Edgar Filing: PEABODY ENERGY CORP

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2007


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

For the transition period from to

Commission File Number: 1-16463

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		13-4004153

(State or other jurisdiction of incorporation or organization)		(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)

(Former name, former address and former fiscal year, if changed since last report)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ		Accelerated filer o		Non-accelerated filer o

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

There were 264,970,320 shares of common stock with a par value of $0.01 per share outstanding at April 27, 2007.

INDEX


			Page
PART I. FINANCIAL INFORMATION

	Item 1.	Financial Statements

		Unaudited Condensed Consolidated Statement of Earnings for the Three Months Ended March 31, 2007 and 2006		2

		Condensed Consolidated Balance Sheet as of March 31, 2007 (unaudited) and December 31, 2006		3

		Unaudited Condensed Consolidated Statement of Cash Flows for the Three Months Ended March 31, 2007 and 2006		4

		Notes to Unaudited Condensed Consolidated Financial Statements		5

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		30

	Item 4.	Controls and Procedures		33

PART II. OTHER INFORMATION

	Item 1.	Legal Proceedings		33

	Item 1A.	Risk Factors		33

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		34

	Item 6.	Exhibits		34

SIGNATURE

EXHIBIT INDEX

302 Certification of Chief Executive Officer
302 Certification of Chief Financial Officer
906 Certification of Chief Executive Officer
906 Certification of Chief Financial Officer

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF EARNINGS


	Three Months Ended March 31,
	2007			2006
	(Dollars in thousands, except share
	and per share data)
Revenues
Sales	$	1,314,815		$	1,288,906
Other revenues		50,356			22,904

Total revenues		1,365,171			1,311,810

Costs and Expenses
Operating costs and expenses		1,091,781			1,022,342
Depreciation, depletion and amortization		102,862			80,964
Asset retirement obligation expense		11,375			7,215
Selling and administrative expenses		42,631			46,526
Other operating income:
Net gain on disposal of assets		(36,649	)		(9,226	)
Income from equity affiliates		(2,160	)		(7,252	)

Operating Profit		155,331			171,241
Interest expense		58,778			27,400
Interest income		(5,390	)		(2,606	)

Income Before Income Taxes and Minority Interests		101,943			146,447
Income tax provision		12,614			11,566
Minority interests		823			4,659


Net Income	$	88,506		$	130,222


Earnings Per Share
Basic	$	0.34		$	0.49
Diluted	$	0.33		$	0.48

Weighted Average Shares Outstanding
Basic		263,031,869			263,491,072
Effect of dilutive securities		5,091,593			5,867,656

Diluted		268,123,462			269,358,728


Dividends Declared Per Share	$	0.06		$	0.06

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET


	(Unaudited)
	March 31, 2007			December 31, 2006
	(Dollars in thousands, except
	share and per share data)
ASSETS
Current assets
Cash and cash equivalents	$	295,327		$	326,511
Accounts receivable, net of allowance for doubtful accounts of $11,034 at March 31, 2007 and $11,144 at December 31, 2006		278,062			358,242
Inventories		217,563			215,384
Assets from coal trading activities		162,018			150,373
Deferred income taxes		106,967			106,967
Other current assets		120,660			116,863

Total current assets		1,180,597			1,274,340
Property, plant, equipment and mine development
Land and coal interests		7,275,088			7,127,385
Buildings and improvements		897,200			893,049
Machinery and equipment		1,576,032			1,516,765
Less accumulated depreciation, depletion and amortization		(2,085,299	)		(1,985,682	)

Property, plant, equipment and mine development, net		7,663,021			7,551,517
Goodwill		240,667			240,667
Investments and other assets		456,068			447,532

Total assets	$	9,540,353		$	9,514,056

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	33,877		$	95,757
Liabilities from coal trading activities		123,665			126,731
Accounts payable and accrued expenses		1,110,496			1,104,881

Total current liabilities		1,268,038			1,327,369
Long-term debt, less current maturities		3,170,966			3,201,992
Deferred income taxes		204,822			195,213
Asset retirement obligations		433,290			423,031
Workers’ compensation obligations		232,814			233,407
Accrued postretirement benefit costs		1,367,726			1,368,686
Other noncurrent liabilities		380,022			392,495

Total liabilities		7,057,678			7,142,193
Minority interests		33,556			33,337
Stockholders’ equity
Preferred Stock – $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of March 31, 2007 or December 31, 2006		—			—
Series A Junior Participating Preferred Stock – 1,500,000 shares authorized, no shares issued or outstanding as of March 31, 2007 or December 31, 2006		—			—
Perpetual Preferred Stock – 750,000 shares authorized, no shares issued or outstanding as of March 31, 2007 or December 31, 2006		—			—
Series Common Stock – $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of March 31, 2007 or December 31, 2006		—			—
Common Stock – $0.01 per share par value; 800,000,000 shares authorized, 267,508,156 shares issued and 264,800,253 shares outstanding as of March 31, 2007 and 266,554,157 shares issued and 263,846,839 shares outstanding as of December 31, 2006		2,675			2,666
Additional paid-in capital		1,588,774			1,572,614
Retained earnings		1,188,619			1,115,994
Accumulated other comprehensive loss		(227,235	)		(249,058	)
Treasury shares, at cost: 2,707,903 shares as of March 31, 2007 and 2,707,318 shares as of December 31, 2006		(103,714	)		(103,690	)

Total stockholders’ equity		2,449,119			2,338,526

Total liabilities and stockholders’ equity	$	9,540,353		$	9,514,056

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS


	Three Months Ended March 31,
	2007			2006
	(Dollars in thousands)
Cash Flows From Operating Activities
Net income	$	88,506		$	130,222
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		102,862			80,964
Deferred income taxes		(2,461	)		(12,864	)
Amortization of debt discount and debt issuance costs		2,169			1,815
Net gain on disposal of assets		(36,649	)		(9,226	)
Income from equity affiliates		(2,160	)		(7,252	)
Dividends received from equity affiliates		12,927			5,442
Stock compensation		6,128			4,102
Changes in current assets and liabilities, net of acquisitions:
Accounts receivable, net of sale		74,380			10,853
Inventories		(2,179	)		(29,918	)
Net assets from coal trading activities		(13,736	)		240
Other current assets		2,343			(15,708	)
Accounts payable and accrued expenses		(8,576	)		(97,991	)
Asset retirement obligations		5,563			22
Workers’ compensation obligations		(532	)		860
Accrued postretirement benefit costs		7,322			5,360
Obligation to industry fund		3,587			(2,968	)
Other, net		7,479			(14,901	)

Net cash provided by operating activities		246,973			49,052

Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		(134,653	)		(87,459	)
Federal coal lease expenditures		(59,829	)		(59,829	)
Additions to advance mining royalties		(2,557	)		(2,250	)
Proceeds from disposal of assets, net of notes receivable		16,451			11,488
Investments in joint ventures		(622	)		—
Other acquisitions, net		—			(44,538	)

Net cash used in investing activities		(181,210	)		(182,588	)

Cash Flows From Financing Activities
Payments of long-term debt		(93,146	)		(12,906	)
Dividends paid		(15,881	)		(15,869	)
Increase of securitized interests in accounts receivable		5,800			—
Proceeds from employee stock purchases		3,097			1,772
Excess tax benefit related to stock options exercised		2,510			13,096
Proceeds from stock options exercised		2,378			6,051
Distributions to minority interests		(875	)		(1,000	)
Payment of debt issuance costs		(830	)		—
Proceeds from long-term debt		—			750
Common stock repurchase		—			(11,476	)

Net cash used in financing activities		(96,947	)		(19,582	)

Net decrease in cash and cash equivalents		(31,184	)		(153,118	)
Cash and cash equivalents at beginning of year		326,511			503,278

Cash and cash equivalents at end of year	$	295,327		$	350,160

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2007

(1) Basis of Presentation

The condensed consolidated financial statements include the accounts of Peabody Energy Corporation (“the Company”) and its controlled affiliates. All intercompany transactions, profits, and balances have been eliminated in consolidation.

The accompanying condensed consolidated financial statements as of March 31, 2007 and for the three months ended March 31, 2007 and 2006, 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, 2006 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the three months ended March 31, 2007 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2007. Certain amounts in prior periods have been reclassified to conform to the report classifications as of March 31, 2007 and for the three months ended March 31, 2007, with no effect on previously reported net income or stockholders’ equity.

(2) New Accounting Pronouncements

In June 2006, the Financial Accounting Standards Board (“FASB”) issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN No. 48”). This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

The Company adopted the provisions of FIN No. 48 on January 1, 2007 with no impact to retained earnings. As a result of adoption, the Company has $135 million of unrecognized tax benefits in its condensed consolidated financial statements. The Company does not expect any significant increases or decreases to its unrecognized tax benefits within 12 months of this reporting date that would affect the Company’s effective tax rate, if recognized.

