PEABODY ENERGY CORP - 10-Q 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 ended March 31, 2005

Commission File Number 1-16463

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		13-4004153 (I.R.S. Employer 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 April 30, 2005: Common Stock, par value $0.01 per share, 130,762,235 shares outstanding.

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 March 31,
	2005			2004
REVENUES
Sales	$	1,067,652		$	744,451
Other revenues		14,959			27,842

Total revenues		1,082,611			772,293

COSTS AND EXPENSES
Operating costs and expenses		919,213			649,776
Depreciation, depletion and amortization		75,953			59,840
Asset retirement obligation expense		9,195			13,037
Selling and administrative expenses		37,760			27,792
Other operating income:
Net gain on disposal of assets		(31,122	)		(10,448	)
Income from equity affiliates		(9,191	)		(6,427	)


OPERATING PROFIT		80,803			38,723
Interest expense		25,556			21,328
Interest income		(1,373	)		(919	)


INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS		56,620			18,314
Income tax provision (benefit)		4,424			(5,602	)
Minority interests		306			263


INCOME FROM CONTINUING OPERATIONS		51,890			23,653
Loss from discontinued operations, net of income tax benefit of $715		—			(1,073	)


NET INCOME	$	51,890		$	22,580


BASIC EARNINGS PER SHARE
Income from continuing operations	$	0.40		$	0.21
Loss from discontinued operations		—			(0.01	)

Net income	$	0.40		$	0.20

WEIGHTED AVERAGE SHARES OUTSTANDING — BASIC		130,346,759			111,576,252


DILUTED EARNINGS PER SHARE
Income from continuing operations	$	0.39		$	0.21
Loss from discontinued operations		—			(0.01	)

Net income	$	0.39		$	0.20

WEIGHTED AVERAGE SHARES OUTSTANDING — DILUTED		133,400,653			114,309,698

DIVIDENDS DECLARED PER SHARE	$	0.075		$	0.0625

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)
	March 31, 2005			December 31, 2004
ASSETS

Current assets
Cash and cash equivalents	$	381,225		$	389,636
Accounts receivable, less allowance for doubtful accounts of zero at March 31, 2005 and $1,361 at December 31, 2004		187,464			193,784
Inventories		345,562			323,609
Assets from coal trading activities		74,272			89,165
Deferred income taxes		15,836			15,461
Other current assets		57,653			42,947

Total current assets		1,062,012			1,054,602
Property, plant, equipment and mine development, net of accumulated depreciation, depletion and amortization of $1,403,975 at March 31, 2005 and $1,333,645 at December 31, 2004		4,894,779			4,781,431
Investments and other assets		359,607			342,559

Total assets	$	6,316,398		$	6,178,592


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	21,001		$	18,979
Liabilities from coal trading activities		50,044			63,565
Accounts payable and accrued expenses		727,874			691,600

Total current liabilities		798,919			774,144
Long-term debt, less current maturities		1,374,718			1,405,986
Deferred income taxes		404,272			393,266
Asset retirement obligations		418,734			396,022
Workers’ compensation obligations		228,117			227,476
Accrued postretirement benefit costs		943,377			939,503
Other noncurrent liabilities		325,528			315,694

Total liabilities		4,493,665			4,452,091
Minority interests		1,591			1,909
Stockholders’ equity
Preferred Stock – $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of March 31, 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 March 31, 2005 or December 31, 2004		—			—
Common Stock – $0.01 per share par value; 150,000,000 shares authorized, 130,963,662 shares issued and 130,702,482 shares outstanding as of March 31, 2005 and 150,000,000 shares authorized, 129,829,134 shares issued and 129,567,954 shares outstanding as of December 31, 2004		1,310			1,298
Additional paid-in capital		1,468,620			1,437,319
Retained earnings		393,086			350,968
Unearned restricted stock awards		(7,083	)		(459	)
Accumulated other comprehensive loss		(30,875	)		(60,618	)
Treasury shares, at cost: 261,180 shares as of March 31, 2005 and December 31, 2004		(3,916	)		(3,916	)

Total stockholders’ equity		1,821,142			1,724,592

Total liabilities and stockholders’ equity	$	6,316,398		$	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)


	Quarter Ended March 31,
	2005			2004
Cash Flows from Operating Activities
Net income	$	51,890		$	22,580
Loss from discontinued operations		—			1,073

Income from continuing operations		51,890			23,653
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization		75,953			59,840
Deferred income taxes		1,252			(6,748	)
Amortization of debt discount and debt issuance costs		1,795			1,899
Net gain on disposal of assets		(31,122	)		(10,448	)
Income from equity affiliates		(9,191	)		(6,427	)
Dividends received from equity investments		716			821
Changes in current assets and liabilities:
Accounts receivable, net of sale		(18,680	)		(5,973	)
Inventories		(21,953	)		(22,593	)
Net assets from coal trading activities		1,372			(5,711	)
Other current assets		(3,664	)		(5,596	)
Accounts payable and accrued expenses		37,800			(9,781	)
Asset retirement obligations		1,534			3,067
Workers’ compensation obligations		1,933			2,217
Accrued postretirement benefit costs		3,874			(5,775	)
Other, net		4,418			(1,738	)

Net cash provided by operating activities		97,927			10,707

Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development		(110,490	)		(24,414	)
Purchase of mining assets		(56,500	)		—
Additions to advance mining royalties		(3,135	)		(1,828	)
Acquisition, net		—			(5,000	)
Proceeds from disposal of assets		47,731			20,481

Net cash used in investing activities		(122,394	)		(10,761	)

Cash Flows from Financing Activities
Proceeds from long-term debt		—			250,000
Payments of long-term debt		(12,229	)		(14,488	)
Net proceeds from equity offering		—			383,125
Proceeds from stock options exercised		12,331			7,803
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		—			(8,422	)
Distributions to minority interests		(624	)		(318	)
Dividends paid		(9,772	)		(6,859	)

Net cash provided by financing activities		16,056			661,980

Net increase (decrease) in cash and cash equivalents		(8,411	)		661,926
Cash and cash equivalents at beginning of period		389,636			117,502

Cash and cash equivalents at end of period	$	381,225		$	779,428

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 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 March 31, 2005 and for the quarters ended March 31, 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 ended March 31, 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 ($201.5 million and $197.2 million as of March 31, 2005 and December 31, 2004, respectively - - see Note 6 to the unaudited condensed consolidated financial statements). 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 . . . .”

