Peabody Energy 10Q 2005 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period endedJune 30, 2005

Commission File Number1-16463

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		13-4004153

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


701 Market Street, St. Louis, Missouri		63101-1826

(Address of principal executive offices)		(Zip Code)

(314) 342-3400

(Registrant’s telephone number, including area code)

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

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

Number of shares outstanding of each of the Registrant’s classes of Common Stock, as of July 31, 2005: Common Stock, par value $0.01 per share, 131,159,264 shares outstanding.

INDEX


	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Condensed Consolidated Statements of Operations for the Quarters and Six Months Ended June 30, 2005 and 2004		2

Condensed Consolidated Balance Sheets as of June 30, 2005 (unaudited) and December 31, 2004		3

Unaudited Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004		4

Notes to Unaudited Condensed Consolidated Financial Statements		5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		25

Item 3. Quantitative and Qualitative Disclosures About Market Risk		39

Item 4. Controls and Procedures		41

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		41

Item 4. Submission of Matters to a Vote of Security Holders		42

Item 6. Exhibits		42
Certificate of Amendment of 3rd Amended/Restated Certificate of Incorporation
Coal Lease
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of EVP/CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to 18 U.S.C. Section 1350
Certification of EVP/CFO Pursuant to 18 U.S.C. Section 1350

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in thousands, except share and per share data)


	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
REVENUES
Sales	$	1,089,817		$	898,582		$	2,152,338		$	1,643,033
Other revenues		18,969			18,189			33,928			46,031

Total revenues		1,108,786			916,771			2,186,266			1,689,064

COSTS AND EXPENSES
Operating costs and expenses		880,274			757,686			1,794,356			1,407,462
Depreciation, depletion and amortization		79,309			73,020			155,262			132,860
Asset retirement obligation expense		7,162			8,627			16,357			21,664
Selling and administrative expenses		40,671			32,144			78,431			59,936
Other operating income:
Net gain on disposal of assets		(16,452	)		(1,907	)		(47,574	)		(12,355	)
Income from equity affiliates		(11,487	)		(4,626	)		(20,678	)		(11,053	)


OPERATING PROFIT		129,309			51,827			210,112			90,550
Interest expense		25,205			24,595			50,761			45,923
Interest income		(1,810	)		(1,209	)		(3,183	)		(2,128	)


INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS		105,914			28,441			162,534			46,755
Income tax provision (benefit)		10,162			(15,194	)		14,586			(20,796	)
Minority interests		498			390			804			653


INCOME FROM CONTINUING OPERATIONS		95,254			43,245			147,144			66,898
Loss from discontinued operations, net of income tax benefit of $1,177 and $1,892, respectively		—			(1,764	)		—			(2,837	)


NET INCOME	$	95,254		$	41,481		$	147,144		$	64,061


BASIC EARNINGS PER SHARE
Income from continuing operations	$	0.73		$	0.34		$	1.13		$	0.56
Loss from discontinued operations		—			(0.02	)		—			(0.03	)

Net income	$	0.73		$	0.32		$	1.13		$	0.53

WEIGHTED AVERAGE SHARES OUTSTANDING — BASIC		130,815,073			127,927,900			130,582,209			119,752,076


DILUTED EARNINGS PER SHARE
Income from continuing operations	$	0.71		$	0.33		$	1.10		$	0.55
Loss from discontinued operations		—			(0.01	)		—			(0.03	)

Net income	$	0.71		$	0.32		$	1.10		$	0.52

WEIGHTED AVERAGE SHARES OUTSTANDING — DILUTED		133,810,208			130,876,522			133,683,624			122,622,612

DIVIDENDS DECLARED PER SHARE	$	0.075		$	0.0625		$	0.15		$	0.125

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in thousands, except share and per share data)


	(Unaudited)
	June 30, 2005			December 31, 2004
ASSETS
Current assets
Cash and cash equivalents	$	459,367		$	389,636
Accounts receivable, less allowance for doubtful accounts of $19,781 at June 30, 2005 and $1,361 at December 31, 2004		204,419			193,784
Inventories		363,561			323,609
Assets from coal trading activities		52,834			89,165
Deferred income taxes		15,050			15,461
Other current assets		57,991			42,947

Total current assets		1,153,222			1,054,602
Property, plant, equipment and mine development, net of accumulated depreciation, depletion and amortization of $1,474,006 at June 30, 2005 and $1,333,645 at December 31, 2004		4,883,277			4,781,431
Investments and other assets		368,162			342,559

Total assets	$	6,404,661		$	6,178,592

						��
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	21,861		$	18,979
Liabilities from coal trading activities		34,812			63,565
Accounts payable and accrued expenses		748,514			691,600

Total current liabilities		805,187			774,144
Long-term debt, less current maturities		1,393,049			1,405,986
Deferred income taxes		400,991			393,266
Asset retirement obligations		402,071			396,022
Workers’ compensation obligations		230,044			227,476
Accrued postretirement benefit costs		942,201			939,503
Other noncurrent liabilities		326,597			315,694

Total liabilities		4,500,140			4,452,091
Minority interests		1,713			1,909
Stockholders’ equity
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of June 30, 2005 or December 31, 2004		—			—
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of June 30, 2005 or December 31, 2004		—			—
Common Stock — $0.01 per share par value; 400,000,000 shares authorized, 131,201,979 shares issued and 130,940,799 shares outstanding as of June 30, 2005 and 150,000,000 shares authorized, 129,829,134 shares issued and 129,567,954 shares outstanding as of December 31, 2004		1,312			1,298
Additional paid-in capital		1,474,590			1,437,319
Retained earnings		478,533			350,968
Unearned restricted stock awards		(6,703	)		(459	)
Accumulated other comprehensive loss		(41,008	)		(60,618	)
Treasury shares, at cost: 261,180 shares as of June 30, 2005 and December 31, 2004		(3,916	)		(3,916	)

Total stockholders’ equity		1,902,808			1,724,592

Total liabilities and stockholders’ equity	$	6,404,661		$	6,178,592

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in thousands)


	Six Months Ended
	June 30,
	2005			2004
Cash Flows from Operating Activities
Net income	$	147,144		$	64,061
Loss from discontinued operations		—			2,837

Income from continuing operations		147,144			66,898
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization		155,262			132,860
Deferred income taxes		11,699			(27,185	)
Amortization of debt discount and debt issuance costs		3,465			3,970
Net gain on disposal of assets		(47,574	)		(12,355	)
Income from equity affiliates		(20,678	)		(11,053	)
Dividends received from equity investments		5,095			1,860
Changes in current assets and liabilities:
Accounts receivable, net of sale		(35,635	)		(45,760	)
Inventories		(40,334	)		(36,950	)
Net assets from coal trading activities		7,578			(2,185	)
Other current assets		(2,811	)		2,634
Accounts payable and accrued expenses		57,787			67,708
Asset retirement obligations		(719	)		(2,423	)
Workers’ compensation obligations		3,860			4,957
Accrued postretirement benefit costs		2,698			(11,612	)
Contributions to pension plans		(2,389	)		(52,484	)
Other, net		9,146			3,154

Net cash provided by operating activities		253,594			82,034

Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development		(187,650	)		(115,858	)
Purchase of mining assets		(56,500	)		—
Additions to advance mining royalties		(6,247	)		(9,677	)
Acquisitions, net		—			(422,164	)
Proceeds from disposal of assets		60,231			22,803

Net cash used in investing activities		(190,166	)		(524,896	)

Cash Flows from Financing Activities
Proceeds from long-term debt		—			250,000
Payments of long-term debt		(14,085	)		(16,697	)
Net proceeds from equity offering		—			383,125
Proceeds from stock options exercised		14,617			11,601
Proceeds from employee stock purchases		1,350			1,139
Increase of securitized interests in accounts receivable		25,000			50,000
Payment of debt issuance costs		—			(8,910	)
Distributions to minority interests		(1,000	)		(694	)
Dividends paid		(19,579	)		(14,852	)

Net cash provided by financing activities		6,303			654,712

Net increase in cash and cash equivalents		69,731			211,850
Cash and cash equivalents at beginning of period		389,636			117,502

Cash and cash equivalents at end of period	$	459,367		$	329,352

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2005

(1) Basis of Presentation

The consolidated financial statements include the accounts of the Company and its controlled affiliates. All intercompany transactions, profits and balances have been eliminated in consolidation.

Effective March 30, 2005, the Company implemented a two-for-one stock split on all shares of its common stock. All share and per share amounts in these condensed consolidated financial statements and related notes reflect the stock split.

The accompanying condensed consolidated financial statements as of June 30, 2005 and for the quarters and six months ended June 30, 2005 and 2004, and the notes thereto, are unaudited. However, in the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation of the results of the periods presented. The balance sheet information as of December 31, 2004 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the quarter and six months ended June 30, 2005 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2005.

(2) New Pronouncements

At the March 17, 2005 Emerging Issues Task Force (“EITF”) meeting, the Task Force reached a consensus in EITF Issue 04-6 “that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred.” Advance stripping costs include those costs necessary to remove overburden above an unmined coal seam as part of the surface mining process, and are included as the “work-in-process” component of “Inventories” in the consolidated balance sheets ($224.1 million and $197.2 million as of June 30, 2005 and December 31, 2004, respectively - see Note 6). This is consistent with the concepts embodied in Accounting Research Bulletin No. 43, “Restatement and Revision of Accounting Research Bulletins,” which provides that “the term inventory embraces goods awaiting sale . . . , goods in the course of production (work in process), and goods to be consumed directly or indirectly in production . . . .” At the June 15-16, 2005 EITF meeting, the Task Force clarified that the intended meaning of “inventory produced” is “inventory extracted.” Based on this clarification, stripping costs incurred during a period will be attributed only to the inventory costs of the coal that is extracted during that same period.

EITF Issue 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006 for the Company), with early adoption permitted. At the June EITF meeting, the Task Force modified the transition provisions of EITF Issue 04-6, indicating that companies that adopt the consensus in periods beginning after June 29, 2005 may utilize a cumulative effect adjustment approach where the cumulative effect adjustment is recorded directly to retained earnings in the year of adoption. Alternatively, a company may recognize this change in accounting by restatement of its prior-period financial statements through retrospective application of this consensus. The Company is currently evaluating which method of adoption it will use. The Company expects to adopt this consensus on January 1, 2006.

The Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations” in March of 2005. FIN 47 clarifies that an entity must record a liability for a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. This interpretation also clarifies the circumstances under which an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The Company expects to adopt this interpretation on December 31, 2005. The adoption of this interpretation will not have a material impact on the Company’s financial condition, results of operations or cash flows.

The Securities and Exchange Commission has deferred the adoption date of Statement of Financial Accounting Standard (“SFAS”) No. 123R, “Share-Based Payment,” to the beginning of fiscal years that begin after June 15, 2005 (January 1, 2006 for calendar year companies). SFAS No. 123R requires the recognition of share-based payments, including employee stock options, in the income statement based on their fair values. The Company expects to adopt this standard on January 1, 2006. Based on stock option grants made in 2005 and currently anticipated for 2006, the Company estimates it will (assuming the modified prospective method is used) recognize stock option expense for the year ending December 31, 2006 of $3.9 million, net of taxes. The Company began utilizing restricted stock as part of its equity-based compensation

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

strategy in January 2005. Based on the restricted stock grants made in 2005 and years prior, and those currently anticipated for 2006, the Company estimates it will recognize expense related to restricted stock of $1.0 million, net of taxes, in 2005 and $1.9 million, net of taxes, in 2006. The Company recognized expense for the six months ended June 30 2005 of $0.5 million, net of taxes, for restricted stock grants made in 2005 and years prior.

(3) Significant Transactions and Events

Gains on Disposal of Assets

In June 2005, the Company recognized an aggregate $12.5 million gain from three property sales involving non-strategic coal assets and properties. As a result of the property transactions, asset retirement obligations were reduced by $9.2 million.

In March 2005, the Company sold its remaining 0.838 million PVR units for net proceeds of $41.9 million and recognized a $31.1 million gain on the sale. In the first quarter of 2004, the Company sold 0.575 million PVR units for net proceeds of $18.5 million and recognized a $9.9 million gain on the sale. The sales of the PVR units were accounted for under SFAS No. 66, “Sales of Real Estate.” In December 2002, the Company entered into a transaction with Penn Virginia Resource Partners, L.P. (“PVR”) whereby the Company sold 120 million tons of coal reserves in exchange for $72.5 million in cash and 2.76 million units, or 15%, of the PVR master limited partnership. The Company’s subsidiaries leased back the coal and pay royalties as the coal is mined. No gain or loss was recorded at the inception of this transaction. As of March 2005 (the time of the final sale of units), a deferred gain from the sales of the reserves and units of $19.0 million remained and will be amortized over the minimum term of the leases.