Due to the existence of net operating loss (“NOL”) carryforwards, the Company has not currently accrued interest on any of its unrecognized tax benefits. The Company has considered the application of penalties on its unrecognized tax benefits and has determined, based on several factors including the existence of its NOL carryforwards, that no accrual of penalties related to its unrecognized tax benefits is required. If the accrual of interest or penalties becomes appropriate, the Company will record an accrual in its income tax provision.

The Company’s Federal income tax returns for the tax years 1999 and beyond remain subject to examination by the Internal Revenue Service. The Company’s state income tax returns for the tax years 1991 and beyond remain subject to examination by various state taxing authorities. The Company’s foreign income tax returns for the tax years 2003 and beyond remain subject to examination by various foreign taxing authorities.

(3) Business Combinations and Acquisitions

In the second half of 2006, through two separate transactions, the Company acquired 100% of Excel Coal Limited (“Excel”), an independent coal company in Australia for a total acquisition price of US$1.54 billion in cash plus assumed debt of US$293.0 million, less US$30.0 million of cash acquired in the transaction. The results of operations of Excel are included in the Company’s Australian Mining Operations segment beginning in October 2006.

The preliminary purchase accounting allocations related to the acquisition were recorded in the accompanying condensed consolidated financial statements as of, and for periods subsequent to, October 2006. The valuation of the net assets acquired is expected to be finalized once certain third-party appraisals and drilling and reserve studies are completed in mid 2007. The preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition have not been adjusted since December 31, 2006.

The following unaudited pro forma financial information presents the combined results of operations of the Company and Excel, on a pro forma basis, as though the companies had been combined as of the beginning of the period presented. The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and Excel constituted a single entity during this period. The Excel acquisition is not expected to be accretive to earnings until the mines under development are fully operational.


	Three Months Ended
	March 31, 2006
	(Dollars in thousands, except per share data)
Revenues:
As reported	$	1,311,810
Pro forma		1,410,154

Net income:
As reported	$	130,222
Pro forma		119,131

Basic earnings per share — net income:
As reported	$	0.49
Pro forma		0.45

Diluted earnings per share — net income:
As reported	$	0.48
Pro forma		0.44

(4) Assets and Liabilities from Coal Trading Activities

The Company’s coal trading portfolio included forward and swap contracts as of March 31, 2007 and December 31, 2006. The fair value of coal trading derivatives and related hedge contracts is set forth below:


	March 31, 2007				December 31, 2006
	Assets		Liabilities		Assets		Liabilities
	(Dollars in thousands)
Forward contracts	$	142,965	$	99,760	$	142,105	$	120,718
Financial swaps		19,053		23,905		8,268		6,013

Total	$	162,018	$	123,665	$	150,373	$	126,731

Of the contracts in the Company’s trading portfolio as of March 31, 2007, 99% 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, 2007, the estimated future realization of the value of the Company’s trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2007		37	%
2008		38	%
2009		20	%
2010		4	%
2011		1	%

		100	%

At March 31, 2007, 56% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties and 44% was with non-investment grade counterparties. The Company’s coal trading operations traded 31.5 million tons and 10.7 million tons for the quarters ended March 31, 2007 and 2006, respectively.

(5) Resource Management and Other Commercial Events

During the three months ended March 31, 2007, the Company sold approximately 35 million tons of non-strategic coal reserves and surface lands located in Kentucky for $13.9 million cash proceeds and a note receivable of $32.2 million with a recognized gain of $34.9 million.

(6) Inventories

Inventories consisted of the following:


	March 31, 2007		December 31, 2006
	(Dollars in thousands)
Materials and supplies	$	89,075	$	85,242
Raw coal		40,240		42,693
Saleable coal		88,248		87,449

Total	$	217,563	$	215,384

(7) Long-Term Debt

The Company’s total indebtedness as of March 31, 2007 and December 31, 2006, consisted of the following:


	March 31,			December 31,
	2007			2006
	(Dollars in thousands)
Term Loan under Senior Unsecured Credit Facility	$	528,662		$	547,000
Convertible Junior Subordinated Debentures due 2066		732,500			732,500
7.375% Senior Notes due 2016		650,000			650,000
6.875% Senior Notes due 2013		650,000			650,000
7.875% Senior Notes due 2026		246,913			246,897
5.875% Senior Notes due 2016		218,090			231,845
5.0% Subordinated Note		—			59,504
6.84% Series C Bonds due 2016		43,000			43,000
6.34% Series B Bonds due 2014		21,000			21,000
6.84% Series A Bonds due 2014		10,000			10,000
Capital lease obligations		95,950			96,869
Fair value of interest rate swaps		(13,898	)		(13,784	)
Other		22,626			22,918


Total	$	3,204,843		$	3,297,749

Long-Term Debt Repayments

During the three months ended March 31, 2007, the Company repaid portions of its long-term debt, which included a $60.0 million retirement of its 5.0% Subordinated Note; an $18.3 million repayment of its outstanding balance of the Term Loan under the Senior Unsecured Credit Facility; and an open-market purchase for $13.8 million in face value of its 5.875% Senior Notes. As of March 31, 2007, the Revolving Credit Facility’s remaining available borrowing capacity under the Senior Unsecured Credit Facility was $1.38 billion.

Capital Lease Obligations

As of December 31, 2006, “Capital lease obligations” reflects an additional $40.2 million that was previously classified as “Accounts payable and accrued expenses” on the Company’s consolidated balance sheet in its Annual Report on Form 10-K for the fiscal year ended December 31, 2006. The reclassification relates to a capital lease transaction structure that was finalized during the three months ended March 31, 2007. The lease term is 7 years with annual payments of approximately $6.7 million over the term of the lease.

Interest Rate Swaps

During the three months ended March 31, 2007, the Company entered into several fixed-to-floating interest rate swaps. The first group of three interest rate swaps had combined notional amounts totaling $200.0 million and was designated to hedge changes in fair value of the 6.875% Senior Notes due 2013. Under the swaps, the Company pays a floating rate that resets each March 15 and September 15 based upon the six-month LIBOR rate for a period of six years ending March 15, 2013 and receives a fixed rate of 6.875%. The second group of two interest rate swaps had combined notional amounts totaling $100.0 million and was designated to hedge changes in fair value of the 5.875% Senior Notes due 2016. Under the swaps, the Company pays a floating rate that resets each April 15 and October 15 based upon the six-month LIBOR rate for a period of nine years ending April 15, 2016 and receives a fixed rate of 5.875%.

The above interest rate swaps were in addition to those the Company entered into in previous years, including the following: five fixed-to-floating interest rate swaps with combined notional amounts totaling $220.0 million that were designated to hedge changes in fair value of the 6.875% Senior Notes due 2013; and a $120.0 million notional amount floating-to-fixed interest rate swap with a fixed rate of 6.25% and a floating rate of LIBOR plus 1.0% that was designated to hedge changes in expected cash flows on the Term Loan under the Senior Unsecured Credit Facility.

(8) Comprehensive Income

The following table sets forth the after-tax components of comprehensive income for the three months ended March 31, 2007 and 2006:


	Three Months Ended March 31,
	2007		2006
	(Dollars in thousands)
Net income	$	88,506	$	130,222
Increase in fair value of cash flow hedges, net of tax provision of $8,857 and $1,242 for the three months ended March 31, 2007 and 2006, respectively		14,261		1,864
Amortization of actuarial loss and prior service cost realized in net income, net of tax provision of $3,387		7,562		—

Comprehensive income	$	110,329	$	132,086

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 during the periods (which include fuel and natural gas hedges, currency forwards, traded coal index contracts and interest rate swaps) and the amortization of actuarial loss and prior service cost associated with the adoption of Statement of Financial Accounting Standard No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans.” The values of the Company’s cash flow hedging instruments are affected by changes in interest rates, crude oil, heating oil and natural gas prices, the price of coal delivered into Europe and the U.S. dollar/Australian dollar exchange rate.

(9) Pension and Postretirement Benefit Costs

Net periodic pension costs included the following components:


	Three Months Ended March 31,
	2007			2006
	(Dollars in thousands)
Service cost for benefits earned	$	2,250		$	3,059
Interest cost on projected benefit obligation		11,975			11,509
Expected return on plan assets		(14,075	)		(13,647	)
Amortization of actuarial loss and other		4,175			5,663

Net periodic pension costs	$	4,325		$	6,584

Net periodic postretirement benefit costs included the following components:


	Three Months Ended March 31,
	2007			2006
	(Dollars in thousands)
Service cost for benefits earned	$	2,229		$	1,879
Interest cost on accumulated postretirement benefit obligation		21,372			18,464
Amortization of prior service cost		(842	)		(1,334	)
Amortization of actuarial loss		10,816			8,012

Net periodic postretirement benefit costs	$	33,575		$	27,021

(10) 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 Company’s chief operating decision maker uses Adjusted EBITDA as the primary measure of segment profit and loss. Adjusted EBITDA is defined as income from operations before deducting net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization.

