, 1998 were
converted to granted shares during the year ended March 31, 2000.
(2) Represents number of shares of common stock underlying options.
(3) Represents certain long-term incentive payments earned during the fiscal
year that relate to our predecessor company's compensation plans.
(4) Represents annual matching contributions and performance contributions to
qualified and non-qualified savings and investment plans and group term
life insurance.

Option/SAR Grants in Fiscal Year 2001

Potential realizable value at assumed
annual rates of stock price
Individual grants appreciation for option term
----------------------------------------- -------------------------------------
Number of Percent of total
securities options/SARs
underlying granted to Exercise or
options/SARs employees in base price 5% 10%
Name granted (#) fiscal year 2001 ($/share) Expiration date ($) ($)
---- ------------ ---------------- ----------- --------------------------- ---------

Irl F. Engelhardt
Time................... 14,214 3.8% 14.29 January 1, 2011 127,743 323,558
Performance............ 10,811 3.1% 14.29 January 1, 2011 97,157 246,086
Superperformance I..... 14,445 2.8% 14.29 January 1, 2011 129,819 328,816
Superperformance II.... 24,549 11.3% 14.29 January 1, 2011 220,622 558,809
Richard M. Whiting
Time................... 5,166 1.4% 14.29 January 1, 2011 46,427 117,594
Performance............ 3,928 1.1% 14.29 January 1, 2011 35,305 89,422
Superperformance I..... 5,412 1.0% 14.29 January 1, 2011 48,641 123,202
Superperformance II.... 8,189 3.8% 14.29 January 1, 2011 73,591 186,397
Roger B. Walcott, Jr.
Time................... 5,166 1.4% 14.29 January 1, 2011 46,427 117,594
Performance............ 3,928 1.1% 14.29 January 1, 2011 35,305 89,422
Superperformance I..... 5,412 1.0% 14.29 January 1, 2011 48,641 123,202
Superperformance II.... 8,189 3.8% 14.29 January 1, 2011 73,591 186,397
Richard A. Navarre
Time................... 11,519 3.1% 14.29 January 1, 2011 103,523 262,212
Performance............ 10,437 3.0% 14.29 January 1, 2011 93,797 237,577
Superperformance I..... 18,963 3.7% 14.29 January 1, 2011 170,420 431,655
Superperformance II.... 14,165 6.5% 14.29 January 1, 2011 127,303 322,442
Paul H. Vining
Time................... 14,000 3.8% 14.29 July 1, 2010 125,818 318,682
Performance............ 14,000 4.0% 14.29 July 1, 2010 125,818 318,682
Superperformance I..... 21,001 4.1% 14.29 July 1, 2010 188,740 478,055
Superperformance II.... 14,000 6.4% 14.29 July 1, 2010 125,818 318,682
Time................... 19,166 5.2% 14.29 January 1, 2011 172,245 436,276
Performance............ 17,928 5.1% 14.29 January 1, 2011 161,123 408,104
Superperformance I..... 26,414 5.1% 14.29 January 1, 2011 237,381 601,257
Superperformance II.... 22,189 10.2% 14.29 January 1, 2011 199,409 505,079

The following table sets forth the number and value of securities underlying
unexercised options held by each of our executive officers listed on the
Summary Compensation Table above as of March 31, 2001. None of our executive
officers exercised any options in fiscal year 2001, and we do not have any
stock appreciation rights.

Aggregated Option/SAR Exercises in Fiscal Year 2001 and
Options/SAR Values as of March 31, 2001

Number of Securities
Underlying Unexercised Value of Unexercised
Option/SARs as of in-the-Money Options/SARs
Shares March 31, 2001 as of March 31, 2001
Acquired In Value ------------------------- -------------------------
Exercise Realized Exercisable Unexercisable Exercisable Unexercisable
Name (#) ($) (#) (#) ($) ($)
---- ----------- -------- ----------- ------------- ----------- -------------

Irl F. Engelhardt....... -- -- 123,200 640,616 $1,073,072 $5,579,765
Richard M. Whiting...... -- -- 44,755 229,700 389,816 2,000,687
Roger B. Walcott, Jr.... -- -- 44,755 229,700 389,816 2,000,687
Richard A. Navarre...... -- -- 33,575 210,372 292,438 1,832,340
Paul H. Vining.......... -- -- 16,394 258,165 142,792 2,248,617

Pension Benefits

Our Salaried Employees Retirement Plan, or pension plan, is a "defined
benefit" plan. The pension plan provides a monthly annuity to salaried
employees when they retire. A salaried employee must have at least five years
of service to be vested in the pension plan. A full benefit is available to a
retiree at age 62. A retiree can begin receiving a benefit as early as age 55;
however, a 4% reduction factor applies for each year a retiree receives a
benefit prior to age 62.

An individual's retirement benefit under the pension plan is equal to the
sum of (1) 1.112% of the highest average monthly earnings over 60 consecutive
months up to the "covered compensation limit" multiplied by the employee's
years of service, not to exceed 35 years, and (2) 1.5% of the average monthly
earnings over 60 consecutive months over the "covered compensation limit"
multiplied by the employee's years of service, not to exceed 35 years.

We announced in February 1999 that the pension plan would be phased out
beginning January 1, 2001. Certain transition benefits were introduced based on
the age and/or service of the employee at December 31, 2000: (1) employees age
50 or older will continue to accrue service at 100%; (2) employees between the
ages of 45 and 49 or under age 45 with 20 years or more of service will accrue
service at the rate of 50% for each year of service worked after December 31,
2000; and (3) employees under age 45 with less than 20 years of service will
have their pension benefits frozen. In all cases, final average earnings for
retirement plan purposes will be capped at December 31, 2000 levels.

The estimated annual pension benefits payable upon retirement at age 62, the
normal retirement age, for the Chief Executive Officer and the named executive
officers are as follows:

Irl F. Engelhardt................................................. $490,008
Richard M. Whiting................................................ 264,786
Roger B. Walcott, Jr.............................................. 24,663
Richard A. Navarre................................................ 37,993
Paul H. Vining.................................................... 61,170

We have two supplemental defined benefit retirement plans that provide
retirement benefits to executives whose pay exceeds legislative limits for
qualified defined benefit plans.

Other Benefit Plans

In addition to the pension plan, we maintain various other benefit plans
covering employees and retirees, including medical insurance plans and the
Employee Retirement Account, a defined contribution plan. We announced in
February 1999 that we were restructuring several of these plans over the
succeeding four years. The benefits associated with the medical insurance plan
and the Employee Retirement Account will be affected most significantly.

The changes to the medical insurance plan include the following as of
January 1, 2000: (1) a decrease in employee and retiree contributions from 15%
to 10% of actual plan costs; (2) an increase in medical contributions for
dependents from 15% to 30% of actual plan costs; (3) a decrease in medical
coverage from 100% to 80% for specified expenses; (4) additional medical plan
options; and (5) changes to dependent eligibility rules for retirees. In
addition, the medical insurance plan was restructured so that employees leaving
us after January 1, 2003 (at age 55 or older with ten years of service) will be
covered under a medical premium reimbursement plan instead of the current
medical insurance plan.

Beginning with fiscal year 2000, a performance contribution feature was
added to the Employee Retirement Account to allow for our contributions of up
to a maximum of 4% of employees' salaries based upon meeting specified company
performance targets. Effective January 1, 2001, we increased our matching
contributions for the Employee Retirement Accounts to 100% of the first 3% of
base pay and 75% of the next 4% of base pay contributed by employee
participants. After this offering, employees will be able to purchase shares of
our stock through the Employee Retirement Account. We have one defined
contribution supplemental plan, which provides benefits to executives whose pay
exceeds legislative limits for qualified defined contribution plans.

Employee Stock Purchase Plan

In connection with this offering, we are adopting an employee stock purchase
plan. One million five hundred thousand shares of common stock will be
available for purchase. Eligible full-time and part-time employees will be able
to contribute up to 15% of their base compensation into this plan subject to a
limit of $25,000 per year. These employees will be able to purchase the shares
at a 15% discount to the lower of the fair market values of the initial and
ending dates of each offering period. There will be two offering periods each
year, one commencing on April 1 (except that the first offering period will
commence on the effective date of the plan) and the other commencing on October
1. Participating employees will be restricted from selling their shares for 18
months from the purchase date, except upon the death of a participant or a
change in control of our company.

Management Annual Incentive Compensation Plan

We have an annual incentive compensation plan that provides a cash bonus to
selected employees based on the participant's base salary, target level and the
attainment of certain company and individual targets. After this offering, the
company targets will be established each year by the compensation committee of
our board of directors or the board of directors based on performance criteria
that may include total shareholder return, various return measures, earnings
per share, EBITDA, cash flow or other appropriate organizational and individual
measures. The annual incentive awards are designed to be exempt from the $1
million limit on deductible compensation under section 162(m) of the Internal
Revenue Code.

Employment Agreements

We have entered into employment agreements with Mr. Engelhardt, our Chairman
and Chief Executive Officer, or CEO, and Messrs. Whiting, Walcott, Navarre,
Vining and other key executive officers. Upon completion of this offering, we
will amend our employment agreements with these executives. The CEO's
employment agreement provides for a three-year term that extends day-to-day so
that there is at all times a

remaining term of three years, and other executives' employment agreements have
a one-year term or will be amended to have a two-year term, each of which
extends day-to-day so that there is at all times a remaining term of one or two
years, respectively. Following a termination without cause or resignation for
good reason, the CEO is entitled to a lump sum payment equal to three years'
base salary and three times the higher of his (A) target annual bonus or (B)
average of the actual annual bonuses paid in the three prior years. The CEO is
also entitled to a one-time prorated bonus for the year of termination (based
on our actual performance multiplied by a fraction, the numerator of which is
the number of business days the CEO was employed during the year of
termination, and the denominator of which is the total number of business days
during that year), payable when bonuses, if any, are paid to our other
executives. He will also receive qualified and nonqualified pension, life
insurance, medical and other benefits for three years. The other key executives
are entitled to the following benefits, payable in equal installments over one
or two years: (1) one or two times base salary and (2) one or two times the
higher of (A) the target annual bonus or (B) the average of the actual annual
bonuses paid in the three prior years. In addition, the other executives are
entitled to (1) a one-time prorated bonus for the year of termination (based on
our actual performance multiplied by a fraction, the numerator of which is the
number of business days the executive was employed during the year of
termination and the denominator of which is the total number of business days
during that year), payable when bonuses, if any, are paid to our other
executives; and (2) qualified and nonqualified pension, life insurance, medical
and other benefits for the one or two-year period, as applicable, following
termination. However, we are not obligated to provide any benefits under tax
qualified plans that are not permitted by the terms of each plan or by
applicable law or that could jeopardize the plan's tax status. Continuing
benefit coverage will terminate to the extent an executive (including the CEO)
is offered or obtains comparable coverage from any other employer. The
employment agreements provide for confidentiality during and following
employment, and include a noncompetition and nonsolicitation agreement that is
effective during and for one year following employment. If an executive
(including the CEO) breaches any of his or her confidentiality, noncompetition
or nonsolicitation agreements, the executive will forfeit any unpaid amounts or
benefits. To the extent that excise taxes are incurred by an executive
(including the CEO) as a result of "excess parachute payments," we will pay
additional amounts up to $10 million, in the aggregate so that executives would
be in the same financial condition as if the excise taxes were not incurred.

Stock Purchase and Option Plan

We adopted our 1998 Stock Purchase and Option Plan for Key Employees.
Pursuant to that plan, the executive officers and 17 other employees acquired,
in the aggregate, approximately 3% of our initial fully-diluted equity, which
was issued as Class B common stock in connection with our acquisition on May
19, 1998. With respect to these shares, we provided a full recourse loan for
the amount of the tax liability to each executive, with a five-year principal
balloon payment that accelerates six months following any termination of
employment or disposition of the stock, with interest payable throughout the
term of the loan at the applicable federal rate. Executives who received Class
B common stock and some other employees were eligible to receive options under
the plan exercisable for common stock to purchase an aggregate of 7% of our
initial fully-diluted equity, or 2,819,460 shares. As of March 31, 2001,
options to purchase 1,296,950 shares were outstanding as "time options" in the
form of Incentive Stock Options (as defined in Section 422 of the Internal
Revenue Code) to the extent permitted under the Internal Revenue Code, and in
the form of non-qualified stock options for the remainder, and 1,301,290
options to purchase shares were outstanding in the form of nonqualified stock
options as "performance options." Time options become exercisable with respect
to 20% of the shares subject to those options on each of the first five
anniversaries of May 19 of the fiscal year during which the options were
granted if the executive's employment continues through and includes that date.
Time options will become fully exercisable early upon death, disability, a
change of control or a recapitalization event. Performance options become
exercisable at the end of nine and one-half years from the date of the grant,
whether or not the applicable performance targets are achieved, but become
exercisable earlier with respect to up to 20% of the shares subject to the
performance options, on each of the first five anniversaries of May 19 of the
fiscal year during which the options were granted, to the extent certain
performance targets based on net debt and EBITDA, as determined by the board of
directors, are met or exceeded. Performance options will become fully
exercisable early upon a change of control, a recapitalization event or an
initial public offering. "Change of

control," for the purposes of this plan, means an acquisition of all or
substantially all of our direct and indirect assets by merger, consolidation,
recapitalization event, stock or asset sale or otherwise, immediately following
which (a) Lehman Brothers and its affiliates own, in the aggregate, less than
50% of our outstanding voting securities that Lehman Brothers and its
affiliates owned after May 19, 1998, excluding the sale of $80 million of their
original investment, which occurred after May 19, 1998, or (b) any person
individually owns more of our then-outstanding voting securities than Lehman
Brothers and its affiliates. "Recapitalization event," for purposes of this
plan, means a recapitalization, reorganization, stock dividend or other special
corporate restructuring which results in an extraordinary distribution to the
stockholders of cash and/or securities through the use of leveraging or
otherwise but that does not result in a change of control. "Initial public
offering," for purposes of this plan, means the first sale of shares of our
stock to the public pursuant to an effective registration statement filed under
the Securities Act that results in the listing on a national exchange or the
NASDAQ National Market of the lesser of 25% of our outstanding common stock and
an aggregate value of outstanding securities equal to $250.0 million.

The plan also provides for the grant of additional performance-based options
as "superperformance options" exercisable for common stock to purchase an
aggregate of another 7% of our initial fully-diluted equity, or 2,819,460
shares. As of March 31, 2001, options to purchase 2,627,269 shares were
outstanding as "superperformance options." Superperformance options become
exercisable upon the earlier of (1) achievement of specified financial
performance targets and the earliest of completion of (A) an initial public
offering, (B) a change of control or (C) a recapitalization event and (2) nine
and one-half years from the date of grant. Superperformance options will become
exercisable early upon completion of an initial public offering by July 31,
2001, at which time, approximately 36% of these options will vest and the
remainder of these options will vest in accordance with the achievement of
specified financial performance targets. Superperformance options will also
become exercisable early upon a change of control or a recapitalization event
prior to May 19, 2001, at which time approximately 71% of these options will
become exercisable, and the remainder will become exercisable in accordance
with the achievement of specified financial performance targets. If
superperformance options do not become exercisable early, these options will
vest in accordance with the achievement of certain financial targets upon the
earlier of two years following this offering, change of control or a
recapitalization event.

All options have an exercise price of $14.29 per share of our common stock.

All options under the plan have a ten-year term. Exercisable options expire
earlier, as follows: (1) upon termination for cause or a resignation without
good reason, immediately upon termination, (2) upon termination without cause,
resignation for good reason, death, disability or retirement, one year after
termination of employment or (3) if the option exercise price is higher than
the fair market value of our shares upon any termination of employment,
immediately upon termination. Unexercisable options terminate earlier upon any
termination of employment unless acceleration in connection with the
termination, subject to specified exceptions. Upon a change of control, the
board of directors may terminate the options so long as the executives are
cashed out at the change of control price or are permitted to exercise their
options prior to the change of control, except as otherwise provided.

Long-Term Equity Incentive Plan

In connection with this offering, we are adopting the Long-Term Equity
Incentive Plan. Under that plan, selected executive officers, key employees and
other service providers will be eligible to receive grants of stock options,
shares of our common stock or monetary payments based on the value of our stock
or based upon the achievement of specified performance goals. This plan is
intended to provide an incentive for employees to contribute to our success and
align the interests of key employees with the interests of our shareholders.
Two million five hundred thousand shares of our outstanding common stock will
be available for issuing awards with a grant of up to one-third of the total in
fiscal year 2002. Awards may include stock appreciation rights, restricted
stock, performance awards, incentive stock options, nonqualified stock options
and stock units. Performance criteria for the vesting of performance awards may
include total shareholder return, various return

measures, earnings per share, EBITDA, cash flow or other appropriate measures.
The compensation committee of our board of directors or the board of directors
will determine performance goals and levels of rewards to be granted upon the
achievement of these goals. If we change the number of issued shares of our
common stock without new consideration, the total number of shares reserved for
issuance under this plan and the number of shares covered by each outstanding
award will be adjusted so that the aggregate consideration payable to us, if
any, and the value of each award will not be changed. Awards are designed to be
exempt from the $1 million limit on deductible compensation under section
162(m) of the Internal Revenue Code.

Deferred Compensation Plan

In connection with this offering, we are adopting a voluntary nonqualified
deferred compensation plan for a number of our senior executives. An executive
can defer (1) 50% of their base salary; (2) 100% of any annual incentive
awards; and (3) 100% of any cash-based long-term incentives.

Equity Incentive Plan for Non-Employee Directors

In connection with this offering, we are adopting the Equity Incentive Plan
for Non-Employee Directors. Under that plan, members of our board of directors
who are not employees of our company or one of our affiliates will be eligible
to receive grants of restricted stock and options to purchase our stock at a
price equal to the fair market value per share of the stock on the date the
option is granted. Restricted stock will be granted to a director upon election
or appointment to the board of directors, and will vest upon the third
anniversary of the date of grant. Options to purchase stock will be granted to
eligible directors each year at the annual meeting of the board of directors,
and will vest ratably over three years. All options granted under the plan will
expire after ten years from the date of the grant, subject to earlier
termination in connection with a director's termination of service. Options to
purchase stock granted under the plan will become fully exercisable and
restricted stock will become fully vested upon a change of control, or upon the
director's involuntary termination other than for cause, voluntary termination
with the board of director's consent, or permanent disability. Options will
remain exercisable for a period ending upon the earlier to occur of five years
after the director's involuntary termination without cause or voluntary
termination with the board of director's consent, or ten years from the date of
grant. In the event of a director's death while serving on the board of
directors, each of the outstanding options of the option holder shall become
exercisable immediately and may be exercised within a period of five years
after death, but no later than the expiration date of the option term. If an
option holder dies or becomes permanently disabled within five years following
termination of service on the board of directors, the option will be
exercisable for the longer of two years after the holder's death or five years
after termination of service on the board of directors, or until the earlier
expiration of the term of the option. Shares of restricted stock and options
will be forfeited upon the director's voluntary termination without consent of
the board of directors or termination for cause.

RELATED PARTY TRANSACTIONS

Transactions with Affiliates of Lehman Brothers

On May 19, 1997, the Peabody Coal group, which at the time was owned by The
Energy Group PLC, purchased Citizens Lehman Power, a joint venture formed in
1994 by Lehman Brothers Holdings and a subsidiary of Citizens Energy
Corporation, from Lehman Brothers Holdings, which owned a 50% interest in
Citizens Lehman Power, and from the other owners of Citizens Lehman Power for a
maximum purchase price of $120.0 million, which included (1) an up-front
payment of $20.0 million and (2) up to $100.0 million of future cash payments
based on a formula taking into account the net asset value of Citizens Lehman
Power as of the date of its sale to The Energy Group PLC and any future
increase in those net asset values over the period ending on the last day of
fiscal year 2002. That payment obligation was subject to acceleration, under
certain circumstances, in the event of a change of control of The Energy Group
PLC. Citizens Lehman Power was renamed Citizens Power after the 1997 purchase.
As a result of the acquisition of Peabody Coal and Citizens Power by Lehman
Brothers Merchant Banking, the change of control payment acceleration
provisions became effective, and we paid the former owners of Citizens Lehman
Power an aggregate of approximately $94.0 million in full settlement of the
deferred purchase price obligations, with approximately $73.0 million,
including $1.0 million of interest, of that payment made on May 19, 1998 and
$21.0 million, including $1.0 million of interest, paid on April 3, 2000.
Amounts paid in settlement of the deferred purchase price obligations,
excluding interest, were included in the cost of the acquisition of Citizens
Lehman Power.

Lehman Brothers Merchant Banking formed the company to acquire Peabody Coal
and various of its subsidiaries, including Citizens Power, from The Energy
Group PLC on May 19, 1998 for $2,003.5 million. In connection with the
acquisition, we also paid the $73.0 million of obligations of Citizens Power
referred to in the prior paragraph, capitalized Citizens Power's energy trading
operations with an additional $50.0 million and paid $61.8 million in
transaction fees and expenses. Lehman Brothers advised Lehman Brothers Merchant
Banking in connection with that acquisition. In addition, Lehman Brothers was
the initial purchaser in connection with the sale of our senior notes and our
senior subordinated notes. Furthermore, Lehman Commercial Paper Inc. arranged
our senior credit facility and is one of our lenders. Lehman Brothers and
Lehman Commercial Paper Inc. collectively received fees of approximately $85
million for those services. In addition, Lehman Brothers advised Texas
Utilities Company in connection with, and arranged financing for, the
concurrent purchase of The Energy Group PLC, for which Texas Utilities Company
paid customary fees.

As part of our acquisition, Lehman Brothers Holdings provided a 364-day
guarantee facility to trading counterparties of Citizens Power Sales, the
trading subsidiary of Citizens Power, for trades initiated after the
acquisition. Lehman Brothers Holdings received a fee of $0.5 million, plus
reimbursement of expenses, for providing this guarantee facility, which expired
in accordance with its terms in November 1998. There are no further guarantee
obligations outstanding under this facility.

Lehman Brothers provided other financial advisory services to us in April
1998, for which we paid a fee of $0.1 million.

Lehman Brothers served as the placement agent in a financing completed in
January 1999 by a subsidiary of Citizens Power relating to a utility power
contract restructuring, and we paid Lehman Brothers a fee of approximately $0.8
million, plus reimbursement of expenses, for those services.

Lehman Brothers served as the placement agent in a financing completed in
October 1999 by a subsidiary of Citizens Power relating to a utility power
contract restructuring, and we paid Lehman Brothers a fee of approximately $0.8
million, plus reimbursement of expenses, for those services.

Lehman Brothers served as our financial advisor in connection with our
acquisition of an additional 38.3% interest in Black Beauty, which we completed
on March 26, 1999. We paid Lehman Brothers a fee of approximately $1.3 million,
plus reimbursement of expenses, for those services.

Lehman Brothers served as our financial advisor in connection with the sale
of Citizens Power, which we completed in fiscal year 2001. We paid Lehman
Brothers a fee of approximately $1.5 million, plus reimbursement of expenses,
for those services.

Lehman Brothers served as one of our financial advisors in connection with
the sale of our Australian operations, which we completed on January 29, 2001.
We paid Lehman Brothers a fee of $2.7 million, plus reimbursement of expenses,
for those services.

Lehman Brothers has been retained to serve as our financial advisor in
connection with the Thoroughbred Energy Campus project.

Lehman Commercial Paper Inc. is a participant in our senior credit facility,
which was amended on April 26, 2001. Lehman Commercial Paper Inc. received
$0.06 million of the $1.4 million credit facility amendment fee.

Lehman Brothers Merchant Banking Partners II L.P. and its affiliates
(collectively, the "Lehman Brothers Merchant Banking Fund") will beneficially
own 59% of our common stock immediately following the completion of this
offering, or 57% if the underwriters exercise their over-allotment option in
full. Messrs. Goodspeed, Lentz and Washkowitz, each one of our directors, are
investors in the Lehman Brothers Merchant Banking Fund and employees of Lehman
Brothers.

Other Transactions with Affiliates

Peabody COALSALES, a subsidiary of ours, purchased 0.3 million tons of coal
from Black Beauty for $5.5 million during the fiscal year ended March 31, 1999.
The terms of these transactions were comparable to those negotiated with
independent third parties. Executive officers of our company, which is a
general partner of Black Beauty, serve on the partnership committee of Black
Beauty. The members of the Black Beauty partnership committee do not receive a
fee for their services. In early 1999 we increased our ownership of Black
Beauty from 43.3% to 81.7%, making Black Beauty our subsidiary.

Transactions with Management

During fiscal years 1999, 2000 and 2001 some of our executive officers and
18 other employees purchased or were granted shares of our Class B common stock
under the 1998 Stock Purchase and Option Plan for Key Employees. In connection
with these purchases and grants, we, affiliates of Lehman Brothers Holdings and
the executives who received our Class B common stock entered into stockholders
agreements providing for certain rights of the investors relating to the
registration of their shares with respect to certain sales of our capital stock
by affiliates of Lehman Brothers Holdings. The stockholders agreements provide
the investors with the right to register and sell their unregistered stock in
the event that we conduct certain types of registered offerings after the
consummation of this offering. The stockholders agreements also provide the
investors with the right to sell their stock in the event that Lehman Brothers
Merchant Banking sells a specified portion of its shares and the rights of the
investors to require other stockholders to sell their shares if those investors
desire to sell the company; however, these rights under the stockholders
agreements terminate upon completion of this offering.

In conjunction with the purchases and grants of our Class B common stock,
the executive officers and employees executed term notes. The term notes
related to these grants are due on May 19, 2003 and the term notes executed for
purchases are due on February 1, 2006. All of the term notes bear annual
interest at an applicable U.S. federal rate used by the Internal Revenue
Service for loans to employees. The maturity of the promissory notes will
accelerate upon the occurrence of certain events, including six months
following any termination of employment or disposition of the stock.

The following table indicates the amounts due under the term notes for our
executive officers with aggregate indebtedness in excess of $60,000 during the
year ended March 31, 2001:

Largest Aggregate Indebtedness
During Fiscal Year Ended March Outstanding Indebtedness at
Name 31, 2001 March 31, 2001
---- ------------------------------ ---------------------------

Irl F. Engelhardt....... $661,503 $652,858
Richard M. Whiting...... 220,542 217,608
Roger B. Walcott, Jr.... 225,381 216,256
Richard A. Navarre...... 185,345 183,119
Paul H. Vining.......... 213,193 213,193
Jeffery L. Klinger...... 130,169 128,728
Sharon D. Fiehler....... 128,724 128,724

PRINCIPAL STOCKHOLDERS

The following table sets forth information concerning ownership of our
capital stock as of March 31, 2001 by persons who beneficially own more than 5%
of the outstanding shares of capital stock, each person who is a director of
our company, each person who is a named executive officer, and all directors
and executive officers as a group.