Contract Losses

The Company recorded contract losses of approximately $34 million in the quarter ended March 31, 2005, primarily related to the breach of a coal supply contract by a producer. The estimated loss related to the supply contract breach reflected amounts accrued for estimated costs to obtain replacement coal in the current market, and no offsetting receivable from the producer who breached the contract was assumed. The loss recorded is not equivalent to, nor indicative of, the economic losses (i.e. legal damages) sought by the Company as a result of the breach.

During the second quarter of 2005, the Company reduced its estimated loss related to the supply contract breach by approximately $12.5 million, primarily as a result of negotiating a settlement late in the second quarter with the producer who breached the contract. The settlement mitigates the loss recognized in the first quarter and enables the Company to secure replacement coal at prices lower than originally anticipated. See Note 12 for more details on the breach of contract, subsequent lawsuit and the negotiated settlement.

(4) Acquisition of Mining Assets

In March 2005, the Company purchased mining assets from Lexington Coal Company for $61.0 million, $59.0 million of which was paid on the closing date and up to $2.0 million is to be paid within 12 months of the close pending no outstanding claims related to the acquired mining assets. The purchased assets included $2.5 million of materials and supplies that were recorded in “Inventories” in the condensed consolidated balance sheet. The remaining purchased assets consisted of approximately 70 million tons of reserves, preparation plants, facilities and mining equipment that were recorded in “Property, plant, equipment and mine development” in the condensed consolidated balance sheet. The Company is using the acquired assets to open a new mine that is expected to produce two to three million tons per year, after it reaches full capacity, and to provide other synergies to existing properties. The new mine, which began production early in the third quarter, will supply coal under a new agreement with Northern Indiana Public Service Company with terms that can be extended through 2015 (and a minimum term through the end of 2008). The Company also recorded $21.6 million for preliminary estimates of asset retirement obligations associated with the acquired assets.

(5) Business Combinations

On April 15, 2004, the Company purchased, through two separate agreements, all of the equity interests in three coal operations from RAG Coal International AG. The combined purchase price, including related costs and fees, of $442.2 million was funded from the Company’s equity and debt offerings in March 2004. Net proceeds from the equity and debt offerings were $383.1 million and $244.7 million, respectively. The purchases included two mines in Queensland, Australia that collectively produce 7 to 8 million tons per year of metallurgical coal and the Twentymile Mine in Colorado, which produces 7 to 8 million tons per year of steam coal with a planned production expansion up to 12 million tons per year by

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

2008. The results of operations of the two mines in Queensland, Australia are included in the Company’s Australian Mining Operations segment and the results of operations of the Twentymile Mine are included in the Company’s Western U.S. Mining Operations segment. The acquisition was accounted for as a purchase.

The purchase accounting allocations related to the acquisition have been finalized and recorded in the accompanying consolidated financial statements as of, and for periods subsequent to, April 15, 2004. The following table summarizes the fair values of the assets acquired and the liabilities assumed at the date of acquisition (dollars in thousands):


Accounts receivable	$	46,639
Materials and supplies		5,669
Coal inventory		11,543
Other current assets		6,234
Property, plant, equipment and mine development		463,567
Accounts payable and accrued expenses		(48,688	)
Other noncurrent assets and liabilities, net		(63,699	)

Total purchase price, net of cash received of $20,914	$	421,265

The following unaudited pro forma financial information presents the combined results of operations of the Company and the operations acquired from RAG Coal International AG, on a pro forma basis, as though the companies had been combined as of the beginning of the period presented. The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and the operations acquired from RAG Coal International AG constituted a single entity during this period (dollars in thousands, except per share data):


	Quarter Ended		Six Months Ended
	June 30, 2004		June 30, 2004 *
Revenues:
As reported	$	916,771	$	1,689,064
Pro forma		942,008		1,814,426

Income from continuing operations
As reported	$	43,245	$	66,898
Pro forma		44,757		64,257

Net income
As reported	$	41,481	$	64,061
Pro forma		42,993		61,420

Basic earnings per share — net income:
As reported	$	0.32	$	0.53
Pro forma		0.34		0.48

Diluted earnings per share — net income:
As reported	$	0.32	$	0.52
Pro forma		0.33		0.47



*		During the first quarter of 2004, prior to the Company’s acquisition, the Australian underground mine acquired by the Company in April 2004 experienced a roof collapse on a portion of the active mine face, resulting in the temporary suspension of mining activities. Due to the inability to ship during a portion of this downtime, costs to return the mine to operations and shipping limits imposed as the result of unrelated restrictions of capacity at a third party loading facility, the Australian operation experienced a pro forma net loss in the quarter immediately prior to acquisition.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(6) Inventories

Inventories consisted of the following (dollars in thousands):


	June 30,		December 31,
	2005		2004
Materials and supplies	$	62,883	$	57,467
Raw coal		15,510		17,590
Advance stripping		224,069		197,225
Saleable coal		61,099		51,327

Total	$	363,561	$	323,609

(7) Assets and Liabilities from Coal Trading Activities

The Company’s coal trading portfolio consisted of forward and swap contracts as of June 30, 2005 and December 31, 2004. The fair value of coal trading derivatives and related hedge contracts as of June 30, 2005 and December 31, 2004 is set forth below (dollars in thousands):


	June 30, 2005				December 31, 2004
	Assets		Liabilities		Assets		Liabilities

Forward contracts	$	52,834	$	34,136	$	89,042	$	60,914
Other		—		676		123		2,651

Total	$	52,834	$	34,812	$	89,165	$	63,565

Ninety-nine percent of the contracts in the Company’s trading portfolio as of June 30, 2005 were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials, and 1% of the Company’s contracts were valued based on similar market transactions.

As of June 30, 2005, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2005		91	%
2006		6	%
2007		1	%
2008		2	%

		100	%

At June 30, 2005, 70% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties. The Company’s coal trading operations traded 8.5 million tons and 8.3 million tons for the quarters ended June 30, 2005 and 2004, respectively, and 17.7 million tons and 18.3 million tons for the six months ended June 30, 2005 and 2004, respectively.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(8) Earnings Per Share and Stockholders’ Equity

Weighted Average Shares Outstanding

A reconciliation of weighted average shares outstanding follows:


	Quarter Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Weighted average shares outstanding — basic		130,815,073		127,927,900		130,582,209		119,752,076
Dilutive impact of stock options		2,995,135		2,948,622		3,101,415		2,870,536

Weighted average shares outstanding — diluted		133,810,208		130,876,522		133,683,624		122,622,612

Stock Compensation

These interim financial statements include the disclosure requirements of SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure.” The Company applies Accounting Principles Board (“APB”) Opinion No. 25 and related interpretations in accounting for its equity incentive plans. The Company recorded in “Selling and administrative expenses” in the condensed consolidated statements of operations $0.4 million and $0.1 million of compensation expense for equity-based compensation during each of the quarters ended June 30, 2005 and 2004, respectively, and $0.8 million and $0.1 million in the six months ended June 30, 2005 and 2004, respectively. The following table reflects pro forma net income and basic and diluted earnings per share as if compensation cost had been determined for the Company’s non-qualified and incentive stock options based on the fair value at the grant dates consistent with the methodology set forth under SFAS No. 123 (dollars in thousands, except per share data):


	Quarter Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Net income:
As reported	$	95,254	$	41,481	$	147,144	$	64,061
Pro forma		93,962		39,786		144,534		60,617

Basic earnings per share:
As reported	$	0.73	$	0.32	$	1.13	$	0.53
Pro forma		0.72		0.31		1.11		0.51

Diluted earnings per share:
As reported	$	0.71	$	0.32	$	1.10	$	0.52
Pro forma		0.70		0.30		1.08		0.49

(9) Comprehensive Income

The following table sets forth the after-tax components of comprehensive income for the quarters and six months ended June 30, 2005 and 2004 (dollars in thousands):


	Quarter Ended					Six Months Ended
	June 30,					June 30,
	2005			2004		2005		2004
Net income	$	95,254		$	41,481	$	147,144	$	64,061
Increase (decrease) in fair value of cash flow hedges, net of tax of ($6,755) and $7,558 for the quarters ended June 30, 2005 and 2004, respectively, and $13,073 and $6,093 for the six months ended June 30, 2005 and 2004, respectively		(10,133	)		11,338		19,610		9,139

Comprehensive income	$	85,121		$	52,819	$	166,754	$	73,200

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Other comprehensive income differs from net income by the amount of unrealized gain or loss resulting from valuation changes of the Company’s cash flow hedges (which include fuel hedges, foreign exchange hedges and interest rate swaps) during the period. Changes in interest rates, crude and heating oil prices, and the U.S. dollar/Australian dollar exchange rate affect the valuation of these instruments.

(10) Pension and Postretirement Benefit Costs

Components of Net Periodic Pension Costs

Net periodic pension costs included the following components (dollars in thousands):


	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Service cost for benefits earned	$	2,963		$	3,055		$	5,926		$	5,928
Interest cost on projected benefit obligation		11,373			10,738			22,746			21,337
Expected return on plan assets		(13,203	)		(12,958	)		(26,406	)		(24,323	)
Amortization of prior service cost		(4	)		64			(8	)		128
Amortization of net loss		5,948			5,401			12,294			11,030

Net periodic pension costs		7,077			6,300			14,552			14,100
Curtailment charges		—			—			9,527			—

Total pension costs	$	7,077		$	6,300		$	24,079		$	14,100

Curtailment

The curtailment loss resulted from the planned closure during 2005 of two of the Company’s three operating mines that participate in the Western Surface UMWA Pension Plan (the “Plan”). The loss is actuarially determined and consists of an increase in the actuarial liability, the accelerated recognition of previously unamortized prior service cost and contractual termination benefits under the Plan resulting from the closures.

Contributions

The Company previously disclosed in its financial statements for the year ended December 31, 2004 that it expected to contribute $4.6 million to its funded pension plans and make $1.2 million in expected benefit payments attributable to its unfunded pension plans during 2005. As of June 30, 2005, $1.8 million of contributions have been made to the funded pension plans and $0.5 million of expected benefit payments attributable to the unfunded pension plans have been made. The Company presently anticipates it will contribute $5.1 million in total to its funded pension plans during 2005.

Components of Net Periodic Postretirement Benefits Costs

Net periodic postretirement benefits costs included the following components (dollars in thousands):


	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Service cost for benefits earned	$	1,325		$	1,180		$	2,649		$	2,400
Interest cost on accumulated postretirement benefit obligation		18,175			15,797			36,351			31,591
Amortization of prior service cost		(1,325	)		(3,308	)		(2,649	)		(6,615	)
Amortization of actuarial losses		6,575			1,063			13,150			1,837

Net periodic postretirement benefit costs	$	24,750		$	14,732		$	49,501		$	29,213

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Cash Flows

The Company previously disclosed in its financial statements for the year ended December 31, 2004 that it expected to pay $85.7 million attributable to its postretirement benefit plans during 2005. As of June 30, 2005, payments of $42.4 million attributable to the Company’s postretirement benefit plans have been made.

(11) Segment Information

The Company reports its operations primarily through the following reportable operating segments: “Western U.S. Mining,” “Eastern U.S. Mining,” “Australian Mining” and “Trading and Brokerage.” The principal business of the Western U.S. Mining, Eastern U.S. Mining and Australian Mining segments is the mining, preparation and sale of steam coal, sold primarily to electric utilities, and metallurgical coal, sold to steel and coke producers. Western U.S. Mining operations are characterized by predominantly surface mining extraction processes, lower sulfur content and Btu of coal, and longer shipping distances from the mine to the customer. Conversely, Eastern U.S. Mining operations are characterized by a majority of underground mining extraction processes, higher sulfur content and Btu of coal, and shorter shipping distances from the mine to the customer. Geologically, Western operations mine primarily subbituminous and Eastern operations mine bituminous coal deposits. Australian Mining operations are characterized by surface and underground extraction processes, mining low sulfur, high Btu coal sold to an international customer base. The Trading and Brokerage segment’s principal business is the marketing, brokerage and trading of coal. “Corporate and Other” includes selling and administrative expenses, net gains on property disposals, costs associated with past mining obligations, joint venture earnings related to the Company’s 25.5% investment in a Venezuelan mine and revenues and expenses related to the Company’s other commercial activities such as coalbed methane, generation development and resource management.