Operating segment results for the three months ended March 31, 2007 and 2006 were as follows:


	Three Months Ended
	March 31,
	2007			2006
	(dollars in thousands)
Revenues:
Western U.S. Mining	$	480,633		$	432,090
Eastern U.S. Mining		518,216			514,463
Australian Mining		286,991			152,999
Trading and Brokerage		76,064			207,015
Corporate and Other		3,267			5,243

Total	$	1,365,171		$	1,311,810


Adjusted EBITDA:
Western U.S. Mining	$	139,648		$	127,793
Eastern U.S. Mining		81,043			132,544
Australian Mining		62,561			47,756
Trading and Brokerage		36,835			16,179
Corporate and Other ⁽¹⁾		(50,519	)		(64,852	)

Total	$	269,568		$	259,420


⁽¹⁾		Corporate and Other results include the gains on the disposal of assets discussed in Note 5.

A reconciliation of Adjusted EBITDA to consolidated income before income taxes and minority interests follows:


	Three Months Ended
	March 31,
	2007			2006
	(dollars in thousands)
Total Adjusted EBITDA	$	269,568		$	259,420

Depreciation, depletion and amortization		102,862			80,964
Asset retirement obligation expense		11,375			7,215
Interest expense		58,778			27,400
Interest income		(5,390	)		(2,606	)


Income before income taxes and minority interests	$	101,943		$	146,447

(11) Commitments and Contingencies

Commitments

As of March 31, 2007, purchase commitments for capital expenditures were $75.0 million and federal coal reserve lease payments due over the next three years totaled $419.9 million.

Litigation Relating to Continuing Operations

Navajo Nation Litigation

On June 18, 1999, the Navajo Nation served three of the Company’s subsidiaries, including 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. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. 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 have terminated due to Peabody Western’s breach of these leases and a reformation of these leases to adjust the royalty rate to 20%. Subsequently, the court allowed the Hopi Tribe to intervene in this lawsuit and the Hopi Tribe is also seeking 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 rejecting the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments. 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 owners of the power plants served by the suspended Black Mesa mine and the Kayenta mine are in mediation with respect to this litigation and other business issues.

The outcome of this litigation, or the current mediation, is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably 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.

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. The trial court subsequently ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. The Company has recorded a receivable for mine decommissioning costs of $77.3 million and $76.8 million included in “Investments and other assets” in the condensed consolidated balance sheets as of March 31, 2007 and December 31, 2006, respectively.

The outcome of this litigation and arbitration is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably 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.

Gulf Power Company Litigation

On June 21, 2006, the Company’s subsidiary filed a complaint in the U.S. District Court, Southern District of Illinois, seeking a declaratory judgment upholding its declaration of a permanent force majeure under a coal supply agreement with Gulf Power Company. On June 22, 2006, Gulf Power Company filed a breach of contract lawsuit against the Company’s subsidiary in the U.S. District Court, Northern District of Florida, contesting the force majeure declaration and seeking damages for alleged past and future tonnage shortfalls of nearly 5 million tons under the coal supply agreement, which would have expired on December 31, 2007. The parties filed motions to determine which court will hear the lawsuits. On October 6, 2006, the Florida District Court stayed Gulf Power’s lawsuit until the Illinois court decided whether it had jurisdiction. On February 23, 2007, the Illinois District Court ruled that it had jurisdiction but exercised its discretion to dismiss the declaratory judgment action. On March 26, 2007, the Florida District Court lifted the stay of the Florida lawsuit. We have filed a motion to dismiss the Florida lawsuit or to transfer it to Illinois.

The outcome of this litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot reasonably 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.

Claims and Litigation Relating to Indemnities or Historical Operations

Oklahoma Lead Litigation

Gold Fields Mining, LLC (“Gold Fields”) is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, the Company’s predecessor owner. In a February 1997 spin-off, Hanson PLC transferred ownership of Gold Fields to the Company, despite the fact that Gold Fields had no ongoing operations and the Company had no prior involvement in its past operations. Today Gold Fields is one of the Company’s subsidiaries. The Company indemnified TXU Group with respect to certain claims relating to a former affiliate of Gold Fields. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950s and mined, in accordance with lease agreements and permits, approximately 0.15% of the total amount of the crude ore mined in the county.

Gold Fields and two other companies are defendants in two class action lawsuits allegedly involving the operations near Picher, Oklahoma. The plaintiffs have asserted claims predicated on allegations of intentional lead exposure by the defendants and are seeking compensatory damages, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. Gold Fields is also a defendant, along with other companies, in personal injury lawsuits involving over 50 children, arising out of the same lead mill operations. Plaintiffs in these actions are seeking compensatory and punitive damages for alleged personal injuries from lead exposure. Gold Fields, along with the former affiliate, has reached a confidential agreement in principle to settle most of the claims in the personal injury lawsuits. Plaintiffs’ counsel are in the process of having the final settlement documentation executed. In December 2003, the Quapaw Indian tribe and certain Quapaw land owners filed a class action lawsuit against Gold Fields and five other companies. The plaintiffs are seeking compensatory and punitive damages based on a variety of theories. Gold Fields has filed a third-party complaint against the United States, and other parties. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other companies regarding a possible natural resources damage claim. All of the lawsuits are pending in the U.S. District Court for the Northern District of Oklahoma.

The outcome of litigation and these claims are subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably 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.

Environmental Claims and Litigation

Environmental claims have been asserted against Gold Fields related to activities of Gold Fields or a former affiliate. Gold Fields or the former affiliate has been named a potentially responsible party (“PRP”) based on CERCLA at five sites, and claims have been asserted at 18 other sites, which have since been reduced to 12 by transfer or regulatory inactivity. The number of PRP sites in and of itself is not a relevant measure of liability, because the nature and extent of environmental concerns varies by site, as does the estimated share of responsibility for Gold Fields or the former affiliate. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above were $42.6 million as of March 31, 2007 and $43.0 million as of December 31, 2006, $14.0 million and $14.4 million of which was reflected as a current liability, respectively. These amounts represent those costs that the Company believes are probable and reasonably

estimable. In September 2005, Gold Fields and other PRPs received a letter from the U.S. Department of Justice alleging that the PRPs’ mining operations caused the Environmental Protection Agency (“EPA”) to incur approximately $125 million in residential yard remediation costs at Picher, Oklahoma and will cause the EPA to incur additional remediation costs relating to historical mining sites. Gold Fields has participated in the ongoing settlement discussions. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950s and mined, in accordance with lease agreements and permits, approximately 0.15% of the total amount of the crude ore mined in the county. Gold Fields believes it has meritorious defenses to these claims. Gold Fields is involved in other litigation in the Picher area, and the Company indemnified TXU Group with respect to a defendant as is more fully discussed under the “Oklahoma Lead Litigation” caption above. 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.

Other

In addition, at times the Company becomes a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. The Company believes that the ultimate resolution of such other pending or threatened proceedings is not reasonably likely to have a material adverse effect on its financial position, results of operations or liquidity.

(12) Guarantees

In the normal course of business, the Company is a party to guarantees and financial instruments with off-balance-sheet risk, such as bank letters of credit, performance or surety bonds and other guarantees and indemnities, which are not reflected in the accompanying condensed consolidated balance sheets. Such financial instruments are valued based on the amount of exposure under the instrument and the likelihood of required performance. In the Company’s past experience, virtually no claims have been made against these financial instruments. Management does not expect any material losses to result from these guarantees or off-balance-sheet instruments.

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. As of March 31, 2007, the Company’s maximum reimbursement obligation to the commercial bank was in turn supported by a letter of credit totaling $42.8 million.

The Company is party to an agreement with the Pension Benefit Guarantee Corporation (“PBGC”) and TXU Europe Limited, an affiliate of the Company’s former parent corporation, under which the Company is required to make special contributions to two of the Company’s defined benefit pension plans and to maintain a $37.0 million letter of credit in favor of the PBGC. If the Company or the PBGC gives notice of an intent to terminate one or more of the covered pension plans in which liabilities are not fully funded, or if the Company fails to maintain the letter of credit, the PBGC may draw down on the letter of credit and use the proceeds to satisfy liabilities under the Employee Retirement Income Security Act of 1974, as amended. The PBGC, however, is required to first apply amounts received from a $110.0 million guarantee in place from TXU Europe Limited in favor of the PBGC before it draws on the Company’s letter of credit. On November 19, 2002, TXU Europe Limited was placed under the administration process in the United Kingdom (a process similar to bankruptcy proceedings in the United States) and continues under this process as of March 31, 2007. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

Other Guarantees

As part of arrangements through which the Company obtains exclusive sales representation agreements with small coal mining companies (the “Counterparties”), the Company issued financial guarantees on behalf of the Counterparties. These guarantees facilitate the Counterparties’ efforts to obtain financing or bonding. The Company issued financial guarantees on behalf of a certain Counterparty to facilitate its efforts in obtaining financing for equipment purchases and guaranteed bonding for a partnership in which the Company formerly held an interest. The Company also issued a guarantee for certain equipment lease arrangements on behalf of one of the sales representation parties. The aggregate amount guaranteed by the Company for all such Counterparties was $14.6 million, and the fair value of the guarantees recognized as a liability was $0.4 million as of March 31, 2007. The Company’s obligations under the guarantees extend to September 2015.