The Company expects the consensus may limit accounting for stripping costs as a component of inventory to merely those costs associated with currently produced coal (i.e. finished or saleable) inventories. Stripping costs associated with in-process (i.e. uncovered, but unextracted) production would not be recognized in inventory under this consensus. Limiting the recognition of production costing for coal to essentially one category (produced coal) of inventory under the consensus would be, in the Company’s view, a material departure from existing inventory accounting practice. Because advance stripping costs incurred prior to the coal being extracted from the pit would be immediately expensed under this consensus, operating costs reported for a given period will not be matched to (i.e. they will be recognized in advance of) the corresponding revenues recognized as coal is transported to customers.

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. The transition provisions of EITF Issue 04-6 allow for adopting this consensus utilizing a cumulative effect adjustment approach or, alternatively, by restating prior periods through retrospective application of this consensus. The Company is currently evaluating the consensus and method of adoption.

The Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations.” 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 under what circumstances 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 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 the fiscal year that begins after June 15, 2005, (January 1, 2006 for calendar year companies) from a July 1, 2005 adoption date previously set by the FASB. SFAS No. 123R requires the recognition of share-based payments, including employee stock options, in the income statement based on

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

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 expense for stock options for the year ending December 31, 2006 of $3.9 million, net of taxes. In addition, the Company began utilizing restricted stock as part of its equity-based compensation strategy in January 2005. Based on restricted stock grants made in 2005 and currently anticipated for 2006, the Company estimates it will recognize expense related to restricted stock of $0.8 million, net of taxes, in 2005 and $1.7 million, net of taxes, in 2006.

(3) Significant Transactions and Events

Gain on Sale of Penn Virginia Resource Partners, L.P. Units

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.

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.” As of March 31, 2005, a remaining deferred gain from the sales of the reserves and units of $19.0 million 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 (see Note 12, Commitments and Contingencies, for more details on the breach of contract and subsequent lawsuit by the Company). The estimated loss related to the supply contract breach reflects amounts accrued for estimated costs to obtain replacement coal in the current market, and no offsetting receivable from the producer who breached the contract has been 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.

(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 $2.0 million to be paid within 12 months of the close pending no outstanding claims related to the acquired mining assets. The assets purchased included $2.5 million of materials and supplies that were recorded in “Inventories” in the condensed consolidated balance sheet. The remaining assets purchased consisted of approximately 70 million tons of reserves, preparation plants, facilities and mining equipment that were recorded to “Property, plant, equipment and mine development” in the condensed consolidated balance sheet. The acquired assets are expected to be used 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 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. 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 segment. The acquisition was accounted for as a purchase.

The preliminary purchase accounting allocations related to the acquisition have been recorded in the accompanying consolidated financial statements as of, and for periods subsequent to, April 15, 2004. The final valuation of the net assets acquired is expected to be finalized once third-party appraisals are completed. Given the size and complexity of the

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

acquisition, the fair valuation of certain assets is still preliminary. Additionally, adjustment to the estimated liabilities assumed in connection with the acquisition may still be required. The Company expects to complete the valuations of the assets and liabilities acquired in the second quarter of 2005.

The following table summarizes the preliminary estimated 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		6,038
Coal inventory		11,543
Other current assets		6,234
Property, plant, equipment and mine development		466,689
Accounts payable and accrued expenses		(49,057	)
Other noncurrent assets and liabilities, net		(66,821	)

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 quarter ended March 31, 2004. 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
	March 31, 2004*
Revenues:
As reported	$	772,293
Pro forma		872,418

Income from continuing operations
As reported	$	23,653
Pro forma		18,710

Net income
As reported	$	22,580
Pro forma		17,637

Basic earnings per share — net income:
As reported	$	0.20
Pro forma		0.14

Diluted earnings per share — net income:
As reported	$	0.20
Pro forma		0.14

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 pro forma Australian operation experienced a 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):


	March 31,		December 31,
	2005		2004
Materials and supplies	$	62,411	$	57,467
Raw coal		19,066		17,590
Advance stripping		201,527		197,225
Saleable coal		62,558		51,327

Total	$	345,562	$	323,609

(7) Assets and Liabilities from Coal Trading Activities

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


	March 31, 2005				December 31, 2004
	Assets		Liabilities		Assets		Liabilities
Forward contracts	$	74,272	$	49,224	$	89,042	$	60,914
Other		—		820		123		2,651

Total	$	74,272	$	50,044	$	89,165	$	63,565

Ninety-nine percent of the contracts in the Company’s trading portfolio as of March 31, 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 March 31, 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		89	%
2006		8	%
2007		2	%
2008		1	%

		100	%

At March 31, 2005, 64% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties. The Company’s coal trading operations traded 9.2 million tons and 9.9 million tons for the quarters ended March 31, 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 March 31,
	2005		2004
Weighted average shares outstanding — basic		130,346,759		111,576,252
Dilutive impact of stock options		3,053,894		2,733,446