Our capital stock consists of our Class A common stock, our Class B common
stock and our non-convertible, exchangeable preferred stock. As of March 31,
2001, there were 26,600,000 shares of Class A common stock, 1,010,509 shares of
Class B common stock and 7,000,000 shares of preferred stock outstanding. Upon
the consummation of this offering, all shares of our Class A common stock,
Class B common stock and preferred stock will be converted into a single class
of common stock on a one-for-one basis. The table below gives effect to these
conversions as though they had occurred on March 31, 2001.

Name and Address of Beneficial As of March 31, Immediately After
Owner 2001 this Offering
------------------------------ ------------------------ ------------------------
Shares(/1/) Percent Shares(/1/) Percent
----------- ------- ----------- -------

Lehman Brothers Merchant
Banking Partners II L.P. and
affiliates
c/o Lehman Brothers Holdings
Inc.
3 World Financial Center, 200
Vesey Street
New York, NY 10285............ 29,400,000 84.9% 29,400,000 59.3%

Co-Investment Partners, L.P.
c/o Lexington Partners Inc.
660 Madison Avenue, 23rd Floor
New York, NY 10021............ 3,500,000 10.1 3,500,000 7.1

Irl F. Engelhardt.............. 443,892(/2/) 1.3 633,364(/3/) 1.3
Richard M. Whiting............. 153,651(/2/) 0.4 223,838(/3/) 0.4
Roger B. Walcott, Jr........... 153,651(/2/) 0.4 223,838(/3/) 0.4
Richard A. Navarre............. 125,671(/2/) 0.4 191,768(/3/) 0.4
Paul H. Vining................. 118,913(/2/) 0.3 203,318(/3/) 0.4
Roger H. Goodspeed(/4/)........ -- -- -- --
Henry E. Lentz(/4/)............ -- -- -- --
Alan H. Washkowitz(/4/)........ -- -- -- --

All executives and directors as
a group (11 people)........... 1,175,861 3.3% 1,778,472 3.6%

--------
(1) Beneficial ownership is determined in accordance with the rules of the SEC
and includes voting and investment power with respect to shares. Unless
otherwise indicated, the persons named in the table have sole voting and
sole investment control with respect to all shares beneficially owned.
(2) Includes options exercisable within 60 days after March 31, 2001.
(3) Includes options exercisable within 60 days after this offering.
(4) Messrs. Goodspeed, Lentz and Washkowitz are Managing Directors of Lehman
Brothers. Mr. Washkowitz is the head of Lehman Brothers Merchant Banking
and Mr. Lentz is a principal of Lehman Brothers Merchant Banking. Messrs.
Goodspeed, Lentz and Washkowitz disclaim beneficial ownership of the shares
held or controlled by these entities or their affiliates.

DESCRIPTION OF INDEBTEDNESS

The following are summaries of the material terms and conditions of our
principal indebtedness.

Senior Credit Facility

The senior credit facility is comprised of a revolving credit facility that
currently provides for aggregate borrowings of up to $200.0 million and letters
of credit of up to $280.0 million. The revolving credit facility commitment
matures in fiscal year 2005. As of March 31, 2001, we had no borrowings
outstanding under the revolving credit facility. The senior credit facility
will be amended in connection with this offering as described below.

All borrowings under the senior credit facility bear interest, at our
option, at either: (A) a "base rate" equal to, for any day, the higher of: (a)
0.50% per annum above the latest Federal Funds Rate and (b) the rate of
interest in effect for the day as publicly announced from time to time by the
administrative agent under the senior credit facility, as the bank's "corporate
base rate," "reference rate," "prime rate" or the substantial equivalent
thereof plus a debt to EBITDA-dependent rate ranging from 1.25% to 0.50% per
year or (B) a "LIBOR rate" equal to, for any Interest Period (as in the senior
credit facility), with respect to LIBOR loans comprising part of the same
borrowing, the London Interbank Offered Rate of interest per year for such
Interest Period as determined by the administrative agent, plus a debt to
EBITDA-dependent rate ranging from 2.25% to 1.50% per year.

We must pay a commitment fee calculated at a debt to EBITDA-dependent rate
ranging from 0.50% to 0.375% per year of the available unused commitment under
the revolving credit facility, in each case, in effect on each day. The fees
are payable quarterly in arrears and upon termination of the revolving credit
facility.

We must pay a letter of credit fee calculated at a debt to EBITDA-dependent
rate ranging from 2.25% to 1.50% per year of the face amount of each letter of
credit and a fronting fee calculated at a rate equal to 0.25% per year of the
aggregate face amount of each letter of credit. These fees are payable
quarterly in arrears and upon the termination of the revolving credit facility.
In addition, we are required to pay customary transaction charges in connection
with any letters of credit.

The foregoing debt to EBITDA-dependent rates range from the high rate
specified if the ratio of debt to EBITDA is greater than 4.75 to 1.0 to the low
rate specified if the ratio is less than 3.75 to 1.0.

Borrowings under the senior credit facility are subject to mandatory
prepayment (1) with the net proceeds of any incurrence of indebtedness (other
than specified indebtedness), (2) with the proceeds of certain asset sales and
(3) on an annual basis with (A) 75% of our excess cash flow (as defined in the
senior credit facility) if the ratio of our debt to EBITDA is greater than 4.0
to 1.0 or (B) 50% of excess cash flow if the ratio is less than or equal to 4.0
to 1.0.

Our obligations under the senior credit facility are secured by a lien on
certain of our and our direct and indirect domestic subsidiaries' tangible and
intangible assets, including: (1) a pledge by us and our direct and indirect
domestic subsidiaries of all of the capital stock of their respective domestic
subsidiaries, (2) certain of our and our direct and indirect domestic
subsidiaries' coal reserves, (3) certain coal supply agreements and other
material contracts to which we or any of our direct or indirect domestic
subsidiaries are a party and (4) substantially all of our other personal
property. In addition, indebtedness under the senior credit facility is
guaranteed by our direct and indirect domestic subsidiaries.

The senior credit facility contains customary covenants and restrictions on
our ability to engage in certain activities, including paying dividends. In
addition, the senior credit facility provides that we must meet or exceed
certain interest coverage ratios and must not exceed a leverage ratio. The
senior credit facility also includes customary events of default.

In connection with this offering, we anticipate repaying the remaining
tranche B term loan outstanding under the senior credit facility.

We have received approval from a sufficient number of our lenders to amend
our senior credit facility. The amendment, which will be effective upon the
consummation of this offering, will permit the payment of cash dividends and
other restricted payments subject to specified limitations, increase the amount
available for borrowing under the revolving credit facility from $200.0 million
to $350.0 million and permit additional joint venture investments. In
connection with the amendment, we agreed to reduce the maximum permitted debt
to EBITDA ratio and increase the minimum required interest coverage ratio. We
paid an amendment fee of $1.4 million to a group of over 100 lenders who
consented to the amendment. Lehman Commercial Paper Inc., an affiliate of
Lehman Brothers, received $0.06 million of that credit facility amendment fee.
All other terms and conditions remain unchanged.

Senior Notes and Senior Subordinated Notes

In May 1998, we issued $400.0 million of senior notes and $500.0 million of
senior subordinated notes. The senior notes are unconditionally guaranteed on a
senior basis by substantially all of our subsidiaries and the subordinated
notes are unconditionally guaranteed on a senior subordinated basis by
substantially all of our subsidiaries. The notes mature on May 15, 2008, with
interest payable semi-annually in arrears on May 15 and November 15. Interest
accrues at the rate of 8.875% per year on the senior notes and at a rate of
9.625% per year on the senior subordinated notes.

The notes may be redeemed at any time, in whole or in part at any time prior
to May 15, 2003 at a price equal to par plus a make-whole premium. We may
redeem the notes on or after May 15, 2003, at a redemption price equal to
104.438% of the principal amount of the senior notes and 104.813% of the
principal amount of the senior subordinated notes in the first year. The
redemption prices decline yearly to par for both the senior notes and the
senior subordinated notes at May 15, 2006, plus accrued and unpaid interest to
the date of redemption.

We intend to offer to repurchase a portion of our senior notes and our
senior subordinated notes using proceeds from this offering.

Upon the occurrence of a change of control, each holder of the notes will
have the right to require us to repurchase that holder's notes at a price equal
to 101% of their principal amount, plus accrued and unpaid interest to the
repurchase date.

The indentures governing the senior notes and the senior subordinated notes
contain covenants that, among other things, limit our ability to:

. lease, convey or otherwise dispose of all or substantially all of our
assets or those of subsidiaries;

. pay dividends or make other distributions;

. issue specified types of capital stock;

. enter into guarantees of indebtedness;

. incur liens;

. restrict our subsidiaries' ability to make dividend payments;

. merge or consolidate with any other person or enter into transactions
with affiliates; and

. repurchase junior securities or make specified types of investments.

5% Subordinated Note

The 5.0% subordinated note, which had an original face value of $400.0
million and a current face value of $220.0 million, is recorded net of discount
at an imputed annual interest rate of approximately 12.0%, resulting in a long-
term debt carrying amount of $169.9 million as of March 31, 2001. Interest and
principal

are payable each March 1 and scheduled principal payments of $20.0 million per
year are due from 2002 through 2006 with any unpaid amounts due March 1, 2007.
The note is a subordinated and unsecured obligation of our subsidiary, Peabody
Holding Company, Inc. The terms of the note permit the merger, consolidation or
the sale of assets of Peabody Holding Company, Inc., as long as the successor
corporation following the merger or consolidation (if Peabody Holding Company,
Inc. does not survive) expressly assumes payment of principal and interest on
and performance of the covenants and conditions of the note.

We repaid $110.2 million of the face value, or $85.0 million carrying
amount, of the 5.0% subordinated note for $100.0 million on May 2, 2001.

Black Beauty Coal Company

As of March 31, 2001, Black Beauty maintained a $100.0 million revolving
credit facility with several banks that matures on February 28, 2002. Black
Beauty may elect one or a combination of interest rates based on LIBOR or the
corporate base rate plus a margin which fluctuates based on specified leverage
ratios. Borrowings outstanding under the Black Beauty revolving credit
agreement totaled $70.0 million at March 31, 2001. The revolving credit
facility contains customary restrictive covenants including limitations on
additional debt, investments and dividends. Black Beauty's ability to pay
dividends is subject to certain financial tests.

Black Beauty's senior unsecured notes include $31.4 million of senior notes
and three series of notes with an aggregate principal amount of $60.0 million
as of March 31, 2001. The senior notes bear interest at 9.2%, payable
quarterly, and are pre-payable in whole or in part at any time, subject to
certain make-whole provisions. The three series of notes include Series A, B
and C notes, totaling $45.0 million, $5.0 million, and $10.0 million,
respectively. The Series A notes bear interest at an annual rate of 7.5% and
are due in fiscal year 2008. The Series B notes bear interest at an annual rate
of 7.4% and are due in fiscal year 2004. The Series C notes bear interest at an
annual rate of 7.4% and are due in fiscal year 2003. The senior unsecured notes
contain customary restrictive covenants including limitations on additional
debt, investments and dividends.

Certain majority-owned subsidiaries of Black Beauty maintain borrowing
facilities with banks and other lenders with customary restrictive covenants.
The aggregate amount of outstanding indebtedness under those facilities totaled
$47.8 million as of March 31, 2001.

Surety Bonds

Federal and state laws require surety bonds to secure our obligations to
reclaim lands disturbed for mining, to pay federal and state workers'
compensation and to satisfy other miscellaneous obligations. The amount of
these bonds varies constantly, depending upon the amount of acreage disturbed
and the degree to which each property has been reclaimed. Under federal law,
partial bond release is provided as mined lands (1) are backfilled and graded
to approximate original contour, (2) are re-vegetated and (3) achieve pre-
mining vegetative productivity levels on a sustained basis for a period of five
to 10 years.

As of March 31, 2001, we had outstanding surety bonds with third parties for
post-mining reclamation totaling $651.8 million, with an additional $216.5
million in self-bonding obligations. We have $77.4 million of surety bonds in
place for federal and state workers' compensation obligations and other
miscellaneous obligations.

DESCRIPTION OF CAPITAL STOCK

Upon consummation of this offering, our authorized capital stock will
consist of (1) 150 million shares of common stock, par value $.01 per share, of
which 49.6 million shares, or 51.9 million shares of common stock if the
underwriters exercise their over-allotment option in full, will be issued and
outstanding, (2) 10 million shares of preferred stock, par value $.01 per
share, of which no shares will be issued and outstanding and (3) 40 million
shares of series common stock, par value $.01 per share, of which no shares
will be issued and outstanding. As of March 31, 2001, there were 36 holders of
our common stock. The following description of our capital stock and related
matters is qualified in its entirety by reference to our certificate of
incorporation and by-laws, copies of which will be filed as exhibits to the
registration statement of which this prospectus forms a part.

The following summary describes elements of our certificate of incorporation
and by-laws after giving effect to the offering.

Common Stock

Holders of common stock are entitled to one vote per share on all matters to
be voted upon by the stockholders. The holders of common stock do not have
cumulative voting rights in the election of directors. Holders of common stock
are entitled to receive ratably dividends if, as and when dividends are
declared from time to time by our board of directors out of funds legally
available for that purpose, after payment of dividends required to be paid on
outstanding preferred stock or series common stock, as described below. Upon
liquidation, dissolution or winding up, any business combination or a sale or
disposition of all or substantially all of the assets, the holders of common
stock are entitled to receive ratably the assets available for distribution to
the stockholders after payment of liabilities and accrued but unpaid dividends
and liquidation preferences on any outstanding preferred stock or series common
stock. The common stock has no preemptive or conversion rights and is not
subject to further calls or assessment by us. There are no redemption or
sinking fund provisions applicable to the common stock.

Preferred Stock and Series Common Stock

Our certificate of incorporation authorizes our board of directors to
establish one or more series of preferred stock or series common stock. With
respect to any series of series common stock, our board of directors is
authorized to determine the terms and rights of that series, including:

. the designation of the series;

. the number of shares of the series, which our board may, except where
otherwise provided in the preferred stock or series common stock
designation, increase or decrease, but not below the number of shares
then outstanding;

. whether dividends, if any, will be cumulative or non-cumulative and the
dividend rate of the series;

. the dates at which dividends, if any, will be payable;

. the redemption rights and price or prices, if any, for shares of the
series;

. the terms and amounts of any sinking fund provided for the purchase or
redemption of shares of the series;

. the amounts payable on shares of the series in the event of any
voluntary or involuntary liquidation, dissolution or winding-up of the
affairs of our company;

. whether the shares of the series will be convertible into shares of any
other class or series, or any other security, of our company or any
other corporation, and, if so, the specification of the other class or
series or other security, the conversion price or prices or rate or
rates, any rate adjustments, the date or dates as of which the shares
will be convertible and all other terms and conditions upon which the
conversion may be made;

. restrictions on the issuance of shares of the same series or of any
other class or series; and

. the voting rights, if any, of the holders of the series.

Unless required by law or by any stock exchange, the authorized shares of
preferred stock and series common stock, as well as shares of common stock,
will be available for issuance without further action by you.

Although we have no intention at the present time of doing so, we could
issue a series of preferred stock or series common stock that could, depending
on the terms of the series, impede the completion of a merger, tender offer or
other takeover attempt. We will make any determination to issue preferred stock
or series common stock based on our judgment as to the best interests of the
company and our stockholders. We, in so acting, could issue preferred stock or
series common stock having terms that could discourage an acquisition attempt
or other transaction that some, or a majority, of you might believe to be in
your best interests or in which you might receive a premium for your common
stock over the market price of the common stock.

Authorized but Unissued Capital Stock

Delaware law does not require stockholder approval for any issuance of
authorized shares. However, the listing requirements of the New York Stock
Exchange, which would apply so long as the common stock remains listed on the
New York Stock Exchange, require stockholder approval of certain issuances
equal to or exceeding 20% of the then-outstanding voting power or then-
outstanding number of shares of common stock. These additional shares may be
used for a variety of corporate purposes, including future public offerings, to
raise additional capital or to facilitate acquisitions.

One of the effects of the existence of unissued and unreserved common stock,
preferred stock or series common stock may be to enable our board of directors
to issue shares to persons friendly to current management, which issuance could
render more difficult or discourage an attempt to obtain control of our company
by means of a merger, tender offer, proxy contest or otherwise, and thereby
protect the continuity of our management and possibly deprive the stockholders
of opportunities to sell their shares of common stock at prices higher than
prevailing market prices.

Anti-Takeover Effects of Provisions of Delaware Law and Our Charter and By-laws

Delaware Law

Our company is a Delaware corporation subject to Section 203 of the Delaware
General Corporation Law. Section 203 provides that, subject to certain
exceptions specified in the law, a Delaware corporation shall not engage in
certain "business combinations" with any "interested stockholder" for a three-
year period following the time that the stockholder became an interested
stockholder unless:

. prior to such time, our board of directors approved either the business
combination or the transaction which resulted in the stockholder becoming
an interested stockholder;

. upon consummation of the transaction which resulted in the stockholder
becoming an interested stockholder, the interested stockholder owned at
least 85% of our voting stock outstanding at the time the transaction
commenced, excluding certain shares; or

. at or subsequent to that time, the business combination is approved by
our board of directors and by the affirmative vote of holders of at least
66 2/3% of the outstanding voting stock which is not owned by the
interested stockholder.

Generally, a "business combination" includes a merger, asset or stock sale
or other transaction resulting in a financial benefit to the interested
stockholder. Subject to certain exceptions, an "interested shareholder" is a
person who together with that person's affiliates and associates owns, or
within the previous three years did own, 15% or more of our voting stock.

Under certain circumstances, Section 203 makes it more difficult for a
person who would be an "interested stockholder" to effect various business
combinations with a corporation for a three-year period. The provisions of
Section 203 may encourage companies interested in acquiring our company to
negotiate in advance with our board of directors because the stockholder
approval requirement would be avoided if our board of directors approves either
the business combination or the transaction which results in the stockholder
becoming an interested stockholder. These provisions also may have the effect
of preventing changes in our board of directors and may make it more difficult
to accomplish transactions which stockholders may otherwise deem to be in their
best interests.

Certificate of Incorporation; By-laws

Our certificate of incorporation and by-laws contain provisions that could
make more difficult the acquisition of the company by means of a tender offer,
a proxy contest or otherwise.

Classified Board. Our certificate of incorporation provides that our board
of directors will be divided into three classes of directors, with the classes
to be as nearly equal in number as possible. As a result, approximately one-
third of the board of directors will be elected each year. The classification
of directors will have the effect of making it more difficult for stockholders
to change the composition of our board. Our certificate of incorporation
provides that, subject to any rights of holders of preferred stock or series
common stock to elect additional directors under specified circumstances, the
number of directors will be fixed in the manner provided in our by-laws. Our
certificate of incorporation and by-laws provide that the number of directors
will be fixed from time to time exclusively pursuant to a resolution adopted by
the board, but must consist of not less than three directors. In addition, our
certificate of incorporation provides that, subject to any rights of holders of
preferred stock or series common stock and unless the board otherwise
determines, any vacancies will be filled only by the affirmative vote of a
majority of the remaining directors, though less than a quorum.

Removal of Directors. Under Delaware General Corporation Law, unless
otherwise provided in our certificate of incorporation, directors serving on a
classified board may only be removed by the stockholders for cause. In
addition, our certificate of incorporation and by-laws provide that directors
may be removed only for cause and only upon the affirmative vote of holders of
at least 75% of the voting power of all the outstanding shares of stock
entitled to vote generally in the election of directors, voting together as a
single class.

Stockholder Action. Our certificate of incorporation and by-laws provide
that stockholder action can be taken only at an annual or special meeting of
stockholders and may not be taken by written consent in lieu of a meeting. Our
certificate of incorporation and by-laws provide that special meetings of
stockholders can be called only by our chief executive officer or pursuant to a
resolution adopted by our board of directors. Stockholders are not permitted to
call a special meeting or to require that the board of directors call a special
meeting of stockholders.

Advance Notice Procedures. Our by-laws establish an advance notice procedure
for stockholders to make nominations of candidates for election as directors,
or bring other business before an annual or special meeting of our
stockholders. This notice procedure provides that only persons who are
nominated by, or at the direction of our board of directors, the chairman of
the board, or by a stockholder who has given timely written notice to the
secretary of our company prior to the meeting at which directors are to be
elected, will be eligible for election as directors. This procedure also
requires that, in order to raise matters at an annual or special meeting, those
matters be raised before the meeting pursuant to the notice of meeting we
deliver or by, or at the direction of, our chairman or by a stockholder who is
entitled to vote at the meeting and who has given timely written notice to the
secretary of our company of his intention to raise those matters at the annual
meeting. If our chairman or other officer presiding at a meeting determines
that a person was not nominated, or other business was not brought before the
meeting, in accordance with the notice procedure, that person will not be
eligible for election as a director, or that business will not be conducted at
the meeting.

Amendment. Our certificate of incorporation provides that the affirmative
vote of the holders of at least 75% of the voting power of the outstanding
shares entitled to vote, voting together as a single class, is required to
amend provisions of our certificate of incorporation relating to the
prohibition of stockholder action without a meeting, the number, election and
term of our directors and the removal of directors. Our certificate of
incorporation further provides that our by-laws may be amended by our board or
by the affirmative vote of the holders of at least 75% of the outstanding
shares entitled to vote, voting together as a single class.

Registrar and Transfer Agent

The registrar and transfer agent for the common stock is EquiServe Trust
Company, N.A.

Listing

The common stock has been authorized for listing on the New York Stock
Exchange, subject to official notice of issuance, under the symbol "BTU."

SHARES ELIGIBLE FOR FUTURE SALE

Prior to this offering, there has not been any public market for our common
stock, and we cannot predict what effect, if any, market sales of shares of
common stock or the availability of shares of common stock for sale will have
on the market price of our common stock. Nevertheless, sales of substantial
amounts of common stock, including shares issued upon the exercise of
outstanding options, in the public market, or the perception that such sales
could occur, could materially and adversely affect the market price of our
common stock and could impair our future ability to raise capital through the
sale of our equity or equity-related securities at a time and price that we
deem appropriate.

Upon the closing of this offering, we will have outstanding an aggregate of
approximately 49.6 million shares of common stock, assuming no exercise of
outstanding options or exercise of the over-allotment option. Of the
outstanding shares, the shares sold in this offering will be freely tradable
without restriction or further registration under the Securities Act, except
that any shares held by our "affiliates," as that term is defined under Rule
144 of the Securities Act, may be sold only in compliance with the limitations
described below. The remaining shares of common stock will be deemed
"restricted securities" as defined under Rule 144. Restricted securities may be
sold in the public market only if registered or if they qualify for an
exemption from registration under Rule 144 or 144(k) under the Securities Act,
which we summarize below.

Subject to the lock-up agreements described below and the provisions of
Rules 144 and 144(k), additional shares of our common stock will be available
for sale in the public market under exemptions from registration requirements
as follows:

Number of Shares Date
---------------- ----

30.2 million After 180 days from the date of this prospectus (subject, in
some cases, to volume limitations and other conditions under
Rule 144)

4.4 million At various times after 180 days from the date of this
prospectus (Rule 144(k))

Lehman Brothers Merchant Banking, which along with its affiliates owns 29.4
million shares, will have the ability to cause us to register the resale of its
shares.

Rule 144

In general, under Rule 144 as currently in effect, a person (or persons
whose shares are required to be aggregated), including an affiliate, who has
beneficially owned shares of our common stock for at least one year is entitled
to sell in any three-month period a number of shares that does not exceed the
greater of:

. 1% of the then-outstanding shares of common stock or approximately
496,000 shares assuming no exercise of the over-allotment option; and

. the average weekly trading volume in the common stock on the New York
Stock Exchange during the four calendar weeks preceding the date on which
notice of sale is filed, subject to restrictions.

Sales under Rule 144 are also subject to manner of sale provisions and
notice requirements and to the availability of current public information about
us.

Rule 144(k)

In addition, a person who is not deemed to have been an affiliate of ours at
any time during the 90 days preceding a sale and who has beneficially owned the
shares proposed to be sold for at least two years, would be entitled to sell
those shares under Rule 144(k) without regard to the manner of sale, public
information, volume limitation or notice requirements of Rule 144. To the
extent that our affiliates sell their shares, other than pursuant to Rule 144
or a registration statement, the purchaser's holding period for the purpose of
effecting a sale under Rule 144 commences on the date of transfer from the
affiliate.

Lock-Up Agreements

Our directors, officers and existing stockholders have agreed that they will
not sell, directly or indirectly, subject to certain exceptions, any shares of
our common stock for a period of 180 days from the date of this prospectus,
without the prior written consent of Lehman Brothers Inc. Lehman Brothers Inc.,
in its sole discretion, may release the shares subject to the lock-up
agreements in whole or in part at anytime with or without notice. When
determining whether to release shares from the lock-up agreements, Lehman
Brothers Inc. will consider, among other factors, the stockholder's reasons for
requesting the release, the number of shares for which the release is being
requested and market conditions at the time. Lehman Brothers Inc. does not at
this time have any intention of releasing any of the shares subject to the
lock-up agreements prior to the expiration of the lock-up period.

We have agreed not to sell or otherwise dispose of any shares of our common
stock during the 180-day period following the date of this prospectus, except
we may issue, and grant options to purchase, shares of common stock under our
existing employee benefit plans referred to in this prospectus. In addition, we
may issue shares of common stock in connection with any acquisition of another
company if the terms of the issuance provide that the common stock may not be
resold prior to the expiration of the 180-day period described above.

Stock Options

Options to purchase up to an aggregate of approximately 5.2 million shares
of our common stock will be outstanding as of the closing of this offering. Of
these options, approximately 2.8 million will have vested at or prior to the
closing of this offering and approximately 2.2 million may vest over the next
two years. Each of our employees who has been granted stock options under our
employee benefit plans has agreed pursuant to their option agreements that they
will not transfer any shares of our common stock for a period of two years
after completion of this offering.

Within one year of this offering, we intend to file one or more registration
statements on Form S-8 under the Securities Act to register all shares of
common stock subject to outstanding stock options and options issuable under
our stock purchase and option plan and long-term equity incentive plan. After
expiration of the applicable contractual resale restrictions, shares covered by
these registration statements will be eligible for sale in the public markets,
other than shares owned by our affiliates, which may be sold in the public
market if they are registered or qualify for an exemption from registration
under Rule 144.