Operating segment results for the quarters and six months ended June 30, 2005 and 2004 are as follows (dollars in thousands):


	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Revenues:
Western U.S. Mining⁽¹⁾	$	376,796		$	344,003		$	781,231		$	648,031
Eastern U.S. Mining		437,763			365,074			862,655			712,231
Australian Mining		140,643			72,813			244,168			81,438
Trading and Brokerage		149,293			132,255			290,862			241,384
Corporate and Other		4,291			2,626			7,350			5,980

Total	$	1,108,786		$	916,771		$	2,186,266		$	1,689,064


Adjusted EBITDA⁽²⁾:
Western U.S. Mining⁽¹⁾	$	105,639		$	100,389		$	226,064		$	183,757
Eastern U.S. Mining		95,898			66,007			190,704			127,421
Australian Mining		47,479			11,948			61,565			12,878
Trading and Brokerage⁽³⁾		15,439			6,443			(6,429	)		20,675
Corporate and Other⁽⁴⁾		(48,675	)		(51,313	)		(90,173	)		(99,657	)

Total	$	215,780		$	133,474		$	381,731		$	245,074



⁽¹⁾		Western U.S. Mining results include a charge related to the reserves established for disputed legal fees billed to customers as discussed in Note 12.

⁽²⁾		Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization.

⁽³⁾		Trading and Brokerage results include a benefit for the quarter and a charge for the six months ended June 30, 2005 related to contract losses and a settlement agreement as discussed in Note 3.

⁽⁴⁾		Corporate and Other results include the gains on the sales of PVR units discussed in Note 3.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

A reconciliation of adjusted EBITDA to consolidated income before income taxes follows (dollars in thousands):


	Quarter Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004

Total adjusted EBITDA	$	215,780		$	133,474		$	381,731		$	245,074

Depreciation, depletion and amortization		79,309			73,020			155,262			132,860

Asset retirement obligation expense		7,162			8,627			16,357			21,664

Interest expense		25,205			24,595			50,761			45,923

Interest income		(1,810	)		(1,209	)		(3,183	)		(2,128	)

Minority interests		498			390			804			653


Income before income taxes	$	105,416		$	28,051		$	161,730		$	46,102

(12) Commitments and Contingencies

Massey Coal Supply Agreement

On March 9, 2005, the Company’s subsidiary, COALTRADE, LLC (“COALTRADE”), filed a lawsuit against Massey Coal Sales Company, Inc. (“Massey”) in the U.S. District Court for the Eastern District of Kentucky. The lawsuit sought to enforce COALTRADE’s contractual rights under a three-year coal supply agreement entered into by the parties effective January 1, 2003, and to recover damages caused by Massey’s repudiation and material breach of that agreement. On April 8, 2005, COALTRADE cancelled the coal supply agreement based upon Massey’s continuing refusal to deliver coal in accordance with its terms, and filed an amended complaint seeking recovery of damages for breach of contract and breach of duty of good faith and fair dealing. On April 18, 2005, Massey filed a counterclaim. The Company believes it has a significant contractual and factual basis for its claim.

During the quarter ended June 30, 2005, the Company worked to mitigate damages resulting from the breach, and negotiated a settlement with Massey. The Company and Massey signed a settlement agreement and mutual release, and the lawsuit has been stayed pending expected completion during the third quarter of 2005 of the transactions contemplated by the settlement. See Note 3 for more details on the negotiated settlement.

Environmental

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.

Environmental claims have been asserted against a subsidiary of the Company, Gold Fields Mining, LLC (“Gold Fields”), at 22 sites in the United States and remediation has been completed or substantially completed at four of those sites. Gold Fields is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, a predecessor owner of the Company. In the February 1997 spin-off of its energy businesses, Hanson PLC transferred ownership of Gold Fields to the Company, despite the fact that Gold Fields had no ongoing operations and the Company had no prior involvement in its past operations. These sites are related to activities of Gold Fields or its former subsidiaries. Some of these claims are based on the Comprehensive Environmental Response Compensation and Liability Act of 1980 (“CERCLA”), as amended, and on similar state statutes.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

The Company’s policy is to accrue environmental cleanup-related costs of a non-capital 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 the estimation of liabilities recorded on its consolidated balance sheets. Undiscounted liabilities for environmental cleanup-related costs totaled $40.0 million at June 30, 2005 and $40.5 million at December 31, 2004, $14.5 million and $15.1 million of which was a current liability, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable. Significant uncertainty exists as to whether 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. The Company anticipates that all significant remaining environmental remediation costs discussed above will be paid by the end of 2009.

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 the Company, and sites to which it has sent waste materials, may be subject to liability under Superfund and similar state laws.

Navajo Nation

On June 18, 1999, the Navajo Nation served the Company’s subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and Peabody Western Coal Company (“Peabody Western”), with a complaint that had been filed in the U.S. District Court for the District of Columbia. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act (“RICO”) violations and fraud and tortious interference with contractual relationships. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. Plaintiff also alleges that defendants interfered with the fiduciary relationship between the United States and the Navajo Nation. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases for the Kayenta and Black Mesa mines have terminated due to Peabody Western’s breach of these leases and a reformation of the two coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted seven claims including fraud and is seeking various remedies including unspecified actual damages, punitive damages and reformation of its coal lease.

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

On February 9, 2005, the U.S. District Court for the District of Columbia granted a consent motion to stay the litigation until further order of the court. Peabody Western, the Navajo Nation, the Hopi Tribe and the customers purchasing coal from the Black Mesa and Kayenta mines are in mediation with respect to this litigation and other business issues.

The outcome of litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any potential loss cannot be estimated. However, the Company believes this matter is likely to be resolved without a material adverse effect on the Company’s financial condition, results of operations or cash flows.

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

Salt River Project 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 the Company’s subsidiary, Peabody Western, under the terms of a coal supply agreement dated February 18, 1977. The contract expires in 2011.

Peabody Western filed a motion to compel arbitration of these claims, which was granted in part by the trial court. Specifically, the trial court ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. This ruling was subsequently upheld on appeal. As a result, Peabody Western,

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Salt River Project 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. The Company has recorded a receivable for mine decommissioning costs of $70.8 million and $68.6 million included in “Investments and other assets” in the condensed consolidated balance sheets at June 30, 2005 and December 31, 2004, respectively.

The outcome of litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any potential loss cannot be estimated. However, the Company believes this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

California Public Utilities Commission Proceedings Regarding the Future of the Mohave Generating Station

Peabody Western has a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to the operation of the Mohave plant beyond 2005 or a temporary or permanent shutdown of the plant. Southern California Edison has stated to the Commission that the Mohave plant is not likely to return to service as a coal-fueled resource until 2010 at the earliest if the plant is shut down at December 31, 2005. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline from Peabody Western’s Black Mesa Mine to the Mohave plant. As a part of the alternate dispute resolution referenced in the Navajo Nation litigation, Peabody Western has been participating in mediation with the owners of the Mohave Generating Station and the Navajo Generating Station, and the two tribes to resolve the complex issues surrounding the groundwater dispute and other disputes involving the two generating stations. Resolution of these issues is critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. The owners of the Mohave Generating Station entered into a consent decree with the Grand Canyon Trust, the Sierra Club, and the National Parks and Conservation Association that required the owners to install scrubbers by December 31, 2005 if the Mohave plant was to operate beyond that date. In a letter dated May 25, 2005, the Grand Canyon Trust, the Sierra Club, and the National Parks and Conservation Association rejected a request by the Navajo Nation and the Hopi Tribe to extend the December 31, 2005 deadline and therefore, the Company believes it is likely that the operation of the Mohave plant will cease or be suspended on December 31, 2005. In the event the Mohave plant shuts down, the operations of the Black Mesa Mine could be adversely impacted starting in the third quarter of 2005, and the mine would be shut down at the end of 2005. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 2.4 million tons of coal in the first six months of 2005 and 4.7 million tons during the year ended December 31, 2004. During the first six months of 2005, the mine generated $11.9 million of Adjusted EBITDA (reconciled to its most comparable measure under generally accepted accounting principles in Note 11), which represented 3.1% of the Company’s total of $381.7 million. In 2004, the mine contributed $25.2 million of Adjusted EBITDA, or 4.5% of the Company’s total Adjusted EBITDA of $559.2 million.

Oklahoma Lead Litigation

Gold Fields, which is a defendant in various litigation discussed below, is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, a predecessor owner of the Company. In the February 1997 spin-off of its energy businesses, Hanson PLC transferred ownership of Gold Fields to the Company, despite the fact that Gold Fields had no ongoing operations and the Company had no prior involvement in its past operations.

Gold Fields and three other companies are defendants in two class action lawsuits filed in the U.S. District Court for the Northern District of Oklahoma (Betty Jean Cole, et al. v. Asarco Inc., et al. and Darlene Evans, et al. v. Asarco Inc., et al.). The plaintiffs have asserted nuisance and trespass claims predicated on allegations of intentional lead exposure by the defendants and are seeking compensatory damages for diminution of property value, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950’s and mined, in accordance with lease agreements and permits, approximately 1.7% of the total amount of the ore mined in the county. Gold Fields has agreed to indemnify one of the other defendants, which is a former subsidiary of Gold Fields.

Gold Fields is also a defendant, along with other companies, in five individual lawsuits arising out of the same lead mill operations. In July 2004, two lawsuits were filed, one in the U.S. District Court for the Northern District of Oklahoma and one in Ottawa County, Oklahoma (subsequently removed to the U.S. District Court for the Northern District of Oklahoma), on behalf of 48 individuals against Gold Fields and three other companies (Billy Holder, et al. v. Asarco Inc., et al.). Plaintiffs in these actions are seeking compensatory and punitive damages for alleged personal injuries from lead exposure. The trials for five of the individual plaintiffs have been set for November 2005. A second trial for seven individuals has been set for January 2006.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

In December 2003, the Quapaw Indian tribe and certain Quapaw owners of interests in land filed a class action lawsuit against Gold Fields and five other companies in the U.S. District Court for the Northern District of Oklahoma. The plaintiffs are seeking compensatory and punitive damages based on public and private nuisance, trespass, strict liability, natural resource damage claims under CERCLA, and claims under the Resource Conservation and Recovery Act. Gold Fields has denied liability to the plaintiffs, has filed counterclaims against the plaintiffs seeking indemnification and contribution and has filed a third-party complaint against the United States, owners of interests in chat and real property in the Picher area. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other potentially responsible parties (“PRPs”) alleging that they had concluded that there is a reasonable probability of making a successful claim against the PRPs for damages to natural resources.

Other

In addition to the matters described above, the Company at times becomes a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. Management believes that the ultimate resolution of pending or threatened proceedings is not likely to have a material adverse effect on the financial condition, results of operations or cash flows of the Company.

Accounts receivable in the condensed consolidated balance sheets as of June 30, 2005 and December 31, 2004, includes $19.4 and $18.1 million, respectively, of receivables billed between 2001 and 2005 related to legal fees incurred in the Company’s defense of the Navajo lawsuit discussed above. The billings have been disputed by two customers, who have withheld payment. The Company believes these billings were made properly under the coal supply agreement with each customer. The billings were consistent with past practice, when litigation costs related to legal or regulatory issues were billed under the contracts and paid by the customers. The Company is in litigation with these customers to resolve this issue. In the second quarter of 2005, the trial court in one of the cases dismissed the Company’s claim, and the Company will appeal that decision. Although the Company believes it has meritorious grounds for appeal and has not yet litigated the other claim, the Company has recognized an allowance against both disputed receivables, which resulted in a charge of $13.4 million and $16.2 million in the quarter and six months ended June 30, 2005, respectively. The receivable balance, net of the allowance, was zero and $18.1 million at June 30, 2005 and December 31, 2004, respectively.

At June 30, 2005, purchase commitments for capital expenditures were approximately $204.8 million.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(13) Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the 6.875% Senior Notes due 2013 and the 5.875% Senior Notes due 2016, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed the 6.875% Senior Notes and the 5.875% Senior 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 the holders of the 6.875% Senior Notes and the 5.875% Senior Notes. The following unaudited condensed historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.

Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)


	Quarter Ended June 30, 2005
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	865,475		$	264,750		$	(21,439	)	$	1,108,786
Costs and expenses:
Operating costs and expenses		(4,508	)		692,203			214,018			(21,439	)		880,274
Depreciation, depletion and amortization		—			70,429			8,880			—			79,309
Asset retirement obligation expense		—			6,441			721			—			7,162
Selling and administrative expenses		952			37,571			2,148			—			40,671
Other operating income:
Net gain on disposal of assets		—			(16,347	)		(105	)		—			(16,452	)
Income from equity affiliates		—			(11,487	)		—			—			(11,487	)
Interest expense		38,328			7,523			5,032			(25,678	)		25,205
Interest income		(5,172	)		(16,030	)		(6,286	)		25,678			(1,810	)

Income (loss) before income taxes and minority interests		(29,600	)		95,172			40,342			—			105,914
Income tax provision (benefit)		(18,106	)		19,858			8,410			—			10,162
Minority interests		—			498			—			—			498

Net income (loss)	$	(11,494	)	$	74,816		$	31,932		$	—		$	95,254

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)


	Quarter Ended June 30, 2004
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	781,274		$	153,204		$	(17,707	)	$	916,771
Costs and expenses:
Operating costs and expenses		(161	)		636,925			138,629			(17,707	)		757,686
Depreciation, depletion and amortization		—			67,780			5,240			—			73,020
Asset retirement obligation expense		—			8,158			469			—			8,627
Selling and administrative expenses		234			31,013			897			—			32,144
Other operating income:
Net gain on disposal of assets		—			(1,877	)		(30	)		—			(1,907	)
Income from equity affiliates		—			(4,626	)		—			—			(4,626	)
Interest expense		38,435			33,835			648			(48,323	)		24,595
Interest income		(21,691	)		(23,441	)		(4,400	)		48,323			(1,209	)

Income (loss) before income taxes and minority interests		(16,817	)		33,507			11,751			—			28,441
Income tax provision (benefit)		(16,359	)		915			250			—			(15,194	)
Minority interests		—			390			—			—			390

Income (loss) from continuing operations		(458	)		32,202			11,501			—			43,245
Loss from discontinued operations, net of taxes		—			(1,764	)		—			—			(1,764	)

Net income (loss)	$	(458	)	$	30,438		$	11,501		$	—		$	41,481

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)


	Six Months Ended June 30, 2005
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	1,764,323		$	462,570		$	(40,627	)	$	2,186,266
Costs and expenses:
Operating costs and expenses		(7,391	)		1,448,708			393,666			(40,627	)		1,794,356
Depreciation, depletion and amortization		—			139,386			15,876			—			155,262
Asset retirement obligation expense		—			15,202			1,155			—			16,357
Selling and administrative expenses		1,548			74,424			2,459			—			78,431
Other operating income:
Net gain on disposal of assets		—			(47,478	)		(96	)		—			(47,574	)
Income from equity affiliates		—			(20,678	)		—			—			(20,678	)
Interest expense		75,776			15,554			10,387			(50,956	)		50,761
Interest income		(10,094	)		(31,565	)		(12,480	)		50,956			(3,183	)

Income (loss) before income taxes and minority interests		(59,839	)		170,770			51,603			—			162,534
Income tax provision (benefit)		(29,219	)		36,237			7,568			—			14,586
Minority interests		—			804			—			—			804

Net income (loss)	$	(30,620	)	$	133,729		$	44,035		$	—		$	147,144

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)


	Six Months Ended June 30, 2004
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	1,506,031		$	216,406		$	(33,373	)	$	1,689,064
Costs and expenses:
Operating costs and expenses		(9	)		1,242,423			198,421			(33,373	)		1,407,462
Depreciation, depletion and amortization		—			126,525			6,335			—			132,860
Asset retirement obligation expense		—			21,153			511			—			21,664
Selling and administrative expenses		556			57,931			1,449			—			59,936
Other operating income:
Net gain on disposal of assets		—			(11,996	)		(359	)		—			(12,355	)
Income from equity affiliates		—			(11,053	)		—			—			(11,053	)
Interest expense		70,166			60,027			1,331			(85,601	)		45,923
Interest income		(42,990	)		(35,781	)		(8,958	)		85,601			(2,128	)

Income (loss) before income taxes and minority interests		(27,723	)		56,802			17,676			—			46,755
Income tax provision (benefit)		(22,181	)		(276	)		1,661			—			(20,796	)
Minority interests		—			653			—			—			653

Income (loss) from continuing operations		(5,542	)		56,425			16,015			—			66,898
Loss from discontinued operations, net of taxes		—			(2,837	)		—			—			(2,837	)

Net income (loss)	$	(5,542	)	$	53,588		$	16,015		$	—		$	64,061

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Balance Sheets
(Dollars in thousands)


	June 30, 2005
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	444,338	$	1,774		$	13,255		$	—		$	459,367
Accounts receivable		3,188		112,664			88,567			—			204,419
Inventories		—		317,864			45,697			—			363,561
Assets from coal trading activities		—		52,834			—			—			52,834
Deferred income taxes		—		15,050			—			—			15,050
Other current assets		31,672		21,030			5,289			—			57,991

Total current assets		479,198		521,216			152,808			—			1,153,222
Property, plant, equipment and mine development		—		5,825,226			532,057			—			6,357,283
Less accumulated depreciation, depletion and amortization		—		(1,408,480	)		(65,526	)		—			(1,474,006	)
Investments and other assets		4,621,435		408,662			3,974			(4,665,909	)		368,162

Total assets	$	5,100,633	$	5,346,624		$	623,313		$	(4,665,909	)	$	6,404,661


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	8,750	$	12,229		$	882		$	—		$	21,861
Payables and notes payable to affiliates, net		1,727,839		(2,097,461	)		369,622			—			—
Liabilities from coal trading activities		—		34,812			—			—			34,812
Accounts payable and accrued expenses		22,575		633,261			92,678			—			748,514

Total current liabilities		1,759,164		(1,417,159	)		463,182			—			805,187
Long-term debt, less current maturities		1,334,654		56,547			1,848			—			1,393,049
Deferred income taxes		18,323		370,264			12,404			—			400,991
Other noncurrent liabilities		17,192		1,876,668			7,053			—			1,900,913

Total liabilities		3,129,333		886,320			484,487			—			4,500,140
Minority interests		—		1,713			—			—			1,713
Stockholders’ equity		1,971,300		4,458,591			138,826			(4,665,909	)		1,902,808

Total liabilities and stockholders’ equity	$	5,100,633	$	5,346,624		$	623,313		$	(4,665,909	)	$	6,404,661

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation

Supplemental Condensed Consolidated Balance Sheets
(Dollars in thousands)


	December 31, 2004
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	373,066	$	3,562		$	13,008		$	—		$	389,636
Accounts receivable		1,611		86,748			105,425			—			193,784
Inventories		—		290,863			32,746			—			323,609
Assets from coal trading activities		—		89,165			—			—			89,165
Deferred income taxes		—		15,050			411			—			15,461
Other current assets		19,737		15,971			7,239			—			42,947

Total current assets		394,414		501,359			158,829			—			1,054,602
Property, plant, equipment and mine development		—		5,686,143			428,933			—			6,115,076
Less accumulated depreciation, depletion and amortization		—		(1,289,947	)		(43,698	)		—			(1,333,645	)
Investments and other assets		4,808,202		34,410			3,577			(4,503,630	)		342,559

Total assets	$	5,202,616	$	4,931,965		$	547,641		$	(4,503,630	)	$	6,178,592


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	5,000	$	12,971		$	1,008		$	—		$	18,979
Payables and notes payable to affiliates, net		2,022,037		(2,332,635	)		310,598			—			—
Liabilities from coal trading activities		—		63,565			—			—			63,565
Accounts payable and accrued expenses		20,120		599,253			72,227			—			691,600

Total current liabilities		2,047,157		(1,656,846	)		383,833			—			774,144
Long-term debt, less current maturities		1,338,465		65,228			2,293			—			1,405,986
Deferred income taxes		5,250		386,351			1,665			—			393,266
Other noncurrent liabilities		18,658		1,852,684			7,353			—			1,878,695

Total liabilities		3,409,530		647,417			395,144			—			4,452,091
Minority interests		—		1,909			—			—			1,909
Stockholders’ equity		1,793,086		4,282,639			152,497			(4,503,630	)		1,724,592

Total liabilities and stockholders’ equity	$	5,202,616	$	4,931,965		$	547,641		$	(4,503,630	)	$	6,178,592

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Statements of Cash Flows
(Dollars in thousands)


	Six Months Ended June 30, 2005
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
Cash Flows from Operating Activities
Net cash provided by (used in) operating activities	$	(84,340	)	$	279,925		$	58,009		$	253,594


Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development		—			(86,218	)		(101,432	)		(187,650	)
Purchase of mining assets		—			(56,500	)		—			(56,500	)
Additions to advance mining royalties		—			(6,242	)		(5	)		(6,247	)
Proceeds from disposal of assets		—			60,098			133			60,231

Net cash used in investing activities		—			(88,862	)		(101,304	)		(190,166	)


Cash Flows from Financing Activities
Payments of long-term debt		(2,500	)		(11,014	)		(571	)		(14,085	)
Proceeds from stock options exercised		14,617			—			—			14,617
Proceeds from employee stock purchases		1,350			—			—			1,350
Increase of securitized interests in accounts receivable		—			—			25,000			25,000
Distributions to minority interests		—			(1,000	)		—			(1,000	)
Dividends paid		(19,579	)		—			—			(19,579	)
Transactions with affiliates, net		161,724			(180,837	)		19,113			—

Net cash provided by (used in) financing activities		155,612			(192,851	)		43,542			6,303


Net increase (decrease) in cash and cash equivalents		71,272			(1,788	)		247			69,731
Cash and cash equivalents at beginning of period		373,066			3,562			13,008			389,636

Cash and cash equivalents at end of period	$	444,338		$	1,774		$	13,255		$	459,367

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Statements of Cash Flows
(Dollars in thousands)


	Six Months Ended June 30, 2004
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
Cash Flows from Operating Activities
Net cash provided by (used in) operating activities	$	(26,666	)	$	103,344		$	5,356		$	82,034


Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development		—			(55,577	)		(60,281	)		(115,858	)
Additions to advance mining royalties		—			(9,427	)		(250	)		(9,677	)
Acquisitions, net		—			(189,656	)		(232,508	)		(422,164	)
Proceeds from disposal of assets		—			22,261			542			22,803

Net cash used in investing activities		—			(232,399	)		(292,497	)		(524,896	)


Cash Flows from Financing Activities
Proceeds from long-term debt		250,000			—			—			250,000
Payments of long-term debt		(2,250	)		(13,458	)		(989	)		(16,697	)
Net proceeds from equity offering		383,125			—			—			383,125
Proceeds from stock options exercised		11,601			—			—			11,601
Proceeds from employee stock purchases		1,139			—			—			1,139
Increase of securitized interests in accounts receivable		—			—			50,000			50,000
Payment of debt issuance costs		(8,910	)		—			—			(8,910	)
Distributions to minority interests		—			(694	)		—			(694	)
Dividends paid		(14,852	)		—			—			(14,852	)
Transactions with affiliates, net		(388,084	)		143,996			244,088			—

Net cash provided by financing activities		231,769			129,844			293,099			654,712


Net increase in cash and cash equivalents		205,103			789			5,958			211,850
Cash and cash equivalents at beginning of period		114,575			1,392			1,535			117,502

Cash and cash equivalents at end of period	$	319,678		$	2,181		$	7,493		$	329,352

(14) Guarantees

In the normal course of business, the Company is a party to the following guarantees:

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 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 maximum reimbursement obligation of $42.8 million is supported by a letter of credit.

The Company owns a 49.0% interest in a joint venture that operates an underground mine and preparation plant facility in West Virginia. The partners have severally agreed to guarantee the debt of the joint venture, which consists of a $17.2 million loan facility as of June 30, 2005. The total amount of the joint venture’s debt guaranteed by the Company was $8.4 million as of June 30, 2005.