Weighted average shares outstanding — diluted		133,400,653		114,309,698

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 March 31, 2005 and 2004, respectively. The following table reflects pro forma net income and basic and diluted earnings per share had compensation cost been determined for the Company’s non-qualified and incentive stock options based on the fair value at the grant dates consistent with the methodology set forth under SFAS No. 123 (dollars in thousands, except per share data):


	Quarter Ended
	March 31,
	2005		2004
Net income:
As reported	$	51,890	$	22,580
Pro forma		50,566		20,838

Basic earnings per share:
As reported	$	0.40	$	0.20
Pro forma		0.39		0.19

Diluted earnings per share:
As reported	$	0.39	$	0.20
Pro forma		0.38		0.18

(9) Comprehensive Income

The following table sets forth the after-tax components of comprehensive income for the quarters ended March 31, 2005 and 2004 (dollars in thousands):


	Quarter Ended
	March 31,
	2005		2004
Net income	$	51,890	$	22,580
Increase (decrease) in fair value of cash flow hedges, net of $19,828 tax provision and $1,465 tax benefit for the quarters ended March 31, 2005 and 2004, respectively		29,743		(2,199	)

Comprehensive income	$	81,633	$	20,381

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 and interest rate swaps) during the period. Increases in crude and heating oil prices and interest rates during the quarter ended March 31, 2005 resulted in increased valuations of these hedging 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
	March 31,
	2005			2004
Service cost for benefits earned	$	2,963		$	2,873
Interest cost on projected benefit obligation		11,373			10,599
Expected return on plan assets		(13,203	)		(11,365	)
Amortization of prior service cost		(4	)		64
Amortization of net loss		6,346			5,629

Net periodic pension costs		7,475			7,800
Curtailment charges		9,527			—

Total pension costs	$	17,002		$	7,800

Curtailment

The curtailment loss resulted from the planned closure of two of the three operating mines that participate in the Western Surface UMWA Pension Plan (the “Plan”) during 2005. 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 March 31, 2005, $0.8 million of contributions have been made to the funded pension plans and $0.3 million of expected benefit payments attributable to the unfunded pension plans have been made.

Components of Net Periodic Postretirement Benefits Costs

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


	Quarter Ended
	March 31,
	2005			2004
Service cost for benefits earned	$	1,325		$	1,220
Interest cost on accumulated postretirement benefit obligation		18,175			15,794
Amortization of prior service cost		(1,325	)		(3,308	)
Amortization of actuarial losses		6,575			774

Net periodic postretirement benefit costs	$	24,750		$	14,480

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 March 31, 2005, payments of $20.8 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 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 mine in Venezuela 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 ended March 31, 2005 and 2004 are as follows (dollars in thousands):


	Quarter Ended
	March 31,
	2005			2004
Revenues:
Western U.S. Mining	$	403,015		$	304,028
Eastern U.S. Mining		424,973			347,157
Australian Mining		103,525			8,625
Trading and Brokerage		147,482			109,129
Corporate and Other		3,616			3,354

Total	$	1,082,611		$	772,293


Adjusted EBITDA ⁽¹⁾:
Western U.S. Mining	$	120,425		$	83,368
Eastern U.S. Mining		94,806			61,415
Australian Mining		14,086			930
Trading and Brokerage ⁽²⁾		(21,868	)		14,231
Corporate and Other ⁽³⁾		(41,498	)		(48,344	)

Total	$	165,951		$	111,600

(1)		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.

(2)		Trading and Brokerage results include a charge for contract losses discussed in Note 3.

(3)		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
	March 31,
	2005			2004
Total adjusted EBITDA	$	165,951		$	111,600

Depreciation, depletion and amortization		75,953			59,840

Asset retirement obligation expense		9,195			13,037

Interest expense		25,556			21,328

Interest income		(1,373	)		(919	)

Minority interests		306			263


Income before income taxes	$	56,314		$	18,051

(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.

While the outcome of litigation is subject to uncertainties, based on a preliminary evaluation of the issues and their potential impact, the Company believes it has a significant contractual and factual basis for its claim, and the Massey counterclaim has no merit.

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 combined Gold Fields with the Company. 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.

The Company’s policy is to accrue environmental cleanup-related costs of a noncapital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures requires an assessment of many factors, including changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. For certain sites, the Company also assesses the financial capability of other potentially responsible parties and, where allegations are based on tentative findings, the reasonableness of the Company’s apportionment. The Company has not anticipated any recoveries from insurance carriers or other

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

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 March 31, 2005 and $40.5 million at December 31, 2004, $14.9 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, 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 $70.3 million and $68.6 million included in “Investments and other assets” in the condensed consolidated balance sheets at March 31, 2005 and December 31, 2004, respectively.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

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. In filings with the California Public Utilities Commission, the operator affirmed that the Mohave plant was not forecast to return to service as a coal-fueled resource until mid-2009 at the earliest if the plant is shutdown at December 31, 2005. On December 2, 2004, the California Public Utilities Commission issued an opinion authorizing Southern California Edison to make necessary expenditures at the Mohave plant to preserve the “Mohave-open” option while Southern California Edison continues to seek resolution of the water and coal issues. 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. Since these issues have not been resolved, it is more likely than not 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 1.3 million tons of coal in the first quarter of 2005 and 4.7 million tons during the year ended December 31, 2004. During the first quarter of 2005, the mine generated $4.5 million of Adjusted EBITDA (reconciled to its most comparable measure under generally accepted accounting principles in Note 11), which represented 2.7% of the Company’s total of $166.0 million. In 2004, the mine contributed $25.2 million, or 4.5% of the Company’s total Adjusted EBITDA of $559.2 million.

Oklahoma Lead Litigation

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. 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. 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. Plaintiffs in these actions are seeking compensatory and punitive damages for alleged personal injuries from lead exposure. The trials for a few of the individual plaintiffs have been set for November 2005.