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 assumes 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. See Note 7 for the descriptions of the Company’s (and its subsidiaries’) debt. Supplemental guarantor/non-guarantor financial information is provided in Note 13.

(13) Supplemental Guarantor/Non-Guarantor Financial Information

In accordance with the indentures governing the 6.875% Senior Notes due March 2013, the 5.875% Senior Notes due March 2016, the 7.375% Senior Notes due November 2016 and the 7.875% Senior Notes due November 2026, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed these Senior Notes, on a joint and several basis. The following historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Three Months Ended March 31, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Total revenues	$	—		$	1,023,373		$	366,405		$	(24,607	)	$	1,365,171

Costs and expenses:
Operating costs and expenses		(610	)		824,570			292,428			(24,607	)		1,091,781
Depreciation, depletion and amortization		—			75,693			27,169			—			102,862
Asset retirement obligation expense		—			11,037			338			—			11,375
Selling and administrative expenses		6,157			35,672			802			—			42,631
Other operating income:
Net (gain) loss on disposal of assets		—			(36,744	)		95			—			(36,649	)
(Income) loss from equity affiliates		—			1,517			(3,677	)		—			(2,160	)
Interest expense		70,091			13,526			6,284			(31,123	)		58,778
Interest income		(4,680	)		(24,024	)		(7,809	)		31,123			(5,390	)

Income (loss) before income taxes and minority interests		(70,958	)		122,126			50,775			—			101,943
Income tax provision (benefit)		(25,985	)		33,568			5,031			—			12,614
Minority interests		—			—			823			—			823

Net income (loss)	$	(44,973	)	$	88,558		$	44,921		$	—		$	88,506

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Three Months Ended March 31, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Total revenues	$	—		$	1,026,857		$	311,520		$	(26,567	)	$	1,311,810

Costs and expenses:
Operating costs and expenses		(4,950	)		808,915			244,944			(26,567	)		1,022,342
Depreciation, depletion and amortization		—			69,095			11,869			—			80,964
Asset retirement obligation expense		—			6,982			233			—			7,215
Selling and administrative expenses		4,546			41,305			675			—			46,526
Other operating income:
Net gain on disposal of assets		—			(9,015	)		(211	)		—			(9,226	)
Income from equity affiliates		—			(3,766	)		(3,486	)		—			(7,252	)
Interest expense		40,092			15,140			3,951			(31,783	)		27,400
Interest income		(5,902	)		(20,980	)		(7,507	)		31,783			(2,606	)

Income (loss) before income taxes and minority interests		(33,786	)		119,181			61,052			—			146,447
Income tax provision (benefit)		(9,724	)		12,225			9,065			—			11,566
Minority interests		—			—			4,659			—			4,659

Net income (loss)	$	(24,062	)	$	106,956		$	47,328		$	—		$	130,222

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Balance Sheets


	March 31, 2007
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Assets
Current assets
Cash and cash equivalents	$	230,894	$	9,469		$	54,964		$	—		$	295,327
Accounts receivable		522		(14,290	)		291,830			—			278,062
Inventories		—		158,396			59,167			—			217,563
Assets from coal trading activities		—		162,018			—			—			162,018
Deferred income taxes		—		106,967			—			—			106,967
Other current assets		59,630		41,567			19,463			—			120,660

Total current assets		291,046		464,127			425,424			—			1,180,597
Property, plant, equipment and mine development — at cost		—		7,091,360			2,656,960			—			9,748,320
Less accumulated depreciation, depletion and amortization		—		(1,869,918	)		(215,381	)		—			(2,085,299	)
Goodwill		—		—			240,667			—			240,667
Investments and other assets		7,390,929		65,858			62,433			(7,063,152	)		456,068

Total assets	$	7,681,975	$	5,751,427		$	3,170,103		$	(7,063,152	)	$	9,540,353


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	26,433	$	1,282		$	6,162		$	—		$	33,877
Payables and notes payable to affiliates, net		2,048,771		(2,141,975	)		93,204			—			—
Liabilities from coal trading activities		—		123,665			—			—			123,665
Accounts payable and accrued expenses		58,927		701,617			349,952			—			1,110,496

Total current liabilities		2,134,131		(1,315,411	)		449,318			—			1,268,038
Long-term debt, less current maturities		2,985,835		11,634			173,497			—			3,170,966
Deferred income taxes		37,951		(24,150	)		191,021			—			204,822
Other noncurrent liabilities		17,782		2,307,717			88,353			—			2,413,852

Total liabilities		5,175,699		979,790			902,189			—			7,057,678
Minority interests		—		—			33,556			—			33,556
Stockholders’ equity		2,506,276		4,771,637			2,234,358			(7,063,152	)		2,449,119

Total liabilities and stockholders’ equity	$	7,681,975	$	5,751,427		$	3,170,103		$	(7,063,152	)	$	9,540,353

Peabody Energy Corporation
Supplemental Condensed Consolidated Balance Sheets


	December 31, 2006
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Assets
Current assets
Cash and cash equivalents	$	272,226	$	3,652		$	50,633		$	—		$	326,511
Accounts receivable		—		41,199			317,043			—			358,242
Inventories		—		146,920			68,464			—			215,384
Assets from coal trading activities		—		150,373			—			—			150,373
Deferred income taxes		—		106,967			—			—			106,967
Other current assets		54,007		41,221			21,635			—			116,863

Total current assets		326,233		490,332			457,775			—			1,274,340
Property, plant, equipment and mine development — at cost		—		6,964,886			2,572,313			—			9,537,199
Less accumulated depreciation, depletion and amortization		—		(1,794,823	)		(190,859	)		—			(1,985,682	)
Goodwill		—		—			240,667			—			240,667
Investments and other assets		7,235,765		34,195			100,115			(6,922,543	)		447,532

Total assets	$	7,561,998	$	5,694,590		$	3,180,011		$	(6,922,543	)	$	9,514,056


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	27,350	$	60,522		$	7,885		$	—		$	95,757
Payables and notes payable to affiliates, net		2,025,605		(2,170,567	)		144,962			—			—
Liabilities from coal trading activities		—		126,731			—			—			126,731
Accounts payable and accrued expenses		46,748		759,002			299,131			—			1,104,881

Total current liabilities		2,099,703		(1,224,312	)		451,978			—			1,327,369
Long-term debt, less current maturities		3,017,107		12,373			172,512			—			3,201,992
Deferred income taxes		29,094		(25,077	)		191,196			—			195,213
Other noncurrent liabilities		20,411		2,294,247			102,961			—			2,417,619

Total liabilities		5,166,315		1,057,231			918,647			—			7,142,193
Minority interests		—		—			33,337			—			33,337
Stockholders’ equity		2,395,683		4,637,359			2,228,027			(6,922,543	)		2,338,526

Total liabilities and stockholders’ equity	$	7,561,998	$	5,694,590		$	3,180,011		$	(6,922,543	)	$	9,514,056

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows


	Three Months Ended March 31, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in thousands)
Cash Flows From Operating Activities
Net cash provided by (used in) operating activities	$	(24,085	)	$	137,901		$	133,157		$	246,973


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(72,565	)		(62,088	)		(134,653	)
Federal coal lease expenditures		—			(59,829	)		—			(59,829	)
Additions to advance mining royalties		—			(2,557	)		—			(2,557	)
Proceeds from disposal of assets, net of notes receivable		—			16,337			114			16,451
Investment in joint venture		—			(622	)		—			(622	)

Net cash used in investing activities		—			(119,236	)		(61,974	)		(181,210	)


Cash Flows From Financing Activities
Payments of long-term debt		(31,475	)		(60,472	)		(1,199	)		(93,146	)
Dividends paid		(15,881	)		—			—			(15,881	)
Increase of securitized interests in accounts receivable		—			—			5,800			5,800
Proceeds from employee stock purchases		3,097			—			—			3,097
Excess tax benefit related to stock options exercised		2,510			—			—			2,510
Proceeds from stock options exercised		2,378			—			—			2,378
Distributions to minority interests		—			—			(875	)		(875	)
Payment of debt issuance costs		—			(830	)		—			(830	)
Transactions with affiliates, net		22,124			48,454			(70,578	)		—

Net cash used in financing activities		(17,247	)		(12,848	)		(66,852	)		(96,947	)


Net increase (decrease) in cash and cash equivalents		(41,332	)		5,817			4,331			(31,184	)
Cash and cash equivalents at beginning of year		272,226			3,652			50,633			326,511

Cash and cash equivalents at end of year	$	230,894		$	9,469		$	54,964		$	295,327

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows


	Three Months Ended March 31, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in thousands)
Cash Flows From Operating Activities
Net cash provided by (used in) operating activities	$	(46,395	)	$	(13,681	)	$	109,128		$	49,052