The Company has guaranteed the performance of Asset Management Group (“AMG”) under a coal purchase contract with a third party, which has terms extending through December 31, 2006. Default occurs upon AMG’s non-delivery of specified monthly tonnage. In the event of a default, the Company assumes AMG’s obligation to ship coal at agreed prices for the remaining term of the purchase contract. The guarantee arose from an agreement by which AMG mines under a royalty-based contract with the Company. As of June 30, 2005, the maximum potential future payments under this

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

guarantee are approximately $10 million, based on recent spot coal prices. As a matter of recourse in the event of a default, the Company has access to cash held in escrow and the ability to trigger an assignment of the AMG assets to the Company. Based on these recourse options and the remote probability of non-performance by AMG due to their proven operating history, the Company has valued the liability associated with the guarantee at zero.

As part of arrangements through which the Company obtains exclusive sales representation agreements with small coal mining companies (the “Counterparties”), the Company issued financial guarantees on behalf of the Counterparties. These guarantees facilitate the Counterparties’ efforts to obtain bonding or financing. The total amount guaranteed by the Company was $1.6 million, and the fair value of the guarantees recognized as a liability was less than $0.1 million as of June 30, 2005. The Company’s obligations under the guarantees extend to the end of 2007.

The Company is the lessee under numerous equipment and property leases. It is common in such commercial lease transactions for the Company, as the lessee, to agree to indemnify the lessor for the value of the property or equipment leased, should the property be damaged or lost during the course of the Company’s operations. The Company expects that losses with respect to leased property would be covered by insurance (subject to deductibles). The Company and certain of its subsidiaries have guaranteed other subsidiaries’ performance under their various lease obligations. Aside from indemnification of the lessor for the value of the property leased, the Company’s maximum potential obligations under its leases are equal to the respective future minimum lease payments and assume that no amounts could be recovered from third parties.

The Company has provided financial guarantees under certain long-term debt agreements entered into by its subsidiaries, and substantially all of the Company’s subsidiaries provide financial guarantees under long-term debt agreements entered into by the Company. The maximum amounts payable under the Company’s debt agreements are equal to the respective principal and interest payments. Supplemental guarantor/non-guarantor financial information is provided in Note 13.

(15) Subsequent Events

On July 21, 2005, the Company announced that its Board of Directors increased the quarterly dividend by 27 percent and authorized a share repurchase program. The share repurchase program allows for the repurchase of up to 5 percent of the Company’s common shares; however, any repurchase under the program requires a separate approval from the Company’s Board of Directors or its Executive Committee. The repurchases may be made from time to time based on an evaluation of the Company’s outlook and general business conditions, as well as alternative investment and debt repayment options. The increase in the regular quarterly dividend on common stock, to $0.095 per share, is payable on August 25, 2005 to shareholders of record on August 4, 2005.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Cautionary Notice Regarding Forward-Looking Statements

This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements relate to future events or our future financial performance, including, without limitation, the section captioned “Outlook.” We use words such as “anticipate,” “believe,” “expect,” “may,” “project,” “will” or other similar words to identify forward-looking statements.

Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are open to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ materially are:

	•		growth of domestic and international coal and power markets;

	•		coal’s market share of electricity generation;

	•		future worldwide economic conditions;

	•		economic and political stability of countries in which we have operations or serve customers;

	•		weather;

	•		transportation performance and costs, including demurrage;

	•		ability to renew sales contracts;

	•		successful implementation of business strategies;

	•		regulatory and court decisions;

	•		future legislation;

	•		variation in revenues related to synthetic fuel production;

	•		changes in postretirement benefit and pension obligations;

	•		negotiation of labor contracts, employee relations and workforce availability;

	•		availability and costs of credit, surety bonds and letters of credit;

	•		the effects of changes in currency exchange rates;

	•		price volatility and demand, particularly in higher-margin products;

	•		risks associated with customers;

	•		reductions of purchases by major customers;

	•		geology and equipment risks inherent to mining;

	•		terrorist attacks or threats;

	•		performance of contractors, third party coal suppliers or major suppliers of mining equipment or supplies;

	•		replacement of reserves;

	•		implementation of new accounting standards and Medicare regulations;

	•		inflationary trends, including those impacting materials used in our business;

	•		the effects of interest rate changes;

	•		the effects of acquisitions or divestitures;

	•		changes to contribution requirements to multi-employer benefit funds; and

	•		other factors, including those discussed in Part II, Item 1, “Legal Proceedings.”

When considering these forward-looking statements, you should keep in mind the cautionary statements in this document, the “Risks Relating to Our Company” section of Item 7 of our 2004 Annual Report on Form 10-K filed with the Securities and Exchange Commission and all related documents incorporated by reference. We do not undertake any obligation to update these statements.

Overview

We are the largest private sector coal company in the world, with majority interests in 32 active coal operations located throughout all major U.S. coal producing regions and internationally in Australia. We also own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. In the second quarter and first half of 2005, we sold 57.7 million and 116.9 million tons of coal, respectively. In 2004, we sold 227.2 million tons of coal that accounted for 20% of all U.S. coal sales, and were more than 85% greater than the sales of our closest competitor. According to reports published by the Energy Information Administration, 1.1 billion tons of coal were consumed in the United States in 2004. The Energy Information Administration also published estimates indicating that domestic consumption of coal by electricity generators would grow at a rate of 1.6% per year through 2025. Coal-fueled generation is used in most cases to meet baseload electricity requirements, and coal use generally grows at the pace of electricity growth. In 2004, coal’s share of U.S. electricity generation was approximately 52%.

Our primary customers are U.S. utilities, which accounted for 90% of our sales in 2004. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2004, approximately 90% of our sales were under long-term contracts. Our results of operations in the near term can be negatively impacted by poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations, the performance of contractors or third party coal suppliers, and by the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections.

We conduct business through four principal operating segments: Western U.S. Mining, Eastern U.S. Mining, Australian Mining, and Trading and Brokerage. Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations, and its principal business is the mining, preparation and sale of steam coal, sold primarily to electric utilities. Our Eastern U.S. Mining operations consist of our Appalachia and Midwest operations, and its principal business is the mining, preparation and sale of steam coal, sold primarily to electric utilities, as well as the mining of metallurgical coal, sold to steel and coke producers.

Geologically, Western operations mine bituminous and subbituminous coal deposits, and Eastern operations mine bituminous coal deposits. Our Western U.S. Mining operations are characterized by predominantly surface extraction processes, lower sulfur content and Btu of coal, and higher customer transportation costs (due to longer shipping distances). Our Eastern U.S. Mining operations are characterized by a majority of underground extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances).

Our Australian Mining operations consist of four mines. The Burton and North Goonyella mines were acquired in April 2004. We opened the Eaglefield Mine in 2004, which is a surface operation adjacent to, and fulfilling contract tonnages in conjunction with, the North Goonyella underground mine. In addition, we have owned and operated our Wilkie Creek Mine since 2002, our only steam coal operation in Australia. Our Australian Mining operations are characterized by surface and underground extraction processes, mining primarily low sulfur, metallurgical coal sold to an international customer base.

Metallurgical coal represented approximately 5% of our total sales volume and approximately 3% of U.S. sales volume in the six months ended June 30, 2005. Each of our mining operations is described in Item 1 of our 2004 Annual Report on Form 10-K.

In addition to our mining operations, which comprised 86% of revenues in the second quarter of 2005, we also generated 13% of our revenues from brokering and trading coal. We generate additional income and cash flows by extracting value from our vast natural resource position by selling non-core, idle or reclaimed land holdings and non-strategic mineral interests.

We are developing three coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. These projects involve mine-mouth generating plants using our surface lands and coal reserves. The projects are as follows: the 1,500 megawatt Prairie State Energy Campus in Washington County, Illinois; the 1,500 megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky; and the 300 megawatt Mustang Energy Project near Grants, N.M. The plants, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, would be operational following a four-year construction phase. The first of these plants will not be operational earlier than mid-2010.

The Prairie State Energy Campus project has continued to advance in 2005. In February 2005, a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire 47% of the Prairie State Energy Campus project. After an initial appeal was successfully resolved related to the air permit that was issued in January 2005, the Illinois Environmental Protection Agency reissued the air permit on April 28, 2005. The same parties who filed the earlier permit challenge filed a new appeal on June 8, 2005. The Company believes the permit was appropriately issued and expects to prevail in the appeal process.

In the first quarter of 2005, the Board of Directors, after completing an orderly succession planning process, elected Gregory H. Boyce, President and Chief Operating Officer, to the position of President and Chief Executive Officer, effective January 1, 2006. Chairman and Chief Executive Officer, Irl F. Engelhardt will continue his CEO duties through 2005, and will remain employed as Chairman of the Board on January 1, 2006. Effective March 1, 2005, Mr. Boyce was also elected to the Board of Directors and Chairman of the Executive Committee of the Board.

Effective March 30, 2005, we implemented a two-for-one stock split on all shares of our common stock. Other than as noted in Part II, Item 4, “Submission of Matters to a Vote of Security Holders,” all share and per share amounts in this Quarterly Report on Form 10-Q reflect the stock split. During July 2005, we increased our quarterly dividend 27% to $0.095 per share and our Board of Directors authorized a share repurchase program of up to 5 percent of the outstanding shares of our common stock. However, any repurchase under the program requires a separate approval from the Company’s Board of Directors or its Executive Committee. The repurchases may be made from time to time based on an evaluation of the Company’s outlook and general business conditions, as well as alternative investment and debt repayment options.

In July 2005, the Board of Directors elected John F. Turner as an independent director who will serve on the Board’s Nominating and Corporate Governance Committee. Turner is former U.S. Assistant Secretary of State for Oceans and International Environmental and Scientific Affairs (OES) within the State Department and is the past President and Chief Executive Officer of the Conservation Fund, a national nonprofit organization dedicated to public-private partnerships to protect land and water resources.

Results of Operations

Adjusted EBITDA

The discussion of our results of operations in 2005 and 2004 below includes references to, and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Because

Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under generally accepted accounting principles, in Note 11 to our unaudited condensed consolidated financial statements included in this report.

Recent Acquisitions Impacting Comparability of Results of Operations

Results in our Western U.S. Mining Operations segment include amounts for our April 15, 2004 acquisition of Twentymile Mine in Colorado. Results in our Australian Mining Operations segment include amounts for our April 15, 2004 acquisition of the Burton and North Goonyella Mines as well as the opening of the Eaglefield Mine adjacent to the North Goonyella Mine in the fourth quarter of 2004. Our Corporate and Other segment includes results from our December 2004 acquisition of a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela.

Quarter Ended June 30, 2005 Compared to Quarter Ended June 30, 2004

Summary

In the second quarter of 2005, our revenues increased $192.0 million to $1,108.8 million, a 20.9% increase over the prior year, primarily driven by improved pricing in most regions. Our segment Adjusted EBITDA totaled $264.5 million in the second quarter of 2005 compared to $184.8 million in the prior year, a 43.1% increase. Net income improved 129.6% to $95.3 million, or $0.71 per share, in the second quarter of 2005, compared to $41.5 million, or $0.32 per share, in the prior year. The improvements were primarily driven by higher sales prices for all of our products, particularly metallurgical coal, and by demand-driven volume increases for our Midwest products and for our ultra-low sulfur Powder River Basin products.

Tons Sold

The following table presents tons sold by operating segment for the quarters ended June 30, 2005 and 2004:


	(Unaudited)
	Quarter Ended June 30,				Increase (Decrease)
	2005		2004		Tons			%
	(Tons in millions)
Western U.S. Mining Operations		36.7		35.0		1.7			4.9	%
Eastern U.S. Mining Operations		13.2		12.7		0.5			3.9	%
Australian Mining Operations		2.1		1.7		0.4			23.5	%
Trading and Brokerage Operations		5.7		7.6		(1.9	)		(25.0	)%

Total		57.7		57.0		0.7			1.2	%

Revenues

The following table presents revenues for the quarters ended June 30, 2005 and 2004:


	(Unaudited)				Increase
	Quarter Ended June 30,				to Revenues
	2005		2004		$		%
			(Dollars in thousands)
Sales	$	1,089,817	$	898,582	$	191,235		21.3	%
Other revenues		18,969		18,189		780		4.3	%

Total revenues	$	1,108,786	$	916,771	$	192,015		20.9	%

Overall, our revenues increased $192.0 million, or 20.9%, over the prior year second quarter. Sales increased $191.2 million in the second quarter of 2005, reflecting increases in every segment: Western U.S. Mining ($33.5 million), Eastern U.S. Mining ($68.0 million), Australian Mining ($68.1 million), and Trading & Brokerage ($21.6 million). Western U.S. Mining sales increased primarily due to higher sales prices in the Powder River and Colorado regions and higher volumes at our Twentymile Mine due to improved productivity from its longwall and 15 additional days of operation in the current year and at our Powder River operations due to continued higher demand for Powder River Basin coal. Average sales prices for the Western U.S. Mining operations were 4.2% higher despite a $13.4 million charge to provide an allowance for disputed receivables as discussed in Note 12 to our unaudited condensed consolidated financial statements. Sales volumes for the Powder River operations were higher in 2005 compared to the prior year despite the negative impact of two train derailments and subsequent rail maintenance, which lowered shipments through much of the quarter. The restricted capacity impacted all coal producers in the area, and rail capacity is not expected to return to pre-derailment levels until late in 2005 as discussed in “Outlook” below. In our Eastern U.S. Mining operations, increases in average selling prices continued, rising 15.6% in the second quarter of 2005 compared to prior year and resulting in a $68.0 million increase in sales due primarily to strong steam and metallurgical coal demand. In addition, volume in our Midwest operations improved over the prior year. The Australian Mining operations’ sales increase primarily reflected higher sales prices for metallurgical coal and an increase in volumes at the mines, primarily due to an additional 15 days of ownership of the Burton and North Goonyella Mines in the second quarter of 2005. Average sales prices in our Australian operations improved 62.5%. Improved Trading and Brokerage sales primarily reflected improved pricing for broker transactions.

Segment Adjusted EBITDA

Our total segment Adjusted EBITDA was $264.5 million for the second quarter of 2005, compared with $184.8 million in the prior year, detailed as follows:


					Increase to
	(Unaudited)				Segmented Adjusted
	Quarter Ended June 30,				EBITDA
	2005		2004		$		%
	(Dollars in thousands)
Western U.S. Mining Operations	$	105,639	$	100,389	$	5,250		5.2	%
Eastern U.S. Mining Operations		95,898		66,007		29,891		45.3	%
Australian Mining Operations		47,479		11,948		35,531		297.4	%
Trading and Brokerage Operations		15,439		6,443		8,996		139.6	%

Total Segment Adjusted EBITDA	$	264,455	$	184,787	$	79,668		43.1	%

Western U.S. Mining operations’ Adjusted EBITDA increased $5.3 million, or 5.2%, in the second quarter of 2005 compared to prior year. Excluding the $13.4 million charge for disputed receivables discussed in Note 12 to our unaudited condensed consolidated financial statements, Adjusted EBITDA increased $18.7 million, or 18.6%. The increase primarily reflected increased volumes and sales prices for the Powder River operations and increased volumes in our Colorado operations, partially offset by higher per unit operating costs from transportation delays in the Powder River Basin and rising fuel costs in all regions. Improvements at our Powder River operations were primarily due to demand-driven sales volume increases and improved margin per ton, primarily due to higher sales prices. Although strong demand for Powder River Basin coal continued, sales volumes at the Powder River operations were impacted by two train derailments, which lowered shipments through much of the quarter and increased per unit costs. Increased volumes in our Colorado operations reflected strong productivity of the Twentymile Mine’s longwall operations and increased demand. Costs were also negatively impacted by an increase in revenue-based production and sales taxes. Excluding the impact of the disputed receivables charge, the Southwest operations’ results were comparable with prior year.

Eastern U.S. Mining operations’ Adjusted EBITDA increased $29.9 million in the second quarter of 2005 compared to prior year, primarily driven by higher sales prices for metallurgical and steam coal in our Appalachia operations. Adjusted EBITDA in our Appalachia operations increased principally as a result of sales price increases of 25% (over 60% for metallurgical coal) in 2005, partially offset by lower production at two of our mines, mainly related to problems from excessive water and geologic issues, and higher contract mining costs. The results in our Midwest operations were higher than prior year as the benefits of higher volumes and prices were partially offset by higher fuel costs.

Australian Mining operations’ Adjusted EBITDA increased $35.5 million in the second quarter of 2005 compared to the prior year. Improved results were mainly driven by sales price increases of over 60% quarter over quarter. Current year results benefited from the strong sales prices, but were negatively impacted by continued port congestion, related demurrage costs, and lower production due to geological problems at the longwall operation.

Trading and Brokerage operations’ Adjusted EBITDA increased $9.0 million in the second quarter of 2005 compared to the prior year, primarily related to a $12.5 million reduction of the previously established reserve for a contractual dispute with one of our coal suppliers, as discussed in Note 3 to our unaudited condensed consolidated financial statements.

Income Before Income Taxes And Minority Interests


	(Unaudited)						Increase (Decrease) to
	Quarter Ended June 30,						Income
	2005			2004			$			%
	(Dollars in thousands)
Total Segment Adjusted EBITDA	$	264,455		$	184,787		$	79,668			43.1	%

Corporate and Other Adjusted EBITDA		(48,675	)		(51,313	)		2,638			5.1	%
Depreciation, depletion and amortization		(79,309	)		(73,020	)		(6,289	)		(8.6	)%
Asset retirement obligation expense		(7,162	)		(8,627	)		1,465			17.0	%
Interest expense		(25,205	)		(24,595	)		(610	)		(2.5	)%
Interest income		1,810			1,209			601			49.7	%

Income before income taxes and minority interests	$	105,914		$	28,441		$	77,473			272.4	%

Income before income taxes and minority interests increased $77.5 million compared with the second quarter of 2004, primarily due to improved segment Adjusted EBITDA results. Corporate and Other Adjusted EBITDA also improved and asset retirement obligation expense was lower, partially offset by an increase in depreciation, depletion and amortization.

Corporate and Other Adjusted EBITDA results include selling and administrative expenses, net gains on asset disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development and resource management. The improvement of Corporate and Other results by $2.6 million included:

	•		higher gain on disposal of assets of $14.5 million primarily related to aggregate gains of $12.5 million on three sales involving non-strategic coal assets and properties; and

	•		income in 2005 of $6.1 million from the December 2004 acquisition of a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela.

These improvements were offset by the following items:

	•		an increase in past mining obligations expense of $10.2 million, primarily related to higher retiree health care costs. The increase in retiree health care costs was primarily associated with higher trend rates, lower interest discount assumptions and the amortization of actuarial losses in 2005; and

	•		an $8.5 million increase in selling and administrative expenses primarily related to higher annual and long-term performance-based incentives, higher outside services related to business development and support services, and higher administrative costs in our Australian operations.

Depreciation, depletion and amortization increased $6.3 million in 2005 primarily associated with increased volumes in 2005 for the mines acquired in April 2004 as well as volume improvements at existing mines.

Net Income


	(Unaudited)						Increase (Decrease) to
	Quarter Ended June 30,						Income
	2005			2004			$			%
				(Dollars in thousands)
Income before income taxes and minority interests	$	105,914		$	28,441		$	77,473			272.4	%

Income tax (provision) benefit		(10,162	)		15,194			(25,356	)		n/a
Minority interests		(498	)		(390	)		(108	)		(27.7	)%

Income from continuing operations		95,254			43,245			52,009			120.3	%
Loss from discontinued operations, net of taxes		—			(1,764	)		1,764			n/a

Net income	$	95,254		$	41,481		$	53,773			129.6	%

Net income increased $53.8 million compared to the second quarter of 2004 due to the increase in income before income taxes and minority interests discussed above, partially offset by an increase in the income tax provision. The income tax provision recorded in 2005 differs from the benefit in 2004 primarily as a result of higher pre-tax income and a positive effective tax rate in 2005, which is driven by the magnitude of the percentage depletion deduction relative to pretax income.

Six Months Ended June 30, 2005 Compared to Six Months Ended June 30, 2004

Summary

In the first six months of 2005, our revenues increased $497.2 million to $2,186.3 million, a 29.4% increase over the prior year, with a 7.4% increase in sales volume and improved pricing in all regions. Our segment Adjusted EBITDA totaled $471.9 million in the first six months of 2005 compared to $344.7 million in the prior year, a 36.9% increase. Net income improved 129.7% to $147.1 million, or $1.10 per share, in the first six months of 2005, compared to $64.1 million, or $0.52 per share, in the prior year. The improvements were primarily driven by improved demand-driven volume, improved sales prices, particularly for our metallurgical and Powder River Basin products, and the impact of mining operations acquired in 2004.

Tons Sold

The following table presents tons sold by operating segment for the six months ended June 30, 2005 and 2004:


	(Unaudited)
	Six Months Ended June 30,				Increase (Decrease)
	2005		2004		Tons			%
	(Tons in millions)
Western U.S. Mining Operations		75.4		67.5		7.9			11.7	%
Eastern U.S. Mining Operations		26.2		25.2		1.0			4.0	%
Australian Mining Operations		4.1		2.0		2.1			105.0	%
Trading and Brokerage Operations		11.2		14.1		(2.9	)		(20.6	)%

Total		116.9		108.8		8.1			7.4	%

Revenues

The following table presents revenues for the six months ended June 30, 2005 and 2004:


	(Unaudited)				Increase (Decrease)
	Six Months Ended June 30,				to Revenues
	2005		2004		$			%
	(Dollars in thousands)
Sales	$	2,152,338	$	1,643,033	$	509,305			31.0	%
Other revenues		33,928		46,031		(12,103	)		(26.3	)%

Total revenues	$	2,186,266	$	1,689,064	$	497,202			29.4	%

Overall, our revenues increased $497.2 million, or 29.4%, over the first six months of the prior year, driven by both increased volumes and sales prices. We acquired three mines in the second quarter of 2004 that contributed approximately $156 million to the increase in revenue in the first six months of 2005. The remaining increase of $341 million is primarily attributable to increases in average sales prices across all segments and increases in volume, particularly in the Powder River Basin, where strong demand continues to drive expansion of our operating capacity.

Sales increased $509.3 million in the first six months of 2005, reflecting increases in every segment: Western U.S. Mining ($137.1 million), Eastern U.S. Mining ($143.8 million), Australian Mining ($162.7 million), and Trading and Brokerage ($65.7 million). Increases in average per ton selling prices continued, rising 7.9% and 16.7% in our Western U.S. and Eastern U.S. mining operations, respectively, in the first six months of 2005 compared to prior year. Western U.S. Mining operations sales increased $137.1 million, or 21.3%, attributable to the 2004 acquisition of Twentymile Mine and to increases in both sales price and sales volumes in the Powder River Basin. Excluding the impact of a $16.2 million allowance that was established relative to disputed receivables (discussed in Note 12 to our unaudited condensed consolidated financial statements), Western US Mining sales increased $153.3 million, or 23.8%. Production in the Powder River Basin continued to increase in response to overall higher demand, increasing 4.9 million tons compared to the prior year, overcoming two train derailments on the main shipping line out of the basin, which reduced our shipments from the region by an estimated 3.5 million tons in the second quarter of 2005. Eastern U.S. Mining operations’ sales increased $143.8 million, or 20.6%, compared with prior year primarily due to improved pricing in Appalachia that resulted from strong steam and metallurgical coal demand, and higher volume in the Midwest. The increase in Australian Mining operations’ sales were primarily due to the acquisition of two mines and the subsequent opening of an adjoining mine in 2004 and increases in the selling price for metallurgical coal. Improved Trading and Brokerage sales primarily reflected increases in coal prices for brokerage sales.

Other revenues decreased $12.1 million in the first six months of 2005 compared to the prior year, primarily as the result of a $12.7 million decrease in coal trading revenues in 2005. In 2004, higher trading revenues were driven by significant pricing increases related to our Eastern trading portfolio. Appalachia steam coal prices remain strong in 2005, but are more stable and have not provided the same opportunities for trading revenues as in 2004.

Segment Adjusted EBITDA

Our total segment Adjusted EBITDA was $471.9 million for the first six months of 2005, compared with $344.7 million in the prior year, detailed as follows:


						Increase (Decrease) to
	(Unaudited)					Segmented Adjusted
	Six Months Ended June 30,					EBITDA
	2005			2004		$			%
				(Dollars in thousands)
Western U.S. Mining Operations	$	226,064		$	183,757	$	42,307			23.0	%
Eastern U.S. Mining Operations		190,704			127,421		63,283			49.7	%
Australian Mining Operations		61,565			12,878		48,687			378.1	%
Trading and Brokerage Operations		(6,429	)		20,675		(27,104	)		n/a

Total Segment Adjusted EBITDA	$	471,904		$	344,731	$	127,173			36.9	%

Western U.S. Mining operations’ Adjusted EBITDA increased $42.3 million, or 23.0%, in the first six months of 2005 compared to prior year. The increase reflected the addition of the Twentymile Mine to our Colorado operations in April 2004 and increased productivity from its operations as well as improvements in the Powder River Basin. The improvement at our Powder River operations was primarily due to an 8.7% increase in volume, in response to increased demand, and improved margin per ton, primarily due to higher sales prices. In 2005, second quarter volumes were reduced from record volume in the first quarter due to constraints on the region’s rail system. Improved revenues overcame increased unit costs that resulted from higher fuel costs, lower than anticipated volume due to rail difficulties, an increase in revenue-based royalties and sales taxes, and the impact of adding higher value Twentymile production in our cost mix.