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.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

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 effect on the financial condition, results of operations or cash flows of the Company.

Accounts receivable in the consolidated balance sheets as of March 31, 2005 and December 31, 2004 includes $19.1 million 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 Company is in arbitration and litigation with these customers to resolve this issue and believes the receivables to be fully collectible under the terms of each agreement.

At March 31, 2005, purchase commitments for capital expenditures were approximately $186.0 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 March 31, 2005
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	899,365		$	202,434		$	(19,188	)	$	1,082,611
Costs and expenses:
Operating costs and expenses		(2,883	)		757,022			184,262			(19,188	)		919,213
Depreciation, depletion and amortization		—			68,957			6,996			—			75,953
Asset retirement obligation expense		—			8,761			434			—			9,195
Selling and administrative expenses		596			36,853			311			—			37,760
Other operating income:
Net (gain) loss on disposal of assets		—			(31,131	)		9			—			(31,122	)
Income from equity affiliates		—			(9,191	)		—			—			(9,191	)
Interest expense		37,448			7,884			5,502			(25,278	)		25,556
Interest income		(4,922	)		(15,388	)		(6,341	)		25,278			(1,373	)

Income (loss) before income taxes and minority interests		(30,239	)		75,598			11,261			—			56,620
Income tax provision (benefit)		(11,113	)		16,379			(842	)		—			4,424
Minority interests		—			306			—			—			306

Net income (loss)	$	(19,126	)	$	58,913		$	12,103		$	—		$	51,890

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

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


	Quarter Ended March 31, 2004
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	724,663		$	63,296		$	(15,666	)	$	772,293
Costs and expenses:
Operating costs and expenses		152			605,404			59,886			(15,666	)		649,776
Depreciation, depletion and amortization		—			58,745			1,095			—			59,840
Asset retirement obligation expense		—			12,995			42			—			13,037
Selling and administrative expenses		322			26,918			552			—			27,792
Other operating income:
Net gain on disposal of assets		—			(10,119	)		(329	)		—			(10,448	)
Income from equity affiliates		—			(6,427	)		—			—			(6,427	)
Interest expense		31,731			26,007			868			(37,278	)		21,328
Interest income		(21,299	)		(12,155	)		(4,743	)		37,278			(919	)

Income (loss) before income taxes and minority interests		(10,906	)		23,295			5,925			—			18,314
Income tax provision (benefit)		(5,822	)		(1,191	)		1,411			—			(5,602	)
Minority interests		—			263			—			—			263

Income (loss) from continuing operations		(5,084	)		24,223			4,514			—			23,653
Loss from discontinued operations, net of taxes		—			(1,073	)		—			—			(1,073	)

Net income (loss)	$	(5,084	)	$	23,150		$	4,514		$	—		$	22,580

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Balance Sheets
(Dollars in thousands)


	March 31, 2005
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
ASSETS
Current assets
Cash and cash equivalents	$	371,209	$	1,261		$	8,755		$	—		$	381,225
Accounts receivable		1,722		92,753			92,989			—			187,464
Inventories		—		311,396			34,166			—			345,562
Assets from coal trading activities		—		74,272			—			—			74,272
Deferred income taxes		—		15,050			786			—			15,836
Other current assets		30,730		22,378			4,545			—			57,653

Total current assets		403,661		517,110			141,241			—			1,062,012
Property, plant, equipment and mine development — at cost		—		5,795,483			503,271			—			6,298,754
Less accumulated depreciation, depletion and amortization		—		(1,351,466	)		(52,509	)		—			(1,403,975	)
Investments and other assets		4,897,850		25,687			4,478			(4,568,408	)		359,607

Total assets	$	5,301,511	$	4,986,814		$	596,481		$	(4,568,408	)	$	6,316,398


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	7,500	$	12,611		$	890		$	—		$	21,001
Payables and notes payable to affiliates, net		2,031,037		(2,400,084	)		369,047			—			—
Liabilities from coal trading activities		—		50,044			—			—			50,044
Accounts payable and accrued expenses		14,723		636,344			76,807			—			727,874

Total current liabilities		2,053,260		(1,701,085	)		446,744			—			798,919
Long-term debt, less current maturities		1,316,781		55,867			2,070			—			1,374,718
Deferred income taxes		25,078		376,743			2,451			—			404,272
Other noncurrent liabilities		16,758		1,891,955			7,043			—			1,915,756

Total liabilities		3,411,877		623,480			458,308			—			4,493,665
Minority interests		—		1,591			—			—			1,591
Stockholders’ equity		1,889,634		4,361,743			138,173			(4,568,408	)		1,821,142

Total liabilities and stockholders’ equity	$	5,301,511	$	4,986,814		$	596,481		$	(4,568,408	)	$	6,316,398

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 — at cost		—		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)


	Quarter Ended March 31, 2005
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
Cash Flows from Operating Activities
Net cash provided by (used in) operating activities	$	(60,981	)	$	138,964		$	19,944		$	97,927

Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development		—			(36,108	)		(74,382	)		(110,490	)
Purchase of mining assets		—			(56,500	)		—			(56,500	)
Additions to advance mining royalties		—			(3,130	)		(5	)		(3,135	)
Proceeds from disposal of assets		—			47,728			3			47,731

Net cash used in investing activities		—			(48,010	)		(74,384	)		(122,394	)


Cash Flows from Financing Activities
Payments of long-term debt		(1,250	)		(10,638	)		(341	)		(12,229	)
Proceeds from stock options exercised		12,331			—			—			12,331
Proceeds from employee stock purchases		1,350			—			—			1,350
Increase of securitized interests in accounts receivable		—			—			25,000			25,000
Distributions to minority interests		—			(624	)		—			(624	)
Dividends paid		(9,772	)		—			—			(9,772	)
Transactions with affiliates, net		56,465			(81,993	)		25,528			—

Net cash provided by (used in) financing activities		59,124			(93,255	)		50,187			16,056

Net decrease in cash and cash equivalents		(1,857	)		(2,301	)		(4,253	)		(8,411	)
Cash and cash equivalents at beginning of period		373,066			3,562			13,008			389,636

Cash and cash equivalents at end of period	$	371,209		$	1,261		$	8,755		$	381,225

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

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


	Quarter Ended March 31, 2004
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
Cash Flows from Operating Activities
Net cash provided by (used in) operating activities	$	(20,806	)	$	30,884		$	629		$	10,707

Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development		—			(23,657	)		(757	)		(24,414	)
Additions to advance mining royalties		—			(1,678	)		(150	)		(1,828	)
Acquisition, net		—			(5,000	)		—			(5,000	)
Proceeds from disposal of assets		—			20,050			431			20,481

Net cash used in investing activities		—			(10,285	)		(476	)		(10,761	)


Cash Flows from Financing Activities
Proceeds from long-term debt		250,000			—			—			250,000
Payments of long-term debt		(1,126	)		(12,854	)		(508	)		(14,488	)
Net proceeds from equity offering		383,125			—			—			383,125
Proceeds from stock options exercised		7,803			—			—			7,803
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		(8,422	)		—			—			(8,422	)
Distributions to minority interests		—			(318	)		—			(318	)
Dividends paid		(6,859	)		—			—			(6,859	)
Transactions with affiliates, net		57,125			(7,940	)		(49,185	)		—

Net cash provided by (used in) financing activities		682,785			(21,112	)		307			661,980

Net increase (decrease) in cash and cash equivalents		661,979			(513	)		460			661,926
Cash and cash equivalents at beginning of period		114,575			1,392			1,535			117,502

Cash and cash equivalents at end of period	$	776,554		$	879		$	1,995		$	779,428

(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 to the commercial bank is in turn supported by a letter of credit totaling $42.8 million.

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 an $18.0 million loan facility as of March 31, 2005. The total amount of the joint venture’s debt guaranteed by the Company was $8.8 million as of March 31, 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 position for the remaining term of the

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

purchase contract. The guarantee arose from an agreement by which AMG mines under a royalty-based contract with the Company. As of March 31, 2005, the maximum potential future payments under this guarantee are approximately $16 million, based on current spot coal prices. As a matter of recourse in the event of a default, the Company has access to a minimal amount of 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 an arrangement through which the Company obtained an exclusive sales representation agreement with a coal mining company (the “Counterparty”) that operates surface mining operations in Illinois, the Company issued a financial guarantee in May 2004 on behalf of the Counterparty. This guarantee facilitated the Counterparty’s efforts to obtain reclamation bonding for the surface mine that will produce the coal to be purchased under the sales representation agreement. The total amount guaranteed by the Company was $1.1 million, and the fair value of the guarantee recognized as a liability was less than $0.1 million as of March 31, 2005. The Company’s obligation under the guarantee is scheduled to expire by June 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.

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 limitations, 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;

•   labor relations and 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 or third party coal suppliers;

•   replacement of reserves;

•   implementation of new accounting standards;

•   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 “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 first quarter of 2005, we sold 59.1 million tons of coal. 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. The Energy Information Administration published that 1.1 billion tons of coal was consumed in the United States in 2004 and expects domestic consumption of coal by electricity generators to 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 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 recently opened the Eaglefield Mine, 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 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 quarter ended March 31, 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 first quarter of 2005, we also generated 14% 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 land holdings and mineral interests.

We are developing 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 three projects involve mine-mouth generating plants using our surface lands and coal reserves — 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 are expected to be operational following a four-year construction phase, which would begin when the Company has completed all necessary permitting, selected partners, secured financing and sold the majority of the output of each plant. These plants will not be operational until at least 2010.

In January 2005, the Prairie State Energy Campus received an air permit from the state of Illinois. 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. In February 2005, certain parties filed an appeal with the Environmental Appeals Board in Washington, D.C. challenging the air permit issued by the Illinois Environmental Protection Agency. In March 2005, the Environmental Appeals Board remanded the permit to the Illinois Environmental Protection Agency to resolve a procedural issue. The Illinois Environmental Protection Agency reissued the air permit on April 28, 2005, and under its terms appeals may be filed through June 8, 2005.

The Board of Directors has 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.

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.

Quarter Ended March 31, 2005 Compared to Quarter Ended March 31, 2004

Summary

In the first quarter of 2005, our revenues rose $310.3 million to $1,082.6 million, a 40.2% increase over the prior year, led by a 13.9% increase in sales volume and improved pricing in all regions. Our segment Adjusted EBITDA totaled $207.4 million in the first quarter of 2005 compared to $159.9 million in the prior year, a 29.7% increase. Net income was $51.9 million, or $0.39 per share, in the first quarter of 2005, compared to $22.6 million, or $0.20 per share, in the prior year. The improvements were primarily driven by improved demand-driven volume, the impact of mining operations acquired in 2004, and improved sales prices, particularly for our metallurgical and Powder River Basin products.

The following table presents tons sold, by operating segment, information for the quarter ended March 31, 2005 compared to the quarter ended March 31, 2004:

Tons Sold


	(Unaudited)		(Unaudited)
	Quarter Ended		Quarter Ended
	March 31,		March 31,		Increase (Decrease)
	2005		2004		Tons			%
			(Tons in millions)
Western U.S. Mining Operations		38.7		32.6		6.1			18.7	%
Eastern U.S. Mining Operations		13.0		12.5		0.5			4.0	%
Australian Mining Operations		2.0		0.3		1.7			566.7	%
Trading & Brokerage Operations		5.4		6.5		(1.1	)		(16.9	%)

Total		59.1		51.9		7.2			13.9	%

Revenues


	(Unaudited)		(Unaudited)
	Quarter Ended		Quarter Ended		Increase (Decrease)
	March 31,		March 31,		to Revenues
	2005		2004		$			%
			(Dollars in thousands)
Sales	$	1,067,652	$	744,451	$	323,201			43.4	%
Other revenues		14,959		27,842		(12,883	)		(46.3	)%

Total revenues	$	1,082,611	$	772,293	$	310,318			40.2	%

Overall, our revenues increased $310.3 million, or 40.2%, over the prior year first quarter, driven by both increased volumes and sales prices. We acquired three mines in the second quarter of 2004 that contributed $133.7 million to the increase in revenue in the first quarter of 2005. The remaining increase of $176.6 million is primarily attributable to increases in average sales prices across all segments and increases in volume, particularly in the Powder River Basin, where demand continues to drive expansion of our operating capacity.

Sales increased $323.2 million in the first quarter of 2005, reflecting increases in every segment: Western U.S. Mining ($103.6 million), Eastern U.S. Mining ($75.8 million), Australian Mining ($94.6 million), and Trading & Brokerage ($49.2 million). The recent trend of higher quarter-over-quarter increases in average selling prices continued, rising 11.7% and 18.0% in our Western U.S. and Eastern U.S. mining operations, respectively, in the first quarter of 2005 compared to prior year. Western U.S. Mining operations sales increased $103.6 million, or 34.5%, attributable to the 2004 acquisition of Twentymile Mine and to increases in both sales price and sales volumes in the Powder River Basin. Production in the Powder River Basin continued to increase in response to overall higher demand, reaching 31.7 million tons

in the first quarter of 2005, an increase of 3.8 million tons compared to the prior year. Eastern U.S. Mining operations’ sales increased $75.8 million, or 22.2%, compared with prior year primarily due to improved pricing that resulted from strong steam and metallurgical coal demand. The increase in Australian Mining operations’ sales primarily reflects the acquisition of two mines and the subsequent opening of an adjoining mine in 2004. Improved Trading and Brokerage sales primarily reflected increases in coal prices for brokerage sales.

Other revenues decreased $12.9 million in the first quarter of 2005 compared to the prior year, primarily as the result of a $10.0 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. Appalachian 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 $207.4 million for the first quarter of 2005, compared with $159.9 million in the prior year, detailed as follows.


	(Unaudited)			(Unaudited)		Increase (Decrease) to
	Quarter Ended			Quarter Ended		Segmented Adjusted
	March 31,			March 31,		EBITDA
	2005			2004		$			%
				(Dollars in thousands)
Western U.S. Mining Operations	$	120,425		$	83,368	$	37,057			44.4	%
Eastern U.S. Mining Operations		94,806			61,415		33,391			54.4	%
Australian Mining Operations		14,086			930		13,156			1,414.6	%
Trading and Brokerage Operations		(21,868	)		14,231		(36,099	)		n/a

Total Segment Adjusted EBITDA	$	207,449		$	159,944	$	47,505			29.7	%

Western U.S. Mining operations’ Adjusted EBITDA increased $37.1 million, or 44.4%, in the first quarter of 2005 compared to prior year. The increase reflected improvements in the Powder River Basin and the addition of the Twentymile Mine in Colorado. The improvement at our Powder River operations was primarily due to a 13.5% increase in volume, which was based on increases in demand, and improved margin per ton, primarily due to higher sales prices. Improved revenues overcame slightly higher costs that resulted from higher fuel costs, an increase in revenue-based production and sales taxes, and the impact of adding higher value Twentymile production in our cost mix. We recorded approximately $9.5 million to 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 insignificant as the majority of these curtailment costs are billable under current supply agreements.

Eastern U.S. Mining operations’ Adjusted EBITDA increased $33.4 million in the first quarter of 2005 compared to prior year, primarily driven by higher sales prices for metallurgical and steam coal. Adjusted EBITDA in our Appalachian operations increased $28.5 million principally as a result of sales price increases of 34% in 2005, partially offset by lower production at one of our mines mainly related to geologic issues and higher roof support costs. The results in our Midwest operations were similar to the prior year results, as the benefits of higher volumes and prices, were mostly offset by higher operating costs due to the impact of heavy rainfall on surface operations, equipment and geologic difficulties, and higher fuel costs.

Australian Mining operations’ Adjusted EBITDA increased $13.2 million in the first quarter 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 one of these mines at the end of 2004. Current year results benefited from strong sales prices, but were negatively impacted by port congestion, related demurrage costs and lost production due to geological problems at the underground longwall operations.

Trading and Brokerage operations’ Adjusted EBITDA decreased $36.1 million compared with the prior year. First quarter 2005 results included an accrual for losses associated with the failure of a coal supplier to ship under a coal supply agreement. See Note 3 to our unaudited condensed consolidated financial statements for more information about the breach of contract. The decrease also reflected less favorable trading results in 2005 compared to 2004, as discussed above.

Income Before Income Taxes And Minority Interests


	(Unaudited)			(Unaudited)
	Quarter Ended			Quarter Ended			Increase (Decrease) to
	March 31,			March 31,			Income
	2005			2004			$			%
				(Dollars in thousands)
Total Segment Adjusted EBITDA	$	207,449		$	159,944		$	47,505			29.7	%

Corporate and Other Adjusted EBITDA		(41,498	)		(48,344	)		6,846			14.2	%
Depreciation, depletion and amortization		(75,953	)		(59,840	)		(16,113	)		(26.9	)%
Asset retirement obligation expense		(9,195	)		(13,037	)		3,842			29.5	%
Interest expense		(25,556	)		(21,328	)		(4,228	)		(19.8	)%
Interest income		1,373			919			454			49.4	%

Income before income taxes and minority interests	$	56,620		$	18,314		$	38,306			209.2	%

Income before income taxes and minority interests increased $38.3 million compared with the first quarter 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 improvement of Corporate and Other results by $6.8 million included:

•   an increase of $21.2 million due to higher gains on sales of Penn Virginia (“PVR”) units. The first quarter of 2005 included a $31.1 million gain from the sale of all of our remaining 0.838 million PVR units compared to a gain of $9.9 million on a sale 0.575 million PVR units in 2004. (See Note 3 to our unaudited condensed consolidated financial statements for more information about our transactions with PVR);

•   income in 2005 of $4.9 million in relation to our newly 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 $1.6 million. The decrease was due to reimbursements of $1.8 million for expenses incurred in relation to the Prairie State Energy Campus generation development project from our new partnership group. In the first quarter of 2005, the partnership group also made a $4.9 million non-refundable payment that will be recognized over the period from the date of receipt through the project development service period, which is expected to end in March 2006.

These improvements were offset by the following items:

• an increase in past mining obligations expense of $11.7 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

• a $10.0 million increase in selling and administrative expenses primarily related to higher performance-based incentives, and higher personnel and outside services costs, which are being driven by the support and management of the Twentymile Mine and Australia operations acquired during 2004.

Depreciation, depletion and amortization increased $16.1 million in 2005 with approximately 52% of the increase due to acquisitions made in 2004 and the remainder of the increase due primarily to increased volume at existing mines in 2005. Asset retirement obligation expense decreased $3.8 million due to expenses in 2004 related to the acceleration of planned reclamation of certain closed mine sites. Interest expense increased $4.2 million primarily related to the issuance of $250 million of 5.875% Senior Notes due 2016 in late March of 2004.

Net Income


	(Unaudited)			(Unaudited)
	Quarter Ended			Quarter Ended			Increase (Decrease) to
	March 31,			March 31,			Income
	2005			2004			$			%

				(Dollars in thousands)
Income before income taxes and minority interests	$	56,620		$	18,314		$	38,306			209.2	%

Income tax (provision) benefit		(4,424	)		5,602			(10,026	)		n/a
Minority interests		(306	)		(263	)		(43	)		(16.3	)%

Income from continuing operations		51,890			23,653			28,237			119.4	%
Loss from discontinued operations, net of taxes		—			(1,073	)		1,073			n/a

Net income	$	51,890		$	22,580		$	29,310			129.8	%

Net income increased $29.3 million compared to the first 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.

Outlook

Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as there continues to be growth in the U.S., Chinese, Pacific Rim and other industrialized economies that are increasing coal demand for electricity generation and steelmaking. The U.S. economy grew 3% in the first quarter of 2005 as reported by the U.S. Commerce Department, and China’s economy grew nearly 9% as published by the National Bureau of Statistics of China. Strong demand for coal and coal-based electricity generation is being driven by the strengthening economy, low customer stockpiles, production difficulties for some producers, capacity constraints of nuclear generation and high prices of natural gas and oil. The high price of natural gas is leading 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. Metallurgical coal is generally selling at a significant premium to steam coal. We expect to capitalize on the strong global market for metallurgical coal primarily through 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 March 31, 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 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 difficulties, our operating margins would be negatively impacted.

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 quarter 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. This provides us with available borrowing capacity ($550.4 million as of March 31, 2005) to use to fund strategic acquisitions or meet other financing needs.

Net cash provided by operating activities was $97.9 million in the first quarter of 2005, an increase of $87.2 million from the first quarter of 2004. The increase was primarily driven by stronger operational performance in 2005. Income from continuing operations increased by $28.2 million, but the cash improvement was more pronounced than the income increase indicates since first quarter 2005 income included higher non-cash charges for depreciation, depletion and amortization of $16.1 million and the non-cash charges related to estimated losses from a contract breach by a coal supplier (see Note 3 in our unaudited condensed consolidated financial statements). The remainder of the increase is due to working capital and other changes.

Net cash used in investing activities was $122.4 million during the first quarter of 2005 compared to $10.8 million used in 2004. Capital expenditures were $110.5 million in the quarter, an increase of $86.1 million over prior year. Included in first quarter 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. During the first quarter of 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. Cash used in investing activities includes $56.5 million paid for reserves and equipment, and an additional $2.5 million was paid for materials and supplies. Proceeds from the disposal of assets increased $27.3 million primarily due to proceeds of $41.9 million from the sale of our remaining 0.838 million PVR units in 2005 compared to the sale of 0.575 million PVR units for $18.5 million in 2004. In

2004, 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.

Financing activities provided $16.1 million during the first quarter of 2005 compared to $662.0 million in the prior year. During the first quarter of 2005 and 2004, we made scheduled payments on our long-term debt of $12.2 and $14.5 million, respectively. We received cash of $12.3 and $7.8 million in the first quarter of 2005 and 2004, respectively, from the exercise of stock options. Securitized interest in accounts receivable increased by $25.0 million in the first quarter of 2005 compared to an increase of $50.0 million in 2004. We paid dividends of $9.8 million and $6.9 million in the first quarter of 2005 and 2004, respectively. During the first quarter of 2004, we issued 17.6 million shares of primary equity at $22.50 per share, netting proceeds of $383.1 million; issued $250 million of 5.875% Senior Notes due in 2016; and paid debt issuance costs of $8.4 million in connection with the acquisition of the Twentymile Mine in Colorado and two mines in Australia in the second quarter of 2004.

As of March 31, 2005, there were no outstanding borrowings under our Revolving Credit Facility. We had letters of credit outstanding under the facility of $349.6 million, leaving $550.4 million available for borrowing. 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 March 31, 2005.

Contractual Obligations

The following table updates, as of March 31, 2005, our contractual coal reserve lease and royalty obligations for the year ended December 31, 2005 as presented in our 2004 Annual Report on Form 10-K. These obligations have changed due to the Federal Coal Lease bid that was 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 March 31, 2005, we had $186.0 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 relates 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 March 31, 2005 and December 31, 2004, respectively.

There were no other material changes to our off-balance sheet arrangements during the quarter ended March 31, 2005. All off-balance sheet arrangements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Form 10-K for the year ended December 31, 2004.

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 (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 potential 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 March 31, 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 quarter ended March 31, 2005, the actual low, high, and average values at risk for our coal trading portfolio were $1.3 million, $2.7 million, and $1.9 million, respectively. As of March 31, 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		89	%
2006		8	%
2007		2	%
2008		1	%

		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 and electric utilities. 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 will 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 and foreign currency forwards and options transactions 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 2005 involves hedging approximately 70% of our anticipated, non-capital Australian dollar-denominated expenditures. As of March 31, 2005, we had in place forward contracts designated as cash flows hedges with Australian dollar-denominated notional amounts outstanding totaling $492.0 million of which $262.0 million, $170.0 million and $60.0 million will expire in 2005, 2006 and 2007, respectively. Our current expectation for 2005 non-capital, Australian dollar-denominated cash expenditures is approximately $480 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 March 31, 2005, after taking into consideration the effects of interest rate swaps, we had $845.3 million of fixed-rate borrowings and $550.5 million of variable-rate borrowings outstanding. A one-percentage point increase in interest rates would result in an annualized increase to interest expense of $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 $55.9 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 March 31, 2005, we are essentially sold out of our planned 2005 production. Also as of March 31, 2005, we had 50 to 60 million tons and 115 to 125 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 none of which is priced beyond March 2006.

Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage 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 our commodity price exposure. As of March 31, 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 66.2 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. The Chief Executive Officer and Executive Vice President and Chief Financial Officer have evaluated our disclosure controls and procedures as of March 31, 2005 and have concluded that the disclosure controls and procedures were effective.

Additionally, during the most recent fiscal quarter, there have been no 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 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 information is incorporated by reference herein.

Item 6. Exhibits.

See Exhibit Index at page 37 of this report.

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).

4.1*		6 7/8% Senior Notes Indenture Due 2013 Sixth Supplemental Indenture, dated as of January 20, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee.

4.2*		5 7/8% Senior Notes Due 2016 Fourth Supplemental Indenture, dated as of January 20, 2005, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee.

10.1		Form of Non-Qualified Stock Option Agreement under the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 7, 2005).

10.2		Form of Performance Units Agreement under the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 7, 2005).

10.3		Letter Agreement, dated as of March 1, 2005, by and between the Company and Gregory H. Boyce (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 4, 2005).

10.4		Letter Agreement, dated as of March 1, 2005, by and between the Company and Irl F. Engelhardt (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 4, 2005).

10.5		Amended and Restated Employment Agreement, dated as of January 1, 2006, by and between the Company and Gregory H. Boyce (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on March 4, 2005).

10.6		Amended and Restated Employment Agreement, dated as of January 1, 2006, by and between the Company and Irl F. Engelhardt (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on March 4, 2005).

10.7		Indemnification Agreement, dated as of April 8, 2005, by and between Registrant and Gregory H. Boyce (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K, dated April 14, 2005).

10.8*		Federal Coal Lease WYW150210: North Antelope Rochelle Mine.

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 2003.

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 2003.


	Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Condensed Consolidated Statements of Operations for the Quarters Ended March 31, 2005 and 2004		2

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

Unaudited Condensed Consolidated Statements of Cash Flows for the Quarters Ended March 31, 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		23

Item 3. Quantitative and Qualitative Disclosures About Market Risk		33

Item 4. Controls and Procedures		35

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		35

Item 6. Exhibits		35
6 7/8% Senior Notes Indenture Due 2013 6th Supplemental Indenture
5 7/8% Senior Notes Due 2016 4th Supplemental Indenture
Federal Coal Lease WYW150210: North Antelope Rochelle Mine
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of EVP/CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to R18 U.S.C. Section 1350
Certification of EVP/CFO Pursuant 18 U.S.C. Section 1350


	PEABODY ENERGY CORPORATION

Date: May 6, 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
No.		Description of Exhibit
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 2003, 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 2003, by Peabody Energy Corporation’s Executive Vice President and Chief Financial Officer.

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	•	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;

	•	labor relations and 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 or third party coal suppliers;

	•	replacement of reserves;

	•	implementation of new accounting standards;

	•	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 “Legal Proceedings.”

	•	an increase of $21.2 million due to higher gains on sales of Penn Virginia (“PVR”) units. The first quarter of 2005 included a $31.1 million gain from the sale of all of our remaining 0.838 million PVR units compared to a gain of $9.9 million on a sale 0.575 million PVR units in 2004. (See Note 3 to our unaudited condensed consolidated financial statements for more information about our transactions with PVR);

	•	income in 2005 of $4.9 million in relation to our newly 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 $1.6 million. The decrease was due to reimbursements of $1.8 million for expenses incurred in relation to the Prairie State Energy Campus generation development project from our new partnership group. In the first quarter of 2005, the partnership group also made a $4.9 million non-refundable payment that will be recognized over the period from the date of receipt through the project development service period, which is expected to end in March 2006.

	•	an increase in past mining obligations expense of $11.7 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

	•	a $10.0 million increase in selling and administrative expenses primarily related to higher performance-based incentives, and higher personnel and outside services costs, which are being driven by the support and management of the Twentymile Mine and Australia operations acquired during 2004.