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(69,939	)		(17,520	)		(87,459	)
Federal coal lease expenditures		—			—			(59,829	)		(59,829	)
Additions to advance mining royalties		—			(2,250	)		—			(2,250	)
Proceeds from disposal of assets		—			11,071			417			11,488
Other acquisitions, net		—			—			(44,538	)		(44,538	)

Net cash used in investing activities		—			(61,118	)		(121,470	)		(182,588	)


Cash Flows From Financing Activities
Payments of long-term debt		(2,500	)		(10,183	)		(223	)		(12,906	)
Dividends paid		(15,869	)		—			—			(15,869	)
Proceeds from employee stock purchases		1,772			—			—			1,772
Excess tax benefit related to stock options exercised		13,096			—			—			13,096
Proceeds from stock options exercised		6,051			—			—			6,051
Distributions to minority interests		—			—			(1,000	)		(1,000	)
Proceeds from long-term debt		—			—			750			750
Common stock repurchase		(11,476	)		—			—			(11,476	)
Transactions with affiliates, net		(92,311	)		48,771			43,540			—

Net cash provided by (used in) financing activities		(101,237	)		38,588			43,067			(19,582	)


Net increase (decrease) in cash and cash equivalents		(147,632	)		(36,211	)		30,725			(153,118	)
Cash and cash equivalents at beginning of year		494,232			2,471			6,575			503,278

Cash and cash equivalents at end of year	$	346,600		$	(33,740	)	$	37,300		$	350,160

(14) Subsequent Events

On April 19, 2007, the Company announced that it is evaluating strategic alternatives regarding its operations in West Virginia and Kentucky. The review is expected to result in a spinoff or other transaction involving these assets to enhance long-term shareholder value. Any proposed transaction would be subject to approval by the Company’s Board of Directors. The timetable and other details of the proposed transaction are expected to be determined in the second quarter of 2007. The assets and operations in the transactions under consideration would consist of a portion of the Company’s Eastern U.S. Mining Operations business segment.

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

Cautionary Notice Regarding Forward-Looking Statements

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

Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject 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:

•		ability to renew sales contracts;

•		reductions of purchases by major customers;

•		transportation performance and costs, including demurrage;

•		geology, equipment and other risks inherent to mining;

•		weather;

•		legislation, regulations and court decisions;

•		new environmental requirements affecting the use of coal including mercury and carbon dioxide related limitations;

•		changes in postretirement benefit and pension obligations;

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

•		availability, timing of delivery and costs of key supplies, capital equipment or commodities such as diesel fuel, steel, explosives and tires;

•		replacement of coal reserves;

•		price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses;

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

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

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

•		risks associated with customer contracts, including credit and performance risk;

•		the effects of acquisitions or divestitures, including integration of new acquisitions;

•		form, extent and timing of divestiture of a portion of our Eastern U.S. Mining Operations;

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

•		risks associated with our Btu conversion or generation development initiatives;

•		risks associated with the conversion of our current information systems;

•		growth of domestic and international coal and power markets;

•		coal’s market share of electricity generation;

•		prices of fuels which compete with or impact coal usage, such as oil or natural gas;

•		future worldwide economic conditions;

•		successful implementation of business strategies;

•		variation in revenues related to synthetic fuel production due to expiration of related tax credits at the end of 2007;

•		the effects of changes in currency exchange rates, primarily the Australian dollar;

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

•		interest rate changes;

•		litigation, including claims not yet asserted;

•		terrorist attacks or threats;

•		impacts of pandemic illnesses;

•		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 and in our other Securities and Exchange Commission (“SEC”) filings, including the more detailed discussion of these factors, as well as other factors that could affect our results, contained in Item 1A, Risk Factors of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006. We do not undertake any obligation to update these statements, except as required by federal securities laws.

Overview

We are the largest private sector coal company in the world, with majority interests in 40 coal operations located throughout all major U.S. coal producing regions and internationally in Australia and Venezuela. In the first quarter of 2007, we sold 60.9 million tons of coal. In 2006, we sold 247.6 million tons of coal, which was approximately 38% greater than the sales of our closest competitor. Our domestic sales represented 22% of all U.S. coal sales and was approximately 80% greater than the sales of our closest domestic competitor. Based on Energy Information Administration (“EIA”) estimates, demand for coal in the United States was approximately 1.1 billion tons in 2006. Domestic coal consumption is expected to grow at an average rate of 1.8% per year through 2030 when U.S. coal demand is forecasted to be 1.8 billion tons. Coal-fueled generation is used in most cases to meet baseload electricity requirements. Electricity growth is expected to average 1.5% annually through 2030. Coal production located west of the Mississippi River is projected to provide most of the incremental growth as Western production increases to an estimated 68% share of total production in 2030. In 2006, coal’s share of electricity generation was approximately 50%, a share that the EIA projects will grow to 57% by 2030.

Our primary customers are U.S. utilities, which accounted for 87% of our sales in 2006. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2006, approximately 90% of our sales were under long-term contracts. As of March 31, 2007, we expect full year 2007 production of 240 to 260 million tons and have essentially sold out of planned production for 2007. As discussed more fully in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, our results of operations in the near-term could be negatively impacted by poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations, 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 our Eastern U.S. Mining operations consist of our Appalachia and Midwest operations. The principal business of the Western U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to U.S. electric utilities. The principal business of the Eastern U.S. Mining segment 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, located in the United States, Europe and South America.

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 predominantly underground extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances).

Australian Mining operations are characterized by both surface and underground extraction processes, mining various qualities of high-quality metallurgical coal as well as low-sulfur steam coal primarily sold to an international customer base with a small portion sold to Australian steel producers and power generators.

We own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine produces approximately 6 to 8 million tons of steam coal annually for export to the United States and Europe. During the first quarter of 2007, our interest in Carbones del Guasare contributed $3.7 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA” and paid a dividend of $12.9 million. At March 31, 2007, our investment in Paso Diablo was $50.9 million. Each of our mining operations is described in Item 1. Business, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

Metallurgical coal is produced primarily from four of our Australian mines and two of our U.S. mines. Metallurgical coal is approximately 5% of our total sales volume and approximately 3% of U.S. sales volume.

In addition to our mining operations, which comprised 87% of revenues in 2006, our trading and brokerage operations (13% of revenues), transactions utilizing our vast natural resource position (selling non-core land holdings and mineral interests) and other ventures generate revenues and additional cash flows.

We continue to pursue the development of 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. The projects involve mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal sales. The projects we are currently pursuing include the 1,600-megawatt Prairie State Energy Campus in Washington County, Illinois and the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky. The plants, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, could be operational following a four-year construction phase.

The EIA projects that the high price of oil will lead to an increase in demand for unconventional sources of transportation fuel, including Btu conversion technologies, and that coal will increase its share as a fuel for generation of electricity. We are exploring several Btu conversion projects, which are designed to expand the uses of coal through various technologies, and we are continuing to explore options particularly as they relate to Btu conversion technologies such as coal-to-liquids and coal-to-gas.

On April 19, 2007, we announced that we are evaluating strategic alternatives regarding our operations in West Virginia and Kentucky. The review is expected to result in a spinoff or other transaction involving these assets to enhance long-term shareholder value. Any proposed transaction would be subject to approval by our Board of Directors. The timetable and other details of the proposed transaction are expected to be determined in the second quarter of 2007. The assets and operations in the transactions under consideration would consist of a portion of our Eastern U.S. Mining Operations business segment.

The majority of our Eastern workforce, represented by the United Mine Workers of America, operate under a recently signed, five-year labor agreement expiring December 31, 2011. This contract replaced a contract that had expired on December 31, 2006 and mirrors the 2007 National Bituminous Coal Wage Agreement. In April 2007, a new labor agreement was ratified for our hourly workforce at the Willow Lake underground mine, which is represented by the International Brotherhood of Boilermakers. The new 4-year labor agreement expires on April 15, 2011. The impact of these new labor agreements will result in higher wage, pension, and retiree healthcare costs of approximately $30 million for 2007.

Results of Operations

Adjusted EBITDA

The discussion of our results of operations below includes references to and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from operations before deducting 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 10 to our condensed consolidated financial statements.

Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006

Summary

Higher average sales prices in the Powder River Basin and increased volumes in Australian Mining operations contributed to a 4.1% increase in revenues to $1.37 billion in the first quarter of 2007 compared to 2006. Segment Adjusted EBITDA decreased 1.3%, or $4.2 million, primarily related to lower sales volumes resulting from extreme winter weather conditions in our U.S. Mining operations, port and rail constraints in our Australian Mining operations, higher costs primarily due to geology issues and the effects of currency translation related to the weak U.S. dollar. Partially offsetting these decreases were improved results from Trading and Brokerage operations, the contribution from new mines in Australia, and higher prices in our Western U.S. Mining operations. Net income was $88.5 million in the first quarter of 2007, or $0.33 per diluted share, a decrease of 32.0% over 2006 net income of $130.2 million, or $0.48 per diluted share. Net income for the first quarter of 2007 includes higher depreciation, depletion and amortization of $21.9 million primarily from our newly acquired mines and additional interest expense of $31.4 million associated with approximately $1.7 billion in new debt issuances in the second half of 2006 to finance the acquisition of Excel Coal Limited (“Excel”). The Excel acquisition is not expected to be accretive to earnings until the mines under development are fully operational.