In the first quarter, we recorded approximately $9.5 million of operating expenses related to pension curtailment charges at our Black Mesa and Seneca mines, which are expected to close during 2005. The impact to Western U.S. Mining operations’ segment Adjusted EBITDA was not significant as the majority of these curtailment costs are billable under current supply agreements.

Eastern U.S. Mining operations’ Adjusted EBITDA increased $63.3 million in the first six months of 2005 compared to prior year, primarily driven by higher sales prices for metallurgical and steam coal. Adjusted EBITDA in our Appalachia operations increased principally as a result of sales price increases of 30% in 2005, partially offset by lower production at two of our mines mainly related to problems from excessive water at one mine and higher costs related to geologic issues, contract mining, and roof support. The results in our Midwest operations were improved compared to the prior year results, as the benefits of higher volumes and prices were partially offset by higher operating costs due to the impact of heavy rainfall on surface operations in the first quarter and higher fuel costs.

Australian Mining operations’ Adjusted EBITDA increased $48.7 million in the first six months of 2005 compared to the prior year. Volumes in Australia increased due to the acquisition of two metallurgical coal mines and the opening of a new surface operation at the end of 2004. Current year results benefited from strong sales prices, but were negatively impacted by port congestion, related demurrage costs and lower production due to geological problems at the longwall operations.

Trading and Brokerage operations’ Adjusted EBITDA decreased $27.1 million compared with the prior year, primarily related to a net $14.1 million charge associated with a contractual dispute (see Note 3

to our unaudited condensed consolidated financial statements) with one of our coal suppliers and less favorable trading results in 2005 compared to 2004, discussed above.

Income Before Income Taxes And Minority Interests


	(Unaudited)						Increase (Decrease) to
	Six Months Ended June 30,						Income
	2005			2004			$			%
	(Dollars in thousands)
Total Segment Adjusted EBITDA	$	471,904		$	344,731		$	127,173			36.9	%

Corporate and Other Adjusted EBITDA		(90,173	)		(99,657	)		9,484			9.5	%
Depreciation, depletion and amortization		(155,262	)		(132,860	)		(22,402	)		(16.9	)%
Asset retirement obligation expense		(16,357	)		(21,664	)		5,307			24.5	%
Interest expense		(50,761	)		(45,923	)		(4,838	)		(10.5	)%
Interest income		3,183			2,128			1,055			49.6	%

Income before income taxes and minority interests	$	162,534		$	46,755		$	115,779			247.6	%

Income before income taxes and minority interests increased $115.8 million compared with the first six months of 2004, primarily due to improved segment Adjusted EBITDA results, improved Corporate and Other Adjusted EBITDA, and lower asset retirement obligation expense, partially offset by increases in depreciation, depletion and amortization and interest expense.

Corporate and Other Adjusted EBITDA results include selling and administrative expenses, net gains on asset disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development and resource management. The $9.5 million improvement in Corporate and Other results included:

	•		higher gains on disposal of assets of $35.2 million primarily related to Penn Virginia (“PVR”) unit sales ($21.2 million) and to three sales involving non-strategic coal assets and properties ($12.5 million) in 2005. In 2005, we recognized a $31.1 million gain (see Note 3 to our unaudited condensed consolidated financial statements) from the sale of all of our remaining 0.838 million PVR units compared to a gain of $9.9 million on the sale of 0.575 million PVR units in 2004;

	•		income in 2005 of $11.0 million from our recently acquired 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela; and

	•		lower net expenses related to generation development of $2.6 million, primarily due to reimbursements from the Prairie State Energy Campus partnership group. The reimbursements include $1.8 million for expenses previously incurred on behalf of the project and the amortization of a $4.9 million non-refundable payment over the project development service period (which ends in mid-2006).

These improvements were offset by the following items:

	•		an increase in past mining obligations expense of $21.9 million, primarily related to higher retiree health care costs. The increase in retiree health care costs was due to higher trend rates, lower interest discount assumptions and the amortization of actuarial losses in 2005; and

	•		an $18.5 million increase in selling and administrative expenses primarily related to higher annual and long-term performance-based incentives and higher personnel and outside services costs, which are being driven by business development initiatives and the support and management of the Twentymile Mine and Australia operations acquired during 2004.

Depreciation, depletion and amortization increased $22.4 million in 2005 with approximately 46% of the increase due to acquisitions made in 2004 and the remainder of the increase due primarily to improved volume at existing mines in 2005. Asset retirement obligation expense decreased $5.3 million due to expenses in 2004 related to the acceleration of planned reclamation of certain closed mine sites. Interest expense increased $4.8 million primarily related to the issuance of $250 million of 5.875% Senior Notes due 2016 in late March of 2004.

Net Income


	(Unaudited)						Increase (Decrease) to
	Six Months Ended June 30,						Income
	2005			2004			$			%
				(Dollars in thousands)
Income before income taxes and minority interests	$	162,534		$	46,755		$	115,779			247.6	%

Income tax (provision) benefit		(14,586	)		20,796			(35,382	)		n/a
Minority interests		(804	)		(653	)		(151	)		(23.1	)%

Income from continuing operations		147,144			66,898			80,246			120.0	%
Loss from discontinued operations, net of taxes		—			(2,837	)		2,837			n/a

Net income	$	147,144		$	64,061		$	83,083			129.7	%

Net income increased $83.1 million compared to the first six months of 2004 due to the increase in income before income taxes and minority interests discussed above, partially offset by an increase in the income tax provision. The income tax provision recorded in 2005 differs from the benefit in 2004 primarily as a result of higher pre-tax income and a positive effective tax rate in 2005, which is driven by the magnitude of the percentage depletion deduction relative to pretax income.

Outlook

Events Impacting Near-Term Operations

Shipments from our Powder River mines were reduced in the second quarter of 2005 due to two train derailments and the beginning of a six-month remedial maintenance program undertaken by the two railroad companies serving the Powder River Basin. The maintenance and repairs are expected to be completed by late 2005 to early 2006. We expect these repairs may restrict shipments from our Powder River operations for the remainder of the current year, but continue to anticipate record shipment levels in 2005 and 2006.

We are continuing to experience transportation difficulties at our Australian operations due to port congestion at Dalrymple Bay Coal Terminal at the Port of Hay Point in Queensland, Australia. The port congestion began in early 2004 as demand began exceeding port capacity and has not eased over the last year. Discussions regarding capacity expansion are on-going. In May 2005, we were notified of a reduced port allocation that is aimed at improving the loading of vessels and reducing demurrage.

Outlook Overview

Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as growth continues in the U.S., Asia and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. The U.S. economy grew almost 4% in the first quarter of 2005 as reported by the U.S. Commerce Department, and China’s economy grew 9.5% as published by the National Bureau of Statistics of China. Strong demand for coal and coal-based electricity generation in the U.S. is being driven by the strengthening economy, low customer stockpiles, production difficulties for some producers, favorable weather, capacity constraints of nuclear generation and high prices of natural gas and oil. The high price of natural gas is leading some coal-fueled generating plants to operate at

increasing levels. U.S. coal inventories at quarter end remained at levels well below the five-year average.

Demand for Powder River Basin coal is increasing, particularly for our ultra-low sulfur products. We control approximately 3.4 billion tons of proven and probable reserves in the Southern Powder River Basin and sold 115.8 million tons of coal from this region during the year ended December 31, 2004, and 60.8 million tons through the first half of 2005. Metallurgical coal is selling at a significant premium to steam coal. We expect to capitalize on the strong global market for metallurgical coal primarily through a portion of our Appalachia operations and our Australian operations, which produce mainly metallurgical coal.

We continue to target 2005 production of 210 million to 220 million tons and total sales volume of 240 million to 250 million tons, including 12 to 14 million tons of metallurgical coal. As of June 30, 2005, we are essentially sold out of our planned 2005 production.

Management expects strong market conditions and operating performance to overcome external cost pressures and adverse port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel and healthcare, and have taken measures to mitigate the increases in these costs. In addition, historically low interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. We may also encounter poor geologic conditions, lower third party contract miner or brokerage source performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See “Cautionary Notice Regarding Forward-Looking Statements” for additional considerations regarding our outlook.

Liquidity and Capital Resources

Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities, sales of non-core assets and financing transactions, including the sale of our accounts receivable through our securitization program. Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs and costs related to past mining obligations as well as planned acquisitions. Our ability to pay dividends, service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. Future dividends, among other things, are subject to limitations imposed by our 6.875% Senior Notes, 5.875% Senior Notes and Senior Secured Credit Facility covenants. We typically fund all of our capital expenditure requirements with cash generated from operations, and during 2004 and the first six months of 2005, have had no borrowings outstanding under our $900.0 million revolving line of credit, which we use primarily for standby letters of credit. As of June 30, 2005, we had letters of credit outstanding under the facility of $412.8 million, leaving $487.2 million available for borrowing. This provides us with available borrowing capacity under the line of credit to fund strategic acquisitions or meet other financing needs. We were in compliance with all of the covenants of the Senior Secured Credit Facility, the 6.875% Senior Notes and the 5.875% Senior Notes as of June 30, 2005.

Net cash provided by operating activities was $253.6 million in the first six months of 2005, an increase of $171.6 million from the first six months of 2004. The increase was primarily driven by stronger operational performance in 2005 and the funding of our pension plans for $52.5 million in 2004 compared to $2.4 million in 2005. Net income increased $83.1 million from the prior year, and in 2004, we electively funded one of our pension plans $50.0 million. The remainder of the increase is due to working capital and other changes.

Net cash used in investing activities was $190.2 million during the first six months of 2005 compared to $524.9 million used in 2004. Capital expenditures were $187.7 million in the first six months of 2005, an increase of $71.8 million over prior year. Included in the 2005 capital expenditures was a $63.5 million payment for the 327 million ton West Roundup federal coal reserve lease in the Powder River Basin, which was awarded to us in February 2005. Also in 2005, we acquired mining assets, including 70 million tons of Illinois and Indiana coal reserves, surface properties and equipment, from Lexington Coal Company for $61.0 million. The purchase price was paid with $59.0 million on the closing date and an additional $2.0

million to be paid within 12 months of the close pending no outstanding claims related to the acquired mining assets. Capital expenditures include $56.5 million paid for reserves and equipment, and inventories include $2.5 million paid for materials and supplies. Proceeds from the disposal of assets increased $37.4 million primarily due to higher proceeds in 2005 from the sale of PVR units and non-strategic property, reserves and equipment. In 2004, we acquired the Twentymile mine in Colorado and two mines in Australia for $417.2 million, and we made a $5.0 million acquisition earn-out payment related to our April 2003 acquisition of the remaining minority interest in Black Beauty Coal Company.

Net cash provided by financing activities was $6.3 million during the first six months of 2005 compared to $654.7 million in the prior year, with the decrease primarily related to the 2004 issuance of 17.6 million shares of common stock at $22.50 per share, netting proceeds of $383.1 million; issuance of $250 million of 5.875% Senior Notes due in 2016; and the payment of debt issuance costs of $8.9 million in connection with the acquisition of the three mines discussed above. During the first six months of 2005 and 2004, we made scheduled payments on our long-term debt of $14.1 and $16.7 million, respectively. We received cash of $14.6 and $11.6 million in the first six months of 2005 and 2004, respectively, from the exercise of stock options. Securitized interest in accounts receivable increased by $25.0 million in the first six months of 2005 compared to an increase of $50.0 million in 2004. We paid dividends of $19.6 million and $14.9 million in the first six months of 2005 and 2004, respectively.

Contractual Obligations

The following table updates, as of June 30, 2005, our contractual coal reserve lease and royalty obligations presented in our 2004 Annual Report on Form 10-K. These obligations have changed due to the Federal Coal Lease bid that we won in February 2005. The first payment of $63.5 million on this lease was made during the first quarter 2005, and future payments of the same amount will be due annually through 2009.


	Payments Due by Year
	Within		2-3		4-5		After
(Dollars in thousands)	1 Year		Years		Years		5 Years
Coal reserve lease and royalty obligations	$	142,575	$	401,642	$	334,736	$	52,996

At June 30, 2005, we had $204.8 million of purchase obligations related to capital expenditures for 2005 and 2006. Commitments for coal reserve-related expenditures, including Federal Coal Leases, are included in the table above. Total projected capital expenditures for calendar year 2005 are approximately $450 million to $500 million. Approximately 50% of projected 2005 capital expenditures relate to the Federal Coal Leases and longwall equipment at the Twentymile Mine and longwall replacement components in Australia, and the remainder is expected to be used to purchase or develop reserves, replace or add equipment, fund cost reduction initiatives and upgrade equipment and facilities at recently acquired operations. We anticipate funding these capital expenditures primarily through operating cash flow.

Off-Balance Sheet Arrangements

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

In March 2000, we established an accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been contributed to our wholly-owned, bankruptcy-remote subsidiary are sold, without recourse, to a multi-seller, asset-backed commercial paper

conduit (“Conduit”). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We used proceeds from the sale of the accounts receivable to repay long-term debt, effectively reducing our overall borrowing costs. The securitization program is scheduled to expire in September 2009, and the maximum amount of undivided interests in accounts receivable that may be sold to the Conduit is $225.0 million. 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 was $225.0 million and $200.0 million as of June 30, 2005 and December 31, 2004, respectively.

There were no other material changes to our off-balance sheet arrangements during the six months ended June 30, 2005. Material off-balance sheet arrangements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2004. See Note 14 to our unaudited condensed consolidated financial statements included in this report for a discussion of our guarantees.

Other

Risks Related to Contract Miners and Brokerage Sources

In conducting our trading, brokerage and mining operations, we utilize third party sources of coal production, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. Recently, certain of our brokerage sources and contract miners have experienced adverse geologic mining and/or financial difficulties that have made their delivery of coal to us at the contractual price difficult or uncertain. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon the reliability (including financial viability) and price of the third-party supply, our obligation to supply coal to customers in the event that adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market, and other factors.

During the first quarter of 2005, a producer ceased shipping to us on a coal supply agreement. We have filed a lawsuit for breach of contract to enforce our contractual rights and to recover damages caused by this material breach of the coal supply agreement. We have agreed to settlement terms with the producer, and the lawsuit has been stayed pending completion of the transactions in the agreed upon settlement. See Notes 3 and 12 to our unaudited condensed consolidated financial statements.

Mohave Generating Station

See Note 12 to our unaudited condensed consolidated financial statements included in this report relating to the likely cessation or suspension of the operations of the Mohave Generating Station on December 31, 2005.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The potential for changes in the market value of our coal trading, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading portfolio is evaluated using a value at risk analysis (described below). Value at risk analysis is not used to evaluate our non-trading, interest rate and currency portfolios. A description of each market risk category is set forth below. We attempt to manage market risks through diversification, controlling position sizes, and executing hedging strategies. Due to lack of quoted market prices and the long term, illiquid nature of the positions, we have not quantified market risk related to our non-trading, long-term coal supply agreement portfolio.

Coal Trading Activities and Related Commodity Price Risk

We engage in over-the-counter and direct trading of coal. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure, in value at risk terms, that we may assume at any point in time.

We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, options, and swaps, at market value in our consolidated financial statements. Our trading portfolio included forwards and swaps at June 30, 2005 and December 31, 2004.

We perform a value at risk analysis on our coal trading portfolio, which includes over-the-counter and brokerage trading of coal. The use of value at risk allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. Value at risk represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon (liquidation period) within a specified confidence level. Our value at risk model is based on the industry standard variance/co-variance approach. This captures our exposure related to both option and forward positions. Our value at risk model assumes a 15-day holding period and a 95% one-tailed confidence interval. This means that there is a one in 20 statistical chance that the portfolio would lose more than the value at risk estimates during the liquidation period.

The use of value at risk allows management to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. Due to the subjectivity in the choice of the liquidation period, reliance on historical data to calibrate the models and the inherent limitations in the value at risk methodology, we perform regular stress and scenario analysis to estimate the impacts of market changes on the value of the portfolio. The results of these analyses are used to supplement the value at risk methodology and identify additional market-related risks.

We use historical data to estimate our value at risk and to better reflect current asset and liability volatilities. Given our reliance on historical data, value at risk is effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. An inherent limitation of value at risk is that past changes in market risk factors may not produce accurate predictions of future market risk. Value at risk should be evaluated in light of this limitation.

During the six months ended June 30, 2005, the actual low, high, and average values at risk for our coal trading portfolio were $1.3 million, $3.9 million, and $2.4 million, respectively. As of June 30, 2005, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2005		91	%
2006		6	%
2007		1	%
2008		2	%

		100	%

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

Credit Risk

Our concentration of credit risk is substantially with energy producers and marketers, electric utilities, steel producers, and financial institutions. Our 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 we engage in a transaction with a counterparty that does not meet our credit standards, we generally seek to protect our position by requiring the counterparty to provide appropriate credit enhancement. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties. Counterparty risk with respect to interest rate swap, foreign currency forwards and options transactions, and fuel hedging derivatives is not considered to be significant based upon the creditworthiness of the participating financial institutions.

Foreign Currency Risk

We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for the remainder of 2005 involves hedging approximately 75% of our anticipated, non-capital Australian dollar-denominated expenditures. As of June 30, 2005, we had in place forward contracts designated as cash flows hedges with Australian dollar-denominated notional amounts outstanding totaling $610 million of which $175 million, $280 million, $120 million, and $35 million will expire in 2005, 2006, 2007 and 2008, respectively. Our current expectation for the remaining 2005 non-capital, Australian dollar-denominated cash expenditures is approximately $240 million. A change in the Australian dollar/U.S. dollar exchange rate of US$0.01 (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of $4.8 million per year.

Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed rate debt as a percent of net debt through the use of various hedging instruments. As of June 30, 2005, after taking into consideration the effects of interest rate swaps, we had $865.9 million of fixed-rate borrowings and $549.0 million of variable-rate borrowings outstanding. A one-percentage point increase in interest rates would result in an annualized increase to interest expense of $5.5 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a one-percentage point increase in interest rates would result in a $56.6 million decrease in the estimated fair value of these borrowings.

Other Non-trading Activities

We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 90% of our sales volume under long-term coal supply agreements during 2004 and 2003. As of June 30, 2005, we are essentially sold out of our planned 2005 production. Also as of June 30, 2005, we had 35 to 45 million tons and 110 to 120 million tons of expected production available for sale or repricing at market prices for 2006 and 2007, respectively. We have an annual metallurgical coal production capacity of 12 to 14 million tons, all of which is priced for 2005 and approximately 50% of which is priced for 2006.

Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage some of this risk, we use a combination of forward contracts with our suppliers and financial derivative contracts, primarily swap contracts with financial institutions. In addition, we utilize derivative contracts to hedge some of our commodity price exposure. As of June 30, 2005, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel. Notional amounts outstanding under these contracts, scheduled to expire through 2007, were 55.7 million gallons of heating oil and 27.3 million gallons of crude oil. Overall, we have fixed prices for approximately 90% of our anticipated diesel fuel requirements in 2005.

We expect to consume approximately 95 million gallons of fuel per year. On a per gallon basis, based on this usage, a change in fuel prices of one cent per gallon (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of approximately $1 million per year. Alternatively, a one dollar per barrel change in the price of crude oil would increase or decrease our annual fuel costs (ignoring the effects of hedging) by approximately $2.3 million.

Item 4. Controls and Procedures.

Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is identified and communicated to senior management on a timely basis. Under the direction of the Chief Executive Officer and Executive Vice President and Chief Financial Officer, management has evaluated our disclosure controls and procedures as of June 30, 2005 and has concluded that the disclosure controls and procedures were effective.

During the second quarter of 2005, we completed the integration of our Australian operations acquired in 2004 into our system of internal control over financial reporting. We implemented new general ledger and reporting systems in our Australian operations and will complete our assessment of the effectiveness of related controls over financial reporting by the end of 2005. Other than changes made in our Australian operations, during the most recent fiscal quarter, there have been no other changes to our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 12 to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report relating to certain legal proceedings, including proceedings brought against us by the Navajo Nation, the Hopi and Quapaw Tribes, two class action lawsuits brought on behalf of the residents of the towns of Cardin, Quapaw and Picher, Oklahoma and natural resource damage claims asserted by Oklahoma and several other parties, which is incorporated by reference herein. See Part I, Item 3, “Legal Proceedings” in our 2004 Annual Report on Form 10-K for a discussion of our legal proceedings.

Item 4. Submission of Matters to a Vote of Security Holders.

Peabody Energy Corporation’s annual meeting of stockholders was held on May 6, 2005. The shares of common stock eligible to vote were based on a record date of March 15, 2005 and do not reflect the March 30, 2005 two-for-one stock split. Four Class I directors were elected to serve for three-year terms expiring in 2008. A tabulation of votes for each director is set forth below:


	For		Withheld
B.R. Brown		59,711,173		1,986,575
Henry Givens, Jr.		58,745,000		2,952,748
James R. Schlesinger		45,976,481		15,721,267
Sandra Van Trease		59,716,590		1,981,158

Stockholders also voted to ratify Ernst & Young LLP as our independent registered public accounting firm for 2005 and voted to approve an increase in the number of authorized common stock shares from 150,000,000 shares to 400,000,000 shares and number of total authorized capital stock shares from 200,000,000 shares to 450,000,000 shares. Three stockholder proposals were voted on at the annual meeting, including a proposal regarding director independence submitted by Amalgamated Bank LongView MidCap 400 Index Fund, a proposal to declassify the Board for the purpose of director elections submitted by the AFL-CIO Reserve Fund, and a proposal to require a majority of affirmative votes for the election of director nominees submitted by the Sheet Metal Workers’ National Pension Fund. The result of the vote on each of these matters is set forth below:


							Broker
	For		Against		Abstentions		Non-votes
Ratification of independent registered public accounting firm		61,153,591		383,733		160,424		—
Approval of increase in number of authorized common stock shares		57,046,627		4,636,333		14,743		—
Proposal regarding director independence		22,560,474		30,184,555		84,274		8,868,445
Proposal regarding declassification of Board		37,246,968		15,482,029		100,305		8,868,445
Proposal regarding majority vote for election of director nominees		19,465,711		33,061,714		301,877		8,868,445

Each of the shareholder proposals submitted at the annual meeting was advisory in nature. The Nominating & Corporate Governance Committee, which consists entirely of independent directors, is evaluating the impact of the vote on these proposals and will recommend a course of action for consideration by the full Board.

Item 6. Exhibits.

See Exhibit Index at page 44 of this report.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


	PEABODY ENERGY CORPORATION

Date: August 8, 2005	By:	/s/ RICHARD A. NAVARRE

	Richard A. Navarre
	Executive Vice President and Chief Financial Officer
	(On behalf of the registrant and as Principal Financial Officer)

EXHIBIT INDEX

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


Exhibit
No.		Description of Exhibit

3.1		Third Amended and Restated Certificate of Incorporation of the Registrant (incorporated by reference to Exhibit 3.1 of the Registrant’s Form S-1 Registration Statement No. 333-55412).

3.2		Amended and Restated By-Laws of the Registrant (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed on March 16, 2005).

3.3*		Certificate of Amendment of Third Amended and Restated Certificate of Incorporation of Peabody Energy Corporation.

10.1*		Federal Coal Lease WYW151134 effective May 1, 2005: West Roundup.

10.2		Indemnification Agreement dated April 8, 2005 by and between Peabody Energy Corporation and Gregory H. Boyce (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 14, 2005).

31.1*		Certification of periodic financial report by Peabody Energy Corporation’s Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of periodic financial report by Peabody Energy Corporation’s Executive Vice President and Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as amended pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1*		Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Peabody Energy Corporation’s Chief Executive Officer.

32.2*		Certification of periodic financial report pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Peabody Energy Corporation’s Executive Vice President and Chief Financial Officer.


*		Filed herewith.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. freshman Avg

Peabody Energy (BTU) 10-Q2005 Q2 Quarterly report

Content analysis