CERTAIN U.S. TAX CONSEQUENCES TO NON-U.S. HOLDERS

The following summary describes the material U.S. federal income and estate
tax consequences of the ownership of common stock by a Non-U.S. Holder (as
defined below) as of the date hereof. This discussion does not address all
aspects of U.S. federal income and estate taxes and does not deal with foreign,
state and local consequences that may be relevant to Non-U.S. Holders in light
of their personal circumstances. Special rules may apply to certain Non-U.S.
Holders, such as "controlled foreign corporations," "passive foreign investment
companies," "foreign personal holding companies," individuals who are U.S.
expatriates and corporations that accumulate earnings to avoid U.S. federal
income tax, that are subject to special treatment under the Internal Revenue
Code of 1986, the Code, as amended. Those entities should consult their own tax
advisors to determine the U.S. federal, state, local and other tax consequences
that may be relevant to them. Furthermore, the discussion below is based upon
the provisions of the Code and regulations, rulings and judicial decisions
thereunder as of the date hereof, and such authorities may be repealed, revoked
or modified so as to result in U.S. federal income tax consequences different
from those discussed below. If a partnership holds common stock, the tax
treatment of a partner will generally depend upon the status of the partner and
the activities of the partnership. A holder that is a partner in a partnership
holding the common stock should consult its own tax advisor. Persons
considering the purchase, ownership or disposition of common stock should
consult their own tax advisors concerning the U.S. federal income tax
consequences in light of their particular situations as well as any
consequences arising under the laws of any other taxing jurisdiction.

As used herein, a "U.S. Holder" of common stock means a holder that is (1) a
citizen or resident of the United States, (2) a corporation or partnership
created or organized in or under the laws of the United States or any political
subdivision thereof, (3) an estate the income of which is subject to U.S.
federal income taxation regardless of its source and (4) a trust (A) that is
subject to the primary supervision of a court within the United States and the
control of one or more U.S. persons as described in section 7701(a)(30) of the
Code or (B) that has a valid election in effect under applicable U.S. Treasury
regulations to be treated as a U.S. person. A "Non-U.S. Holder" is a holder
that is not a U.S. Holder.

Dividends

Dividends paid to a Non-U.S. Holder of common stock generally will be
subject to withholding of U.S. federal income tax at a 30% rate or such lower
rate as may be specified by an applicable income tax treaty. However, dividends
that are effectively connected with the conduct of a trade or business by the
Non-U.S. Holder within the United States and, where a tax treaty applies, are
attributable to a United States permanent establishment of the Non-U.S. Holder,
are not subject to the withholding tax, but instead are subject to U.S. federal
income tax on a net income basis at applicable graduated individual or
corporate rates. Certain certification and disclosure requirements must be
complied with in order for effectively connected income to be exempt from
withholding. Any such effectively connected dividends received by a foreign
corporation may, under certain circumstances, be subject to an additional
"branch profits tax" at a 30% rate or a lower rate that is specified by an
applicable income tax treaty.

A Non-U.S. Holder of common stock who wishes to claim an exemption from, or
reduction in, withholding under the benefit of an applicable treaty rate (and
avoid back-up withholding as discussed below) for dividends, will be required
to file Internal Revenue Service Form W-8BEN (or successor form) and satisfy
certification requirements of applicable U.S. Treasury regulations.

A Non-U.S. Holder of common stock eligible for a reduced rate of U.S.
withholding tax under an income tax treaty may obtain a refund of any excess
amounts withheld by filing an appropriate claim for refund with the Internal
Revenue Service.

Gain on Disposition of Common Stock

A Non-U.S. Holder generally will not be subject to U.S. federal income tax
with respect to gain recognized on a sale or other disposition of common stock
unless (1) the gain is effectively connected with a trade or

business of the Non-U.S. Holder in the United States, and, where a tax treaty
applies, is attributable to a U.S. permanent establishment of the Non-U.S.
Holder, (2) in the case of a Non-U.S. Holder who is an individual and holds the
common stock as a capital asset, such holder is present in the United States
for 183 or more days in the taxable year of the sale or other disposition and
certain other conditions are met, or (3) the company is or has been a "U.S.
real property holding corporation" for U.S. federal income tax purposes at any
time during the shorter of the five-year period ending on the date of
disposition and the Non-U.S. Holder's holding period for the common stock.

An individual Non-U.S. Holder described in clause (1) above will be subject
to tax on the net gain derived from the sale under regular graduated U.S.
federal income tax rates. An individual Non-U.S. Holder described in clause (2)
above will be subject to a flat 30% tax on the gain derived from the sale,
which may be offset by U.S. source capital losses (even though the individual
is not considered a resident of the U.S.). If a Non-U.S. Holder that is a
foreign corporation falls under clause (1) above, it will be subject to tax on
its gain under regular graduated U.S. federal income tax rates and, in
addition, may be subject to the branch profits tax equal to 30% of its
effectively connected earnings and profits or at such lower rate as may be
specified by an applicable income tax treaty.

The determination of whether a corporation is a "United States real property
holding corporation" involves a complex factual analysis, with a valuation of
all of the company's assets. We have not determined at this time whether we are
a United States real property holding corporation for U.S. federal income tax
purposes, although investors should be aware that there is a significant
possibility that we are or will become a United States real property holding
corporation. If we are or become a United States real property holding
corporation, then assuming the common stock is regularly traded on an
established securities market, only a Non-U.S. Holder who holds or held (at any
time during the shorter of the five-year period ending on the date of
disposition and the Non-U.S. Holder's holding period for the common stock) more
than five percent of the common stock will be subject to U.S. federal income
tax on the disposition of the common stock under these rules.

U.S. Estate Tax

Common stock held by an individual Non-U.S. Holder at the time of death will
be included in such holder's gross estate for U.S. federal estate tax purposes,
unless an applicable estate tax treaty provides otherwise.

Information Reporting and Backup Withholding

Our company must report annually to the IRS and to each Non-U.S. Holder the
amount of dividends paid to that holder and the tax withheld with respect to
those dividends, regardless of whether withholding was required. Copies of the
information returns reporting those dividends and withholding may also be made
available to the tax authorities in the country in which the Non-U.S. Holder
resides under the provisions of an applicable income tax treaty.

A Non-U.S. Holder will be subject to back-up withholding at the rate of 31%
unless applicable certification requirements are met.

Proceeds of a sale of common stock paid within the United States or through
certain U.S. related financial intermediaries are subject to both back-up
withholding and information reporting unless the beneficial owner certifies
under penalties of perjury that it is a Non-U.S. Holder (and the payor does not
have actual knowledge that the beneficial owner is a U.S. person), or the
holder establishes another exemption.

Any amounts withheld under the back-up withholding rules may be allowed as a
refund or a credit against such holder's U.S. federal income tax liability if
the required information is furnished to the Internal Revenue Service.

UNDERWRITING

Under the terms of an Underwriting Agreement, which is filed as an exhibit
to the registration statement relating to this prospectus, each of the U.S.
underwriters named below, for whom Lehman Brothers Inc., Bear, Stearns & Co.
Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley & Co.
Incorporated, UBS Warburg LLC and A.G. Edwards & Sons, Inc. are acting as U.S.
representatives for the sale of our common stock in the United States and
Canada, and the international underwriters named below, for whom Lehman
Brothers International (Europe), Bear, Stearns International Limited, Merrill
Lynch International, Morgan Stanley & Co. International Limited, UBS AG, acting
through its business group UBS Warburg, and Cazenove & Co. are acting as
international representatives for the sale of our common stock outside the
United States and Canada, have severally agreed to purchase from us the
respective number of shares of common stock opposite their names below:

U.S. Underwriters Number of Shares
----------------- ----------------

Lehman Brothers Inc......................................... 2,075,000
Bear, Stearns & Co. Inc..................................... 2,075,000
Merrill Lynch, Pierce, Fenner & Smith
Incorporated........................................... 2,075,000
Morgan Stanley & Co. Incorporated........................... 2,075,000
UBS Warburg LLC............................................. 2,075,000
A.G. Edwards & Sons, Inc. .................................. 270,000
ABN AMRO Rothschild LLC..................................... 125,000
Fidelity Capital Markets, a division of National Financial
Services LLC............................................... 125,000
Prudential Securities Incorporated.......................... 125,000
Robertson Stephens, Inc. ................................... 125,000
Scotia Capital (USA) Inc. .................................. 125,000
SG Cowen Securities Corporation............................. 125,000
Stifel, Nicolaus & Company, Incorporated.................... 125,000
Cazenove Inc. .............................................. 60,000
Chatsworth Securities LLC................................... 60,000
Fahnestock & Co. Inc. ...................................... 60,000
First Southwest Company..................................... 60,000
Johnson Rice & Company L.L.C. .............................. 60,000
Edward D. Jones & Co. L.P. ................................. 60,000
Petrie Parkman & Co. ....................................... 60,000
Sanders Morris Harris....................................... 60,000
----------
Total..................................................... 12,000,000
==========

International Underwriters Number of Shares
-------------------------- ----------------

Lehman Brothers International (Europe)...................... 540,000
Bear, Stearns International Limited......................... 540,000
Merrill Lynch International................................. 540,000
Morgan Stanley & Co. International Limited.................. 540,000
UBS AG, acting through its business group UBS Warburg....... 540,000
Cazenove & Co............................................... 300,000
----------
Total..................................................... 3,000,000
==========

100

The U.S. underwriters and the international underwriters are collectively
referred to as the underwriters, and the U.S. representatives and the
international representatives are collectively referred to as the
representatives. The underwriting agreement provides that the underwriters'
obligations to purchase our common stock depend on the satisfaction of the
conditions contained in the underwriting agreement, and that if any shares of
common stock are purchased by the underwriters under the underwriting
agreement, then all the shares of common stock that the underwriters have
agreed to purchase under the underwriting agreement must be purchased. If an
underwriter defaults, the underwriting agreement provides that the purchase
commitments of the non-defaulting underwriters may be increased or the
underwriting agreement may be terminated. The conditions contained in the
underwriting agreement include that:

. the representations and warranties made by us to the underwriters are
true;

. there is no material change in the financial markets; and

. we deliver customary closing documents to the underwriters.

We have granted the underwriters a 30-day option after the date of this
prospectus, to purchase, from time to time, in whole or in part, up to an
aggregate of 2,250,000 shares at the public offering price less underwriting
discounts and commissions. The option may be exercised to cover over-
allotments, if any, made in connection with the offering. To the extent that
this option is exercised, each underwriter will be obligated, subject to
certain conditions, to purchase its pro rata portion of these additional shares
based on the underwriter's percentage underwriting commitment in the offering
as indicated in the preceding table.

The representatives have advised us that the offering price and the
underwriting discounts and commission per share for the U.S. offering and the
international offering are identical and that the underwriters propose to offer
shares of common stock directly to the public at the public offering price on
the cover of this prospectus and to selected dealers, who may include the
underwriters, at such offering price less a selling concession not in excess of
$1.02 per share. The underwriters may allow, and the selected dealers may re-
allow, a discount from the concession not in excess of $0.10 per share to other
dealers. After the offering, the representatives may change the public offering
price and other offering terms.

The following table summarizes the underwriting discounts and commissions we
will pay to the underwriters. These amounts are shown assuming both no exercise
and full exercise of the underwriters' over-allotment option to purchase
2,250,000 additional shares. The underwriting fee is the difference between the
initial price to the public and the amount the underwriters pay to us for the
shares.

Full
No Exercise Exercise
----------- -----------

Per share............................................ $ 1.575 $ 1.575
----------- -----------
Total.............................................. $23,625,000 $27,168,750
=========== ===========

The expenses of the offering that are payable by us are estimated to be
$3,375,000.

Our shares have been authorized for listing on the New York Stock Exchange
under the symbol "BTU." In connection with that listing, the underwriters have
undertaken to sell the minimum number of shares to the minimum number of
beneficial owners necessary to meet the New York Stock Exchange listing
requirements.

The U.S. underwriters and the international underwriters have entered into
an agreement pursuant to which each U.S. underwriter has agreed that, as a part
of the distribution of the shares of common stock offered in the offering in
the United States and Canada:

. it is not purchasing any such shares for the account of anyone other than
a U.S. person; and

. it has not offered or sold, will not offer, sell, resell or deliver,
directly or indirectly, any shares or distribute any prospectus relating
to the offering in the United States and Canada to anyone other than a
U.S. person.

101

In addition, pursuant to this agreement, each international underwriter has
agreed that, as part of the distribution of the shares of common stock offered
in the offering outside the United States and Canada:

. it is not purchasing any such shares for the account of a U.S. person;
and

. it has not offered or sold, will not offer, sell, resell or deliver,
directly or indirectly, any shares or distribute any prospectus relating
to the offering outside the United States and Canada to any U.S. person.

As used in this section, the term "U.S. person" means any resident or
national of the United States or Canada, any corporation, partnership or other
entity created or organized in or under the laws of the United States or
Canada, or any estate or trust the income of which is subject to United States
or Canadian federal income taxation regardless of the source. "Canada" means
Canada, its provinces, its territories, its possessions and other areas subject
to its jurisdiction.

The foregoing limitations do not apply to stabilization transactions or to
other transactions specified in the agreement between the U.S. underwriters and
the international underwriters, including:

. purchase and sales between U.S. underwriters and the international
underwriters;

. offers, sales, resales, deliveries or distributions to or through
investment advisors or other persons exercising investment discretion;

. purchases, offers or sales by a U.S. underwriter who is also acting as an
international underwriter or by an international underwriter who is also
acting as a U.S. underwriter; and

. other transactions specifically approved by the U.S. representatives and
the international representatives.

Pursuant to the agreement between the U.S. underwriters and the
international underwriters, sales may be made between the U.S. underwriters and
the international underwriters of such a number of shares of common stock as
may be mutually agreed. The price of any shares so sold will be the public
offering price as then in effect for the shares of common stock being sold by
the U.S. underwriters and the international underwriters less an amount equal
to the selling concession allocable to the shares of common stock, unless
otherwise determined by mutual agreement. To the extent that there are sales
between the U.S. underwriters and the international underwriters pursuant to
the agreement between the U.S. underwriters and the international underwriters,
the number of shares of common stock available for sale by the U.S.
underwriters or by the international underwriters may be more or less than the
amount specified on the cover page of this prospectus.

Prior to this offering, there has been no public market for our common
stock. The initial public offering price was determined by negotiation between
us and the underwriters. The factors that the representatives considered in
determining the public offering price include:

. the history and prospects for the industry in which we compete;

. the ability of our management and our business potential and earning
prospects;

. the prevailing securities markets at the time of this offering; and

. the recent market prices of, and the demand for, publicly traded shares
of generally comparable companies.

The representatives may engage in over-allotment, stabilizing transactions,
syndicate covering transactions, and penalty bids or purchases for the purpose
of pegging, fixing or maintaining the price of the common stock, in accordance
with Regulation M under the Exchange Act of 1934:

. Over-allotment involves sales by the underwriters of shares in excess of
the number of shares the underwriters are obligated to purchase, which
creates a syndicate short position. The short position may be either a
covered short position or a naked short position. In a covered short
position, the number of shares over-allotted by the underwriters is not
greater than the number of shares that they may purchase in the over-
allotment option. In a naked short position, the number of shares
involved is greater than the number of shares in the over-allotment
option. The underwriters may close out any short position by either
exercising their over-allotment option and/or purchasing shares in the
open market;

102

. Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum;

. Syndicate covering transactions involve purchases of the common stock in
the open market after the distribution has been completed in order to
cover syndicate short positions. In determining the source of shares to
close out the short position, the underwriters will consider, among other
things, the price of shares available for purchase in the open market as
compared to the price at which they may purchase shares through the over-
allotment option. If the underwriters sell more shares than could be
covered by the over-allotment option, a naked short position, the
position can be closed out only by buying shares in the open market. A
naked short position is more likely to be created if the underwriters are
concerned that there could be downward pressure on the price of the
shares in the open market after pricing that could adversely affect
investors who purchase in the offering; and

. Penalty bids permit the representatives to reclaim a selling concession
from a syndicate member when the common stock originally sold by the
syndicate member is purchased in a stabilizing or syndicate covering
transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty
bids may have the effect of raising or maintaining the market price of our
common stock or preventing or retarding a decline in the market price of the
common stock. As a result, the price of the common stock may be higher than the
price that might otherwise exist in the open market. These transactions may be
effected on The New York Stock Exchange or otherwise and, if commenced, may be
discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction
as to the direction or magnitude of any effect that the transactions described
above may have on the price of the common stock. In addition, neither we nor
any of the underwriters make representations that the representatives will
engage in these stabilizing transactions or that any transaction, once
commenced, will not be discontinued without notice.

The underwriters have informed us that they do not intend to confirm sales
to discretionary accounts without the prior written approval of the customer.
Discretionary accounts are accounts over which a customer has given an
underwriter the authority to make investment decisions on the customer's
behalf.

We, our directors, officers, and all current stockholders have agreed
subject to specified exceptions, not to offer to sell, sell or otherwise
dispose of, directly or indirectly, any shares of capital stock or any
securities that may be converted into or exchanged for any shares of capital
stock for a period of 180 days from the date of the prospectus without the
prior written consent of Lehman Brothers Inc.

Each international underwriter has represented and agreed that:

. it has not offered or sold and, prior to the date that is six months
after the date of issue of the shares of common stock, will not offer or
sell any shares of common stock to persons in the United Kingdom, except
to persons whose ordinary activities involve them in acquiring, holding,
managing or disposing of investments (as principal or agent) for the
purposes of their businesses or otherwise in circumstances which have
not resulted and will not result in an offer to the public in the United
Kingdom within the meaning of the Public Offers of Securities
Regulations 1995;

. it has complied and will comply with all applicable provisions of the
Financial Services Act 1986 with respect to anything done by it in
relation to the shares of common stock in, from or otherwise involving
the United Kingdom; and

. it has only issued or passed on, and will only issue or pass on to any
person in the United Kingdom any document received by it in connection
with the issue of the shares of common stock if that person is of a kind
described in Article 11(3) of the Financial Services Act 1986
(Investment Advertisements) (Exemptions) Order 1996 or is a person to
whom such document may otherwise be issued or passed upon.

103

Messrs. Goodspeed, Lentz and Washkowitz, each one of our directors, are also
each Managing Directors of Lehman Brothers Inc.

We have agreed to indemnify the underwriters against liabilities relating to
this offering, including liabilities under the Securities Act, liabilities
arising from breaches of the representations and warranties contained in the
underwriting agreement, and liabilities incurred in connection with the
directed share program referred to below, and to contribute to payments that
the underwriters may be required to make for these liabilities.

At our request, the underwriters have reserved up to 750,000 shares of the
common stock offered by this prospectus for sale pursuant to a directed share
program to our employees, directors and friends at the initial public offering
price on the cover page of this prospectus. These persons must commit to
purchase no later than the close of business on the day following the date of
this prospectus. The number of shares available for sale to the general public
will be reduced to the extent these persons purchase the reserved shares.

One or more of the underwriters and/or selling group members participating
in this offering, or their affiliates, may make this prospectus available, in
electronic format, on Internet sites or through other online services
maintained by them. In those cases, prospective investors may view offering
terms online and, depending upon the particular underwriter or selling group
member, prospective investors may be allowed to place orders online. Those
prospective investors consist of customers of the respective underwriters or
selling group members. The underwriters may agree with us to allocate a
specific number of shares for sale to online brokerage account holders. Any
allocation for online distributions will be made by the underwriters on the
same basis as other allocations.

Neither we nor any underwriter or selling group member, in its capacity as
underwriter or selling group member, has approved and/or endorsed any
information contained on any underwriter's or selling group member's Internet
site, or any information contained in any other Internet site maintained by an
underwriter or selling group member, other than this prospectus in electronic
format. That information is not part of this prospectus or the registration
statement of which this prospectus forms a part and you should not rely upon it
in making your investment decision.

This prospectus is not, and under no circumstances is to be construed as, an
advertisement or a public offering of shares in Canada or any province or
territory of Canada. Any offer or sale of shares in Canada will be made only
under an exemption from the requirements to file a prospectus and an exemption
from the dealer registration requirement in the relevant province or territory
of Canada in which the offer or sale is made.

Purchasers of the shares of our common stock offered by this prospectus may
be required to pay stamp taxes and other charges under the laws and practices
of the country of purchase, in addition to the offering price listed on the
cover of the prospectus. Accordingly, we urge you to consult a tax advisor with
respect to whether you may be required to pay those taxes or charges, as well
as any other tax consequences that may arise under the laws of the country of
purchase.

Lehman Brothers Merchant Banking Partners II L.P. and other of its
affiliates, each of which is an affiliate of Lehman Brothers Inc., beneficially
own more than 10% of our common stock. Lehman Brothers Inc. was the initial
purchaser in connection with the sale of our senior notes and our senior
subordinated notes, and has served as our financial advisor, from time to time,
in connection with various transactions. Because of these relationships, the
offering is being conducted in accordance with Rule 2720 of the National
Association of Securities Dealers, or NASD. This rule requires that the initial
public offering price for our shares cannot be higher than the price
recommended by a "qualified independent underwriter," as defined by the NASD.
Morgan Stanley & Co. Incorporated is serving as a qualified independent
underwriter and will assume the customary responsibilities of acting as a
qualified independent underwriter in pricing the offering and conducting due
diligence.

104

LEGAL MATTERS

The validity of the issuance of the shares of common stock to be sold in the
offering will be passed upon for us by our counsel, Simpson Thacher & Bartlett,
New York, New York. Certain legal matters in connection with the issuance of
the common stock to be sold in the offering will be passed upon for the
underwriters by Weil, Gotshal & Manges LLP, New York, New York.

EXPERTS

Ernst & Young LLP, independent auditors, have audited our consolidated
financial statements and schedule as of March 31, 2001 and 2000 and for each of
the fiscal years ended March 31, 2001 and 2000 and the period from May 20, 1998
to March 31, 1999, and the combined financial statements and schedule of P&L
Coal Group (our predecessor company) for the period from April 1, 1998 to May
19, 1998, as set forth in their report. We have included our financial
statements and schedule in the prospectus and elsewhere in the registration
statement in reliance on Ernst & Young LLP's report, given on their authority
as experts in accounting and auditing. The estimates of our proven and probable
coal reserves referred to in this prospectus to the extent described in this
prospectus, have been prepared by us and reviewed by Marshall Miller &
Associates.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We file annual, quarterly and current reports and other information with the
SEC. You may access and read our SEC filings, including the complete
registration statement and all of the exhibits to it, through the SEC's
Internet site at www.sec.gov. This site contains reports and other information
that we file electronically with the SEC. You may also read and copy any
document we file at the SEC's public reference room located at 450 Fifth
Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for
further information on the public reference room.

We have filed with the SEC a registration statement under the Securities Act
with respect to the common stock offered by this prospectus. This prospectus,
which constitutes part of the registration statement, does not contain all of
the information presented in the registration statement and its exhibits and
schedules. Our descriptions in this prospectus of the provisions of documents
filed as exhibits to the registration statement or otherwise filed with the SEC
are only summaries of the terms of those documents that we consider material.
If you want a complete description of the content of the documents, you should
obtain the documents yourself by following the procedures described above.

You may request copies of the filings, at no cost, by telephone at (314)
342-3400 or by mail at: Peabody Energy Corporation, 701 Market Street, Suite
700, St. Louis, Missouri 63101, attention: Public Relations.

105

GLOSSARY OF SELECTED TERMS

Anthracite. The highest rank of economically usable coal with moisture
content less than 15% by weight and heating value as high as 15,000 Btu per
pound. It is jet black with a high luster. It is mined primarily in
Pennsylvania.

Appalachia. Coal producing states of Alabama, Georgia, eastern Kentucky,
Maryland, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia and West
Virginia.

Ash. Impurities consisting of iron, alumina and other incombustible matter
that are contained in coal. Since ash increases the weight of coal, it adds to
the cost of handling and can affect the burning characteristics of coal.

Assigned reserves. Coal that has been committed to be mined at operating
facilities.

Bituminous coal. The most common type of coal with moisture content less
than 20% by weight and heating value of 10,500 to 14,000 Btu per pound. It is
dense and black and often has well-defined bands of bright and dull material.

British thermal unit, or "Btu." A measure of the energy required to raise
the temperature of one pound of water one degree Fahrenheit.

Clean Air Act Amendments of 1990. A comprehensive set of amendments to the
federal law governing the nation's air quality. The Clean Air Act was
originally passed in 1970 to address significant air pollution problems in our
cities. The 1990 amendments broadened and strengthened the original law to
address specific problems such as acid deposition, urban smog, hazardous air
pollutants and stratospheric ozone depletion.

Coal seam. Coal deposits occur in layers. Each layer is called a "seam."

Coke. A hard, dry carbon substance produced by heating coal to a very high
temperature in the absence of air. Coke is used in the manufacture of iron and
steel. Its production results in a number of useful byproducts.

Coking coal. Coal used to make coke and interchangeably referred to as
metallurgical coal.

Compliance coal. Coal having a sulfur dioxide content of 1.2 pounds or less
per million Btu, as required by Phase II of the Clean Air Act.

Continuous mining. A form of underground room-and-pillar mining that uses a
continuous mining machine to cut coal from the seam and load it onto conveyors
or into shuttle cars in a continuous operation.

Deep mine. An underground coal mine.

Draglines. A large excavating machine used in the surface mining process to
remove overburden.

Dragline mining. A form of mining where large capacity electric-powered
draglines remove overburden to expose the coal seam. Smaller shovels load coal
in haul trucks for transportation to the preparation plant and then to the
rail loadout.

Fossil fuel. Fuel such as coal, petroleum or natural gas formed from the
fossil remains of organic material.

Illinois basin. Coal producing area in Illinois, southern Indiana and
western Kentucky.

Lignite. The lowest rank of coal with a high moisture content of up to 45%
by weight and heating value of 6,500 to 8,300 Btu per pound. It is brownish
black and tends to oxidize and disintegrate when exposed to air.

106

Longwall mining. A form of underground mining in which a panel or block of
coal, generally at least 700 feet wide and often over one mile long, is
completely extracted. The working area is protected by a moveable, powered roof
support system.

Metallurgical coal. The various grades of coal suitable for carbonization to
make coke for steel manufacture. Also known as "met" coal, it possesses four
important qualities: volatility, which affects coke yield; the level of
impurities, which affects coke quality; composition, which affects coke
strength; and basic characteristics, which affect coke oven safety. Met coal
has a particularly high Btu, but low ash content.

Nitrogen oxide (NOx). A gas formed in high temperature environments such as
coal combustion. It is a harmful pollutant that contributes to acid rain.

Non-compliance coal. Coal having a sulfur dioxide content of more than 1.2
pounds per million Btu.

Overburden. Layers of earth and rock covering a coal seam. In surface mining
operations, overburden is removed prior to coal extraction.

Overburden ratio/stripping ratio. The amount of overburden that must be
removed to excavate a given quantity of coal. It is commonly expressed in cubic
yards per ton of coal or as a ratio comparing the thickness of the overburden
with the thickness of the coalbed.

Pillar. An area of coal left to support the overlying strata in a mine;
sometimes left permanently to support surface structures.