Tons Sold

The following table presents tons sold by operating segment for the three months ended March 31, 2007 and 2006:


	Three Months Ended March 31,				Increase (Decrease)
	2007		2006		Tons			%
	(Tons in millions)
Western U.S. Mining Operations		37.9		39.8		(1.9	)		(4.8	)%
Eastern U.S. Mining Operations		13.5		13.7		(0.2	)		(1.5	)%
Australian Mining Operations		5.0		1.9		3.1			163.2	%
Trading and Brokerage Operations		4.5		6.0		(1.5	)		(25.0	)%

Total tons sold		60.9		61.4		(0.5	)		(0.8	)%

Revenues

The following table presents revenues for the three months ended March 31, 2007 and 2006:


	Three Months Ended March 31,				Increase to Revenues
	2007		2006		$		%
	(Dollars in thousands)
Sales	$	1,314,815	$	1,288,906	$	25,909		2.0	%
Other revenues		50,356		22,904		27,452		119.9	%

Total revenues	$	1,365,171	$	1,311,810	$	53,361		4.1	%

Our first quarter 2007 total revenues increased $53.4 million, or 4.1%, compared to prior year. The primary drivers of the increase were higher volumes in Australia and average sales price increases of 16.9% in our Western U.S. Mining operations. Volumes from recently acquired Australian mines accounted for 2.8 million tons of the increase in tons sold and approximately 85% of the sales increase in Australia (discussed below). Partially offsetting these volume and average sales price increases were lower volumes in our Western U.S. Mining operations related to a blizzard in the Powder River Basin that effectively shut down operations and transportation for several days, equipment issues and availability of trains, and lower volumes in our Eastern U.S Mining operations related to equipment and geology issues.

Brokerage operations’ sales decreased $156.2 million in the current quarter compared to prior year as the amount of brokerage business was reduced and replacement business was in the form of traded contracts. Contracts for trading activity are recorded at net margin in other revenues, and contracts for brokerage activity are recorded at gross sales price to revenues and operating costs. While the shift to trading contracts reduced total revenues by approximately $125 million, there was little to no impact to Adjusted EBITDA.

Sales increased $25.9 million, or 2.0%, during the first quarter of 2007. Included in the increase was $48.6 million from Western U.S. Mining sales, and $133.2 million from Australian Mining sales, partially offset by a decrease of $156.2 million from our brokerage operations. Overall, average sales prices in our Western U.S. Mining operations increased, mainly reflecting an increase of almost 24% per ton in the Powder River Basin. These increases from our Powder River Basin operations resulted from higher prices on contracts signed in the prior year that are replacing legacy contracts as they reprice or expire, and were partially offset by lower volumes due to weather, equipment issues and higher repairs and maintenance costs. On average, per ton sales prices in our Eastern U.S. Mining operations increased 2.1%, driven by higher contract pricing in certain regions. Sales volumes were flat in our Eastern U.S. Mining operations compared to the first quarter of prior year due to lower production caused by equipment and geologic issues. Sales from our Australian Mining operations were $133.2 million, or 87.2%, higher than the prior year, primarily due to additional volumes from our newly acquired mines, timing of shipments, and higher realized metallurgical pricing compared to the first quarter of 2006. Overall, average sales prices in our Australian Mining operations declined due to higher thermal product sales in the mix.

Other revenues for the first quarter of 2007 increased $27.5 million, or 119.9%, compared to prior year primarily due to proceeds received from the monetization of in-the-money contracts with third-party coal producers and the shift toward trading contracts mentioned above.

Segment Adjusted EBITDA

Our total segment Adjusted EBITDA was $320.1 million for the three months ended March 31, 2007, compared with $324.3 million in the prior year. Details were as follows:


					Increase (Decrease)
	Three Months Ended March 31,				to Segment Adjusted EBITDA
	2007		2006		$			%
	(Dollars in thousands)
Western U.S. Mining Operations	$	139,648	$	127,793	$	11,855			9.3	%
Eastern U.S. Mining Operations		81,043		132,544		(51,501	)		(38.9	)%
Australian Mining Operations		62,561		47,756		14,805			31.0	%
Trading and Brokerage Operations		36,835		16,179		20,656			127.7	%

Total Segment Adjusted EBITDA	$	320,087	$	324,272	$	(4,185	)		(1.3	)%

Adjusted EBITDA from our Western U.S. Mining operations increased $11.9 million, or 9.3%, during the first quarter of 2007 primarily related to an overall increase in average sales prices from our Powder River Basin operations and a 27.7% increase in our premium product prices from our Powder River Basin operations. Partially offsetting higher average sales prices were lower sales volumes due to weather and equipment issues and the timing of repairs and maintenance. The Western U.S. Mining operations experienced higher per ton costs also related to lower volumes driven by a blizzard that effectively shut down Powder River Basin shipments and operations during the last week of March, equipment issues and higher add-on taxes and royalties.

Eastern U.S. Mining operations’ Adjusted EBITDA decreased $51.5 million, or 38.9%, during the first quarter of 2007 compared to prior year. Modest increases in average sales prices were offset by the loss of a contract miner and an increase in cost per ton of $4.46, or 16.0%, due to higher costs associated with production shortfalls stemming from geology at several of our mines, including a metallurgical coal mine; commodities, including fuel; and equipment. Results in the first quarter of 2006 also reflected favorable sulfur premiums and an $8.9 million settlement of customer billings regarding coal quality.

Our Australian Mining operations’ Adjusted EBITDA increased $14.8 million, or 31.0%, during the first quarter of 2007 compared to prior year primarily due to a $22.3 million contribution from our newly acquired mines, higher metallurgical coal prices and higher volumes from two of our metallurgical mines as well as a $6.3 million insurance recovery on a business interruption claim. Partially offsetting these increases were higher costs of approximately $10 million each resulting from the weakening of the U.S. dollar in the quarter and higher costs for demurrage related to port congestion at coal export terminals.

Trading and Brokerage operations’ Adjusted EBITDA increased $20.7 million during the first quarter of 2007 compared to prior year due to proceeds from the monetization of in-the-money contracts with third-party coal producers and contributions from newly established international trading operations. Trading contracts may be financially or physically settled. During the first quarter of 2007, while the total tons settled under trading contracts remained essentially the same as prior year, financially settled contracts increased by approximately 1.5 million tons with a corresponding decrease in physically settled contracts.

Income Before Income Taxes and Minority Interests


							Increase (Decrease)
	Three Months Ended March 31,						to Income
	2007			2006			$			%
	(Dollars in thousands)
Total Segment Adjusted EBITDA	$	320,087		$	324,272		$	(4,185	)		(1.3	)%
Corporate and Other Adjusted EBITDA		(50,519	)		(64,852	)		14,333			22.1	%
Depreciation, depletion and amortization		(102,862	)		(80,964	)		(21,898	)		(27.0	)%
Asset retirement obligation expense		(11,375	)		(7,215	)		(4,160	)		(57.7	)%
Interest expense		(58,778	)		(27,400	)		(31,378	)		(114.5	)%
Interest income		5,390			2,606			2,784			106.8	%

Income before income taxes and minority interests	$	101,943		$	146,447		$	(44,504	)		(30.4	)%

Income before income taxes and minority interests for the first quarter of 2007 was $44.5 million, or 30.4%, lower than the prior year primarily due to higher interest expense and depreciation, depletion and amortization, partially offset by lower net expense in Corporate and Other Adjusted EBITDA.

Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our joint ventures, 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, Btu conversion and resource management. The $14.3 million improvement in Corporate and Other Adjusted EBITDA during the first quarter of 2007 compared to 2006 includes the following:

	•		Higher gains on asset disposals of $27.4 million. The first quarter of 2007 activity included a gain of $34.9 million from the sale of non-strategic coal reserves and surface lands located in Kentucky, compared to gains on asset disposals of $9.2 million in the prior year;

	•		Lower selling and administrative expenses of $3.9 million resulted primarily from lower equity-based performance incentive costs;

	•		Lower equity income of $5.1 million due to trucking issues impacting operations from our 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela; and

•

Higher net expenses of $13.7 million primarily associated with higher past mining obligations and provision for legal costs. Higher past mining obligations resulted from increased healthcare costs and costs associated with additional pension funding in accordance with the Surface Mining Control and Reclamation Act Amendments of 2006.

Depreciation, depletion and amortization increased $21.9 million during the first quarter of 2007 primarily related to the addition of recently acquired Australian operations.

Interest expense increased $31.4 million primarily due to approximately $1.7 billion in new debt issuances in the second half of 2006 to finance the acquisition of Excel.

Net Income


							Increase (Decrease)
	Three Months Ended March 31,						to Income
	2007			2006			$			%
	(Dollars in thousands)
Income before income taxes and minority interests	$	101,943		$	146,447		$	(44,504	)		(30.4	)%
Income tax provision		(12,614	)		(11,566	)		(1,048	)		(9.1	)%
Minority interests		(823	)		(4,659	)		3,836			82.3	%

Net income	$	88,506		$	130,222		$	(41,716	)		(32.0	)%

Net income decreased $41.7 million during the first quarter of 2007 compared to prior year due to the decrease in income before income taxes and minority interests discussed above. Minority interests decreased primarily from slightly lower earnings and a lower minority interest in our largest consolidated joint venture due to acquiring a larger share during 2006.

Outlook

Events Impacting Near-Term Operations

Global coal markets continued to grow, driven by increased demand from growing economies. International pricing for thermal coal has been strong and continues to increase. The U.S. economy grew at an annual rate of 3.5% based on fourth quarter 2006 data as reported by the U.S. Commerce Department, while China’s economy grew 11.1% in the first quarter of 2007 as published by the National Bureau of Statistics of China.

In October 2006, we acquired Excel, which included three operating mines, two late development-stage mines and a development-stage mine. These development stage mines are expected to begin shipments in 2007, and our 2007 results will be impacted to the extent we complete ramp up activities at these development stage mines on time and at expected capacity. Furthermore, port congestion at our two primary Australian shipping points, Dalrymple Bay Coal Terminal and Port of Newcastle, is causing significant queuing of vessels, which could result in delayed shipments and demurrage charges. Congestion at Australia coal export terminals led to mandatory reductions of throughput entitlements for coal shippers, ranging from 10-15% for the remainder of 2007.

We expect our Eastern second quarter results will be impacted by planned outages, two longwall moves and continued geology issues, partially offset by the start-up of our new Black Stallion mine. Prices appear to be strengthening in Central Appalachia as overall production declined 10% compared to prior year and a recent court ruling related to future valley fill permits in the region may also impact production.

Although we expect to increase our shipment levels from our Powder River Basin operations in 2007 compared with 2006, our ability to reach these targeted shipment levels is dependent upon our ability to load trains as they become available and the completion of key capital projects. While Powder River Basin pricing has retreated from its highs in the first quarter of 2006, prices have firmed recently.

In the United States we are targeting our investments to improve productivity and lower costs in the Powder River Basin with a new dragline, in-pit conveyor and blending system. Additional capital projects are targeted for the expansion of our international platform, including the completion of three new Australian mines.

Long-term Outlook

Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, as long as growth continues in the U.S., Asia and other undeveloped economies that are increasing coal demand for electricity generation and steelmaking. Approximately 155 gigawatts of new coal-fueled electricity generating capacity is scheduled to come on line around the world over the next three years, and the EIA projects an additional 156 gigawatts of new U.S. coal-fueled generation by 2030, which by itself could represent more than 500 million tons of additional coal demand.

Metallurgical coal continued to sell at a significant premium to steam coal. Metallurgical markets, while off record pricing levels, remain strong as seaborne metallurgical coal prices for the upcoming fiscal year were settled from a reference price near $100 per metric ton and as China steel production shows signs of continued growth over 2005 levels. We expect to capitalize on the strong global market for metallurgical coal primarily through production and sales of metallurgical coal from our Appalachia and Australian operations. In response to growing international markets, we established an international trading group in 2006 and added a trading office in Europe in early 2007.

Coal-to-gas and coal-to-liquids (“CTL”) plants represent an emerging opportunity for long-term industry growth. The EIA continues to project an increase in demand for unconventional sources of transportation fuel, including coal-to-liquids, and in the U.S. coal-to-liquid technologies are receiving growing bipartisan U.S. support as demonstrated by the newly introduced CTL bills such as the “Coal-to-Liquid Fuel Promotion Act” within the Senate. Coal-to-gas and CTL facilities are being built and operated outside the United States as alternatives to high-priced conventional oil and gas.

Demand for Powder River Basin coal remains strong, particularly for our ultra-low sulfur products. The Powder River Basin represents more than half of our production. We control approximately 3.5 billion tons of proven and probable reserves in the Southern Powder River Basin, and we sold 138.4 million tons of coal from this region during 2006, an increase of 10.1% over the prior year.

As of March 31, 2007, we expect full year 2007 production of 240 to 260 million tons and have essentially sold out of planned production for 2007. Our total unpriced planned production for 2008 is approximately 60 to 70 million tons in the United States.

Management plans to aggressively control costs and operating performance to mitigate external cost pressures, geologic conditions and potentially adverse port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel, tires, contract mining, new wage agreements and healthcare, and have taken measures to mitigate the increases in these costs, including a company-wide initiative to instill best practices at all operations. In addition, historically low long-term interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. In spite of our efforts to manage controllable costs, we expect a year-over-year increase in these costs of approximately $90 million. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage source performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See “Cautionary Notice Regarding Forward-Looking Statements” and Item 1A. Risk Factors for additional cautionary factors regarding our outlook.

Liquidity and Capital Resources

Our primary sources of cash include sales of our coal production to customers, cash generated from our trading and brokerage activities, sales of non-core assets and financing transactions, including the sale of our accounts receivable (through our securitization program). Our primary uses of cash include our cash costs of coal production, capital expenditures, interest costs and costs related to past mining obligations as well as planned acquisitions. Our ability to pay dividends, service our debt (interest and principal) and acquire new productive assets or businesses is dependent upon our ability to continue to generate cash from the primary sources noted above in excess of the primary uses. Future dividends, among other things, are subject to limitations imposed by our Senior Notes and Debenture covenants. We expect to fund all of our capital expenditure requirements with cash generated from operations.

Net cash provided by operating activities for the three months ended March 31, 2007 increased $197.9 million compared to the prior year.

Net cash used in investing activities decreased $1.4 million for the three months ended March 31, 2007 compared to the prior year. The slight decrease reflects higher capital spending of $47.2 million in 2007 offset by the acquisition of an additional interest in a joint venture for $44.5 million in 2006. Capital expenditures in 2007 included mine development at our recently acquired Australian mines and an in–pit conveyor and blending system at one of our Western mines.

Net cash used for financing activities increased $77.3 million compared to the prior year. The increase primarily related to the repayment of $93.1 million of debt that included a $60.0 million retirement of our 5.0% Subordinated Note; an $18.3 million prepayment on our outstanding balance of the Term Loan under the Senior Unsecured Credit Facility; and a $13.8 million open-market purchase of 5.875% Senior Notes. Also contributing to the increase in net cash used in financing activities were lower proceeds from the exercise of stock options and lower tax benefit related to stock option exercises. The prior year includes payments for common stock repurchases of $11.5 million and higher usage of our accounts receivable securitization program of $5.8 million.

Our total indebtedness as of March 31, 2007 and December 31, 2006, consisted of the following:


	March 31,			December 31,
	2007			2006
	(Dollars in thousands)
Term Loan under Senior Unsecured Credit Facility	$	528,662		$	547,000
Convertible Junior Subordinated Debentures due 2066		732,500			732,500
7.375% Senior Notes due 2016		650,000			650,000
6.875% Senior Notes due 2013		650,000			650,000
7.875% Senior Notes due 2026		246,913			246,897
5.875% Senior Notes due 2016		218,090			231,845
5.0% Subordinated Note		—			59,504
6.84% Series C Bonds due 2016		43,000			43,000
6.34% Series B Bonds due 2014		21,000			21,000
6.84% Series A Bonds due 2014		10,000			10,000
Capital lease obligations		95,950			96,869
Fair value of interest rate swaps		(13,898	)		(13,784	)
Other		22,626			22,918


Total	$	3,204,843		$	3,297,749

As of March 31, 2007, the Revolving Credit Facility’s remaining available borrowing capacity under the Senior Unsecured Credit Facility was $1.38 billion.

Capital Lease Obligations

As of December 31, 2006, “Capital lease obligations” reflects an additional $40.2 million that was previously classified as “Accounts payable and accrued expenses” on the consolidated balance sheet in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006. The reclassification relates to a capital lease transaction structure that was finalized during the three months ended March 31, 2007.

Interest Rate Swaps

To limit the impact of interest rate changes on earnings and cash flows, we manage fixed-rate debt as a percentage of net debt through the use of various hedging instruments.

During the three months ended March 31, 2007, we entered into several fixed-to-floating interest rate swaps. The first group of three interest rate swaps had combined notional amounts totaling $200.0 million and was designated to hedge changes in fair value of the 6.875% Senior Notes due 2013. Under the swaps, we pay a floating rate that resets each March 15 and September 15 based upon the six-month LIBOR rate for a period of six years ending March 15, 2013 and receives a fixed rate of 6.875%. The second group of two interest rate swaps had combined notional amounts totaling $100.0 million and was designated to hedge changes in fair value of the 5.875% Senior Notes due 2016. Under the swaps, we pay a floating rate that resets each April 15 and October 15 based upon the six-month LIBOR rate for a period of nine years ending April 15, 2016 and receives a fixed rate of 5.875%.