Powder River Basin. Coal producing area in northeastern Wyoming and
southeastern Montana. This is the largest known source of coal reserves and the
largest producing region in the United States.

Preparation plant. Usually located on a mine site, although one plant may
serve several mines. A preparation plant is a facility for crushing, sizing and
washing coal to prepare it for use by a particular customer. The washing
process has the added benefit of removing some of the coal's sulfur content.

Probable reserves. Reserves for which quantity and grade and/or quality are
computed from information similar to that used for proven reserves, but the
sites for inspection, sampling and measurement are farther apart or are
otherwise less adequately spaced. The degree of assurance, although lower than
that for proven reserves, is high enough to assume continuity between points of
observation.

Proven reserves. Reserves for which: (a) quantity is computed from
dimensions revealed in outcrops, trenches, workings or drill holes; grade
and/or quality are computed from the results of detailed sampling; and (b) the
sites for inspection, sampling and measurement are spaced so closely and the
geologic character is so well defined that size, shape, depth and mineral
content of reserves are well-established.

Reclamation. The process of restoring land and the environment to their
original state following mining activities. The process commonly includes
"recontouring" or reshaping the land to its approximate original appearance,
restoring topsoil and planting native grass and ground covers. Reclamation
operations are usually underway before the mining of a particular site is
completed. Reclamation is closely regulated by both state and federal law.

Reserve. That part of a mineral deposit that could be economically and
legally extracted or produced at the time of the reserve determination.

Roof. The stratum of rock or other mineral above a coal seam; the overhead
surface of a coal working place. Same as "back" or "top."

Room-and-Pillar Mining. The most common method of underground mining in
which the mine roof is supported mainly by coal pillars left at regular
intervals. Rooms are placed where the coal is mined; pillars are areas of coal
left between the rooms. Room-and-pillar mining is done either by conventional
or continuous mining.

107

Scrubber (flue gas desulfurization unit). Any of several forms of
chemical/physical devices which operate to neutralize sulfur compounds formed
during coal combustion. These devices combine the sulfur in gaseous emissions
with other chemicals to form inert compounds, such as gypsum, that must then be
removed for disposal. Although effective in substantially reducing sulfur from
combustion gases, scrubbers require about 6% to 7% of a power plant's
electrical output and thousands of gallons of water to operate.

Steam coal. Coal used by power plants and industrial steam boilers to
produce electricity or process steam. It generally is lower in Btu heat content
and higher in volatile matter than metallurgical coal.

Subbituminous coal. Dull, black coal that ranks between lignite and
bituminous coal. Its moisture content is between 20% and 30% by weight, and its
heat content ranges from 7,800 to 9,500 Btu per pound of coal.

Sulfur. One of the elements present in varying quantities in coal that
contributes to environmental degradation when coal is burned. Sulfur dioxide is
produced as a gaseous by-product of coal combustion.

Sulfur content. Coal is commonly described by its sulfur content due to the
importance of sulfur in environmental regulations. "Low sulfur" coal has a
variety of definitions but typically is used to describe coal consisting of
1.0% or less sulfur. A majority of our Appalachian and Powder River Basin
reserves are of low sulfur grades.

Surface mine. A mine in which the coal lies near the surface and can be
extracted by removing the covering layer of soil (see "Overburden"). About 60%
of total U.S. coal production comes from surface mines.

Tons. A "short" or net ton is equal to 2,000 pounds. A "long" or British ton
is 2,240 pounds; a "metric" ton is approximately 2,205 pounds. The short ton is
the unit of measure referred to in this prospectus.

Truck-and-shovel mining. A form of mining where large shovels are used to
remove overburden, which is used to backfill pits after the coal is removed.
Smaller shovels load coal in haul trucks for transportation to the preparation
plant or rail loadout.

Unassigned reserves. 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.

Underground mine. Also known as a "deep" mine. Usually located several
hundred feet below the earth's surface, an underground mine's coal is removed
mechanically and transferred by shuttle car or conveyor to the surface. Most
underground mines are located east of the Mississippi River and account for
about 40% of annual U.S. coal production.

Unit train. A train of 100 or more cars carrying only coal. A typical unit
train can carry at least 10,000 tons of coal in a single shipment.

Western bituminous coal regions. Coal producing area including, the Hanna
Basin in Wyoming, the Uinta Basin of northwestern Colorado and Utah, the Four
Corners Region in New Mexico and Arizona and the Raton Basin in southern
Colorado.

108

Index to Financial Statements

Page
----

Report of Independent Auditors............................................ F-2

Audited Financial Statements:

Statements of Operations--Period from April 1, 1998 to May 19, 1998,
period from May 20, 1998 to March 31, 1999 and years ended March 31,
2000 and 2001.......................................................... F-3

Balance Sheets--March 31, 2000 and 2001................................. F-4

Statements of Cash Flows--Period from April 1, 1998 to May 19, 1998,
period from May 20, 1998 to March 31, 1999 and years ended March 31,
2000 and 2001.......................................................... F-5

Statements of Changes in Stockholders' Equity/Invested Capital--Period
from April 1, 1998 to May 19, 1998, period from May 20, 1998 to March
31, 1999 and years ended March 31, 2000 and 2001....................... F-7

Notes to Financial Statements............................................. F-8

F-1

REPORT OF INDEPENDENT AUDITORS

Board of Directors
Peabody Energy Corporation

We have audited the accompanying consolidated balance sheets of Peabody
Energy Corporation (the Company), formerly P&L Coal Holdings Corporation, as of
March 31, 2001 and 2000, and the related consolidated statements of operations,
changes in stockholders' equity and cash flows of the Company for the years
then ended and the period from May 20, 1998 to March 31, 1999. We have also
audited the combined statements of operations, changes in invested capital and
cash flows of P&L Coal Group (the Predecessor Company) for the period from
April 1, 1998 to May 19, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Peabody Energy
Corporation at March 31, 2001 and 2000, the consolidated results of operations
and cash flows of the Company for the years ended March 31, 2001 and 2000 and
the period from May 20, 1998 to March 31, 1999, and the combined results of
operations and cash flows of the Predecessor Company for the period from April
1, 1998 to May 19, 1998 in conformity with accounting principles generally
accepted in the United States.

Ernst & Young LLP

St. Louis, Missouri
April 20, 2001
except for the fourth paragraph of Note 1 as to which the date is May 17, 2001

F-2

PEABODY ENERGY CORPORATION

STATEMENTS OF OPERATIONS
(Dollars in thousands, except share data)

Predecessor
Company
----------------
April 1, 1998 to May 20, 1998 to Year Ended Year Ended
May 19, 1998 March 31, 1999 March 31, 2000 March 31, 2001
---------------- --------------- -------------- --------------

REVENUES
Sales........................................................ $278,930 $ 1,970,957 $ 2,610,991 $ 2,579,104
Other revenues............................................... 11,728 85,875 99,509 90,588
-------- ----------- ----------- -----------
Total revenues............................................. 290,658 2,056,832 2,710,500 2,669,692
COSTS AND EXPENSES
Operating costs and expenses................................. 244,128 1,643,718 2,178,664 2,165,090
Depreciation, depletion and amortization..................... 25,516 179,182 249,782 240,968
Selling and administrative expenses.......................... 12,017 76,888 95,256 99,267
Gain on sale of Australian operations........................ -- -- -- (171,735)
Net gain on property and equipment disposals................. (328) -- (6,439) (5,737)
-------- ----------- ----------- -----------
OPERATING PROFIT.............................................. 9,325 157,044 193,237 341,839
Interest expense............................................. 4,222 176,105 205,056 197,686
Interest income.............................................. (1,667) (18,527) (4,421) (8,741)
-------- ----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS...... 6,770 (534) (7,398) 152,894
Income tax provision (benefit)............................... 4,530 3,012 (141,522) 42,690
Minority interests........................................... -- 1,887 15,554 7,524
-------- ----------- ----------- -----------
INCOME (LOSS) FROM CONTINUING OPERATIONS...................... 2,240 (5,433) 118,570 102,680
(Income) loss from discontinued operations, net of income
tax provision (benefit) of ($189), $6,035 and ($1,297),
respectively................................................ 1,764 (6,442) 12,087 --
(Gain) loss from disposal of discontinued operations, net of
income tax provision (benefit) of ($31,188) and $4,240,
respectively................................................ -- -- 78,273 (12,925)
-------- ----------- ----------- -----------
INCOME BEFORE EXTRAORDINARY ITEM.............................. 476 1,009 28,210 115,605
Extraordinary loss from early extinguishment of debt, net of
income tax provision of $2,480.............................. -- -- -- 8,545
-------- ----------- ----------- -----------
NET INCOME.................................................... $ 476 $ 1,009 $ 28,210 $ 107,060
======== =========== =========== ===========
BASIC AND DILUTED EARNINGS (LOSS) PER SHARE...................
Income (loss) from continuing operations $ (0.16) $ 3.43 $ 2.97
Income (loss) from discontinued operations................... 0.19 (2.61) 0.38
Extraordinary loss from early extinguishment of debt......... -- -- (0.25)
----------- ----------- -----------
Net income................................................... $ 0.03 $ 0.82 $ 3.10
=========== =========== ===========
WEIGHTED AVERAGE SHARES OUTSTANDING........................... 26,823,383 27,586,370 27,524,626
--------------------------------------------------
=========== =========== ===========

See accompanying notes to financial statements.

F-3

PEABODY ENERGY CORPORATION

BALANCE SHEETS
(Dollars in thousands, except share data)

As of March 31,
----------------------
2000 2001
---------- ----------

ASSETS
Current assets
Cash and cash equivalents............................. $ 65,618 $ 62,723
Accounts receivable, less allowance of $1,233 and
$1,213, respectively................................. 153,021 147,808
Materials and supplies................................ 48,809 38,733
Coal inventory........................................ 193,341 171,479
Assets from coal and emission allowance trading
activities........................................... 78,695 172,330
Deferred income taxes................................. 49,869 12,226
Other current assets.................................. 43,192 24,656
---------- ----------
Total current assets................................ 632,545 629,955
Property, plant, equipment and mine development
Land and coal interests............................... 4,135,010 3,895,966
Building and improvements............................. 350,284 332,428
Machinery and equipment............................... 741,486 631,605
Less accumulated depreciation, depletion and
amortization......................................... (411,270) (537,360)
---------- ----------
Property, plant, equipment and mine development, net... 4,815,510 4,322,639
Net assets of discontinued operations.................. 90,000 --
Investments and other assets........................... 288,794 256,893
---------- ----------
Total assets...................................... $5,826,849 $5,209,487
========== ==========

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Short-term borrowings and current maturities of long-
term debt............................................ $ 57,977 $ 36,305
Income taxes payable.................................. 13,594 491
Liabilities from coal and emission allowance trading
activities........................................... 75,883 163,713
Accounts payable and accrued expenses................. 573,137 576,476
---------- ----------
Total current liabilities........................... 720,591 776,985
Long-term debt, less current maturities................ 2,018,189 1,369,316
Deferred income taxes.................................. 625,124 570,705
Accrued reclamation and other environmental
liabilities........................................... 502,092 447,713
Workers' compensation obligations...................... 212,260 210,780
Accrued postretirement benefit costs................... 971,186 974,079
Obligation to industry fund............................ 64,737 52,172
Other noncurrent liabilities........................... 162,979 135,041
---------- ----------
Total liabilities................................... 5,277,158 4,536,791
Minority interests..................................... 41,265 41,458
Stockholders' equity
Preferred stock--$0.01 per share par value;
14,000,000 shares authorized,
7,000,000 shares issued and outstanding as of March
31, 2000 and 2001.................................... 50 50
Common stock--Class A, $0.01 per share par value;
42,000,000 shares authorized,
26,600,000 shares issued and outstanding as of March
31, 2000 and 2001.................................... 190 190
Common stock--Class B, $0.01 per share par value;
4,200,000 shares authorized,
1,039,176 shares issued and 958,263 shares
outstanding as of March 31, 2000;
4,200,000 shares authorized, 1,033,490 shares issued
and 1,010,509 shares
outstanding as of March 31, 2001..................... 7 8
Additional paid-in capital............................ 494,237 498,198
Employee stock loans.................................. (2,391) (2,553)
Accumulated other comprehensive loss.................. (12,667) (862)
Retained earnings..................................... 29,219 136,279
Treasury shares, at cost: 80,913 and 22,981 Class B
shares as of March 31, 2000 and 2001................. (219) (72)
---------- ----------
Total stockholders' equity.......................... 508,426 631,238
---------- ----------
Total liabilities and stockholders' equity........ $5,826,849 $5,209,487
========== ==========

See accompanying notes to financial statements.

F-4

PEABODY ENERGY CORPORATION

STATEMENTS OF CASH FLOWS
(Dollars in thousands)

CASH FLOWS FROM OPERATING ACTIVITIES
Net income.................................................... $ 476 $ 1,009 $ 28,210 $ 107,060
(Income) loss from discontinued operations................... 1,764 (6,442) 12,087 --
(Gain) loss from disposal of discontinued operations......... -- -- 78,273 (12,925)
Extraordinary loss from early extinguishment of debt......... -- -- -- 8,545
-------- ----------- --------- ---------
Income (loss) from continuing operations................... 2,240 (5,433) 118,570 102,680
Adjustments to reconcile income from continuing operations to
net cash provided by (used in) continuing operations:
Depreciation, depletion and amortization..................... 25,516 179,182 249,782 215,450
Deferred income taxes........................................ 2,835 (679) (157,803) 31,795
Amortization of debt discount and debt issuance costs........ 1,379 16,120 18,911 16,709
Gain on sale of Australian operations........................ -- -- -- (171,735)
Net gain on property and equipment disposals................. (328) -- (6,439) (4,782)
Gain on coal contract restructurings......................... -- (5,300) (12,957) --
Stock compensation........................................... -- 13,124 265 3,961
Minority interests........................................... -- 1,887 15,554 7,524
Changes in current assets and liabilities, excluding effects
of acquisitions:
Sale of accounts receivable................................ -- -- 100,000 40,000
Accounts receivable, net of sale........................... (9,768) 20,164 18,712 (50,179)
Materials and supplies..................................... 881 3,620 5,227 5,677
Coal inventory............................................. (2,807) 5,781 10,774 (15,749)
Net assets from coal and emission allowance trading
activities................................................ -- -- (310) (5,805)
Other current assets....................................... (10,707) 7,459 (16,862) 6,912
Accounts payable and accrued expenses...................... (34,685) (50,373) (15,064) 51,659
Income taxes payable....................................... 1,234 173 7,549 316
Accrued reclamation and related liabilities................... (1,622) (4,468) (18,233) (35,080)
Workers' compensation obligations............................. (2,156) (10,449) 4,716 (1,480)
Accrued postretirement benefit costs.......................... 6,092 6,094 14,472 (833)
Obligation to industry fund................................... (2,379) (3,619) 1,630 (12,565)
Royalty prepayment............................................ -- 135,903 -- --
Other, net.................................................... (5,586) 21,737 (35,079) (12,371)
Net cash used in assets sold--Australian operations........... -- -- -- (20,124)
-------- ----------- --------- ---------
Net cash provided by (used in) continuing operations..... (29,861) 330,923 303,415 151,980
Net cash provided by (used in) discontinued operations... 1,704 (48,901) (40,504) --
-------- ----------- --------- ---------
Net cash provided by (used in) operating activities...... (28,157) 282,022 262,911 151,980
-------- ----------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant, equipment and mine development.. (20,874) (174,520) (178,754) (151,358)
Additions to advance mining royalties......................... (2,302) (11,509) (25,292) (20,260)
Acquisitions, net............................................. -- (2,110,400) (63,265) (10,502)
Investment in joint venture................................... -- -- (4,325) --
Proceeds from coal contract restructurings.................... 328 2,515 32,904 --
Proceeds from sale of Australian operations................... -- -- -- 455,000
Proceeds from property and equipment disposals................ 1,374 11,448 19,284 18,925
Proceeds from sale-leaseback transactions..................... -- -- 34,234 28,800
Net cash used in assets sold--Australian operations........... -- -- -- (34,684)
-------- ----------- --------- ---------
Net cash provided by (used in) continuing operations..... (21,474) (2,282,466) (185,214) 285,921
Net cash provided by (used in) discontinued operations... (76) 33,130 (170) 102,541
-------- ----------- --------- ---------
Net cash provided by (used in) investing activities...... (21,550) (2,249,336) (185,384) 388,462
-------- ----------- --------- ---------

(Continued on following page)
See accompanying notes to financial statements.

F-5

PEABODY ENERGY CORPORATION

STATEMENTS OF CASH FLOWS (continued)
(Dollars in thousands)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from short-term borrowings and long-term debt........ 53,597 1,870,778 22,026 65,302
Payments of short-term borrowings and long-term debt.......... (19,423) (222,715) (209,985) (633,905)
Capital contribution.......................................... -- 480,000 -- --
Distributions to minority interests........................... -- (3,080) (3,353) (4,690)
Dividend received............................................. -- -- -- 19,916
Dividends paid................................................ (173,330) -- -- --
Proceeds from sale of treasury stock.......................... -- -- -- 562
Repurchase of treasury stock.................................. -- -- -- (1,113)
Net cash provided by assets sold--Australian operations....... -- -- -- 10,591
Transactions with affiliates:
Proceeds from affiliated loan................................ 141,000 -- -- --
Repayments to affiliates..................................... -- (3,647) -- --
Invested capital transactions with affiliates................ -- (30,369) -- --
--------- ---------- --------- ---------
Net cash provided by (used in) continuing operations..... 1,844 2,090,967 (191,312) (543,337)
Net cash provided by (used in) discontinued operations... 21,693 70,314 (13,869) --
--------- ---------- --------- ---------
Net cash provided by (used in) financing activities...... 23,537 2,161,281 (205,181) (543,337)
Effect of exchange rate changes on cash and cash equivalents.. (292) 111 (806) --
--------- ---------- --------- ---------
Net increase (decrease) in cash and cash equivalents.......... (26,462) 194,078 (128,460) (2,895)
Cash and cash equivalents at beginning of period.............. 96,821 -- 194,078 65,618
--------- ---------- --------- ---------
Cash and cash equivalents at end of period.................... $ 70,359 $ 194,078 $ 65,618 $ 62,723
========= ========== ========= =========

See accompanying notes to financial statements.

F-6

PEABODY ENERGY CORPORATION

STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY/INVESTED CAPITAL
(Dollars in thousands, except share data)

Accumulated
Other
Shares Compre-
------------------------------ Additional Employee hensive
Predecessor Preferred Common Paid-in Stock Income Retained Invested Treasury
Company Preferred Class A Class B Stock Stock Capital Loans (Loss) Earnings Capital Stock
----------- --------- ---------- --------- --------- ------ ---------- -------- ----------- -------- ---------- --------

March 31, 1998... -- -- -- $ -- $ -- $ -- $ -- $(42,184) $ -- $1,730,026 $ --
Comprehensive
loss:
Net income...... -- -- -- -- -- -- -- -- -- 476 --
Foreign currency
translation
adjustment...... -- -- -- -- -- -- -- (17,974) -- -- --
Comprehensive
loss............
Dividend paid... -- -- -- -- -- -- -- -- -- (173,330) --
Net transactions
with
affiliates...... -- -- -- -- -- -- -- -- -- 360 --
--------- ---------- --------- ----- ----- -------- ------- -------- -------- ---------- ------
May 19, 1998..... -- -- -- $ -- $ -- $ -- $ -- $(60,158) $ -- $1,557,532 $ --
========= ========== ========= ===== ===== ======== ======= ======== ======== ========== ======
----------------------------------------------------------------------------------------------------------------------------------
May 20, 1998..... -- -- -- $ -- $ -- $ -- $ -- $ -- $ -- $ -- $ --
Capital
contribution.... 7,000,000 26,600,000 -- 50 190 479,760 -- -- -- -- --
Comprehensive
income:
Net income...... -- -- -- -- -- -- -- -- 1,009 -- --
Foreign currency
translation
adjustment...... -- -- -- -- -- -- -- 4,128 -- -- --
Minimum pension
liability (net
of $1,248 tax
provision)...... -- -- -- -- -- -- -- (1,795) -- -- --
Comprehensive
income..........
Stock grants to
employees....... -- -- 775,778 -- 5 13,119 (1,236) -- -- -- --
Stock purchases
by employees.... -- -- 216,499 -- 2 1,093 (1,095) -- -- -- --
--------- ---------- --------- ----- ----- -------- ------- -------- -------- ---------- ------
March 31, 1999... 7,000,000 26,600,000 992,277 50 197 493,972 (2,331) 2,333 1,009 -- --
Comprehensive
income:
Net income...... -- -- -- -- -- -- -- -- 28,210 -- --
Foreign currency
translation
adjustment...... -- -- -- -- -- -- -- (16,795) -- -- --
Minimum pension
liability (net
of $1,248 tax
benefit)........ -- -- -- -- -- -- -- 1,795 -- -- --
Comprehensive
income..........
Stock grants to
employees....... -- -- 46,899 -- -- 265 (103) -- -- -- --
Loan
repayments...... -- -- -- -- -- -- 901 -- -- -- --
Additional
loans........... -- -- -- -- -- -- (858) -- -- -- --
Shares
repurchased..... -- -- (80,913) -- -- -- -- -- -- -- (219)
--------- ---------- --------- ----- ----- -------- ------- -------- -------- ---------- ------
March 31, 2000... 7,000,000 26,600,000 958,263 50 197 494,237 (2,391) (12,667) 29,219 -- (219)
Comprehensive
income:
Net income...... -- -- -- -- -- -- -- -- 107,060 -- --
Foreign currency
translation
adjustment...... -- -- -- -- -- -- -- (26,144) -- -- --
Reclassification
of foreign
currency
translation
adjustment...... -- -- -- -- -- -- -- 38,811 -- -- --
Minimum pension
liability (net
of $615 tax
benefit)........ -- -- -- -- -- -- -- (862) -- -- --
Comprehensive
income..........
Stock grants to
employees....... -- -- 284,362 -- 1 3,961 (705) -- -- -- 1,260
Loan
repayments...... -- -- -- -- -- -- 543 -- -- -- --
Shares
repurchased..... -- -- (232,116) -- -- -- -- -- -- -- (1,113)
--------- ---------- --------- ----- ----- -------- ------- -------- -------- ---------- ------
March 31, 2001... 7,000,000 26,600,000 1,010,509 $ 50 $ 198 $498,198 $(2,553) $ (862) $136,279 $ -- $ (72)
========= ========== ========= ===== ===== ======== ======= ======== ======== ========== ======

Total
Stockholders'
Equity/
Predecessor Invested
Company Capital
----------- -------------

March 31, 1998... $1,687,842
Comprehensive
loss:
Net income...... 476
Foreign currency
translation
adjustment...... (17,974)
-------------
Comprehensive
loss............ (17,498)
Dividend paid... (173,330)
Net transactions
with
affiliates...... 360
-------------
May 19, 1998..... $1,497,374
=============
----------------------------------------------------------------------------------------------------------------------------------
May 20, 1998..... $ --
Capital
contribution.... 480,000
Comprehensive
income:
Net income...... 1,009
Foreign currency
translation
adjustment...... 4,128
Minimum pension
liability (net
of $1,248 tax
provision)...... (1,795)
-------------
Comprehensive
income.......... 3,342
Stock grants to
employees....... 11,888
Stock purchases
by employees.... --
-------------
March 31, 1999... 495,230
Comprehensive
income:
Net income...... 28,210
Foreign currency
translation
adjustment...... (16,795)
Minimum pension
liability (net
of $1,248 tax
benefit)........ 1,795
-------------
Comprehensive
income.......... 13,210
Stock grants to
employees....... 162
Loan
repayments...... 901
Additional
loans........... (858)
Shares
repurchased..... (219)
-------------
March 31, 2000... 508,426
Comprehensive
income:
Net income...... 107,060
Foreign currency
translation
adjustment...... (26,144)
Reclassification
of foreign
currency
translation
adjustment...... 38,811
Minimum pension
liability (net
of $615 tax
benefit)........ (862)
-------------
Comprehensive
income.......... 118,865
Stock grants to
employees....... 4,517
Loan
repayments...... 543
Shares
repurchased..... (1,113)
-------------
March 31, 2001... $ 631,238
=============

See accompanying notes to financial statements.

F-7

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS
(Dollars in thousands, except where noted and per share data)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The consolidated financial statements include the consolidated balance
sheets of Peabody Energy Corporation (the "Company" or "Peabody") as of March
31, 2000 and 2001, and the consolidated results of operations and cash flows
for the period from May 20, 1998 to March 31, 1999 (hereafter referred to as
the "period ended March 31, 1999") and the years ended March 31, 2000 and 2001.
These financial statements include the subsidiaries (collectively, known as the
"Predecessor Company" or "P&L Coal Group") of Peabody Holding Company, Inc.
("Peabody Holding Company"), Gold Fields Mining Corporation ("Gold Fields")
which owns Lee Ranch Coal Company ("Lee Ranch"), Citizens Power LLC ("Citizens
Power") and Peabody Resources Limited ("Peabody Resources"), an Australian
company. The combined financial statements include the combined results of
operations and cash flows of the Predecessor Company from April 1, 1998 to May
19, 1998 (hereafter referred to as the "period ended May 19, 1998"). P&L Coal
Holdings Corporation, a holding company that was formed by Lehman Brothers
Merchant Banking Partners II L.P. ("Lehman Brothers Merchant Banking") on
February 27, 1998, acquired P&L Coal Group from The Energy Group PLC effective
May 20, 1998. Lehman Brothers Merchant Banking is an investment fund affiliated
with Lehman Brothers Inc.

In May 2000, the Company signed a purchase and sale agreement with Edison
Mission Energy to sell Citizens Power (see Note 4). Results of operations and
cash flows for all periods presented reflect Citizens Power as a discontinued
operation. In January 2001, the Company sold its Australian operations (see
Note 3).

On April 10, 2001, the Company changed its name from P&L Coal Holdings
Corporation to Peabody Energy Corporation.

Stock Split

On May 17, 2001, the Company effected a 1.4-for-one stock split of its
preferred and common stock. All references to number of shares, per share
amounts and stock option data have been restated to reflect the anticipated
stock split.

Description of Business

The Company is principally engaged in the mining of coal for sale primarily
to electric utilities. The Company also markets and trades coal and emission
allowances.

New Pronouncements

Effective April 1, 1998, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income." SFAS No.
130 requires that noncash changes in stockholders' equity be combined with net
income and reported in a new financial statement category entitled "accumulated
other comprehensive income."

The Company also adopted SFAS No. 131, "Disclosures About Segments of an
Enterprise and Related Information" and SFAS No. 132, "Employers' Disclosures
About Pensions and Other Postretirement Benefits" effective April 1, 1998. SFAS
No. 131 and SFAS No. 132, address the disclosures required for the Company's
operating segments and employee benefit obligations, respectively.

The adoption of SFAS Nos. 130, 131 and 132 had no effect on the Company's
financial condition or results of operations.

F-8

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
(as amended by SFAS Nos. 137 and 138) requires the recognition of all
derivatives as assets or liabilities within the balance sheet and requires both
the derivatives and the underlying exposure to be recorded at fair value. Any
gain or loss resulting from changes in fair value will be recorded as part of
the results of operations, or as a component of comprehensive income or loss,
depending upon the intended use of the derivative. The effective date of SFAS
No. 133 is fiscal years beginning after June 15, 2000 (effective April 1, 2001
for the Company). The Company does not anticipate that the adoption of SFAS No.
133 will have a material effect on its financial condition or results of
operations, subject to new or revised implementation guidelines issued by the
Derivatives Implementation Group.

Joint Ventures

Joint ventures are accounted for using the equity method except for
undivided interests in Australia, which, prior to its sale in January 2001, was
reported using pro rata consolidation whereby the Company reported its
proportionate share of assets, liabilities, income and expenses. All
significant intercompany transactions have been eliminated in consolidation.

The financial statements include the following asset and operating amounts
for Australian entities utilizing pro rata consolidation (dollars in
thousands):

Predecessor
Company
------------
Period Ended Period Ended Year Ended Year Ended
May 19, 1998 March 31, 1999 March 31, 2000 March 31, 2001
------------ -------------- -------------- --------------

Total revenue........... $10,996 $72,057 $122,689 $144,481
Operating profit........ 3,695 18,767 17,038 21,111
Total assets (at period
end)................... 149,864 --

Accounting for Coal and Emission Allowance Trading

The Company engages in risk management activities for both trading and non-
trading purposes. Activities for trading purposes, generally consisting of coal
and emission allowance trading, are accounted for using the fair value method.
Under such method, the derivative commodity instruments (forwards, options and
swaps) with third parties are reflected at market value and are included in
"Assets and liabilities from coal and emission allowance trading activities" in
the consolidated balance sheets. In the absence of quoted values, financial
commodity instruments are valued at fair value, considering the net present
value of the underlying sales and purchase obligations, volatility of the
underlying commodity, appropriate reserves for market and credit risks and
other factors, as determined by management. Subsequent changes in market value
are recognized as gains or losses in "Other revenues" in the period of change.

As a writer of options, the Company receives a premium when the option is
written and then bears the risk of unfavorable changes in the price of the
financial instruments underlying the option. Forwards, swaps and over-the-
counter options are traded in unregulated markets.

Over-the-counter forwards, options and swaps are either liquidated with the
same counterparty or held to settlement date. For these financial instruments,
the unrealized gains or losses on financial settlements, rather than the
contract amounts, represent the approximate future cash requirements. Realized
gains and losses on trading activities are recorded as part of "Other revenues"
as they occur. Physical settlements are recorded on a gross basis within
"Sales" and "Operating costs and expenses."

F-9

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

Derivative Financial Instruments

A portion of the Company's long-term indebtedness bears interest at rates
that fluctuate based upon certain indices. The Company utilizes financial
instruments, such as interest rate swap agreements, to mitigate the impact of
changes in interest rates on a portion of its floating rate debt. Gains or
losses on interest rate swap agreements are recognized as they occur and are
included as a component of interest expense.

Prior to the sale in January 2001, the Company's Australian operations used
forward currency contracts to manage their exposure against foreign currency
fluctuations on sales denominated in U.S. dollars. These financial instruments
were accounted for using the deferral method. Changes in the market value of
these transactions were deferred until the gain or loss on the underlying
hedged item was recognized as part of the related transaction. If the future
sale was no longer anticipated, the changes in market value of the forward
currency contracts were recognized as an adjustment to revenue in the period of
change.

Revenue Recognition

The Company incurs certain "add-on" taxes and fees on coal sales. Coal sales
are reported including taxes and fees charged by various federal and state
governmental bodies. The Company recognizes revenue from coal sales when title
passes to the customer.

Other Revenues

Other revenues include royalties related to coal lease agreements, earnings
and losses from joint ventures, management fees, farm income, contract
restructuring payments, coalbed methane extraction, coal and emission allowance
trading activities and revenues from contract mining services. Royalty income
generally results from the lease or sub-lease of mineral rights to third
parties, with payments based upon a percentage of the selling price or an
amount per ton of coal produced. Certain agreements require minimum annual
lease payments regardless of the extent to which minerals are produced from the
leasehold. The terms of these agreements generally range from specified periods
of five to 20 years, or can be for an unspecified period until all reserves are
depleted.

Revenues from coal trading activities are recognized for the differences
between contract and market prices.

Cash and Cash Equivalents

Cash and cash equivalents are stated at cost, which approximates fair value.
Cash equivalents consist of highly liquid investments with original maturities
of three months or less.

Inventories

Materials and supplies and coal inventory are valued at the lower of average
cost or market. Coal inventory costs include labor, supplies, equipment costs,
operating overhead and other related costs.

Property, Plant, Equipment and Mine Development

Property, plant, equipment and mine development are recorded at cost.
Interest costs applicable to major asset additions are capitalized during the
construction period, including $0.2 million and $3.0 million for the periods
ended May 19, 1998 and March 31, 1999, respectively, and $1.8 million and $0.3
million for the years ended March 31, 2000 and 2001, respectively.

Expenditures which extend the useful lives of existing plant and equipment
are capitalized. Maintenance and repairs are charged to operating costs as
incurred. Costs incurred to develop coal mines or to expand the capacity of
operating mines are capitalized. Costs incurred to maintain current production
capacity at a mine

F-10

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

and exploration expenditures are charged to operating costs as incurred.
Certain costs to acquire computer hardware and the development and/or purchase
of software for internal use are capitalized and depreciated over the estimated
useful lives.

The fair value of coal reserves was established by an independent third
party review and evaluation at the time of the Company's acquisition in May
1998. Reserves acquired subsequent to that date are recorded at cost. At March
31, 2001, the net book value of coal reserves totaled $3.5 billion. This amount
includes $1.3 billion attributable to properties where the Company is not
currently engaged in mining operations or leasing to third parties and,
therefore, the coal reserves are not currently being depleted.

Depletion of coal interests is computed using the units-of-production method
utilizing only proven and probable reserves in the depletion base. Mine
development costs are principally amortized over the estimated lives of the
mines using the straight-line method. Depreciation of plant and equipment
(excluding life of mine assets) is computed using the straight-line method over
the estimated useful lives as follows:

Years
-------------

Building and improvements...................................... 10 to 20
Machinery and equipment........................................ 2 to 30
Leasehold improvements......................................... Life of Lease

In addition, certain plant and equipment assets associated with mining are
depreciated using the straight-line method over the estimated life of the mine,
which varies from three to 24 years.

Accrued Reclamation and Other Environmental Liabilities

The Company records a liability for the estimated costs to reclaim land as
the acreage is disturbed during the ongoing surface mining process. The
estimated costs to reclaim support acreage and to perform other related
functions at both surface and underground mines are recorded ratably over the
lives of the mines. As of March 31, 2001, the Company had $651.8 million in
surety bonds outstanding to secure reclamation obligations or activities. The
amount of reclamation self-bonding in certain states in which the Company
qualifies was $216.5 million as of March 31, 2001.

Accruals for other environmental matters are recorded in operating expenses
when it is probable that a liability has been incurred and the amount of the
liability can be reasonably estimated. Accrued liabilities are exclusive of
claims against third parties and are not discounted. In general, costs related
to environmental remediation are charged to expense.

Income Taxes

Income taxes are accounted for using a balance sheet approach known as the
liability method. The liability method accounts for deferred income taxes by
applying statutory tax rates in effect at the date of the balance sheet to
differences between the book and tax basis of assets and liabilities.

Postemployment Benefits

The Company provides postemployment benefits to qualifying employees, former
employees and dependents under the provisions of various benefit plans or as
required by state or federal law. The Company accounts for workers'
compensation obligations and other Company-provided postemployment benefits on
the accrual basis of accounting.

Earnings Per Share

The Company has two classes of common stock and, as such, applies the "two-
class method" of computing earnings per share as prescribed in SFAS No. 128,
"Earnings Per Share." In accordance with SFAS No. 128, income or loss is
allocated to preferred stock, Class A common stock and Class B common stock on
a pro-rata basis.

F-11

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

Basic earnings (loss) per share is calculated by dividing income (loss) from
continuing operations, income (loss) from discontinued operations,
extraordinary loss from early extinguishment of debt and net income,
respectively, that is attributed to the Company's Class A and Class B common
shares by the weighted average number of common shares outstanding for each
class of common stock for each respective period. Diluted earnings (loss) per
share is calculated by dividing income from continuing operations, income
(loss) from discontinued operations, extraordinary loss from early
extinguishment of debt and net income, respectively, that is attributed to the
Company's Class A and Class B common shares by the weighted average number of
common and common equivalent shares outstanding for each class of common stock
for each respective period. Any potential difference between basic and diluted
earnings (loss) per share is solely attributable to stock options. For the
period ended March 31, 1999 and the years ended March 31, 2000 and 2001, all
options (for 5.3 million shares, 5.2 million shares and 5.2 million shares,
respectively) were excluded from the diluted earnings per share calculations
for the Company's Class A and Class B common stock because they were anti-
dilutive. A reconciliation of income (loss) from continuing operations, income
(loss) from discontinued operations, extraordinary loss from early
extinguishment of debt and net income follows:

May 20,
1998 to Year Ended Year Ended
March 31, March 31, March 31,
1999 2000 2001
----------- ----------- -----------
(Dollars in thousands)

Income (loss) from continuing
operations attributed to:
Preferred stock................... $ (1,124) $ 23,998 $ 20,819
Class A common stock.............. (4,273) 91,190 79,111
Class B common stock.............. (36) 3,382 2,750
----------- ----------- -----------
$ (5,433) $ 118,570 $ 102,680
=========== =========== ===========
Income (loss) from discontinued
operations attributed to:
Preferred stock................... $ 1,333 $ (18,289) $ 2,621
Class A common stock.............. 5,067 (69,494) 9,958
Class B common stock.............. 42 (2,577) 346
----------- ----------- -----------
$ 6,442 $ (90,360) $ 12,925
=========== =========== ===========
Extraordinary loss from early
extinguishment of debt attributed
to:
Preferred stock................... $ -- $ -- $ (1,733)
Class A common stock.............. -- -- (6,583)
Class B common stock.............. -- -- (229)
----------- ----------- -----------
$ -- $ -- $ (8,545)
=========== =========== ===========
Net income attributed to:
Preferred stock................... $ 209 $ 5,709 $ 21,707
Class A common stock.............. 793 21,696 82,486
Class B common stock.............. 7 805 2,867
----------- ----------- -----------
$ 1,009 $ 28,210 $ 107,060
=========== =========== ===========
Weighted average shares outstanding:
Class A common stock.............. 26,600,000 26,600,000 26,600,000
Class B common stock.............. 223,383 986,370 924,626
----------- ----------- -----------
26,823,383 27,586,370 27,524,626
=========== =========== ===========

F-12

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

Concentration of Credit Risk and Market Risk

The Company's power, coal and emission allowance trading and risk management
activities give rise to market risk, which represents the potential loss caused
by a change in the market value of a particular commitment. Market risks are
actively monitored to ensure compliance with the risk management policies of
the Company. Policies are in place that limit the Company's total net exposure
at any point in time. Procedures exist which allow for monitoring of all
commitments and positions, with daily reporting to senior management.

The Company's concentration of credit risk is substantially with energy
producers and marketers and electric utilities. The Company's policy is to
independently evaluate each customer's creditworthiness prior to entering into
transactions and to constantly monitor the credit extended. In the event that
the Company engages in a transaction with a counterparty that does not meet its
credit standards, the Company will protect its position by requiring the
counterparty to provide appropriate credit enhancement. Counterparty risk with
respect to interest rate swap transactions is not considered to be significant
based upon the creditworthiness of the participating financial institutions.

Approximately 37% of the Company's U.S. coal employees are affiliated with
organized labor unions, which accounts for approximately 23% of sales volume in
the U.S. during fiscal year 2001. Hourly workers at the Company's mines in
Arizona, Colorado and Montana are represented by the United Mine Workers' of
America under the Western Surface Agreement, which was ratified in 2000 and is
effective through September 1, 2005. Union labor east of the Mississippi is
also represented by the United Mine Workers of America but is subject to the
National Bituminous Coal Wage Agreement. On December 16, 1997, this five-year
labor agreement effective from January 1, 1998 to December 31, 2002, was
ratified by the United Mine Workers of America.

Use of Estimates in the Preparation of the Financial Statements

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.

Impairment of Long-Lived Assets

The Company records impairment losses on long-lived assets used in
operations when events and circumstances indicate that the assets might be
impaired and the undiscounted cash flows estimated to be generated by those
assets under various assumptions are less than the carrying amounts of those
assets. Impairment losses are measured by comparing the estimated fair value of
the assets to their carrying amount.

Foreign Currency Translation

Assets and liabilities of foreign affiliates are generally translated at
current exchange rates, and related translation adjustments are reported as a
component of comprehensive income. Income statement accounts are translated at
an average rate for each period. The Company sold its Australian mining
operations in January 2001.

Reclassifications

Certain amounts in prior periods have been reclassified to conform with the
report classifications of the year ended March 31, 2001, with no effect on
previously reported net income or stockholders' equity.

F-13

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(2) BUSINESS COMBINATIONS

Black Beauty Coal Company

Effective January 1, 1999, the Company purchased an additional 38.3%
interest in Black Beauty Coal Company ("Black Beauty"), raising its ownership
percentage to 81.7%. Total consideration paid for the additional interest was
$150.7 million. The acquisition was accounted for as a purchase and,
accordingly, the operating results of Black Beauty have been included in the
Company's financial statements since the effective date of acquisition. Prior
to the acquisition, the Company accounted for its ownership using the equity
method of accounting.

Effective January 1, 2000, Black Beauty invested $6.6 million to increase
its ownership interest and obtain control of three of its Midwestern coal
mining affiliates--Sugar Camp Coal, LLC, Arclar Coal Company, LLC and United
Minerals Company, LLC. Prior to fiscal year 2000, interests in these affiliates
were accounted for under the equity method, and effective January 1, 2000, the
Company obtained decision-making control and began accounting for its 75%
interest in the affiliates on a consolidated basis. The Company has elected to
consolidate these affiliates as part of Black Beauty's results of operations
effective April 1, 1999.

Peabody Resources

Effective August 20, 1999, Peabody Resources purchased a 55% interest in the
Moura Mine in Queensland, Australia for $30.2 million. The acquisition was
accounted for as a purchase and the operating results were included in the
Company's financial statements since the date of acquisition using pro rata
consolidation. The Moura Mine was included in the sale of the Australian
operations in January 2001.

P&L Coal Group

Effective May 20, 1998, the Company paid The Energy Group PLC $2,003.5
million in cash for P&L Coal Group. The acquisition was financed by a $480.0
million equity contribution by Lehman Brothers Merchant Banking and affiliates
and borrowings of $1,523.5 million.

The acquisition has been accounted for under the purchase method of
accounting. Historical assets received of $6,406.6 million were increased to a
fair value of $7,252.4 million. Historical liabilities assumed of $4,909.2
million were increased to a fair value of $5,248.9 million. Fair value
adjustments to liabilities consist primarily of recognition of restructuring
liabilities that are discussed in Note 15, an increase in the fair value of
long-term debt assumed, the elimination of actuarial gains, losses and
deferrals, adjustments to conform foreign entities to U.S. generally accepted
accounting principles and the deferred income tax effects of purchase
accounting. The fair value of liabilities assumed included an estimated $75.0
million of transaction fees.

Below are the balance sheet of Peabody Energy Corporation (including the
effect of acquisition financing), the Company's historical balance sheet at May
19, 1998, purchase accounting adjustments and the opening balance sheet.

F-14

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

Acquisition
of
Acquisition Predecessor
Financing & Co. and
Formation of Predecessor Purchase
Peabody Energy Company Accounting
Corporation Historical Adjustments May 19, 1998
-------------- ----------- ----------- ------------

ASSETS
Cash related to
acquisition/financing... $ 2,297,390 $ -- $(2,297,390) $ --
Other current assets..... -- 2,151,059 285,376 2,436,435
Property, plant,
equipment and mine
development, net........ -- 3,642,551 746,961 4,389,512
Investments and other
assets.................. 75,000 612,977 32,334 720,311
----------- ---------- ----------- ----------
Total assets........... $ 2,372,390 $6,406,587 $(1,232,719) $7,546,258
=========== ========== =========== ==========
LIABILITIES AND
STOCKHOLDERS' EQUITY
Current maturities of
long-term debt.......... $ 16,500 $ 73,681 $ -- $ 90,181
Other current
liabilities............. 75,000 1,764,343 19,868 1,859,211
Long-term debt, less
current maturities...... 1,800,890 -- -- 1,800,890
Other long-term debt..... -- 559,881 33,779 593,660
Deferred income taxes.... -- 662,064 93,940 756,004
Other noncurrent
liabilities............. -- 1,849,244 117,068 1,966,312
----------- ---------- ----------- ----------
Total liabilities...... 1,892,390 4,909,213 264,655 7,066,258
Invested capital......... -- 1,497,374 (1,497,374) --
Stockholder's equity..... 480,000 -- -- 480,000
----------- ---------- ----------- ----------
Total liabilities &
stockholders' equity
...................... $ 2,372,390 $6,406,587 $(1,232,719) $7,546,258
=========== ========== =========== ==========

The Company finalized its purchase price allocation at March 31, 1999 based
upon the receipt of all the information it had arranged to obtain in order to
complete its estimates. This included independent appraisals on property,
plant, equipment and mine development (including land and coal interests) and
actuarial valuations supporting final adjustments to its employee-related
liabilities. In addition, agreement on the final purchase price was reached
with The Energy Group PLC.

The following unaudited pro forma results of operations assumed the
acquisitions had occurred as of April 1, 1998:

1999 2000
---------- ----------
(Dollars in
thousands)

Total revenues..................................... $2,765,979 $2,728,694
Loss before income taxes, minority interests,
discontinued operations and extraordinary loss.... (1,464) (6,278)
Net income (loss).................................. (8,964) 28,916

(3) SALE OF AUSTRALIAN OPERATIONS

On January 29, 2001, the Company sold its Australian operations to Coal &
Allied, a 71%-owned subsidiary of Rio Tinto Limited. The selling price was
$446.8 million, plus the assumption of all liabilities. The selling price
represents the $455.0 million original contract price at January 29, 2001 less
an $8.2 million purchase price adjustment. The Company used the proceeds from
the sale to repay long-term debt.

The pretax gain on sale of $171.7 million is included in the statement of
operations for the year ended March 31, 2001. The gain on sale was $124.2
million on an after-tax basis.

F-15

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(4) DISCONTINUED OPERATIONS

On March 13, 2000 the Board of Directors authorized management to sell
Citizens Power, its wholly-owned subsidiary that engaged in power trading and
power contract restructuring transactions. Subsequent to March 31, 2000, the
Company signed an agreement to sell Citizens Power to Edison Mission Energy. As
of March 31, 2000, the Company estimated its loss on disposal of the entity to
be $109.5 million on a pretax basis ($78.3 million after-tax), which included
an $8.0 million pretax provision for expected operating losses through the
expected disposal date. The Company completed the sale of operations and the
monetization of non-trading assets held by Citizens Power in March 2001,
resulting in an after-tax decrease to the loss on disposal of $12.9 million.

As a result of the estimated loss on the disposal of the entity, the results
of operations of Citizens Power were reported separately as a discontinued
operation in the statements of operations for all periods presented, and are
summarized as follows (dollars in thousands):

Predecessor
Company
----------------
April 1, 1998 to May 20, 1998 to Year Ended
May 19, 1998 March 31, 1999 March 31, 2000
---------------- --------------- --------------

Revenues................... $ 1,750 $37,394 $ 17,225
Income (loss) before income
taxes..................... (1,953) 12,477 (13,369)
Income tax provision (bene-
fit)...................... (189) 6,035 (1,297)
Income (loss) from discon-
tinued operations......... (1,764) 6,442 (12,087)

The fair value of net assets related to the discontinued operation were
segregated in the March 31, 2000 consolidated balance sheet and include the
following (dollars in thousands):

Cash.............................................................. $ 41,222
Accounts receivable............................................... 46,339
Assets from power trading activities.............................. 908,256
Liabilities from power trading.................................... (524,366)
Other current liabilities......................................... (75,701)
Non-recourse debt................................................. (305,750)
---------
$ 90,000
=========

(5) ACCOUNTS RECEIVABLE SECURITIZATION

In March 2000, the Company and its wholly-owned, bankruptcy-remote
subsidiary ("Seller") established a five-year accounts receivable
securitization program. Under the program, undivided interests in a pool of
eligible trade receivables that have been contributed to the Seller are sold,
without recourse, to a multi-seller, asset backed commercial paper conduit
("Conduit"). Purchases by the Conduit are financed with the sale of highly
rated commercial paper. The Company utilized proceeds from the sale of its
accounts receivable to repay long-term debt, effectively reducing its overall
borrowing costs. The funding cost of the securitization program for fiscal year
2001 was $8.7 million.

Under the provisions of SFAS No. 125, "Accounting for Transfers and
Servicing of Financial Assets and Extinguishments of Liabilities," (as amended
by SFAS No. 140) the securitization transactions have been recorded as sales,
with those accounts receivable sold to the Conduit removed from the
consolidated balance sheet. The amount of undivided interests in accounts
receivable sold to the Conduit were $100.0 million and $140.0 million at March
31, 2000 and March 31, 2001, respectively.

F-16

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

The Seller is a separate legal entity from the Company. The Seller's assets
are available first and foremost to satisfy the claims of its creditors.
Eligible receivables, as defined in the securitization agreement, consist of
trade receivables from our domestic subsidiaries, excluding Black Beauty,
reduced for certain items, including past due balances and concentration
limits. Of the eligible pool of receivables contributed to the Seller,
undivided interests in only a portion of the pool are sold to the Conduit. The
portion of eligible receivables not sold to the Conduit remain an asset of the
Seller ($50.9 million as of March 31, 2001). The Seller's interest in these
receivables is subordinate to the Conduit's interest in the event of default
under the securitization agreement.

(6) COAL INVENTORY

Coal inventory consisted of the following as of March 31:

2000 2001
-------- --------
(Dollars in
thousands)

Saleable coal.............................................. $ 41,047 $ 34,193
Raw coal................................................... 18,400 14,587
Work in process............................................ 133,894 122,699
-------- --------
$193,341 $171,479
======== ========

Raw coal represents coal stockpiles that may be sold in current condition or
may be further processed prior to shipment to a customer. Work in process
consists of the costs to remove overburden above an unmined coal seam as part
of the surface mining process. These costs include labor, supplies, equipment
costs and operating overhead, and are charged to operations as coal from the
seam is sold.

(7) LEASES

The Company leases equipment and facilities under various noncancelable
lease agreements. Certain lease agreements require the maintenance of specified
ratios and contain restrictive covenants which limit indebtedness, subsidiary
dividends, investments, asset sales and other Company actions. Rental expense
under operating leases was $5.4 million and $34.6 million for the periods ended
May 19, 1998 and March 31, 1999 and $55.7 million and $60.4 million for the
years ended March 31, 2000 and 2001, respectively. The net book value of
property, plant, equipment and mine development assets under capital leases was
$24.9 million and $2.2 million at March 31, 2000 and 2001, respectively.

The Company also leases coal reserves under agreements that require
royalties to be paid as the coal is mined. Certain agreements also require
minimum annual royalties to be paid regardless of the amount of coal mined
during the year. Total royalty expense was $17.3 million and $123.2 million for
the periods ended May 19, 1998 and March 31, 1999, respectively and $164.2
million and $163.9 million for the years ended March 31, 2000 and 2001,
respectively.

A substantial amount of the coal mined by the Company is produced from
reserves leased from the owner of the coal. One of the major lessors is the
U.S. government, from which the Company leases substantially all of the coal it
mines in Wyoming, Montana and Colorado under terms set by Congress and
administered by the U.S. Bureau of Land Management. The terms of these leases
are generally for an initial term of ten years but may be extended by diligent
development and mining of the reserve until all economically recoverable
reserves are depleted. The Company has met the diligent development
requirements for substantially all of these federal leases either directly
through production or by including the lease as a part of a logical mining unit
with other leases upon which development has occurred. Annual production on
these federal leases must total at least 1%

F-17

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

of the original amount of coal in the entire logical mining unit. Royalties are
payable monthly at a rate of 12.5% of the gross realization from the sale of
the coal mined using surface mining methods and at a rate of 8.0% of the gross
realization for coal produced using underground mining methods. The Company
also leases the coal production at its Arizona mines from The Navajo Nation and
the Hopi Tribe under leases that are administered by the U.S. Department of the
Interior. These leases expire once mining activities cease. The royalty rates
are also generally based upon a percentage of the gross realization from the
sale of coal. These rates are subject to redetermination every ten years under
the terms of the leases. The remainder of the leased coal is generally leased
from state governments, land holding companies and various individuals. The
duration of these leases varies greatly. Typically, the lease terms are
automatically extended as long as active mining continues. Royalty payments are
generally based upon a specified rate per ton or a percentage of the gross
realization from the sale of the coal.

In fiscal years 2000 and 2001, the Company sold certain assets for $34.2
million and $28.8 million, respectively, and those assets were leased back
under operating lease agreements from the purchasers over a period of seven to
13 years. No gains were recognized on these transactions. Each lease agreement
contains renewal options at lease termination and purchase options at amounts
approximating fair market value during the lease and at lease termination.

Future minimum lease and royalty payments as of March 31, 2001 are as
follows:

Capital Operating Coal
Fiscal Year Ending March 31 Leases Leases Reserves
--------------------------- ------- --------- --------
(Dollars in thousands)

2002................................................ $ 802 $ 59,211 $ 39,114
2003................................................ 493 52,675 36,504
2004................................................ 371 48,428 14,243
2005................................................ 363 42,645 14,061
2006................................................ 470 37,845 11,738
2007 and thereafter................................. 53 68,836 37,612
------ -------- --------
Total minimum lease payments........................ 2,552 $309,640 $153,272
======== ========
Less interest....................................... 397
------
Present value of minimum capital lease payments..... $2,155
======

(8) ACCOUNTS PAYABLE AND ACCRUED EXPENSES

Accounts payable and accrued expenses consisted of the following as of March
31:

2000 2001
-------- --------
(Dollars in
thousands)

Trade accounts payable....................................... $180,682 $208,174
Accrued taxes other than income.............................. 76,841 78,342
Accrued payroll and related benefits......................... 85,281 48,224
Accrued health care.......................................... 62,127 66,407
Accrued interest............................................. 46,166 38,170
Workers' compensation obligations............................ 35,246 33,568
Accrued royalties............................................ 18,624 21,445
Accrued lease payments....................................... 11,188 10,296
Other accrued expenses....................................... 56,982 71,850
-------- --------
Total accounts payable and accrued expenses................ $573,137 $576,476
======== ========

F-18

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(9) INCOME TAXES

Pretax income (loss) from continuing operations consisted of the following
(dollars in thousands):

Predecessor
Company
-------------
April 1, 1998 May 20, 1998
to to Year Ended Year Ended
May 19, 1998 March 31, 1999 March 31, 2000 March 31, 2001
------------- -------------- -------------- --------------

Pretax income (loss) from continuing operations:
United States................................................... $4,134 $(32,142) $(49,550) $105,184
Non U.S......................................................... 2,636 31,608 42,152 47,710
------ -------- -------- --------
$6,770 $ (534) $ (7,398) $152,894
====== ======== ======== ========

Total income tax provision (benefit) from continuing operations consisted of
the following (dollars in thousands):

Current:
U.S. federal.................................................... $ -- $ -- $ -- $ 170
Non U.S......................................................... 1,427 9,700 16,224 19,150
State........................................................... 79 26 57 100
------ ------- --------- -------
Total current................................................. 1,506 9,726 16,281 19,420
------ ------- --------- -------
Deferred:
U.S. federal.................................................... 1,904 (8,309) (124,807) 29,284
Non U.S......................................................... -- 2,026 (4,037) (1,039)
State........................................................... 1,120 (431) (28,959) (4,975)
------ ------- --------- -------
Total deferred................................................ 3,024 (6,714) (157,803) 23,270
------ ------- --------- -------
Total provision (benefit)..................................... $4,530 $ 3,012 $(141,522) $42,690
====== ======= ========= =======

The deferred tax benefit for the year ended March 31, 2000 includes the
effect of a change in tax regulations and statutes in that current period which
allowed the Company to make a tax election to treat a wholly-owned partnership
as a corporation. The election eliminated a $144.0 million deferred tax
liability previously recognized pursuant to the provisions of SFAS No. 109 on
the "outside tax basis," which represents the tax effected difference between
the book value and the tax basis of the investment in the partnership interest.
The election allowed the Company to treat the partnership as a corporation and
look to the "inside tax basis," which represents the tax effected difference
between the book value of the assets and liabilities recorded on the balance
sheet of the partnership and the tax basis of the individual assets and
liabilities. The Company recognized a deferred tax benefit of $144.0 million in
the year ended March 31, 2000 related to this election.

The non U.S. deferred tax provision for the year ended March 31, 2000
included a benefit of $3.2 million due to changes in the Australian tax rate
from 36% to 34% effective April 1, 2000.

F-19

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

The income tax rate on income (loss) from continuing operations differed
from the U.S. federal statutory rate as follows (dollars in thousands):

Federal statutory rate............................................ $ 2,369 $ (187) $ (2,590) $ 53,513
Changes in valuation allowance.................................... 6,012 16,386 31,907 35,775
Partnership tax basis election.................................... -- -- (144,028) --
Foreign earnings and disposition gains............................ 506 676 (2,566) (7,079)
State income taxes, net of U.S. federal tax benefit............... 2,881 (3,391) (6,458) (4,912)
Depletion......................................................... (2,182) (13,320) (26,151) (37,369)
Other, net........................................................ (5,056) 2,848 8,364 2,762
------- -------- --------- --------
$ 4,530 $ 3,012 $(141,522) $ 42,690
======= ======== ========= ========

The tax effects of temporary differences that give rise to significant
portions of the deferred tax assets and liabilities consisted of the following
as of March 31:

2000 2001
----------- -----------
(Dollars in thousands)

Deferred tax assets:
Accrued long-term reclamation and mine closing
liabilities.................................... $ 71,661 $ 82,678
Accrued long-term workers' compensation
liabilities.................................... 101,756 101,700
Postretirement benefit obligations.............. 425,155 429,035
Intangible tax asset and purchased contract
rights......................................... 211,283 174,326
Tax credits and loss carryforwards.............. 201,513 257,796
Obligation to industry fund..................... 26,875 23,106
Others.......................................... 106,972 108,097
----------- -----------
Total gross deferred tax assets............... 1,145,215 1,176,738
----------- -----------
Deferred tax liabilities:
Property, plant, equipment and mine development
principally due to differences in depreciation,
depletion and asset writedowns................. 1,373,982 1,339,033
Long-term debt.................................. 49,539 45,579
Others.......................................... 156,883 173,110
----------- -----------
Total gross deferred tax liabilities.......... 1,580,404 1,557,722
----------- -----------
Valuation allowance............................... (140,066) (177,495)
----------- -----------
Net deferred tax liability........................ $ (575,255) $ (558,479)
=========== ===========

Deferred taxes consisted of the following as of March 31:
Current deferred income taxes..................... $ 49,869 $ 12,226
Noncurrent deferred income taxes.................. (625,124) (570,705)
----------- -----------
Net deferred tax liability...................... $ (575,255) $ (558,479)
=========== ===========

F-20

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

The Company's deferred tax assets include alternative minimum tax ("AMT")
credits of $50.6 million and net operating loss ("NOL") carryforwards of $207.2
million at March 31, 2001. The AMT credits have no expiration date and the NOL
carryforwards expire beginning in the year 2019. The AMT credits and NOL
carryforwards are offset by a valuation allowance of $177.5 million.

No payments for U.S. federal taxes were made for the periods ended May 19,
1998 or March 31, 1999. The Company made U.S. federal tax payments totaling
$0.3 million and $0.2 million for the years ended March 31, 2000 and 2001,
respectively. No state or local income tax payments were made for the period
ended May 19, 1998. The Company paid state and local income taxes totaling $0.7
million for the period ended March 31, 1999 and $0.6 million and $0.1 million
for the years ended March 31, 2000 and 2001, respectively.

Non U.S. tax payments were $0.3 million and $11.9 million for the periods
ended May 19, 1998 and March 31, 1999, respectively and $8.8 million and $19.1
million and for the years ended March 31, 2000 and 2001, respectively.

(10) SHORT-TERM BORROWINGS

Short-term borrowings were $9.9 million at March 31, 2000. The Company was
not obligated for any short-term borrowings at March 31, 2001.

The Company maintains a Revolving Credit Facility that provides for
aggregate borrowings of up to $200.0 million and letters of credit of up to
$280.0 million. Interest rates on the revolving loans under the Revolving
Credit Facility are based on the Base Rate (as defined in the Senior Credit
Facilities) or LIBOR (as defined in the Senior Credit Facilities) at the
Company's option. The applicable rate was 6.3% at March 31, 2001. The Revolving
Credit Facility commitment matures in fiscal year 2005. As of March 31, 2001,
the Company had $73.4 million of letters of credit outstanding under the
Revolving Credit Facility.

As of March 31, 2000 and 2001, Lehman Commercial Paper Inc. had committed to
provide $23.3 million and $18.9 million of the Company's total available
borrowing capacity under the Revolving Credit Facility.

Interest paid was $0.2 million and $1.4 million for the periods ended May
19, 1998 and March 31, 1999, respectively, and $2.1 million and $1.4 million
for the years ended March 31, 2000 and 2001, respectively.

F-21

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(11) LONG-TERM DEBT

Long-term debt consisted of the following as of March 31:

2000 2001
---------- ----------
(Dollars in
thousands)

Term loans under Senior Credit Facilities due
2006.............................................. $ 690,000 $ 125,000
9.625% Senior Subordinated Notes ("Senior
Subordinated Notes") due 2008..................... 498,747 498,854
8.875% Senior Notes ("Senior Notes") due 2008...... 398,971 399,062
5.0% Subordinated Note............................. 180,335 169,875
Senior unsecured notes under various agreements.... 99,286 91,429
Unsecured revolving credit agreement............... 44,721 69,975
Other long-term debt............................... 154,171 51,426
---------- ----------
Total long-term debt............................. 2,066,231 1,405,621
Less current maturities............................ (48,042) (36,305)
---------- ----------
Long-term debt, less current maturities.......... $2,018,189 $1,369,316
========== ==========

The Senior Credit Facilities are secured by a first priority lien on certain
assets of the Company and its domestic subsidiaries. During fiscal year 2001,
the Company made optional prepayments of $565.0 million on the Senior Credit
Facilities, which it applied against mandatory Term Loan A and B payments in
order of maturity. As a result of the prepayments, the Company recorded an
extraordinary loss on debt extinguishment of $8.5 million, net of income taxes.
As of March 31, 2000 and 2001, Lehman Brothers Inc.'s and its affiliates' share
of the Company's term loans outstanding under the Senior Credit Facilities was
$1.9 million and $1.8 million, respectively.

In fiscal years 1999 and 2000, the Company maintained interest rate swap
agreements to fix the interest cost on $500 million of long-term debt
outstanding under the Term Loan Facility. During fiscal year 2001, the Company
terminated its interest rate swap agreements and realized a net gain of
approximately $5.1 million which has been included as a component of interest
expense for the year ended March 31, 2001.

The Senior Subordinated Notes are general unsecured obligations of the
Company and are subordinate in right of payment to all existing and future
senior debt (as defined), including borrowings under the Senior Credit
Facilities and the Senior Notes. The Senior Notes are general unsecured
obligations of the Company, rank senior in right of payment to all subordinated
indebtedness (as defined) and rank equally in right of payment with all current
and future unsecured indebtedness of the Company. As of March 31, 2000 and
2001, Lehman Brothers Inc.'s and its affiliates' share of the Company's Senior
Notes outstanding was $3.9 million and $1.1 million, respectively. As of March
31, 2000 and 2001, Lehman Brothers Inc.'s and its affiliates' share of the
Company's Senior Subordinated Notes outstanding was $12.4 million and $8.9
million, respectively.

The indentures governing the Senior Notes and Senior Subordinated Notes
permit the Company and its Restricted Subsidiaries to incur additional
indebtedness, including secured indebtedness, subject to certain limitations.
In addition, among other customary restrictive covenants, the indentures
prohibit the Company and its Restricted Subsidiaries from creating or otherwise
causing any encumbrance or restriction on the ability of any Restricted
Subsidiary that is not a Guarantor to pay dividends or to make certain other
upstream payments to the Company or any of its Restricted Subsidiaries (subject
to certain exceptions). The Revolving Credit Facility and related term loans
also contain certain restrictions and limitations including, but not limited
to, financial covenants that will require the Company to maintain and achieve
certain levels of financial performance and limit the payment of cash dividends
and similar restricted payments. In addition, the Senior

F-22

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

Credit Facilities prohibit the Company from allowing its Restricted
Subsidiaries (which include all Guarantors) to create or otherwise cause any
encumbrance or restriction on the ability of any such Restricted Subsidiary to
pay any dividends or make certain other upstream payments subject to certain
exceptions. At March 31, 2001, restricted net assets of the Company's
consolidated subsidiaries was $500.0 million.

The 5.0% Subordinated Note, which had an original face value of $400.0
million, is recorded net of discount at an effective annual interest rate of
approximately 12.0%. Interest and principal are payable each March 1 and
scheduled principal payments of $20.0 million per year are due from 2002
through 2006 with any unpaid amounts due March 1, 2007. The 5.0% Subordinated
Note is expressly subordinated in right of payment to all prior indebtedness
(as defined), including borrowings under the Senior Credit Facilities and the
Senior Notes.

The senior unsecured notes represent obligations of Black Beauty and include
$31.4 million of senior notes and three series of notes with an aggregate
principal amount of $60.0 million. The senior notes bear interest at 9.2%,
payable quarterly, and are prepayable in whole or in part at any time, subject
to certain make-whole provisions. The three series of notes include Series A, B
and C Notes, totaling $45.0 million, $5.0 million, and $10.0 million,
respectively. The Series A Notes bear interest at an annual rate of 7.5% and
are due in fiscal year 2008. The Series B Notes bear interest at an annual rate
of 7.4% and are due in fiscal year 2004. The Series C Notes bear interest at an
annual rate of 7.4% and are due in fiscal year 2003.

At March 31, 2001, Black Beauty maintained a $100.0 million revolving credit
facility with several banks that matures on February 28, 2002. Black Beauty may
elect one or a combination of interest rates on its borrowings; the effective
annual interest rate was 8.0% at March 31, 2001. Borrowings outstanding at
March 31, 2001 were $70.0 million. Quarterly commitment fees are paid on the
unused portion of the facility at a 0.16% rate.

Other long-term debt at March 31, 2000 included a project finance facility
and capital lease obligations totaling $98.9 million related to the Company's
Australian operations. Other, principally notes payable at March 31, 2001, is
due in installments through 2006 with a weighted average effective interest
rate of 7.6%.

The aggregate amounts of long-term debt maturities subsequent to March 31,
2001 are as follows (dollars in thousands):

2002.............................................................. $ 36,305
2003.............................................................. 57,742
2004.............................................................. 70,225
2005.............................................................. 105,645
2006.............................................................. 27,913
2007 and thereafter............................................... 1,107,791
----------
$1,405,621
==========

The amount of interest paid was $0.5 million and $138.8 million for the
periods ended May 19, 1998 and March 31, 1999, respectively and $196.9 million
and $184.6 million for the years ended March 31, 2000 and 2001, respectively.

F-23

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(12) WORKERS' COMPENSATION OBLIGATIONS

The workers' compensation obligations consisted of the following as of March
31:

2000 2001
-------- --------
(Dollars in
thousands)

Occupational disease costs............................... $156,729 $159,229
Traumatic injury claims.................................. 89,355 84,704
State assessment taxes................................... 1,422 415
-------- --------
Total obligations...................................... 247,506 244,348
Less current portion..................................... (35,246) (33,568)
-------- --------
Noncurrent obligations................................. $212,260 $210,780
======== ========

Workers' compensation obligations consist of amounts accrued for loss
sensitive insurance premiums, uninsured claims, and related taxes and
assessments under traumatic injury and occupational disease workers'
compensation programs. As of March 31, 2001, the Company had $77.4 million in
surety bonds outstanding to secure workers' compensation obligations.

Certain subsidiaries of the Company are subject to the Federal Coal Mine
Health & Safety Act of 1969, and the related workers' compensation laws in the
states in which they operate. These laws require the subsidiaries to pay
benefits for occupational disease resulting from coal workers' pneumoconiosis
("CWP"). The provision for CWP claims (including projected claims costs and
interest discount accruals) was a benefit of $0.4 million for the period ended
May 19, 1998, a charge of $11.1 million for the period ended March 31, 1999, a
charge of $12.0 million and a charge of $11.9 million and for the years ended
March 31, 2000 and 2001, respectively.

The Company provides income replacement and medical treatment for work
related traumatic injury claims as required by the applicable state law. The
provision for traumatic injury claims (including projected claims costs and
interest discount accruals) was a charge of $2.4 million for the period ended
May 19, 1998, a charge of $16.0 million for the period ended March 31, 1999, a
charge of $16.7 million and a charge of $15.7 million for the years ended March
31, 2000 and 2001, respectively.

Certain subsidiaries are required to contribute to state workers'
compensation funds for second injury and other costs incurred by the state fund
based on a payroll based assessment by the applicable state. The provision for
state assessments was a charge of $1.3 million for the period ended May 19,
1998, a charge of $8.8 million for the period ended March 31, 1999, a charge of
$14.0 million and a charge of $13.7 million for the years ended March 31, 2000
and 2001, respectively.

The liability for occupational disease claims represents the present value
of known claims and an actuarially-determined estimate of future claims that
will be awarded to current and former employees. The projections at March 31,
2000 were based on a 7.125% per annum interest discount rate and a 3.5%
estimate for the annual rate of inflation. The projections at March 31, 2001
were based on a 8.1% per annum interest discount rate and a 3.5% estimate for
the annual rate of inflation. Traumatic injury workers' compensation
obligations are estimated from both case reserves and actuarial determinations
of historical trends, discounted at 7.125% and 8.1% per annum at March 31, 2000
and 2001, respectively.

Federal Black Lung Excise Tax Refund Claims

In addition to the obligations discussed above, certain subsidiaries of the
Company are required to pay Black Lung excise taxes to the Federal Black Lung
Trust Fund. The trust fund pays CWP benefits to entitled former miners who
worked prior to July 1, 1973. Excise taxes are based on the selling price of
the coal, up to a maximum per ton amount.

F-24

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

Pursuant to a Federal District Court ruling, which the Internal Revenue
Service did not appeal, the Black Lung excise tax was declared unconstitutional
for export coal sales. As a result, the Company recorded income of $5.0 million
and $13.7 million during fiscal years 2000 and 2001, respectively, related to
refund claims filed with the Internal Revenue Service. In addition, related
interest income of $3.6 million was recorded during fiscal year 2001.

(13) PENSION AND SAVINGS PLANS

Peabody Holding Company sponsors a defined benefit pension plan covering
substantially all salaried U.S. employees (the "Peabody Plan"). A Peabody
Holding Company subsidiary also has a defined benefit pension plan covering
eligible employees who are represented by the United Mine Workers of America
under the Western Surface Agreement of 1996 (the "Western Plan"). Peabody
Holding Company and Gold Fields sponsor separate unfunded supplemental
retirement plans to provide senior management with benefits in excess of limits
under the federal tax law and increased benefits to reflect a service
adjustment factor. Powder River Coal Company, a wholly-owned subsidiary,
sponsored a defined benefit pension plan for its salaried employees that was
merged into the Peabody Plan effective January 1, 1999. Pension benefits were
not affected by the merger. Lee Ranch sponsors two defined benefit pension
plans, one which covers substantially all Lee Ranch hourly employees (the "Lee
Ranch Hourly Plan") and one which covers substantially all Lee Ranch salaried
employees (the "Lee Ranch Salaried Plan").

Benefits under the Peabody Plan and the Lee Ranch Salaried Plan are computed
based on the number of years of service and compensation during certain years.
Benefits under the Western Plan are computed based on the number of years of
service with the subsidiary or other specified employers. Benefits under the
Lee Ranch Hourly Plan are computed based on job classification and years of
service.

Annual contributions to the plans are made as determined by consulting
actuaries based upon the Employee Retirement Income Security Act of 1974
minimum funding standard. As a result of the acquisition of the Predecessor
Company, the Company entered into an agreement with the Pension Benefit
Guaranty Corporation which requires the Company to maintain minimum funding
requirements. Assets of the plans are primarily invested in various marketable
securities, including U.S. government bonds, corporate obligations and listed
stocks. The funds are part of a master trust arrangement managed by the
Company.

Net periodic pension costs included the following components (dollars in
thousands):

Service cost for
benefits earned........ $ 2,323 $ 9,098 $ 9,773 $ 8,916
Interest cost on
projected benefit
obligation............. 7,543 29,640 34,389 37,484
Expected return on plan
assets................. (9,125) (48,546) (42,691) (43,932)
Other amortizations and
deferrals.............. -- 12,083 (455) (2,174)
------- -------- -------- --------
Net periodic pension
costs................... $ 741 $ 2,275 $ 1,016 $ 294
======= ======== ======== ========

During the period ended March 31, 1999, the Company made an amendment to
phase out the Peabody Plan beginning January 1, 2000 that resulted in a
curtailment gain of $7.1 million. Effective January 1, 2001, certain employees
no longer accrue future service under the plan and certain employees accrue
reduced service under the plan based on their age and years of service at
December 31, 2000. For plan benefit calculation purposes, employee earnings are
also frozen at December 31, 2000. The Company has adopted an enhanced savings
plan contribution structure in lieu of benefits formerly accrued under the
defined benefit pension plan.

F-25

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

The following summarizes the change in benefit obligation, change in plan
assets and funded status of the Company's plans:

2000 2001
--------- ---------
(Dollars in thousands)

Change in benefit obligation:
Benefit obligation at beginning of year.... $ 492,867 $ 459,195
Service cost............................... 9,773 8,916
Interest cost.............................. 34,389 37,484
Plan amendments............................ -- 6,995
Benefits paid.............................. (28,506) (29,340)
Actuarial (gain) loss...................... (49,328) 29,654
--------- ---------
Benefit obligation at end of year............ 459,195 512,904
--------- ---------
Change in plan assets:
Fair value of plan assets at beginning of
year...................................... 474,385 507,776
Actual return on plan assets............... 60,375 (611)
Employer contributions..................... 1,522 1,029
Benefits paid.............................. (28,506) (29,340)
--------- ---------
Fair value of plan assets at end of year..... 507,776 478,854
--------- ---------
Funded status.............................. 48,581 (34,050)
Unrecognized actuarial (gain) loss......... (54,773) 21,515
Unrecognized prior service cost (benefit).. (5,205) 1,873
--------- ---------
Accrued pension expense...................... $ (11,397) $ (10,662)
========= =========
Amounts recognized in the balance sheets:
Prepaid benefit cost....................... $ 2,832 $ 4,594
Accrued benefit liability.................. (14,229) (23,333)
Intangible asset........................... -- 6,600
Additional minimum pension liability....... -- 1,477
--------- ---------
Net amount recognized........................ $ (11,397) $ (10,662)
========= =========

The projected benefit obligation applicable to pension plans with
accumulated benefit obligations in excess of plan assets was $13.2 million and
$72.9 million at March 31, 2000 and 2001, respectively. The accumulated benefit
obligation related to these plans was $13.0 million and $71.3 million at March
31, 2000 and 2001, respectively. The fair value of plan assets related to these
plans was zero at March 31, 2000, and $48.6 million at March 31, 2001.

The projected benefit obligation applicable to pension plans with projected
benefit obligations in excess of plan assets was $15.0 million at March 31,
2000. The plan assets related to these plans was $1.5 million at March 31,
2000. At March 31, 2001, the projected benefit obligation exceeded plan assets
for all plans.

The provisions of SFAS No. 87, "Employers' Accounting for Pensions," require
the recognition of an additional minimum liability and related intangible asset
to the extent that accumulated benefits exceed plan assets. As of March 31,
2001, the Company recorded an adjustment of $1.5 million which was required to
reflect the Company's minimum liability.

F-26

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

The assumptions used to determine the above projected benefit obligation at
the end of each fiscal period were as follows:

March 31, 2000 March 31, 2001
-------------- --------------

Discount rate.................................. 8.1% 7.85%
Rate of compensation increase.................. 4.25% 4.25%
Expected rate of return on plan assets......... 9.0% 9.0%

Certain subsidiaries make contributions to multiemployer pension plans,
which provide defined benefits to substantially all hourly coal production
workers represented by the United Mine Workers of America other than those
covered by the Western Plan. Benefits under the United Mine Workers of America
plans are computed based on service with the subsidiaries or other signatory
employers. The amounts contributed to the plans and included in operating costs
were $0.6 million and $1.1 million for the periods ended May 19, 1998 and March
31, 1999, respectively and $0.3 million and $0.1 million for the years ended
March 31, 2000 and 2001, respectively.

The Company sponsors an employee retirement account for eligible salaried
U.S. employees. The Company matches between 50.0% and 75.0% of voluntary
contributions up to a maximum matching contribution between 3.0% and 6.0% of a
participant's salary. Beginning with fiscal year 2000, a performance
contribution feature was added to the Employee Retirement Account to allow for
contributions up to a maximum of 4% of a participants salary based upon meeting
specified company performance targets. Effective January 1, 2001, the Company
increased the matching contribution to a maximum of 6.0% of a participant's
salary. The expense for these plans was $0.6 million and $4.1 million for the
periods ended May 19, 1998 and March 31, 1999, respectively and $6.1 million
and $6.4 million for the years ended March 31, 2000 and 2001, respectively.

The Company utilizes an alternative method for amortization of actuarial
gains and losses. The method is a 5% corridor and an amortization period of
five years.

(14) POSTRETIREMENT HEALTH CARE AND LIFE INSURANCE BENEFITS

The Company currently provides health care and life insurance benefits to
qualifying salaried and hourly retirees and their dependents from defined
benefit plans established by the Company. Employees of Gold Fields are only
eligible for life insurance benefits as provided by the Company. Plan coverage
for the health and life insurance benefits is provided to future hourly
retirees in accordance with the applicable labor agreement. The Company
accounts for postretirement benefits using the accrual method.

Net periodic postretirement benefits costs included the following components
(dollars in thousands):

Service cost for
benefits earned........ $ 897 $ 4,750 $ 4,835 $ 3,379
Interest cost on
accumulated
postretirement benefit
obligations............ 10,075 60,519 70,029 74,227
Amortization of prior
service cost........... (242) (625) (2,488) (2,610)
Amortization of
actuarial gains........ -- -- -- (4,339)
------- ------- ------- -------
Net periodic
postretirement benefit
costs.................. $10,730 $64,644 $72,376 $70,657
======= ======= ======= =======

F-27

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

The following table sets forth the plans' combined funded status reconciled
with the amounts shown in the balance sheets:

2000 2001
---------- ----------
(Dollars in
thousands)

Change in benefit obligation:
Benefit obligation at beginning of year.......... $1,008,702 $ 964,380
Service cost..................................... 4,835 3,379
Interest cost.................................... 70,029 74,227
Plan amendments.................................. (1,097) --
Benefits paid.................................... (57,586) (60,589)
Actuarial (gain) loss............................ (60,503) 9,837
---------- ----------
Benefit obligation at end of year.................. 964,380 991,234
---------- ----------
Change in plan assets:
Fair value of plan assets at beginning of year... -- --
Employer contributions........................... 57,586 60,589
Benefits paid.................................... (57,586) (60,589)
---------- ----------
Fair value of plan assets at end of year........... -- --
---------- ----------
Funded status.................................... (964,380) (991,234)
Unrecognized actuarial gain...................... (41,420) (27,080)
Unrecognized prior service cost.................. (20,386) (17,776)
---------- ----------
Total accrued postretirement benefit
obligation.................................... (1,026,186) (1,036,090)
Less current portion............................... 55,000 62,011
---------- ----------
Noncurrent obligation.......................... $ (971,186) $ (974,079)
========== ==========

The assumptions used to determine the accumulated postretirement benefit
obligation at the end of each fiscal years were as follows:

March 31, 2000 March 31, 2001
------------------ ------------------

Discount rate........................ 8.1% 7.85%
Salary increase rate for life
insurance benefit................... 4.25% 4.25%
Health care trend rate:
Pre-65............................. 6.95% down to 6.95% down to
4.75% over 4 years 4.75% over 4 years
Post-65............................ 6.13% down to 6.13% down to
4.75% over 4 years 4.75% over 4 years
Medicare........................... 5.68% down to 5.68% down to
4.75% over 4 years 4.75% over 4 years

Assumed health care cost trend rates have a significant effect on the
amounts reported for health care plans. A one-percentage-point change in the
assumed health care cost trend would have the following effects:

One-Percentage- One-Percentage-
Point Increase Point Decrease
--------------- ---------------
(Dollars in thousands)

Effect on total service and interest cost
components.............................. $ 9,827 $ (8,169)
Effect on postretirement benefit
obligation.............................. $126,255 $(105,321)

F-28

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

In October 1999, Powder River announced changes in its medical plan for
active employees and retirees. Employees who retired prior to December 31, 1999
were not affected by these changes. The changes included: 90/10 coinsurance,
maximum out-of-pocket limits, copay for prescription drugs and mandatory
generic drug usage. The effect of the change on the salaried retiree health
care liability is $1.1 million. Powder River is recognizing the effect of the
plan amendment over nine years. The effect for the years ended March 31, 2000
and 2001 was $0.1 million.

In January 1999, the Company adopted reductions to the salaried employee
medical coverage levels for employees retiring before January 1, 2003. For
employees retiring on or after January 1, 2003, the current medical plan is
replaced with a medical premium reimbursement plan. This plan change does not
apply to Powder River or Lee Ranch salaried employees. The change in the
retiree health care plan resulted in a $22.4 million reduction to the salaried
retiree health care liability. The Company is recognizing the effect of the
plan amendment over nine years beginning January 1, 1999. Therefore, the effect
for the three months ended March 31, 1999 was $0.6 million, and $2.5 million
for each of the years ended March 31, 2000 and 2001.

The Company utilizes an alternative method for amortization of actuarial
gains and losses. The method is a 5% corridor and an amortization period of
three years.

Multi-Employer Pension and Benefit Plans

Retirees formerly employed by certain subsidiaries and their predecessors,
who were members of the United Mine Workers of America, last worked before
January 1, 1976 and were receiving health benefits on July 20, 1992, receive
health benefits provided by the Combined Fund, a fund created by the Coal
Industry Retiree Health Benefit Act of 1992 (the "Coal Act"). The Coal Act
requires former employers (including certain subsidiaries of the Company) and
their affiliates to contribute to the Combined Fund according to a formula. In
addition, certain Federal Abandoned Mine Lands funds will be used to pay
benefits to orphaned retirees through 2004.

The Company has recorded an actuarially determined liability representing
the amounts anticipated to be due for the Combined Fund. The "Obligation to
industry fund" reflected in the balance sheets at March 31, 2000 and 2001 was
$64.7 million and $52.2 million, respectively. The current portion related to
this obligation reflected in "Accounts payable and accrued expenses" in the
balance sheets at March 31, 2000 and 2001 was $5.1 million and $5.6 million,
respectively.

A benefit of $0.9 million was recognized for the period ended May 19, 1998
which included amortization of an actuarial gain of $1.7 million, net of the
interest discount accrual of $0.8 million. Expense of $4.5 million was
recognized for the period ended March 31, 1999 due to the interest discount
accrual. Expense of $2.6 million was recognized for the period ended March 31,
2000 which includes interest discount of $4.8 million, net of the amortization
of an actuarial gain of $2.2 million. A benefit of $8.0 million was recognized
for the period ended March 31, 2001, which includes interest discount of $4.6
million, net amortization of an actuarial gain of $1.1 million and a gain of
$11.5 million related to beneficiaries formerly assigned to the Company by the
Social Security Administration and withdrawn in the current year.

The Coal Act also established a multiemployer benefit plan ("1992 Plan")
which will provide medical and death benefits to persons who are not eligible
for the Combined Fund, whose employer and any affiliates are no longer in
business and who retired prior to October 1, 1994. A prior labor agreement
established the 1993 United Mine Workers of America Benefit Trust ("1993 Plan")
to provide health benefits for retired miners not covered by the Coal Act. The
1992 Plan and the 1993 Plan qualify under SFAS No. 106 as multiemployer

F-29

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

benefit plans, which allows the Company to recognize expense as contributions
are made. The amounts related to these funds were $0.2 million and $0.7 million
for the periods ended May 19, 1998 and March 31, 1999, respectively and $1.7
million and $1.9 million for the years ended March 31, 2000 and 2001,
respectively.

Pursuant to the provisions of the Coal Act and the 1992 Plan, the Company is
required to provide security in an amount equal to three times the cost of
providing health care benefits for one year for all individuals receiving
benefits from the 1992 Plan who are attributable to the Company, plus all
individuals receiving benefits from an individual employer plan maintained by
the Company who are entitled to receive such benefits. In accordance with the
Coal Act and the 1992 Plan, the Company has outstanding surety bonds at March
31, 2001 of $109.3 million. The surety bonds represent security for the
postretirement liability included on the balance sheets.

(15) RESTRUCTURING LIABILITY

In conjunction with the acquisition of the Predecessor Company, the Company
established a $39.4 million liability for estimated costs associated with a
restructuring plan resulting from the business combination. The estimate was
comprised of costs associated with restructuring certain management and
administrative functions ("restructuring plan") and exiting certain activities
("exit plan"). The primary actions of the restructuring plan were to eliminate
or significantly downsize administrative functions for operating locations, and
consolidate and relocate administrative functions to the corporate
headquarters. The restructuring activities were substantially complete by
September 1998, resulting in the involuntary termination of 118 employees and
the relocation of 102 employees. Costs included severance pay, relocation
costs, office closure costs (primarily non-cancelable leases) and payments due
to employees resulting from the change in ownership. The costs associated with
the exit plan relate to the decision at the date of the acquisition to suspend
the operations of the Rawhide Mine in Wyoming. Exit activities included
stabilizing the coal face, covering the coal pit, sloping the highwall and
idling equipment and facilities, which were necessary to obtain the required
approval from state and federal regulatory agencies to suspend operations.
Costs associated with the restructuring and exit plans have been charged
against the liability as incurred. The total costs charged against the
liability were $28.8 million and $6.4 million for the period ended March 31,
1999 and the year ended March 31, 2000, respectively.

The exit plan was completed in the third quarter of fiscal year 2000 and the
liability was reduced by $3.8 million at that time to reflect the most recent
cost estimates. This amount was recorded as an adjustment to the cost of the
acquisition. The majority of the adjustment related to lower exit plan costs
than originally estimated. The $0.3 million remaining liability as of March 31,
2000 was recorded as an adjustment to the cost of the acquisition during the
year ended March 31, 2001.

The following table displays a rollforward of the restructuring liability
from the acquisition date to March 31, 2001:

May 19, March 31, Adjustment March 31, Adjustment March 31,
1998 1999 to Cost of 2000 to Cost of 2001
Balance Charges Balance Charges Acquisition Balance Acquisition Balance
------- -------- --------- ------- ----------- --------- ----------- ---------
(Dollars in thousands)

Restructuring plan...... $26,154 $(20,536) $ 5,618 $(4,409) $ (880) $329 $(329) $--
Exit plan............... 13,214 (8,296) 4,918 (1,995) (2,923) -- -- --
------- -------- ------- ------- ------- ---- ----- ----
Total................. $39,368 $(28,832) $10,536 $(6,404) $(3,803) $329 $(329) $--
======= ======== ======= ======= ======= ==== ===== ====

F-30

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(16) STOCKHOLDERS' EQUITY

Preferred Stock

The Company has 14,000,000 authorized shares of $0.01 par value preferred
stock. The Board of Directors is authorized to issue any or all of the
preferred stock. Shares of preferred stock are exchangeable on a one-for-one
basis into shares of Class A common stock upon resolution by the Board of
Directors.

Common Stock

The Company has 42,000,000 authorized shares of $0.01 par value Class A
common stock, and 4,200,000 authorized shares of $0.01 par value Class B common
stock. Holders of the Class A and Class B common stock are entitled to one vote
for each share held on all matters submitted to a vote of the stockholders.
Shares of Class B common stock are convertible into shares of Class A common
stock on a one-for-one basis upon a resolution by the Board of Directors, a
change of control, an initial public offering, a recapitalization that does not
result in a change of control or the passing of nine years after the issuance.

Subject to the rights of the holders of the preferred stock, holders of
Class A and Class B common stock are entitled to ratably receive such dividends
as may be declared by the Board of Directors. In the event of liquidation,
dissolution or winding up of the Company, holders of the Class A common stock
are entitled to share ratably in the distribution of all assets remaining after
payment of liabilities, subject to the rights of the preferred stockholders.
Holders of Class B common stock have a junior liquidation right to the holders
of Class A common stock.

The Company recognized compensation cost related to grants of Class B common
stock to management of $13.1 million, $0.3 million and $3.9 million during the
period ended March 31, 1999 and the years ended March 31, 2000 and 2001,
respectively.

Stock Option Plan

Effective May 19, 1998, the Company adopted the "1998 Stock Purchase and
Option Plan for Key Employees of P&L Coal Holdings Corporation" (the "Plan"),
making 5,638,920 shares of the Company's common stock available for grant. The
Board of Directors may provide such grants in the form of stock, non-qualified
options or incentive stock options.

A portion of the options vest solely on the passage of time ("time options")
to the extent permitted under the Internal Revenue Code. Additionally, a
portion of the options vest at the end of nine and one-half years, whether or
not the applicable performance targets are achieved, but become exercisable
earlier with the achievement of performance goals determined by the Board of
Directors ("performance options"). Time options become fully vested early upon
death, disability, a change in control or a recapitalization event, as defined.
Performance options become fully vested early upon a change on control, a
recapitalization event or an initial public offering, as defined.

During the period ended March 31, 1999, the Company granted 5,314,222
options to purchase Class A common stock, 1,304,639 of which are time options
and 4,009,583 of which are performance options. During the year ended March 31,
2000, the Company granted 282,275 options to purchase Class A common stock,
81,414 of which are time options and 200,861 of which are performance options.
During the year ended March 31, 2001, the Company granted 1,456,542 options to
purchase Class A common stock, 371,934 of which are time options and 1,084,608
of which are performance options. All options have an exercise price of $14.29
per share, and expire 10 years after date of grant.

F-31

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

A summary of outstanding option activity is as follows:

1999 2000 2001
--------- --------- ----------

Beginning balance........................... -- 5,314,222 5,165,538
Granted................................... 5,314,222 282,275 1,456,542
Exercised................................. -- -- --
Forfeited................................. -- (430,959) (1,396,570)
--------- --------- ----------
Outstanding at March 31..................... 5,314,222 5,165,538 5,225,510
========= ========= ==========
Exercisable at March 31..................... -- 488,025 779,962
========= ========= ==========

The Company applies APB Opinion No. 25 and related interpretations in
accounting for the Plan. The Company recorded $0.1 million of compensation
expense for stock options granted during the year ended March 31, 2001. The
Company deferred $2.0 million of compensation related to stock option grants as
of that date, $0.8 million of which is expected to be recognized as expense
upon completion of an initial public offering, and $1.2 million of which will
be recognized in subsequent periods as the stock options become exercisable.
The Company recorded no compensation expense for stock options granted during
the period ended March 31, 1999 or the year ended March 31, 2000. The following
table reflects pro forma net income (loss) and earnings (loss) per share had
compensation cost been determined for the Company's non-qualified and incentive
stock options based on the fair value at the grant dates consistent with the
minimum value method set forth under SFAS No. 123, "Accounting for Stock-Based
Compensation:"

1999 2000 2001
------ ------- --------

Net income (loss):
As reported...................................... $1,009 $28,210 $107,060
Pro forma........................................ (2,248) 24,842 105,117
Earnings (loss) per share:
As reported...................................... $ .03 $ 0.82 $ 3.10
Pro forma........................................ (.06) 0.72 3.04

These pro forma amounts may not be representative of future disclosures
since the estimated fair value of stock options is amortized to expense over
the vesting period, and additional options may be granted in future years.

The weighted average fair values of the Company's stock options and the
assumptions used in applying the minimum value method were as follows:

1999 2000 2001
-------- -------- --------

Weighted average fair value.................... $ 4.71 $ 4.71 $ 5.97
Risk-free interest rate........................ 5.7% 5.7% 5.5%
Expected option life........................... 7 years 7 years 7 years
Dividend yield................................. 0% 0% 0%

The weighted average remaining contractual life of stock options outstanding
as of March 31, 2001 was 7.8 years.

F-32

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(17) COMPREHENSIVE INCOME

The after-tax components of accumulated other comprehensive income (loss)
are as follows:

Total Accumulated
Foreign Currency Minimum Pension Other Comprehensive
Translation Adjustment Liability Adjustment Income/(Loss)
---------------------- -------------------- -------------------
(Dollars in thousands)

Predecessor Company
-------------------
Beginning balance March
31, 1998............... $(42,184) $ -- $(42,184)
Current period change... (17,974) -- (17,974)
-------- ------- --------
Ending balance May 19,
1998................... $(60,158) $ -- $(60,158)
======== ======= ========
-----------------------------------------------------------------------------------------
Beginning balance May
20, 1998............... $ -- $ -- $ --
Current period change... 4,128 (1,795) 2,333
-------- ------- --------
Ending balance March 31,
1999................... 4,128 (1,795) 2,333
Current period change... (16,795) 1,795 (15,000)
-------- ------- --------
Ending balance March 31,
2000................... (12,667) -- (12,667)
Current period change... (26,144) (862) (27,006)
Reclassification adjust-
ment resulting from the
sale of Australian op-
erations............... 38,811 -- 38,811
-------- ------- --------
Ending balance March 31,
2001................... $ -- $ (862) $ (862)
======== ======= ========

In conjunction with the sale of the Australian operations as discussed in
Note 3, the Company recorded a reduction of the foreign currency translation
adjustment of the Company's Australian operations.

(18) RELATED PARTY TRANSACTIONS

On May 19, 1997, the Predecessor Company, which at the time was owned by The
Energy Group PLC, purchased Citizens Lehman Power, a joint venture formed in
1994 by Lehman Brothers Holdings and a subsidiary of Citizens Energy
Corporation, from Lehman Brothers Holdings, which owned a 50% interest in
Citizens Lehman Power, and from the other owners of Citizens Lehman Power for a
maximum purchase price of $120.0 million, which included (1) an up-front
payment of $20.0 million and (2) up to $100.0 million of future cash payments
based on a formula taking into account the net asset value of Citizens Lehman
Power as of the date of its sale to The Energy Group PLC and any future
increase in net asset value over the period ending on the last day of fiscal
year 2002. That payment obligation was subject to acceleration, under certain
circumstances, in the event of a change of control of The Energy Group PLC.
Citizens Lehman Power was renamed Citizens Power after the 1997 purchase. As a
result of the May 19, 1998 acquisition of the Predecessor Company by Lehman
Brothers Merchant Banking, the change of control payment acceleration
provisions became effective, and the Company paid the former owners of Citizens
Lehman Power an aggregate of approximately $94.0 million in full settlement of
the deferred purchase price obligations, with approximately $73.0 million,
including $1.0 million of interest, of that payment made on May 19, 1998 and
$21.0 million, including $1.0 million of interest, paid on April 3, 2000.
Amounts paid in settlement of the deferred purchase price obligations,
excluding interest, were included in the cost of the acquisition of Citizens
Lehman Power.

Lehman Brothers provided other financial advisory services to the
Predecessor Company in April 1998, for which the Company paid a fee of $0.1
million.

F-33

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

Lehman Brothers Merchant Banking formed the company to acquire the
Predecessor Company and various of its subsidiaries, including Citizens Power,
from The Energy Group PLC on May 19, 1998. In connection with the acquisition,
the Company paid the $73.0 million of obligations of Citizens Power referred to
above. Lehman Brothers advised Lehman Brothers Merchant Banking in connection
with that acquisition. In addition, Lehman Brothers was the initial purchaser
in connection with the sale of the Company's senior notes and our senior
subordinated notes. Furthermore, Lehman Commercial Paper Inc. arranged the
Company's senior credit facility and is one of the Company's lenders. Lehman
Brothers and Lehman Commercial Paper Inc. collectively received fees of
approximately $85 million for those services.

As part of the acquisition, Lehman Brothers Holdings Inc. provided a 364-day
guarantee facility to trading counterparties of Citizens Power Sales, the
trading subsidiary of Citizens Power, for trades initiated after the
acquisition. Lehman Brothers Holdings received a fee of $0.5 million, plus
reimbursement of expenses, for providing this guarantee facility, which expired
in accordance with its terms in November 1998. There are no further guarantee
obligations outstanding under this facility.

Lehman Brothers served as the placement agent in a financing completed in
January 1999 by a subsidiary of Citizens Power relating to a utility power
contract restructuring, and the Company paid Lehman Brothers a fee of
approximately $0.8 million, plus reimbursement of expenses, for those services.

Lehman Brothers served as the placement agent in a financing completed in
October 1999 by a subsidiary of Citizens Power relating to a utility power
contract restructuring, and the Company paid Lehman Brothers a fee of
approximately $0.8 million, plus reimbursement of expenses, for those services.

Lehman Brothers served as the Company's financial advisor in connection with
the Company's acquisition of an additional 38.3% interest in Black Beauty. The
Company paid Lehman Brothers a fee of approximately $1.3 million, plus
reimbursement of expenses, for those services.

Lehman Brothers served as the Company's financial advisor in connection with
the sale of Citizens Power, which was completed in fiscal year 2001. The
Company paid Lehman Brothers a fee of approximately $1.5 million, plus
reimbursement of expenses, for those services.

Lehman Brothers served as one of the Company's financial advisors in
connection with the sale of the Company's Australian operations, which was
completed on January 29, 2001. The Company paid Lehman Brothers a fee of $2.7
million, plus reimbursement of expenses, for those services.

(19) CONTRACT RESTRUCTURINGS

The Company has periodically agreed to terminate coal supply agreements in
return for payments by the customer. There were no gains related to coal supply
agreement terminations for the period ended May 19, 1998 or the year ended
March 31, 2001. The amounts included in "Other revenues" were $5.3 million for
the period ended March 31, 1999 and $13.0 million for the year ended March 31,
2000.

(20) FINANCIAL INSTRUMENTS WITH OFF-BALANCE-SHEET RISK

The Company owns a 30.0% interest in a partnership that leases a coal export
terminal from the Peninsula Ports Authority of Virginia under a 30-year lease
that permits the partnership to purchase the terminal at the end of the lease
term for a nominal amount. The partners have severally (but not jointly) agreed
to make payments under various agreements which in the aggregate provide the
partnership with sufficient funds to pay

F-34

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

rents and to cover the principal and interest payments on the floating-rate
industrial revenue bonds issued by the Peninsula Ports Authority, and which are
supported by letters of credit from a commercial bank. The Company's
reimbursement obligation to the commercial bank is in turn supported by a
letter of credit totaling $42.8 million.

In December 1999, the Company entered into a 49.0% interest in a joint
venture to develop and rehabilitate an underground mine and prep plant
facility. The partners have severally agreed to guarantee a $32.3 million
financing agreement provided by two commercial banks of which 49.0% ($15.8
million) is guaranteed by the Company. Principal payments are due beginning
April 1, 2001 at $0.3 million per month for 24 months, then increase to $0.4
million per month for 20 months beginning April 1, 2003. A final principal
payment of $17.1 million is due December 31, 2004. Interest payments are due
monthly and accrue at prime, which was 8.0% at March 31, 2001.

Prior to the sale of the Company's Australian operations, as discussed in
Note 3, Peabody Resources used forward currency contracts to manage its
exposure against foreign currency fluctuations on sales denominated in U.S.
dollars. Realized gains and losses on these contracts were recognized in the
same period as the hedged transactions. The Company had deferred unrealized
gains and (losses) of $16.2 million as of March 31, 1999 and ($13.9 million) as
of March 31, 2000.

In the normal course of business, the Company is a party to financial
instruments with off-balance-sheet risk, such as bank letters of credit,
performance bonds and other guarantees, which are not reflected in the
accompanying balance sheets. Such financial instruments are to be valued based
on the amount of exposure under the instrument and the likelihood of
performance being required. In the Company's past experience, virtually no
claims have been made against these financial instruments. Management does not
expect any material losses to result from these off-balance-sheet instruments
and, therefore, is of the opinion that the fair value of these instruments is
zero.

(21) FAIR VALUE OF FINANCIAL INSTRUMENTS

SFAS No. 107, "Disclosures About Fair Value of Financial Instruments,"
defines the fair value of a financial instrument as the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced or liquidation sale.

The following methods and assumptions were used by the Company in estimating
its fair value disclosures for financial instruments:

Cash and cash equivalents, accounts receivable and accounts payable and
accrued expenses have carrying values which approximate fair value due to
the short maturity or the financial nature of these instruments.

Long-term debt fair value estimates are based on estimated borrowing
rates to discount the cash flows to their present value. The 5.0%
Subordinated Note carrying amount is net of unamortized note discount.

Other noncurrent liabilities include a deferred purchase obligation
related to the prior purchase of a mine facility. The fair value estimate
is based on the same assumption as long-term debt.

Investments and other assets include certain notes receivable with
customers at various interest rates. Notes receivable fair value estimates
are based on estimated borrowing rates to discount the cash flows to their
present values.

F-35

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

The carrying amounts and estimated fair values of the Company's financial
instruments are summarized as follows:

2000 2001
--------------------- ---------------------
Carrying Estimated Carrying Estimated
Amount Fair Value Amount Fair Value
---------- ---------- ---------- ----------
(Dollars in thousands)

Interest rate swaps............. $ -- $ 20,022 $ -- $ --
Long-term debt.................. 2,066,231 1,943,440 1,405,621 1,483,996
Deferred purchase obligation.... 28,377 25,033 23,301 23,246

The fair value of the financial instruments related to coal and emission
allowance trading activities as of March 31, 2001, and the average fair value
during the year ended March 31, 2001, which include energy commodities, are set
forth below:

Fair Value Average Fair Value
-------------------- -------------------
Assets Liabilities Assets Liabilities
-------- ----------- ------- -----------
(Dollars in thousands)

Forward contracts................... $151,212 $143,912 $78,088 $73,560
Option contracts.................... 21,118 19,801 13,471 12,772
-------- -------- ------- -------
Total............................. $172,330 $163,713 $91,559 $86,322
======== ======== ======= =======

The approximate gross contract or notional amounts of financial instruments
are as follows:

Fixed Price Fixed Price
Payor Receiver
----------- -----------
(Dollars in thousands)

Forward contracts.................................... $242,812 $232,586
Option contracts..................................... 86,348 108,639

There was no net gain or loss from coal and emission allowance trading
activities for the period ended May 19, 1998. The net gain arising from coal
and emission allowance trading activities was $0.5 million for the period ended
March 31, 1999 and $1.3 million and $7.8 million for the years ended March 31,
2000 and 2001, respectively. The change in unrealized gain from coal trading
activities for the year ended March 31, 2001 was $4.3 million.

(22) COMMITMENTS AND CONTINGENCIES

Environmental claims have been asserted against a subsidiary of the Company
at 18 sites in the United States. Some of these claims are based on the
Comprehensive Environmental Response Compensation and Liability Act of 1980, as
amended, and on similar state statutes. The majority of these sites are related
to activities of former subsidiaries of the Company.

The Company's policy is to accrue environmental cleanup-related costs of a
noncapital nature when those costs are believed to be probable and can be
reasonably estimated. The quantification of environmental exposures requires an
assessment of many factors, including changing laws and regulations,
advancements in environmental technologies, the quality of information
available related to specific sites, the assessment stage of each site
investigation, preliminary findings and the length of time involved in
remediation or settlement. For certain sites, the Company also assesses the
financial capability of other potentially responsible parties and, where
allegations are based on tentative findings, the reasonableness of the
Company's apportionment. The Company has not anticipated any recoveries from
insurance carriers or other potentially responsible third parties in its
balance sheets. The undiscounted liabilities for environmental cleanup-related
costs recorded as part of

F-36

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

"Other noncurrent liabilities" at March 31, 2000 and 2001 were $57.7 million
and $48.0 million, respectively. This amount represents those costs that the
Company believes are probable and reasonably estimable.

On June 18, 1999, The Navajo Nation served our subsidiaries, Peabody
Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company,
with a complaint that had been filed in the U.S. District Court for the
District of Columbia. Other defendants in the litigation are two customers,
one current employee and one former employee. The Navajo Nation has alleged 16
claims, including Civil Racketeer Influenced and Corrupt Organizations Act, or
RICO, violations and fraud and tortious interference with contractual
relationships. The complaint alleges that the defendants jointly participated
in unlawful activity to obtain favorable coal lease amendments. Plaintiff also
alleges that defendants interfered with the fiduciary relationship between the
United States and the Navajo Nation. The plaintiff is seeking various remedies
including actual damages of at least $600 million, which could be trebled
under the RICO counts, punitive damages of at least $1 billion, a
determination that Peabody Western Coal Company's two coal leases for the
Kayenta and Black Mesa mines have terminated due a breach of these leases and
a reformation of the two coal leases to adjust the royalty rate to 20%. All
defendants have filed motions to dismiss the complaint. On March 15, 2001, the
court denied the Peabody defendants' motions to dismiss.

In March 2000, the Hopi Tribe filed a motion to intervene in this lawsuit.
The Hopi Tribe has alleged seven claims, including fraud. The Hopi Tribe is
seeking various remedies, including unspecified actual and punitive damages,
reformation of its coal lease and a termination of the coal lease. On March
15, 2001, the court granted the Hopi Tribe's motion. On April 17, 2001, the
Company filed a motion to dismiss the Hopi complaint.

The Company believes this matter will be resolved without a material
adverse effect on the financial condition or results of operations.

In addition, the Company at times becomes a party to claims, lawsuits,
arbitration proceedings and administrative procedures in the ordinary course
of business. Management believes that the ultimate resolution of pending or
threatened proceedings will not have a material effect on the financial
position, results of operations or liquidity of the Company.

At March 31, 2001, purchase commitments for capital expenditures were
approximately $94.4 million.

F-37

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(23) SUMMARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

The following is a summary of the unaudited quarterly results of operations
for fiscal years 2000 and 2001 (dollars in thousands, except share data):

2000
--------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
----------- ----------- ----------- -----------

Revenues.................... $ 664,400 $ 678,343 $ 709,446 $ 658,311
Operating profit............ 41,967 46,703 52,405 52,162
Income (loss) from continu-
ing operations............. (9,427) (7,057) (6,085) 141,139
Net income (loss)........... (12,880) (8,093) (9,705) 58,888
Basic and diluted earnings
(loss) per share per
share from continuing oper-
ations.................... $ (0.27) $ (0.20) $ (0.18) $ 4.08
Weighted average shares used
in calculating basic
and diluted earnings (loss)
per share.................. 27,592,277 27,587,335 27,582,549 27,583,350

2001
--------------------------------------------------
First Second Third Fourth
Quarter Quarter Quarter Quarter
----------- ----------- ----------- -----------

Revenues.................... $ 673,021 $ 677,591 $ 634,081 $ 684,999
Operating profit............ 40,957 39,360 52,723 208,799
Income (loss) from continu-
ing operations............. (8,470) (11,233) (2,034) 124,417
Income (loss) before ex-
traordinary item........... 350 (8,293) (2,034) 125,582
Net income (loss)........... 350 (8,293) (2,034) 117,037
Basic and diluted earnings
(loss) per share per
share from continuing oper-
ations.................... $ (0.25) $ (0.33) $ (0.06) $ 3.60
Weighted average shares used
in calculating basic
and diluted earnings (loss)
per share.................. 27,511,978 27,554,065 27,491,443 27,541,242

Results of operations for the fourth quarter of fiscal year 2000 included a
$144.0 million income tax benefit associated with an increase in the tax basis
of a subsidiary's assets due to a change in federal income tax regulations, and
a $78.3 million estimated loss from the disposal of Citizens Power that was
classified as a discontinued operation in March 2000. Results of operations for
the first quarter, second quarter and fourth quarter of fiscal year 2001
included reductions to the after-tax estimated loss on disposal of Citizens
Power of $8.8 million, $3.0 million and $1.1 million, respectively.
Additionally, results of operations for the fourth quarter of fiscal year 2001
included an after-tax gain of $124.2 million on the sale of the Company's
Australian operations, and an after-tax extraordinary loss of $8.5 million
related to the early extinguishment of debt.

F-38

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(24) SEGMENT INFORMATION

The Company operates primarily in the coal industry. "Other" data represents
an aggregation of the Company's other non-mining entities including Gold
Fields. The Company's material operations outside the U.S. related to its
operations in Australia that were sold in January 2001. The Company's industry
and geographic data for continuing operations were as follows (dollars in
thousands):

Predecessor May 20,
Company 1998 to Year Ended Year Ended
April 1, 1998 to March 31, March 31, March 31,
May 19, 1998 1999 2000 2001
---------------- ---------- ---------- ----------

Revenues:
U.S. Mining.............................................................. $269,597 $1,903,214 $2,462,166 $2,427,963
Non U.S. Mining.......................................................... 20,882 145,687 244,347 238,498
Other.................................................................... 179 7,931 3,987 3,231
-------- ---------- ---------- ----------
$290,658 $2,056,832 $2,710,500 $2,669,692
======== ========== ========== ==========
Operating profit (loss):
U.S. Mining.............................................................. $ 6,929 $ 122,827 $ 140,699 $ 277,316
Non U.S. Mining.......................................................... 2,950 32,676 48,355 53,377
Other.................................................................... (554) 1,541 4,183 11,146
-------- ---------- ---------- ----------
$ 9,325 $ 157,044 $ 193,237 $ 341,839
======== ========== ========== ==========
Depreciation, depletion and amortization:
U.S. Mining.............................................................. $ 22,475 $ 155,220 $ 216,327 $ 215,450
Non U.S. Mining.......................................................... 3,041 23,962 33,455 25,518
-------- ---------- ---------- ----------
$ 25,516 $ 179,182 $ 249,782 $ 240,968
======== ========== ========== ==========
Total assets, at March 31:
U.S. Mining.............................................................. $5,141,661 $5,038,423 $5,035,716
Non U.S. Mining.......................................................... 494,123 527,771 --
Other.................................................................... 1,388,147 260,655 173,771
---------- ---------- ----------
$7,023,931 $5,826,849 $5,209,487
========== ========== ==========
Capital Expenditures:
U.S. Mining.............................................................. $ 13,582 $ 110,622 $ 150,130 $ 150,401
Non U.S. Mining.......................................................... 7,292 63,898 28,624 35,702
Other.................................................................... -- -- -- 957
-------- ---------- ---------- ----------
$ 20,874 $ 174,520 $ 178,754 $ 187,060
======== ========== ========== ==========
Revenues:
United States............................................................ $269,776 $1,911,145 $2,466,153 $2,431,194
Non U.S.................................................................. 20,882 145,687 244,347 238,498
-------- ---------- ---------- ----------
$290,658 $2,056,832 $2,710,500 $2,669,692
======== ========== ========== ==========
Operating profit:
United States............................................................ $ 6,375 $ 124,368 $ 144,882 $ 288,462
Non U.S.................................................................. 2,950 32,676 48,355 53,377
-------- ---------- ---------- ----------
$ 9,325 $ 157,044 $ 193,237 $ 341,839
======== ========== ========== ==========
Depreciation, depletion and amortization:
United States............................................................ $ 22,475 $ 155,220 $ 216,327 $ 215,450
Non U.S.................................................................. 3,041 23,962 33,455 25,518
-------- ---------- ---------- ----------
$ 25,516 $ 179,182 $ 249,782 $ 240,968
======== ========== ========== ==========
Property, plant, equipment and mine development, net, at March 31:
United States............................................................ $4,386,465 $4,388,843 $4,322,639
Non U.S.................................................................. 411,480 426,667 --
---------- ---------- ----------
$4,797,945 $4,815,510 $4,322,639
========== ========== ==========

F-39

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

(25) SUPPLEMENTAL GUARANTOR/NON-GUARANTOR FINANCIAL INFORMATION

In accordance with the indentures governing the Senior Notes and Senior
Subordinated Notes, certain wholly-owned U.S. subsidiaries of the Company have
fully and unconditionally guaranteed the Senior Notes and Senior Subordinated
Notes on a joint and several basis. Separate financial statements and other
disclosures concerning the Guarantor Subsidiaries are not presented because
management believes that such information is not material to holders of the
Senior Notes and the Senior Subordinated Notes. The following condensed
historical financial statement information is provided for such Guarantor/Non-
Guarantor Subsidiaries.

SUPPLEMENTAL CONDENSED COMBINED STATEMENTS OF OPERATIONS
April 1, 1998 to May 19, 1998

Predecessor Company
----------------------------------
Non-
Guarantor guarantor
Subsidiaries Subsidiaries Combined
------------ ------------ --------
(Dollars in thousands)

Total revenues............................. $269,776 $20,882 $290,658
Costs and expenses:
Operating costs and expenses............. 229,711 14,417 244,128
Depreciation, depletion and
amortization............................ 22,475 3,041 25,516
Selling and administrative expenses...... 11,523 494 12,017
Net gain on property and equipment
disposals............................... (308) (20) (328)
Interest expense......................... 3,856 366 4,222
Interest income.......................... (1,615) (52) (1,667)
-------- ------- --------
Income before income taxes................. 4,134 2,636 6,770
Income tax provision..................... 3,185 1,345 4,530
-------- ------- --------
Income from continuing operations.......... 949 1,291 2,240
Loss from discontinued operations, net of
income taxes............................ -- 1,764 1,764
-------- ------- --------
Net income (loss).......................... $ 949 $ (473) $ 476
======== ======= ========

F-40

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
May 20, 1998 to March 31, 1999

Parent Guarantor Non-guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------- ------------ ------------
(Dollars in thousands)

Total revenues.......... $ -- $1,829,438 $229,150 $ (1,756) $2,056,832
Costs and expenses:
Operating costs and
expenses............. -- 1,494,487 150,987 (1,756) 1,643,718
Depreciation,
depletion and
amortization......... -- 150,584 28,598 -- 179,182
Selling and
administrative
expenses............. 13,124 60,142 3,622 -- 76,888
Interest expense...... 160,068 11,292 4,745 -- 176,105
Interest income....... (5,716) (11,897) (914) -- (18,527)
--------- ---------- -------- -------- ----------
Income (loss) before
income taxes and
minority interests..... (167,476) 124,830 42,112 -- (534)
Income tax provision
(benefit)............ (36,873) 31,213 8,672 -- 3,012
Minority interests.... -- -- 1,887 -- 1,887
--------- ---------- -------- -------- ----------
Income (loss) from
continuing operations.. (130,603) 93,617 31,553 -- (5,433)
Income from
discontinued
operations, net of
income taxes......... -- -- (6,442) -- (6,442)
--------- ---------- -------- -------- ----------
Net income (loss)....... $(130,603) $ 93,617 $ 37,995 $ -- $ 1,009
========= ========== ======== ======== ==========

F-41

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended March 31, 2000

Non-
Parent Guarantor guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------ ------------
(Dollars in thousands)

Total revenues.......... $ -- $1,963,823 $777,165 $ (30,488) $2,710,500
Costs and expenses:
Operating costs and
expenses............. -- 1,651,477 557,675 (30,488) 2,178,664
Depreciation,
depletion and
amortization......... -- 180,287 69,495 -- 249,782
Selling and
administrative
expenses............. 1,251 72,093 21,912 -- 95,256
Net gain on property
and equipment
disposals............ -- (6,034) (405) -- (6,439)
Interest expense...... 174,949 73,330 21,080 (64,303) 205,056
Interest income....... (43,896) (23,933) (895) 64,303 (4,421)
--------- ---------- -------- --------- ----------
Income (loss) before
income taxes and
minority interests..... (132,304) 16,603 108,303 -- (7,398)
Income tax provision
(benefit)............ (34,804) (136,307) 29,589 -- (141,522)
Minority interests.... -- -- 15,554 -- 15,554
--------- ---------- -------- --------- ----------
Income (loss) from
continuing operations.. (97,500) 152,910 63,160 -- 118,570
Loss from discontinued
operations, net of
income taxes......... -- -- 12,087 -- 12,087
Loss from disposal of
discontinued
operations, net of
income taxes......... 783 77,490 -- -- 78,273
--------- ---------- -------- --------- ----------
Net income (loss)....... $ (98,283) $ 75,420 $ 51,073 $ -- $ 28,210
========= ========== ======== ========= ==========

F-42

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended March 31, 2001

Non-
Parent Guarantor guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
--------- ------------ ------------ ------------ ------------
(Dollars in thousands)

Total revenues.......... $ -- $1,954,866 $772,343 $(57,517) $2,669,692
Costs and expenses:
Operating costs and
expenses............. -- 1,633,271 589,336 (57,517) 2,165,090
Depreciation,
depletion and
amortization......... -- 175,162 65,806 -- 240,968
Selling and
administrative
expenses............. 4,058 77,190 18,019 -- 99,267
Gain on sale of
Australian
operations........... -- (171,735) -- -- (171,735)
Net gain on property
and equipment
disposals............ -- (4,667) (1,070) -- (5,737)
Interest expense...... 158,622 109,420 18,457 (88,813) 197,686
Interest income....... (68,655) (27,915) (984) 88,813 (8,741)
--------- ---------- -------- -------- ----------
Income (loss) before
income taxes and
minority interests..... (94,025) 164,140 82,779 -- 152,894
Income tax provision
(benefit)............ (33,608) 45,463 30,835 -- 42,690
Minority interests.... -- -- 7,524 -- 7,524
--------- ---------- -------- -------- ----------
Income (loss) from
continuing operations.. (60,417) 118,677 44,420 -- 102,680
Gain from disposal of
discontinued
operations, net of
income taxes......... (88) (12,837) -- -- (12,925)
--------- ---------- -------- -------- ----------
Income (loss) before
extraordinary item..... (60,329) 131,514 44,420 -- 115,605
Extraordinary loss
from early
extinguishment of
debt, net of income
taxes................ 8,545 -- -- -- 8,545
--------- ---------- -------- -------- ----------
Net income (loss)....... $ (68,874) $ 131,514 $ 44,420 $ -- $ 107,060
========= ========== ======== ======== ==========

F-43

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS
As of March 31, 2000

Non-
Parent Guarantor guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
---------- ------------ ------------ ------------ ------------
(Dollars in thousands)

ASSETS
Current assets
Cash and cash
equivalents.......... $ 347 $ 45,931 $ 19,340 $ -- $ 65,618
Accounts receivable... 1,605 95,055 92,083 (35,722) 153,021
Inventories........... -- 187,965 54,185 -- 242,150
Assets from coal and
emission allowance
trading activities... -- 78,695 -- -- 78,695
Deferred income
taxes................ -- 49,869 -- -- 49,869
Other current assets.. 1,282 14,351 27,559 -- 43,192
---------- ---------- ---------- ----------- ----------
Total current
assets............. 3,234 471,866 193,167 (35,722) 632,545
Property, plant,
equipment and mine
development, at
cost................. -- 4,360,648 866,132 -- 5,226,780
Less accumulated
depreciation,
depletion and
amortization......... -- (323,870) (87,400) -- (411,270)
---------- ---------- ---------- ----------- ----------
Property, plant,
equipment and mine
development, net..... -- 4,036,778 778,732 -- 4,815,510
Net assets of
discontinued
operations........... 900 89,100 -- -- 90,000
Investments and other
assets............... 1,883,781 1,444,307 208,095 (3,247,389) 288,794
---------- ---------- ---------- ----------- ----------
Total assets........ $1,887,915 $6,042,051 $1,179,994 $(3,283,111) $5,826,849
========== ========== ========== =========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Short-term borrowings
and current
maturities of
long-term debt....... $ -- $ 21,122 $ 36,855 $ -- $ 57,977
Payable to affiliates,
net.................. (284,294) 319,473 (35,179) -- --
Income taxes payable.. -- 521 13,073 -- 13,594
Liabilities from coal
and emission
allowance trading
activities........... -- 75,883 -- -- 75,883
Accounts payable and
accrued expenses..... 76,066 416,505 116,288 (35,722) 573,137
---------- ---------- ---------- ----------- ----------
Total current
liabilities........ (208,228) 833,504 131,037 (35,722) 720,591
Long-term debt, less
current maturities... 1,587,717 162,116 268,356 -- 2,018,189
Deferred income
taxes................ -- 567,918 57,206 -- 625,124
Other noncurrent
liabilities.......... -- 1,873,508 39,746 -- 1,913,254
---------- ---------- ---------- ----------- ----------
Total liabilities... 1,379,489 3,437,046 496,345 (35,722) 5,277,158
Minority interests.... -- -- 41,265 -- 41,265
Stockholders' equity.. 508,426 2,605,005 642,384 (3,247,389) 508,426
---------- ---------- ---------- ----------- ----------
Total liabilities
and stockholders'
equity............. $1,887,915 $6,042,051 $1,179,994 $(3,283,111) $5,826,849
========== ========== ========== =========== ==========

F-44

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATED BALANCE SHEETS
As of March 31, 2001

Non-
Parent Guarantor guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
---------- ------------ ------------ ------------ ------------
(Dollars in thousands)

ASSETS
Current assets
Cash and cash
equivalents.......... $ 173 $ 57,194 $ 5,356 $ -- $ 62,723
Accounts receivable... -- 122,582 105,298 (80,072) 147,808
Inventories........... -- 195,082 15,130 -- 210,212
Assets from coal and
emission allowance
trading activities... -- 172,330 -- -- 172,330
Deferred income
taxes................ -- 12,226 -- -- 12,226
Other current assets.. 4,250 12,370 8,036 -- 24,656
---------- ---------- -------- ----------- ----------
Total current
assets............. 4,423 571,784 133,820 (80,072) 629,955
Property, plant,
equipment and mine
development, at cost... -- 4,435,413 424,586 -- 4,859,999
Less accumulated
depreciation, depletion
and amortization....... -- (479,655) (57,705) -- (537,360)
---------- ---------- -------- ----------- ----------
Property, plant,
equipment and mine
development, net....... -- 3,955,758 366,881 -- 4,322,639
Investments and other
assets................. 1,251,550 1,942,193 486,473 (3,423,323) 256,893
---------- ---------- -------- ----------- ----------
Total assets........ $1,255,973 $6,469,735 $987,174 $(3,503,395) $5,209,487
========== ========== ======== =========== ==========

LIABILITIES AND STOCKHOLDERS'
EQUITY
Current liabilities
Short-term borrowings
and current
maturities of long-
term debt............ $ -- $ 20,395 $ 15,910 $ -- $ 36,305
Payable to affiliates,
net.................. (486,736) 495,111 (8,375) -- --
Income taxes payable.. -- 491 -- -- 491
Liabilities from coal
and emission
allowance trading
activities........... -- 163,713 -- -- 163,713
Accounts payable and
accrued expenses..... 88,555 520,111 47,882 (80,072) 576,476
---------- ---------- -------- ----------- ----------
Total current
liabilities........ (398,181) 1,199,821 55,417 (80,072) 776,985
Long-term debt, less
current maturities..... 1,022,916 151,319 195,081 -- 1,369,316
Deferred income taxes... -- 570,657 48 -- 570,705
Other noncurrent
liabilities............ -- 1,811,419 8,366 -- 1,819,785
---------- ---------- -------- ----------- ----------
Total liabilities... 624,735 3,733,216 258,912 (80,072) 4,536,791
Minority interests...... -- -- 41,458 -- 41,458
Stockholders' equity.... 631,238 2,736,519 686,804 (3,423,323) 631,238
---------- ---------- -------- ----------- ----------
Total liabilities
and stockholders'
equity............. $1,255,973 $6,469,735 $987,174 $(3,503,395) $5,209,487
========== ========== ======== =========== ==========

F-45

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED COMBINED STATEMENTS OF CASH FLOWS
April 1, 1998 to May 19, 1998

Predecessor Company
------------------------------------
Guarantor Non-guarantor
Subsidiaries Subsidiaries Combined
------------ ------------- ---------
(Dollars in thousands)

Net cash provided by (used in) continuing
operations.............................. $ (41,999) $ 12,138 $ (29,861)
Net cash provided by discontinued
operations.............................. -- 1,704 1,704
--------- -------- ---------
Net cash provided by (used in) operating
activities.............................. (41,999) 13,842 (28,157)
--------- -------- ---------
Additions to property, plant, equipment
and mine development.................. (13,582) (7,292) (20,874)
Additions to advance mining royalties.. (1,767) (535) (2,302)
Proceeds from coal contract
restructurings........................ 308 20 328
Proceeds from property and equipment
disposals............................. 1,374 -- 1,374
--------- -------- ---------
Net cash used in continuing investing
activities.............................. (13,667) (7,807) (21,474)
Net cash used in discontinued
operations.............................. -- (76) (76)
--------- -------- ---------
Net cash used in investing activities.... (13,667) (7,883) (21,550)
--------- -------- ---------
Proceeds from short-term borrowings and
long-term debt........................ -- 53,597 53,597
Payments of short-term borrowings and
long-term debt........................ (464) (18,959) (19,423)
Dividends paid......................... (141,000) (32,330) (173,330)
Other.................................. 141,831 (831) 141,000
--------- -------- ---------
Net cash provided by continuing financing
activities.............................. 367 1,477 1,844
Net cash provided by discontinued
operations.............................. -- 21,693 21,693
--------- -------- ---------
Net cash provided by financing
activities.............................. 367 23,170 23,537
Effect of exchange rate changes on cash
and equivalents....................... -- (292) (292)
--------- -------- ---------
Net increase (decrease) in cash and cash
equivalents............................. (55,299) 28,837 (26,462)
Cash and cash equivalents at beginning of
period.................................. 83,812 13,009 96,821
--------- -------- ---------
Cash and cash equivalents at end of
period.................................. $ 28,513 $ 41,846 $ 70,359
========= ======== =========

F-46

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
May 20, 1998 to March 31, 1999

Parent Guarantor Non-guarantor
Company Subsidiaries Subsidiaries Consolidated
----------- ------------ ------------- ------------
(Dollars in thousands)

Net cash provided by
(used in) continuing
operations.............. $ (140,674) $ 407,889 $ 63,708 $ 330,923
Net cash used in
discontinued
operations.............. -- -- (48,901) (48,901)
----------- --------- --------- -----------
Net cash provided by
(used in) operating
activities.............. (140,674) 407,889 14,807 282,022
----------- --------- --------- -----------
Additions to property,
plant, equipment and
mine development...... -- (108,186) (66,334) (174,520)
Additions to advance
mining royalties...... -- (8,836) (2,673) (11,509)
Acquisitions, net...... (1,933,178) (143,742) (33,480) (2,110,400)
Proceeds from coal
contract
restructurings........ -- 2,515 2,515
Proceeds from property
and equipment
disposals............. -- 10,494 954 11,448
----------- --------- --------- -----------
Net cash used in
continuing investing
activities.............. (1,933,178) (247,755) (101,533) (2,282,466)
Net cash provided by
discontinued
operations.............. -- -- 33,130 33,130
----------- --------- --------- -----------
Net cash used in
investing activities.... (1,933,178) (247,755) (68,403) (2,249,336)
----------- --------- --------- -----------
Proceeds from short-
term borrowings and
long-term debt........ 1,817,390 -- 53,388 1,870,778
Payments of short-term
borrowings and long-
term debt............. (158,263) (21,470) (42,982) (222,715)
Capital contribution... 480,000 -- -- 480,000
Distributions to
minority interests.... -- 9,096 (12,176) (3,080)
Other.................. (65,275) (16,899) 48,158 (34,016)
----------- --------- --------- -----------
Net cash provided by
(used in) continuing
financing activities.... 2,073,852 (29,273) 46,388 2,090,967
Net cash provided by
discontinued
operations.............. -- -- 70,314 70,314
----------- --------- --------- -----------
Net cash provided by
(used in) financing
activities.............. 2,073,852 (29,273) 116,702 2,161,281
Effect of exchange rate
changes on cash and
equivalents........... -- -- 111 111
----------- --------- --------- -----------
Net increase in cash and
cash equivalents........ -- 130,861 63,217 194,078
Cash and cash equivalents
at beginning of period.. -- -- -- --
----------- --------- --------- -----------
Cash and cash equivalents
at end of period........ $ -- $ 130,861 $ 63,217 $ 194,078
=========== ========= ========= ===========

F-47

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended March 31, 2000

Non-
Parent Guarantor guarantor
Company Subsidiaries Subsidiaries Consolidated
--------- ------------ ------------ ------------
(Dollars in thousands)

Net cash provided by (used
in) continuing operations... $ (83,810) $ 283,472 $ 103,753 $ 303,415
Net cash used in discontinued
operations.................. -- -- (40,504) (40,504)
--------- --------- --------- ---------
Net cash provided by (used
in) operating activities.... (83,810) 283,472 63,249 262,911
--------- --------- --------- ---------
Additions to property,
plant, equipment and mine
development............... -- (106,593) (72,161) (178,754)
Additions to advance mining
royalties................. -- (7,475) (17,817) (25,292)
Acquisitions, net.......... -- -- (63,265) (63,265)
Investment in joint
venture................... -- (4,325) -- (4,325)
Proceeds from coal contract
restructurings............ -- 11,904 21,000 32,904
Proceeds from property and
equipment disposals....... -- 9,637 9,647 19,284
Proceeds from sale-
leaseback transactions.... -- 34,234 -- 34,234
--------- --------- --------- ---------
Net cash used in continuing
operations.................. -- (62,618) (122,596) (185,214)
Net cash used in discontinued
operations.................. -- -- (170) (170)
--------- --------- --------- ---------
Net cash used in investing
activities.................. -- (62,618) (122,766) (185,384)
--------- --------- --------- ---------
Proceeds from short-term
borrowings and long-term
debt...................... -- -- 22,026 22,026
Payments of short-term
borrowings and long-term
debt...................... (171,088) (21,695) (17,202) (209,985)
Capital contribution
(distribution)............ -- (1,073) 1,073 --
Distributions to minority
interests................. -- -- (3,353) (3,353)
Dividends (paid) received.. 121,903 15,422 (137,325) --
Other...................... 133,342 (298,438) 165,096 --
--------- --------- --------- ---------
Net cash provided by (used
in) continuing operations... 84,157 (305,784) 30,315 (191,312)
Net cash used in discontinued
operations.................. -- -- (13,869) (13,869)
--------- --------- --------- ---------
Net cash provided by (used
in) financing activities.... 84,157 (305,784) 16,446 (205,181)
Effect of exchange rate
changes on cash and
equivalents............... -- -- (806) (806)
--------- --------- --------- ---------
Net increase (decrease) in
cash and cash equivalents... 347 (84,930) (43,877) (128,460)
Cash and cash equivalents at
beginning of year........... -- 130,861 63,217 194,078
--------- --------- --------- ---------
Cash and cash equivalents at
end of year................. $ 347 $ 45,931 $ 19,340 $ 65,618
========= ========= ========= =========

F-48

PEABODY ENERGY CORPORATION

NOTES TO FINANCIAL STATEMENTS--(Continued)

SUPPLEMENTAL CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended March 31, 2001

Non-
Parent Guarantor guarantor
Company Subsidiaries Subsidiaries Consolidated
--------- ------------ ------------ ------------
(Dollars in thousands)

Net cash provided by (used
in) operating activities.... $ (20,172) $ 113,212 $ 58,940 $ 151,980
Additions to property,
plant, equipment and mine
development............... -- (94,577) (56,781) (151,358)
Additions to advance mining
royalties................. -- (8,785) (11,475) (20,260)
Acquisitions, net.......... -- (10,502) -- (10,502)
Proceeds from sale of
Australian operations..... -- 455,000 -- 455,000
Proceeds from property and
equipment disposals....... -- 7,711 11,214 18,925
Proceeds from sale-
leaseback transactions.... -- 28,800 -- 28,800
Net cash used in assets
sold--Australian
operations................ -- -- (34,684) (34,684)
--------- --------- -------- ---------
Net cash provided by (used
in) continuing operations... -- 377,647 (91,726) 285,921
Net cash provided by
discontinued operations..... 604 101,937 -- 102,541
--------- --------- -------- ---------
Net cash provided by (used
in) investing activities.... 604 479,584 (91,726) 388,462
--------- --------- -------- ---------
Proceeds from short-term
borrowings and long-term
debt...................... -- -- 65,302 65,302
Payments of short-term
borrowings and long-term
debt...................... (565,000) (21,063) (47,842) (633,905)
Distributions to minority
interests................. -- -- (4,690) (4,690)
Dividend received.......... -- 19,916 -- 19,916
Proceeds from sale of
treasury stock............ -- 562 -- 562
Repurchase of treasury
stock..................... -- (1,113) -- (1,113)
Other...................... 584,394 (579,835) (4,559) --
Net cash provided by assets
sold--Australian
operations................ -- -- 10,591 10,591
--------- --------- -------- ---------
Net cash provided by (used
in) financing activities.... 19,394 (581,533) 18,802 (543,337)
--------- --------- -------- ---------
Net increase (decrease) in
cash and cash equivalents... (174) 11,263 (13,984) (2,895)
Cash and cash equivalents at
beginning of year........... 347 45,931 19,340 65,618
--------- --------- -------- ---------
Cash and cash equivalents at
end of year................. $ 173 $ 57,194 $ 5,356 $ 62,723
========= ========= ======== =========

F-49

[GRAPHIC]

15,000,000 Shares

[LOGO OF PEABODY ENERGY CORPORATION]

Peabody Energy Corporation

Common Stock

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

PROSPECTUS
May 21, 2001

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

Lehman Brothers

Bear, Stearns International Limited

Merrill Lynch International

Morgan Stanley Dean Witter

UBS Warburg

Cazenove & Co.