The above interest rate swaps were in addition to those we entered into in previous years, including the following: five fixed-to-floating interest rate swaps with combined notional amounts totaling $220.0 million that were designated to hedge changes in fair value of the 6.875% Senior Notes due 2013; and a $120.0 million notional amount floating-to-fixed interest rate swap with a fixed rate of 6.25% and a floating rate of LIBOR plus 1.0% that was designated to hedge changes in expected cash flows on the Term Loan under the Senior Unsecured Credit Facility.

Third-party Security Ratings

The ratings for our senior unsecured credit facility and our senior unsecured notes are as follows: Moody — Ba1 rating, Standard & Poor — BB rating and Fitch — BB+ rating. The ratings on our convertible junior subordinated debentures were as follows: Moody — Ba3 rating (downgraded from a Ba2 rating at December 31, 2006 due to changes in Moody’s methodology for evaluating the instrument), Standard & Poor — B rating and Fitch — BB- rating. These security ratings reflected the views of the rating agencies only. An explanation of the significance of these ratings may be obtained from the rating agencies. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Contractual Obligations

The following table updates, as of March 31, 2007, our capital lease obligations as presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006. The obligations changed due to a capital lease finalized during the three months ended March 31, 2007.


	Payments Due By Year
	Within		2 - 3		4 - 5		After
	1 Year		Years		Years		5 Years
	(dollars in thousands)
Capital lease obligations (principal and interest)	$	4,942	$	13,528	$	13,528	$	24,734

We do not expect any of the $135 million of unrecognized tax benefits reported in our condensed consolidated financial statements to require cash settlement within the next year. Beyond that, we are unable to make reasonably reliable estimates of periodic cash settlements with respect to such unrecognized tax benefits.

As of March 31, 2007, we had $75.0 million of purchase obligations for capital expenditures and $419.9 million of obligations related to federal coal reserve lease payments due over the next three years. Total capital expenditures for 2007 are expected to range from $450 million to $525 million, excluding federal coal reserve lease payments, and relate to replacement, improvement, or expansion of existing mines and growth initiatives. Capital expenditures were funded 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 condensed 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.

Under our accounts receivable securitization program, undivided interests in a pool of eligible trade receivables 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 utilize proceeds from the sale of our accounts receivable as an alternative to other forms of debt, effectively reducing our overall borrowing costs. The securitization program is scheduled to expire in September 2009. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the condensed consolidated balance sheets. The amount of undivided interests in accounts receivable sold to the Conduit was $225.0 million as of March 31, 2007 and $219.2 million as of December 31, 2006.

There were no other material changes to our off-balance sheet arrangements during the three months ended March 31, 2007. See Note 12 to our unaudited condensed consolidated financial statements included in this report for a discussion of our guarantees. Our off-balance sheet arrangements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

Newly Adopted Accounting Pronouncements

In June 2006, the FASB issued Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN No. 48”). This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

We adopted the provisions of FIN No. 48 on January 1, 2007 with no impact to retained earnings. As a result of adoption, we have $135 million of unrecognized tax benefits in our condensed consolidated financial statements. We do not expect any significant increases or decreases to our unrecognized tax benefits within 12 months of this reporting date that would affect our effective tax rate, if recognized.

Due to the existence of net operating loss (“NOL”) carryforwards, we have not currently accrued interest on any of our unrecognized tax benefits. We have considered the application of penalties on our unrecognized tax benefits and have determined, based on several factors including the existence of our NOL carryforwards, that no accrual of penalties related to our unrecognized tax benefits is required. If the accrual of interest or penalties becomes appropriate, we will record an accrual in our income tax provision.

Our Federal income tax returns for the tax years 1999 and beyond remain subject to examination by the Internal Revenue Service. Our state income tax returns for the tax years 1991 and beyond remain subject to examination by various state taxing authorities. Our foreign income tax returns for the tax years 2003 and beyond remain subject to examination by various foreign taxing authorities.

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 condensed consolidated financial statements. Our trading portfolio included forwards and swaps as of March 31, 2007 and December 31, 2006.

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 5 to 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. Additionally, back-testing is regularly performed to monitor the effectiveness of our value at risk measure. 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, we believe 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 three months ended March 31, 2007, the actual low, high, and average values at risk for our coal trading portfolio were as follows:


	Domestic		International
	(Dollars in thousands)
Low	$	741	$	496
High		3,541		4,347
Average		2,104		3,180

As of March 31, 2007, the timing of the estimated future realization of the value of our trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2007		37	%
2008		38	%
2009		20	%
2010		4	%
2011		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 electric utilities, energy marketers and industrial customers. 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 other similar instruments. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into 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 to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2007 targets hedging approximately 70% of our anticipated, non-capital Australian dollar-denominated expenditures. As of March 31, 2007, we had in place forward contracts designated as cash flow hedges with notional amounts outstanding totaling A$1.15 billion of which A$563.0 million, A$359.7 million, A$196.7 million and A$28.8 million will expire in 2007, 2008, 2009, and 2010, respectively. Our current expectation for the remaining 2007 non-capital, Australian dollar-denominated cash expenditures is approximately A$972.1 million. An increase or decrease 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, respectively, in our “Operating costs and expenses” of $9.7 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, which are discussed in detail in Note 7 to our condensed consolidated financial statements. As of March 31, 2007, after taking into consideration the effects of interest rate swaps, we had $2.27 billion of fixed-rate borrowings and $930.3 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $9.3 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 $0.3 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 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. As of March 31, 2007, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel and explosives.

Notional amounts outstanding under fuel-related, derivative swap contracts were 10.8 million gallons of heating oil scheduled to expire through 2007 and 102.0 million gallons of crude oil scheduled to expire through 2010. At March 31, 2007, we had outstanding option contracts designated as a collar of crude oil prices with notional amounts of 32.7 million gallons, expiring through 2007. We expect to consume 100 to 105 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 $2.4 million.

Notional amounts outstanding under explosives-related swap contracts, scheduled to expire through 2010, were 6.2 mmbtu of natural gas. We expect to consume 315,000 to 325,000 tons of explosives per year. Through our natural gas hedge contracts, we have fixed prices for approximately 53% of our anticipated explosives requirements for 2007. Based on our expected usage, a change in natural gas prices of ten cents per mmbtu (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of approximately $0.4 million per year.

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 accumulated and communicated to senior management, including the Chief Executive Officer and Chief Financial Officer, on a timely basis. Under the direction of the Chief Executive Officer and Chief Financial Officer, management has evaluated our disclosure controls and procedures as of March 31, 2007 and has concluded that the disclosure controls and procedures were adequate and 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 11 to the unaudited condensed consolidated financial statements included in Part I. Item 1 of this report relating to certain legal proceedings, which information is incorporated by reference herein.

Item 1A. Risk Factors.

The form, extent and timing of divestiture of a portion of our Eastern U.S. Mining Operations are unknown.

On April 19, 2007, we announced that we are evaluating strategic alternatives regarding our operations in West Virginia and Kentucky. The review is expected to result in a spinoff or other transaction involving these assets. The timetable and other details of the proposed transaction are expected to be determined in the second quarter of 2007.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

In July 2005, our Board of Directors authorized a share repurchase program of up to 5% of the then outstanding shares of our common stock, approximately 13.1 million shares. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. There were no share repurchases made during the three months ended March 31, 2007 under the share repurchase program. In March 2007, the Company accepted shares as payment for the exercise of stock options.


					Total Number of
	Total				Shares Purchased		Maximum Number
	Number of		Average		as Part of Publicly		of Shares that May
	Shares		Price per		Announced		Yet Be Purchased
Period	Purchased		Share		Program		Under the Program
January 1 through January 31, 2007		—		—		—		10,920,605
February 1 through February 28, 2007		—		—		—		10,920,605
March 1 through March 31, 2007		585	$	40.24		—		10,920,605

Total		585	$	40.24		—

Item 6. Exhibits.

See Exhibit Index at page 36 of this report.

SIGNATURE

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


	PEABODY ENERGY CORPORATION
Date: May 4, 2007	By:	/s/ RICHARD A. NAVARRE
		Richard A. Navarre
		Chief Financial Officer and Executive Vice President of Corporate Development (On behalf of the registrant and as Principal Financial Officer)

EXHIBIT INDEX

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


Exhibit
No.		Description of Exhibit
3.1		Third Amended and Restated Certificate of Incorporation of the Registrant, as amended (Incorporated by reference to Exhibit 3.1 of the Registrant’s Quarterly Report on Form 10-Q for the period ended June 30, 2006).

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

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

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

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

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


*		Filed herewith.

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents