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 June 30, 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		(I.R.S. Employer
incorporation or organization)		Identification No.)

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

(Address of principal executive offices)		(Zip Code)

(314) 342-3400

(Registrant’s telephone number, including area code)

(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 265,506,092 shares of common stock with a par value of $0.01 per share outstanding at August 3, 2007.

INDEX


	Page
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Condensed Consolidated Statement of Earnings for the Three and Six Months Ended June 30, 2007 and 2006		2

Condensed Consolidated Balance Sheet as of June 30, 2007 (unaudited) and December 31, 2006		3

Unaudited Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 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		23

Item 3. Quantitative and Qualitative Disclosures About Market Risk		35

Item 4. Controls and Procedures		37

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		38

Item 1A. Risk Factors		38

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		38

Item 4. Submission of Matters to a Vote of Security Holders		39

Item 6. Exhibits		39

SIGNATURE

EXHIBIT INDEX
Senior Notes Due 2013 Fourteenth Supplemental Indenture
Senior Notes Due 2016 Eighteenth Supplemental Indenture
Senior Notes Due 2016 Nineteenth Supplemental Indenture
Senior Notes Due 2026 Twentieth Supplemental Indenture
Supplemental Employee Retirement Account
Second Amendment to Amended and Restated Receivables Purchase Agreement
Target Price Engineering, Procurement and Construction Agreement
Certification by CEO
Certification by CFO
Section 1350 Certification by CEO
Section 1350 Certification by CFO

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF EARNINGS


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(Dollars in thousands, except share and per share data)
Revenues
Sales	$	1,276,035		$	1,293,658		$	2,590,850		$	2,582,564
Other revenues		46,017			22,730			96,373			45,634


Total revenues		1,322,052			1,316,388			2,687,223			2,628,198

Costs and Expenses
Operating costs and expenses		1,077,517			1,053,534			2,169,298			2,075,876
Depreciation, depletion and amortization		108,501			91,475			211,363			172,439
Asset retirement obligation expense		7,473			11,628			18,848			18,843
Selling and administrative expenses		42,999			40,779			85,630			87,305
Other operating income:
Net gain on disposal or exchange of assets		(98,716	)		(50,043	)		(135,365	)		(59,269	)
Income from equity affiliates		(4,324	)		(6,680	)		(6,484	)		(13,932	)


Operating Profit		188,602			175,695			343,933			346,936
Interest expense		59,036			25,338			117,814			52,738
Interest income		(3,639	)		(1,534	)		(9,029	)		(4,140	)

Income Before Income Taxes and Minority Interests		133,205			151,891			235,148			298,338
Income tax provision (benefit)		19,155			(3,318	)		31,769			8,248
Minority interests		6,358			1,775			7,181			6,434


Net Income	$	107,692		$	153,434		$	196,198		$	283,656


Earnings Per Share
Basic	$	0.41		$	0.58		$	0.75		$	1.08
Diluted	$	0.40		$	0.57		$	0.73		$	1.05

Weighted Average Shares Outstanding
Basic		263,479,042			263,958,590			263,256,691			263,726,123
Effect of dilutive securities		5,233,267			5,798,076			5,200,611			5,871,033

Diluted		268,712,309			269,756,666			268,457,302			269,597,156


Dividends Declared Per Share	$	0.06		$	0.06		$	0.12		$	0.12

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET


	(Unaudited)
	June 30, 2007			December 31, 2006
	(Dollars in thousands, except
	share and per share data)
ASSETS
Current assets
Cash and cash equivalents	$	82,275		$	326,511
Accounts receivable, net of allowance for doubtful accounts of $11,608 at June 30, 2007 and $11,144 December 31, 2006		259,625			358,242
Inventories		285,670			237,602
Assets from coal trading activities		270,334			150,373
Deferred income taxes		106,967			106,967
Other current assets		140,070			116,863

Total current assets		1,144,941			1,296,558
Property, plant, equipment and mine development
Land and coal interests		7,341,559			7,127,385
Buildings and improvements		900,228			893,049
Machinery and equipment		1,620,211			1,516,765
Less accumulated depreciation, depletion and amortization		(2,098,057	)		(1,985,682	)

Property, plant, equipment and mine development, net		7,763,941			7,551,517
Goodwill		242,406			240,667
Investments and other assets		534,513			425,314

Total assets	$	9,685,801		$	9,514,056

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	36,793		$	95,757
Liabilities from coal trading activities		227,135			126,731
Accounts payable and accrued expenses		1,005,414			1,104,881

Total current liabilities		1,269,342			1,327,369
Long-term debt, less current maturities		3,155,207			3,201,992
Deferred income taxes		221,142			195,213
Asset retirement obligations		440,097			423,031
Workers’ compensation obligations		233,029			233,407
Accrued postretirement benefit costs		1,368,793			1,368,686
Other noncurrent liabilities		374,124			392,495

Total liabilities		7,061,734			7,142,193
Minority interests		39,806			33,337
Stockholders’ equity
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of June 30, 2007 or December 31, 2006		—			—
Series A Junior Participating Preferred Stock — 1,500,000 shares authorized, no shares issued or outstanding as of June 30, 2007 or December 31, 2006		—			—
Perpetual Preferred Stock — 750,000 shares authorized, no shares issued or outstanding as of June 30, 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 June 30, 2007 or December 31, 2006		—			—
Common Stock — $0.01 per share par value; 800,000,000 shares authorized, 268,112,377 shares issued and 265,403,491 shares outstanding as of June 30, 2007 and 266,554,157 shares issued and 263,846,839 shares outstanding as of December 31, 2006		2,681			2,666
Additional paid-in capital		1,614,598			1,572,614
Retained earnings		1,280,413			1,115,994
Accumulated other comprehensive loss		(209,668	)		(249,058	)
Treasury shares, at cost: 2,708,886 shares as of June 30, 2007 and 2,707,318 shares as of December 31, 2006		(103,763	)		(103,690	)

Total stockholders’ equity		2,584,261			2,338,526

Total liabilities and stockholders’ equity	$	9,685,801		$	9,514,056

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS


	Six Months Ended June 30,
	2007			2006
	(Dollars in thousands)
Cash Flows From Operating Activities
Net income	$	196,198		$	283,656
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		211,363			172,439
Deferred income taxes		(825	)		(51,104	)
Amortization of debt discount and debt issuance costs		3,839			3,434
Net gain on disposal or exchange of assets		(135,365	)		(59,269	)
Income from equity affiliates		(6,484	)		(13,932	)
Dividends received from equity affiliates		12,927			9,935
Stock compensation		12,477			8,409
Changes in current assets and liabilities, net of acquisitions:
Accounts receivable, net of sale		86,316			(12,277	)
Inventories		(48,068	)		(21,985	)
Net assets from coal trading activities		(26,973	)		3,802
Other current assets		(10,819	)		(14,606	)
Accounts payable and accrued expenses		(113,057	)		(102,687	)
Asset retirement obligations		6,151			1,554
Workers’ compensation obligations		(256	)		2,248
Accrued postretirement benefit costs		20,025			12,271
Obligation to industry fund		7,976			(3,397	)
Other, net		11,115			(5,086	)

Net cash provided by operating activities		226,540			213,405

Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		(288,316	)		(200,135	)
Federal coal lease expenditures		(123,369	)		(123,369	)
Proceeds from disposal of assets, net of notes receivable		47,120			24,628
Additions to advance mining royalties		(4,157	)		(4,863	)
Investment in joint venture		(599	)		(968	)
Other acquisitions, net		—			(44,538	)

Net cash used in investing activities		(369,321	)		(349,245	)

Cash Flows From Financing Activities
Payments of long-term debt		(102,951	)		(42,753	)
Dividends paid		(31,779	)		(31,762	)
Excess tax benefit related to stock options exercised		12,616			26,482
Increase of securitized interests in accounts receivable		12,300			—
Proceeds from stock options exercised		8,249			11,015
Proceeds from employee stock purchases		3,097			1,772
Distributions to minority interests		(2,131	)		(2,730	)
Common stock repurchase		—			(11,476	)
Other financing activities		(856	)		750

Net cash used in financing activities		(101,455	)		(48,702	)

Net decrease in cash and cash equivalents		(244,236	)		(184,542	)
Cash and cash equivalents at beginning of year		326,511			503,278

Cash and cash equivalents at end of year	$	82,275		$	318,736

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

JUNE 30, 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 June 30, 2007 and for the three and six months ended June 30, 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 six months ended June 30, 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 June 30, 2007 and for the three and six months ended June 30, 2007, with no effect on previously reported net income or stockholders’ equity.

The Company advanced its evaluation of strategic opportunities, including a possible spin-off or other strategic transaction, for portions of its Eastern U.S. Mining Operations business segment. The Company filed an initial Form 10 with the Securities and Exchange Commission and requested a Private Letter Ruling from the Internal Revenue Service as prerequisites for a possible tax-free spin-off of Patriot Coal Corporation (Patriot). Patriot would become an independent publicly-traded company producing steam and metallurgical quality coal in the eastern United States from operations and coal reserves in Appalachia and Western Kentucky. The potential spin-off would separate businesses with fundamentally different characteristics and allow management to pursue distinct operating and business strategies. The timetable and other details of the proposed transaction are expected to be finalized in the second-half of 2007.

(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. At adoption, the Company had $135 million of unrecognized tax benefits in its condensed consolidated financial statements, and an additional $3 million has been added since January 1, 2007 resulting from tax positions taken during the current year. The Company does not expect 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 are 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 the second-half of 2007.

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 Company expects to begin to realize the full benefit of the Excel acquisition when the mines under development are fully operational. One of the development-stage mines began operations in the first half of 2007, and the remaining two development-stage mines are expected to be fully commissioned in the second half of 2007.


	Three Months Ended		Six Months Ended
	June 30, 2006		June 30, 2006
	(Dollars in thousands, except per share data)
Revenues:
As reported	$	1,316,388	$	2,628,198
Pro forma		1,414,732		2,824,886

Net income:
As reported	$	153,434	$	283,656
Pro forma		147,657		272,101

Basic earnings per share — net income:
As reported	$	0.58	$	1.08
Pro forma		0.56		1.03

Diluted earnings per share — net income:
As reported	$	0.57	$	1.05
Pro forma		0.55		1.01

(4) Assets and Liabilities from Coal Trading Activities

The Company’s coal trading portfolio included forward and swap contracts as of June 30, 2007 and December 31, 2006. The fair value of coal trading derivatives and related hedge contracts are set forth below:


	June 30, 2007				December 31, 2006
	Assets		Liabilities		Assets		Liabilities
	(Dollars in thousands)
Forward contracts	$	188,677	$	118,919	$	142,105	$	120,718
Financial swaps		81,657		108,216		8,268		6,013

Total	$	270,334	$	227,135	$	150,373	$	126,731

Of the contracts in the Company’s trading portfolio as of June 30, 2007, 98% were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials, and 2% of the Company’s contracts were valued based on similar market transactions.

As of June 30, 2007, the estimated future realization of the value of the Company’s trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2007		28	%
2008		45	%
2009		22	%
2010		4	%
2011		1	%
		100	%

At June 30, 2007, 40% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties and 60% was with counterparties that are not rated or non-investment grade counterparties. The Company’s coal trading operations traded 34.9 million tons and 18.1 million tons for the three months ended June 30, 2007 and 2006, respectively, and 66.4 million tons and 28.8 million tons for the six months ended June 30, 2007 and 2006, respectively.

(5) Resource Management and Other Commercial Events

In June 2007, the Company exchanged oil and gas rights and assets in more than 860,000 acres in the Illinois Basin, West Virginia, New Mexico and the Powder River Basin for approximately 41 million tons of high-Btu coal reserves in West Virginia and Kentucky and $15.0 million in cash proceeds. The Company’s subsidiaries received approximately 28 million tons of Pittsburgh seam coal reserves adjacent to the Company’s Federal No. 2 mining operation in West Virginia and more than 14 million tons of coal reserves in Western Kentucky. Based on the fair value of the coal reserves received, the Company recognized a $50.5 million gain on the exchange. The non-cash portion of this transaction was excluded from the investing section of the statement of cash flows.

During the six months ended June 30, 2007, the Company sold approximately 88 million tons of non-strategic coal reserves and surface lands in Kentucky for $26.5 million cash and notes receivable of $69.4 million. The Company recognized gains totaling $78.5 million on these transactions.

During the six months ended June 2006, the Company exchanged approximately 63 million tons of leased coal reserves at its Caballo mining operation for approximately 46 million tons of coal reserves contiguous with the Company’s North Antelope Rochelle mining operation. Based on the fair value of the coal reserves exchanged, the Company recognized a gain on assets exchanged totaling $39.2 million. This non-cash transaction was excluded from the investing section of the statement of cash flows.

(6) Inventories

Inventories consisted of the following:


	June 30, 2007		December 31, 2006
	(Dollars in thousands)
Materials and supplies	$	93,153	$	85,243
Raw coal		46,231		42,693
Saleable coal		146,286		109,666

Total	$	285,670	$	237,602

As of December 31, 2006, “Inventories” reflected an additional $22.2 million that was previously classified as “Investments and other assets” on the Company’s consolidated balance sheet in its Annual Report on Form 10-K for the fiscal year ended December 31, 2006. Certain assets related to the Excel acquisition were reclassified to conform to changes made to the purchase price allocation.

(7) Long-Term Debt

The Company’s total indebtedness as of June 30, 2007 and December 31, 2006, consisted of the following:


	June 30,			December 31,
	2007			2006
	(Dollars in thousands)
Term Loan under Senior Unsecured Credit Facility	$	522,054		$	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		246,931			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		97,792			96,869
Fair value of interest rate swaps		(21,668	)		(13,784	)
Other		22,301			22,918


Total	$	3,192,000		$	3,297,749

Long-Term Debt Repayments

During the six months ended June 30, 2007, the Company repaid portions of its long-term debt, which included a $60.0 million retirement of its 5.0% Subordinated Note; a $24.9 million repayment of its outstanding balance of the Term Loan under the Senior Unsecured Credit Facility; an open-market purchase of $13.8 million in face value of its 5.875% Senior Notes; and capital lease payments totaling $4.3 million. As of June 30, 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” reflected 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 $7.2 million over the term of the lease, and a balloon payment at maturity of approximately $11.2 million.

Interest Rate Swaps

During the six months ended June 30, 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 and six months ended June 30, 2007 and 2006:


	Three Months Ended June 30,				Six Months Ended June 30,
	2007		2006		2007		2006
	(Dollars in thousands)
Net income	$	107,692	$	153,434	$	196,198	$	283,656
Increase in fair value of cash flow hedges, net of tax provision of $4,065 and $8,870 for the three months ended June 30, 2007 and 2006, respectively, and $12,923 and $10,113 for the six months ended June 30, 2007 and 2006, respectively		5,122		13,306		19,383		15,170
Accumulated actuarial loss and prior service cost realized in net income, net of tax provision of $8,267 and $11,654 for the three and six months ended June 30, 2007, respectively		12,445		—		20,007		—

Comprehensive income	$	125,259	$	166,740	$	235,588	$	298,826

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 June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(Dollars in thousands)
Service cost for benefits earned	$	2,250		$	3,058		$	4,500		$	6,117
Interest cost on projected benefit obligation		11,975			11,508			23,950			23,017
Expected return on plan assets		(14,075	)		(13,646	)		(28,150	)		(27,293	)
Amortization of actuarial loss and other		4,175			5,663			8,350			11,326

Net periodic pension costs	$	4,325		$	6,583		$	8,650		$	13,167

Net periodic postretirement benefit costs included the following components:


	Three Months Ended June 30,						Six Months Ended June 30,
	2007			2006			2007			2006
	(Dollars in thousands)
Service cost for benefits earned	$	3,013		$	1,880		$	5,242		$	3,759
Interest cost on accumulated postretirement benefit obligation		21,511			18,462			42,883			36,926
Amortization of prior service cost		(165	)		(1,335	)		(1,007	)		(2,669	)
Amortization of actuarial loss		10,816			8,012			21,632			16,024

Net periodic postretirement benefit costs	$	35,175		$	27,019		$	68,750		$	54,040

The Company expects to pay approximately $89 million attributable to its postretirement benefit plans during the year ended December 31, 2007, which reflects an increase of approximately $6 million from its previously disclosed estimate in the notes to the financial statements of its 2006 Annual Report on Form 10-K. The increase primarily relates to greater than expected number of retirees, higher than anticipated utilization and revised estimates of the impact of the recently approved 2007 National Bituminous Coal Wage Agreement. As of June 30, 2007, payments of $45.2 million attributable to the Company’s postretirement benefit plans were made.

(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 and six months ended June 30, 2007 and 2006 were as follows:


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2007		2006			2007			2006
	(Dollars in thousands)
Revenues:
Western U.S. Mining	$	490,970	$	400,317		$	971,603		$	832,407
Eastern U.S. Mining		505,023		517,465			1,023,239			1,031,928
Australian Mining		260,384		217,892			547,375			370,891
Trading and Brokerage		59,387		175,542			135,451			382,557
Corporate and Other		6,288		5,172			9,555			10,415

Total	$	1,322,052	$	1,316,388		$	2,687,223		$	2,628,198


Adjusted EBITDA:
Western U.S. Mining	$	136,941	$	99,989		$	276,550		$	227,782
Eastern U.S. Mining		72,311		108,094			153,519			240,638
Australian Mining		41,882		65,928			104,443			113,684
Trading and Brokerage		26,510		21,199			63,345			37,378
Corporate and Other ⁽¹⁾		26,932		(16,412	)		(23,713	)		(81,264	)

Total	$	304,576	$	278,798		$	574,144		$	538,218


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

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2007			2006			2007			2006
	(Dollars in thousands)
Total Adjusted EBITDA	$	304,576		$	278,798		$	574,144		$	538,218
Depreciation, depletion and amortization		108,501			91,475			211,363			172,439
Asset retirement obligation expense		7,473			11,628			18,848			18,843
Interest expense		59,036			25,338			117,814			52,738
Interest income		(3,639	)		(1,534	)		(9,029	)		(4,140	)

Income before income taxes and minority interests	$	133,205		$	151,891		$	235,148		$	298,338

(11) Commitments and Contingencies

Commitments

As of June 30, 2007, purchase commitments for capital expenditures were $153.7 million and federal coal reserve lease payments due over the next three years totaled $356.4 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 $79.8 million and $76.8 million included in “Investments and other assets” in the condensed consolidated balance sheets as of June 30, 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, a Company 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 that at one time involved 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 settled most of the claims in the personal injury lawsuits and the related lawsuits have been dismissed (with lawsuits involving 7 children remaining). In December 2003, the Quapaw Indian tribe and certain Quapaw land owners filed a lawsuit against Gold Fields, five other companies and the United States. 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 5 sites, and claims have been asserted at 18 other sites, which have since been reduced to 12 by completion of work, 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 $41.6 million as of June 30, 2007 and $43.0 million as of December 31, 2006, $13.1 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. 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

The Company’s wholly-owned subsidiary, Prairie State Generating Company, LLC (PSGC), entered into a cost reimbursable Target Price Engineering, Procurement and Construction Agreement (Agreement) with Bechtel Power Corporation (Bechtel) related to a mine mouth pulverized coal-fired generating facility. At the financial closing (expected in the second half of 2007), the Company’s ownership interest in PSGC will be transferred to an Indiana non-profit corporation that will be owned and controlled by a group of owners (Owners), including one or more of the Company’s affiliates. The Company provided an absolute and unconditional payment guarantee of all amounts due until financial closing by PSGC to Bechtel under the Agreement (Initial Owner Guarantee). Following the transfer of PSGC’s membership interests, each Owner will issue a guarantee to Bechtel for its proportionate share of PSGC’s obligations under the Agreement. The Company will provide a guarantee to Bechtel for the proportionate share of the Company’s affiliates that will ultimately (together with the other Owners) control PSGC and own a proportionate share in the facility. The Initial Owner Guarantee will terminate (other than for claims then existing) following the transfer of PSGC’s membership interest to the Indiana non-profit corporation controlled by the Owners. The Company currently expects that reimbursements from partners will substantially offset 2007 project expenditures and that construction will commence shortly after financial closing.

The Company has an established accounts receivable securitization program through its wholly-owned, bankruptcy-remote subsidiary. In May 2007, the Company amended its accounts receivable securitization program and increased the purchase limit from $225.0 million to $275.0 million.

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 June 30, 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 June 30, 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. 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 $14.4 million, and the fair value of the guarantees recognized as a liability was $0.4 million as of June 30, 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 long-term 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 June 30, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(Dollars in thousands)
Total revenues	$	—		$	1,030,942		$	327,724		$	(36,614	)	$	1,322,052
Costs and expenses:
Operating costs and expenses		(2,326	)		843,177			273,280			(36,614	)		1,077,517
Depreciation, depletion and amortization		—			78,275			30,226			—			108,501
Asset retirement obligation expense		—			6,000			1,473			—			7,473
Selling and administrative expenses		8,329			33,068			1,602			—			42,999
Other operating income (loss):
Net gain on disposal or exchange of assets		—			(98,102	)		(614	)		—			(98,716	)
(Income) loss from equity affiliates		(152,097	)		1,606			(5,930	)		152,097			(4,324	)
Interest expense		68,970			15,086			6,046			(31,066	)		59,036
Interest income		(4,198	)		(23,709	)		(6,798	)		31,066			(3,639	)

Income (loss) before income taxes and minority interests		81,322			175,541			28,439			(152,097	)		133,205
Income tax provision (benefit)		(26,370	)		44,607			918			—			19,155
Minority interests		—			—			6,358			—			6,358

Net income (loss)	$	107,692		$	130,934		$	21,163		$	(152,097	)	$	107,692

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Three Months Ended June 30, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(Dollars in thousands)
Total revenues	$	—		$	962,023		$	381,045		$	(26,680	)	$	1,316,388
Costs and expenses:
Operating costs and expenses		(7,380	)		790,623			296,971			(26,680	)		1,053,534
Depreciation, depletion and amortization		—			77,155			14,320			—			91,475
Asset retirement obligation expense		—			11,495			133			—			11,628
Selling and administrative expenses		4,923			35,678			178			—			40,779
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets		—			(50,286	)		243			—			(50,043	)
(Income) loss from equity affiliates		(176,693	)		310			(6,990	)		176,693			(6,680	)
Interest expense		40,031			13,403			2,963			(31,059	)		25,338
Interest income		(4,806	)		(20,890	)		(6,897	)		31,059			(1,534	)

Income (loss) before income taxes and minority interests		143,925			104,535			80,124			(176,693	)		151,891
Income tax provision (benefit)		(9,509	)		(9,434	)		15,625			—			(3,318	)
Minority interests		—			—			1,775			—			1,775

Net income (loss)	$	153,434		$	113,969		$	62,724		$	(176,693	)	$	153,434

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Six Months Ended June 30, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(Dollars in thousands)
Total revenues	$	—		$	2,054,315		$	694,129		$	(61,221	)	$	2,687,223
Costs and expenses:
Operating costs and expenses		(2,936	)		1,667,747			565,708			(61,221	)		2,169,298
Depreciation, depletion and amortization		—			153,968			57,395			—			211,363
Asset retirement obligation expense		—			17,037			1,811			—			18,848
Selling and administrative expenses		14,486			68,740			2,404			—			85,630
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(134,846	)		(519	)		—			(135,365	)
(Income) loss from equity affiliates		(285,576	)		3,123			(9,607	)		285,576			(6,484	)
Interest expense		139,061			28,612			12,330			(62,189	)		117,814
Interest income		(8,878	)		(47,733	)		(14,607	)		62,189			(9,029	)

Income (loss) before income taxes and minority interests		143,843			297,667			79,214			(285,576	)		235,148
Income tax provision (benefit)		(52,355	)		78,175			5,949			—			31,769
Minority interests		—			—			7,181			—			7,181

Net income (loss)	$	196,198		$	219,492		$	66,084		$	(285,576	)	$	196,198

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Six Months Ended June 30, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
							(Dollars in thousands)
Total revenues	$	—		$	1,988,880		$	692,565		$	(53,247	)	$	2,628,198
Costs and expenses:
Operating costs and expenses		(12,330	)		1,599,538			541,915			(53,247	)		2,075,876
Depreciation, depletion and amortization		—			146,144			26,295			—			172,439
Asset retirement obligation expense		—			18,477			366			—			18,843
Selling and administrative expenses		9,469			76,983			853			—			87,305
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets		—			(59,301	)		32			—			(59,269	)
(Income) loss from equity affiliates		(330,977	)		1,460			(15,392	)		330,977			(13,932	)
Interest expense		80,123			28,544			6,913			(62,842	)		52,738
Interest income		(10,708	)		(41,870	)		(14,404	)		62,842			(4,140	)

Income (loss) before income taxes and minority interests		264,423			218,905			145,987			(330,977	)		298,338
Income tax provision (benefit)		(19,233	)		2,792			24,689			—			8,248
Minority interests		—			—			6,434			—			6,434

Net income (loss)	$	283,656		$	216,113		$	114,864		$	(330,977	)	$	283,656

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Balance Sheets


	June 30, 2007
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
						(Dollars in thousands)
Assets
Current assets
Cash and cash equivalents	$	35,583	$	9,751		$	36,941		$	—		$	82,275
Accounts receivable		1,340		(35,015	)		293,300			—			259,625
Inventories		—		172,969			112,701			—			285,670
Assets from coal trading activities		—		270,334			—			—			270,334
Deferred income taxes		—		106,967			—			—			106,967
Other current assets		65,278		38,833			35,959			—			140,070

Total current assets		102,201		563,839			478,901			—			1,144,941
Property, plant, equipment and mine development - at cost		—		7,171,673			2,690,325			—			9,861,998
Less accumulated depreciation, depletion and amortization		—		(1,852,098	)		(245,959	)		—			(2,098,057	)
Goodwill		—		—			242,406			—			242,406
Investments and other assets		7,559,201		131,943			68,638			(7,225,269	)		534,513

Total assets	$	7,661,402	$	6,015,357		$	3,234,311		$	(7,225,269	)	$	9,685,801


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	26,433	$	1,156		$	9,204		$	—		$	36,793
Payables and notes payable to affiliates, net		1,974,792		(2,171,052	)		196,260			—			—
Liabilities from coal trading activities		—		227,135			—			—			227,135
Accounts payable and accrued expenses		34,110		707,895			263,409			—			1,005,414

Total current liabilities		2,035,335		(1,234,866	)		468,873			—			1,269,342
Long-term debt, less current maturities		2,971,473		11,636			172,098			—			3,155,207
Deferred income taxes		44,983		(17,267	)		193,426			—			221,142
Other noncurrent liabilities		25,350		2,296,301			94,392			—			2,416,043

Total liabilities		5,077,141		1,055,804			928,789			—			7,061,734
Minority interests		—		—			39,806			—			39,806
Stockholders’ equity		2,584,261		4,959,553			2,265,716			(7,225,269	)		2,584,261

Total liabilities and stockholders’ equity	$	7,661,402	$	6,015,357		$	3,234,311		$	(7,225,269	)	$	9,685,801

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			90,682			—			237,602
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			479,993			—			1,296,558
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		7,178,608		34,195			77,897			(6,865,386	)		425,314

Total assets	$	7,504,841	$	5,694,590		$	3,180,011		$	(6,865,386	)	$	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		2,338,526		4,637,359			2,228,027			(6,865,386	)		2,338,526

Total liabilities and stockholders’ equity	$	7,504,841	$	5,694,590		$	3,180,011		$	(6,865,386	)	$	9,514,056

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows


	Six Months Ended June 30, 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	$	(141,575	)	$	300,161		$	67,954		$	226,540


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(183,741	)		(104,575	)		(288,316	)
Federal coal lease expenditures		—			(123,369	)		—			(123,369	)
Additions to advance mining royalties		—			(4,157	)		—			(4,157	)
Proceeds from disposal of assets, net of notes receivable		—			46,315			805			47,120
Investment in joint venture		—			(599	)		—			(599	)

Net cash used in investing activities		—			(265,551	)		(103,770	)		(369,321	)


Cash Flows From Financing Activities
Payments of long-term debt		(38,083	)		(59,980	)		(4,888	)		(102,951	)
Dividends paid		(31,779	)		—			—			(31,779	)
Excess tax benefit related to stock options exercised		12,616			—			—			12,616
Increase of securitized interests in accounts receivable		—			—			12,300			12,300
Proceeds from stock options exercised		8,249			—			—			8,249
Proceeds from employee stock purchases		3,097			—			—			3,097
Distributions to minority interests		—			—			(2,131	)		(2,131	)
Other financing activities		—			(856	)		—			(856	)
Transactions with affiliates, net		(49,168	)		32,325			16,843			—

Net cash provided by (used in) financing activities		(95,068	)		(28,511	)		22,124			(101,455	)


Net increase (decrease) in cash and cash equivalents		(236,643	)		6,099			(13,692	)		(244,236	)
Cash and cash equivalents at beginning of year		272,226			3,652			50,633			326,511

Cash and cash equivalents at end of year	$	35,583		$	9,751		$	36,941		$	82,275

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows


	Six Months Ended June 30, 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	$	(81,359	)	$	233,923		$	60,841		$	213,405


Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development		—			(161,226	)		(38,909	)		(200,135	)
Federal coal lease expenditures		—			(63,540	)		(59,829	)		(123,369	)
Additions to advance mining royalties		—			(4,863	)		—			(4,863	)
Proceeds from disposal of assets		—			24,166			462			24,628
Investment in joint venture		—			(968	)		—			(968	)
Acquisitions, net		—			—			(44,538	)		(44,538	)

Net cash used in investing activities		—			(206,431	)		(142,814	)		(349,245	)


Cash Flows from Financing Activities
Payments of long-term debt		(12,680	)		(10,362	)		(19,711	)		(42,753	)
Dividends paid		(31,762	)		—			—			(31,762	)
Excess tax benefit related to stock options exercised		26,482			—			—			26,482
Proceeds from stock options exercised		11,015			—			—			11,015
Proceeds from employee stock purchases		1,772			—			—			1,772
Distributions to minority interests		—			—			(2,730	)		(2,730	)
Common stock repurchase		(11,476	)		—			—			(11,476	)
Other financing activities		—			—			750			750
Transactions with affiliates, net		(89,570	)		(16,488	)		106,058			—

Net cash provided by (used in) financing activities		(106,219	)		(26,850	)		84,367			(48,702	)


Net increase (decrease) in cash and cash equivalents		(187,578	)		642			2,394			(184,542	)
Cash and cash equivalents at beginning of period		494,232			2,471			6,575			503,278

Cash and cash equivalents at end of period	$	306,654		$	3,113		$	8,969		$	318,736

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 potential 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 existing information systems across major business processes to an integrated information technology system;

	•		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; and

•

other factors, including those discussed in Legal Proceedings.

When considering these forward-looking statements, you should keep in mind the cautionary statements in this document 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 six months of 2007, we sold 123.4 million tons of coal, and in 2006, we sold 247.6 million tons of coal. Our domestic sales represented 22% of all U.S. coal sales. 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. 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 U.S. customers are domestic utilities, which accounted for 87% of our sales in 2006. Internationally, we sell our metallurgical coal to industrial customers and steam coal to utility customers in the Pacific Rim. 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 June 30, 2007, our full year 2007 targets include fully committed production of 220 to 225 million tons in the United States and production of 20 to 22 million tons in Australia, along with trading and brokerage volumes. 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, 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. See the Outlook section for discussion of near-term and long-term impacts to our business.

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 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 six months of 2007, our interest in Carbones del Guasare contributed $9.6 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA” and paid a dividend of $12.9 million. At June 30, 2007, our investment in Paso Diablo was $56.8 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. operations. 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. On June 19, 2007, we announced the signing of a $2.9 billion cost reimbursable Target Price Engineering, Procurement and Construction Agreement with Bechtel Power Corporation for the 1,600-megawatt Prairie State Energy Campus in Washington County, Illinois. We have entered into agreements with two new participants for the project and the collective participant commitments now total 1,300-megawatts. The plant, 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 July 23, 2007, we announced an agreement with ConocoPhillips to explore development of a commercial scale coal-to-substitute natural gas (SNG) facility in the Midwest. The project would be developed as a mine-mouth facility at a location where we have access to large reserves and existing infrastructure. The facility would be designed to annually produce 50 billion to 70 billion cubic-feet of pipeline quality SNG from more than 3.5 million tons of Midwest coal and petroleum coke.

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 and Six Months Ended June 30, 2007 Compared to Three and Six Months Ended June 30, 2006

Summary

Higher average sales prices primarily in the Powder River Basin and increased volumes in Australian Mining operations contributed to moderate increases in revenues during the three and six months ended June 30, 2007 compared to the prior year. Segment Adjusted EBITDA decreased for the quarter and six months compared to prior year primarily related to lower sales volumes resulting from adverse weather conditions, transportation issues and certain capital project delays in our Western U.S. and Australia mining operations; geology issues in our Eastern U.S. Mining operations; and the effects of currency translation related to the weaker U.S. dollar against the very strong Australian dollar. Disruption of the coal chain, including port congestion at our two primary Australian shipping points, Dalrymple Bay Coal Terminal and the Port of Newcastle, was caused by record demand and severe flooding in Newcastle. This led to significant queuing of vessels, which resulted in delayed shipments and increased demurrage charges. Partially offsetting these unfavorable events were improved results from Trading and Brokerage operations, the contribution from new mines in Australia, and higher prices in our U.S. Mining operations.

Net income decreased for the three and six months ended June 30, 2007 compared to prior year, and included higher depreciation, depletion and amortization primarily from our newly acquired mines and additional interest expense associated with approximately $1.7 billion in debt issuances in the second half of 2006 to finance the acquisition of Excel Coal Limited (Excel). We expect to begin to realize the full benefit of the Excel acquisition when the mines under development are fully operational. One of the development-stage mines began operations in the first half of 2007, and the remaining two development-stage mines are expected to be fully commissioned in the second half of 2007. Partially offsetting these decreases were higher gains from asset disposals or exchanges.

Tons Sold


	Three Months Ended				2007 from 2006						Six Months Ended				2007 from 2006
	June 30,				Increase (Decrease)						June 30,				Increase (Decrease)
	2007		2006		Tons			%			2007		2006		Tons			%
	(Tons in millions)										(Tons in millions)
Western U.S. Mining Operations		38.3		38.8		(0.5	)		(1.3	)%		76.2		78.6		(2.4	)		(3.1	)%
Eastern U.S. Mining Operations		13.1		14.1		(1.0	)		(7.1	)%		26.6		27.8		(1.2	)		(4.3	)%
Australian Mining Operations		5.0		2.4		2.6			108.3	%		10.0		4.3		5.7			132.6	%
Trading and Brokerage Operations		6.1		5.5		0.6			10.9	%		10.6		11.4		(0.8	)		(7.0	)%

Total tons sold		62.5		60.8		1.7			2.8	%		123.4		122.1		1.3			1.1	%

Revenues


	Three Months Ended				Increase (Decrease)							Six Months Ended				Increase
	June 30,				to Revenues							June 30,				to Revenues
	2007		2006		$			%				2007		2006		$			%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining Operations	$	491.0	$	400.2	$	90.8			22.7	%		$	971.6	$	832.2	$	139.4			16.8	%
Eastern U.S. Mining Operations		493.1		515.5		(22.4	)		(4.3	)%			999.4		1,021.4		(22.0	)		(2.2	)%
Australian Mining Operations		259.1		217.5		41.6			19.1	%			544.9		370.2		174.7			47.2	%
Trading and Brokerage Operations		32.9		160.5		(127.6	)		(79.5	)%			74.9		358.8		(283.9	)		(79.1	)%

Sales		1,276.1		1,293.7		(17.6	)		(1.4	)%			2,590.8		2,582.6		8.2			0.3	%
Other revenues		46.0		22.7		23.3			102.6	%			96.4		45.6		50.8			111.4	%

Total revenues	$	1,322.1	$	1,316.4	$	5.7			0.4	%		$	2,687.2	$	2,628.2	$	59.0			2.2	%

Total revenues increased for the three and six months ended June 30, 2007 compared to prior year while our total sales decreased for the three months ended June 30, 2007 and increased for the six months ended June 30, 2007. The primary causes of the change in these periods included the following:

	•		Continued shift towards trading contracts versus brokerage contracts in our Trading and Brokerage operations. Trading and Brokerage operations’ sales decreased in the quarter and six months 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, whereas contracts for brokerage activity are recorded at gross sales price to revenues and operating costs. While the shift to trading contracts reduced total sales, there was no impact to Adjusted EBITDA;

	•		Lower volumes in our Eastern U.S Mining operations related to geology issues;

	•		Lower average sales prices in our Australia Mining operations related to lower metallurgical contract pricing (Pacific Rim seaborne market fiscal year began April 1) and higher thermal product sales in our overall price mix;

	•		Lower volumes in our Australia Mining operations resulting from adverse weather events that affected production (excluding the impact of recently acquired mines), damaged rails, and further amplified port and rail congestion; and

	•		Lower volumes in the Powder River Basin of our Western U.S. Mining operations for the quarter related to capital project delays and equipment issues that affected production and adverse weather conditions. The impact of adverse weather conditions on sales during the six months also included a blizzard in the Powder River Basin that effectively shut down operations and transportation for several days in the first quarter.

The decline in volume and average sales prices discussed above was partially offset in the second quarter and fully offset in the six months by the following:

	•		Higher volumes in Australia from recently acquired mines;

	•		Higher average sales prices, increasing over 20%, in our Western U.S. Mining operations (mainly reflecting increases of approximately 25% per ton on new contracts in the Powder River Basin for each period presented). These increases in the Powder River Basin drove the overall increase in total sales for the six months. Additionally, we also benefited from higher volumes at our other Western U.S. Mining operations;

	•		Higher average sales prices experienced in our Eastern U.S. Mining operations were driven by favorable contract pricing, partially offset by coal quality issues.

Higher other revenues in the second quarter and six months primarily related to higher trading gains resulting from increased international volumes and favorable international pricing (quarter — $9.5 million; six months — $15.2 million) and higher revenues from synthetic fuel plants in the current period as customers idled those plants in the prior year (quarter — $6.0 million; six months — $9.1 million). Higher proceeds received from the monetization of in-the-money contracts with third-party coal producers contributed $16.2 million to the increase for the six months.

Segment Adjusted EBITDA


					Increase (Decrease)											Increase (Decrease)
	Three Months Ended				to Segment							Six Months Ended				to Segment
	June 30,				Adjusted EBITDA							June 30,				Adjusted EBITDA
	2007		2006		$			%				2007		2006		$			%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining Operations	$	136.9	$	100.0	$	36.9			36.9	%		$	276.6	$	227.8	$	48.8			21.4	%
Eastern U.S. Mining Operations		72.3		108.1		(35.8	)		(33.1	)%			153.4		240.6		(87.2	)		(36.2	)%
Australian Mining Operations		41.9		65.9		(24.0	)		(36.4	)%			104.4		113.7		(9.3	)		(8.2	)%
Trading and Brokerage Operations		26.5		21.2		5.3			25.0	%			63.3		37.4		25.9			69.3	%

Total Segment Adjusted EBITDA	$	277.6	$	295.2	$	(17.6	)		(6.0	)%		$	597.7	$	619.5	$	(21.8	)		(3.5	)%

Adjusted EBITDA from our Western U.S. Mining operations increased during the second quarter and six months primarily related to an overall increase in average sales prices from our Powder River Basin operations and a 28% increase in our premium product prices from our Powder River Basin operations. Partially offsetting higher average sales prices were lower sales volumes and higher costs associated with equipment repairs and maintenance, adverse weather conditions in the first and second quarters, capital project delays and higher add-on taxes and royalties.

Eastern U.S. Mining operations’ Adjusted EBITDA decreased during the second quarter and six months primarily related to lower sales volumes and higher costs associated with production shortfalls stemming from geology issues at several of our mines; higher costs for commodities, including fuel; and loss of a contract miner. Modest increases in average sales prices were offset by lower coal quality at one of our mines. Results in the six months of 2006 reflected favorable sulfur premiums and an $8.9 million settlement of customer billings regarding coal quality.

Our Australian Mining operations’ Adjusted EBITDA decreased during the second quarter and six months compared to prior year primarily due to lower pricing on metallurgical coal contracts; rail and port congestion at Dalrymple Bay Coal Terminal and the Port of Newcastle; higher congestion-related demurrage costs; and higher non-cash costs resulting from the weakening U.S. dollar, net of hedging gains. Dalrymple Bay Coal Terminal has been experiencing queues of over 50 vessels at a time (approximately a 34-day queue). Partially offsetting these decreases were contributions from our newly acquired mines and a $6.3 million insurance recovery on a business interruption claim in the first half of 2007. Our newly acquired mines experienced reduced shipments and damaged rail lines resulting from a storm late in the second quarter. The Port of Newcastle was closed for several days in June due to the storm, with up to 79 vessels in the queue at certain times (a 35 — 40 day queue).

Trading and Brokerage operations’ Adjusted EBITDA increased during the second quarter and six months due to higher international trading gains resulting from higher volumes in 2007 and higher pricing. The price increases were driven by strong supply/demand fundamentals that were further strengthened by tightened Australian supply due to adverse weather impacting rail and port availability. Trading and Brokerage operations’ Adjusted EBITDA was also impacted by lower gains in the second quarter, but higher gains in the six months ended June 30, 2007 related to the monetization of in-the-money contracts with third-party coal producers and trading partners.

Income Before Income Taxes and Minority Interests


	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2007			2006			$			%			2007			2006			$			%
	(Dollars in millions)												(Dollars in millions)
Total Segment Adjusted EBITDA	$	277.6		$	295.2		$	(17.6	)		(6.0	)%	$	597.7		$	619.5		$	(21.8	)		(3.5	)%
Corporate and Other Adjusted EBITDA		27.0			(16.4	)		43.4			264.6	%		(23.6	)		(81.3	)		57.7			71.0	%
Depreciation, depletion and amortization		(108.5	)		(91.5	)		(17.0	)		(18.6	)%		(211.4	)		(172.4	)		(39.0	)		(22.6	)%
Asset retirement obligation expense		(7.5	)		(11.6	)		4.1			35.3	%		(18.8	)		(18.9	)		0.1			0.5	%
Interest expense		(59.0	)		(25.3	)		(33.7	)		(133.2	)%		(117.8	)		(52.7	)		(65.1	)		(123.5	)%
Interest income		3.6			1.5			2.1			140.0	%		9.0			4.1			4.9			119.5	%

Income before income taxes and minority interests	$	133.2		$	151.9		$	(18.7	)		(12.3	)%	$	235.1		$	298.3		$	(63.2	)		(21.2	)%

Income before income taxes and minority interests for the three and six months ended June 30, 2007 was 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 disposal or exchange of assets, 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 improvement in Corporate and Other Adjusted EBITDA during the second quarter and six months includes the following:

	•		Higher net gains on disposals or exchanges of assets (quarter — $48.7 million; six months — $76.1 million). Activity for the second quarter and six months included a gain of $50.5 million on the exchange of our coalbed methane and oil and gas rights in the Illinois Basin, West Virginia, New Mexico and the Powder River Basin for high-Btu coal reserves located in West Virginia and Kentucky and cash proceeds. Our 2007 activity also included gains totaling $78.5 million ($43.6 million in the second quarter) from sales of non-strategic coal reserves and surface lands located in Kentucky. Net gains on disposals or exchanges of assets in the prior year included a $39.2 million gain on exchange of coal reserves (see Note 5); and

	•		Higher cost reimbursement and partner fees for the Prairie State Energy Campus project, primarily related to the entrance of new project partners (quarter — $13.1 million; six months — $11.5 million).

The improvement in Corporate and Other Adjusted EBITDA during the second quarter and six months was partially offset by:

	•		Lower equity income (quarter — $2.2 million; six months — $6.0 million) from our 25.5% interest in Carbones del Guasare (owner and operator of the Paso Diablo Mine in Venezuela), which primarily resulted from trucking issues, a temporary shortage of explosives, and delays in receiving equipment, which impacted operations; and

	•		Higher expenses (quarter — $11.4 million; six months — $19.4 million) associated with higher past mining obligations resulting from increased healthcare costs and additional multiemployer pension and retiree healthcare funding in accordance with 2006 legislation and requirements under the 2007 National Bituminous Coal Wage Agreement.

Depreciation, depletion and amortization increased (quarter — $17.0 million; six months - $39.0 million) primarily related to the addition of recently acquired Australian operations.

Interest expense increased (quarter — $33.7 million; six months — $65.1 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


	Three Months Ended						Decrease						Six Months Ended						Decrease
	June 30,						to Income						June 30,						to Income
	2007			2006			$			%			2007			2006			$			%
	(Dollars in millions)												(Dollars in millions)
Income before income taxes and minority interests	$	133.2		$	151.9		$	(18.7	)		(12.3	)%	$	235.1		$	298.3		$	(63.2	)		(21.2	)%
Income tax (provision) benefit		(19.1	)		3.3			(22.4	)		(678.8	)%		(31.7	)		(8.2	)		(23.5	)		(286.6	)%
Minority interests		(6.4	)		(1.8	)		(4.6	)		(255.6	)%		(7.2	)		(6.4	)		(0.8	)		(12.5	)%

Net income	$	107.7		$	153.4		$	(45.7	)		(29.8	)%	$	196.2		$	283.7		$	(87.5	)		(30.8	)%

Net income decreased during the three and six months ended June 30, 2007 compared to prior year due to the decrease in income before income taxes discussed above, a higher income tax provision and an increase in minority interests. The income tax provision was higher for the quarter and six months primarily due to a reduction in tax reserves totaling $21.4 million in the prior year related to the favorable finalization of former parent companies’ federal tax audits. Minority interests increased primarily from the absorption of losses in excess of the minority interest capital contribution at one of our mines, partially offset by lower earnings allocable to partners.

Outlook

Events Impacting Near-Term Operations

Global coal markets continued to reflect high demand and pricing, with prices strengthening in the international and domestic markets in early 2007. China’s economy grew 11.5% year-over-year in the first half of 2007 as published by the National Bureau of Statistics of China, while the U.S. economy grew at an annual rate of 3.4% based on recent reports by the U.S. Commerce Department.

Operationally, we dealt with several external events in the first half of 2007, including adverse weather, transportation logistic issues and a weakening U.S. dollar. We anticipate that the impact from certain of these events will continue to affect our Australian Mining operations results in the second half of 2007, including higher costs due to demurrage and currency exchange rate changes. The port congestion and significant queuing of vessels at Dalrymple Bay Coal Terminal and Port of Newcastle are expected to continue into the second half of 2007, as congestion at these coal export terminals led to mandatory reductions of throughput entitlements for coal shippers, ranging from 13-21% for the remainder of 2007. We anticipate that planned incremental production cuts from original targets at our U.S. operations, as well as higher fuel charges, will impact our Eastern U.S. and Western U.S. Mining operations’ results in the second half of 2007. The U.S. market continues to experience high utility customer stockpiles, which has decreased demand and led to our planned production cuts. As of June 30, 2007, we expect full year 2007 sales targets of 260 to 275 million tons. We expect U.S. production targets of 220 to 225 million tons and Australian production of 20 to 22 million tons for the year.

We advanced our evaluation of strategic opportunities, including a possible spin-off or other strategic transaction, for portions of our Eastern U.S. Mining Operations business segment. We filed an initial Form 10 with the Securities and Exchange Commission and requested a Private Letter Ruling from the Internal Revenue Service as prerequisites for a possible tax-free spin-off of Patriot Coal Corporation (Patriot). Patriot would become an independent publicly-traded company producing steam and metallurgical quality coal in the eastern United States from operations and coal reserves in Appalachia and Western Kentucky. The potential spin-off would separate businesses with fundamentally different characteristics and allow management to pursue distinct operating and business strategies. The timetable and other details of the proposed transaction are expected to be finalized in the second-half of 2007.

The majority of our United Mine Workers of America (UMWA)-represented eastern workforce operates 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. Additionally, the UMWA-represented workforce at our Arizona mine operates under the Western Surface Agreement of 2000 and the UMWA-represented workforce at one of our eastern mines operates under a separate contract, both of which expire in the second half of 2007. Furthermore, new labor agreements are being negotiated at two of our 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. We estimate that more than 115 gigawatts of new coal-fueled electricity generating capacity is under construction around the world and more than 12,000 megawatts is under construction or recently come on line in the United States. 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.

Coal prices continue to strengthen. Internationally, Australian thermal coal prices have increased during 2007, exceeding $70 per metric tonne for seaborne shipments during the second quarter for spot sales. The spot prices for metallurgical coal have also increased recently in 2007, signaling the potential for higher 2008 contract pricing. Both China and India increased net imports of coal to satisfy growth in electricity generation and steel production. Russia is predicting a decline in its coal exports due to continued domestic demand. We expect to capitalize on the strong global market for metallurgical and thermal coal from sales of our Australian production, including our newly acquired thermal coal mines. Also, in response to growing international markets, we established an international trading group in 2006 and added a trading office in Europe in early 2007, which expands our trading activities to four continents. U.S. coal markets showed signs of strengthening, with approximately 55% and 35% improvements in current 2009 published prices over prompt levels at the beginning of 2007 for reference Powder River Basin and Central Appalachian coal products, respectively.

By early 2008, we expect to have dramatically reshaped our global platform, with major enhancements to our flagship Powder River Basin operations, expansion in Australia, strategic evaluation of our Eastern operations and a larger global trading presence. Capital projects are targeted for the expansion of our international platform in Australia, including the completion of our Wilpinjong Mine, North Wambo Underground Mine and Millennium Mine.

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. Our major 2007 projects include the installation of a new dragline system at our North Antelope Rochelle Mine in the Powder River Basin, which is expected to reduce fuel usage and costs, the completion of a new in-pit conveyor system and progress on a new coal blending and loadout facility also at North Antelope Rochelle, which is expected to increase capacity and improve blending capabilities.

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 CTL. Coal-to-gas and CTL facilities are being built and operated outside the United States as alternatives to high-priced conventional oil and gas.

Management continues to focus on cost control 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, 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. 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 six months ended June 30, 2007 increased $13.1 million compared to the prior year. This increase primarily related to working capital changes partially offset by lower cash income from operations.

Net cash used in investing activities increased $20.1 million for the six months ended June 30, 2007 compared to the prior year. The increase reflects higher capital spending of $88.2 million in 2007, partially offset by the acquisition of an additional interest in a joint venture for $44.5 million in 2006 and $22.5 million in proceeds from disposals or exchanges of assets, net of notes receivable. Capital expenditures in 2007 included mine development at our recently acquired Australian mines, the completion of an in–pit conveyor system and progress on a coal blending and loadout facility at one of our Western mines.

Net cash used for financing activities increased $52.8 million compared to the prior year. The increase primarily related to the repayment of $103.0 million of debt that included a $60.0 million retirement of our 5.0% Subordinated Note; a $24.9 million repayment on the outstanding balance of our Term Loan under the Senior Unsecured Credit Facility; a $13.8 million open-market purchase of 5.875% Senior Notes; and capital lease payments totaling $4.3 million. Also contributing to the increase in net cash used in financing activities were lower tax benefit related to stock option exercises and lower proceeds from the exercise of stock options, partially offset by higher usage of our accounts receivable securitization program of $12.3 million during 2007 and payments for common stock repurchases of $11.5 million in the prior year.

Our total indebtedness as of June 30, 2007 and December 31, 2006, consisted of the following:


	June 30,			December 31,
	2007			2006
	(Dollars in thousands)
Term Loan under Senior Unsecured Credit Facility	$	522,054		$	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		246,931			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		97,792			96,869
Fair value of interest rate swaps		(21,668	)		(13,784	)
Other		22,301			22,918


Total	$	3,192,000		$	3,297,749

As of June 30, 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 six months ended June 30, 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’s — Ba1 rating, Standard & Poor’s — BB rating and Fitch — BB+ rating. The ratings on our convertible junior subordinated debentures were as follows: Moody’s — Ba3 rating (downgraded from a Ba2 rating at December 31, 2006 due to changes in Moody’s methodology for evaluating the instrument), Standard & Poor’s — 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 June 30, 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 six months ended June 30, 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)	$	3,604	$	14,414	$	14,414	$	26,214

We do not expect any of the $138 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 June 30, 2007, we had $153.7 million of purchase obligations for capital expenditures and $356.4 million of obligations related to federal coal reserve lease payments due over the next three years. Total capital expenditures for 2007 are now expected to range from $550 to $600 million, excluding capital projects associated with the Prairie State Energy Campus project and federal coal reserve lease payments. Contractor escalations, materials, currency impact and project delays in Australia and the Powder River Basin have led to higher capital costs. Additionally, we added a new preparation plant project at one of our Western mines to improve coal quality. Capital expenditures relate to replacement, improvement, or expansion of existing mines and growth initiatives. Capital expenditures were funded through operating cash flow.

Our wholly-owned subsidiary, Prairie State Generating Company, LLC (PSGC), entered into a cost reimbursable Target Price Engineering, Procurement and Construction Agreement (Agreement) with Bechtel Power Corporation (Bechtel) related to a mine mouth pulverized coal-fired generating facility. At the financial closing (expected in the second half of 2007), our interest in PSGC will be transferred to an Indiana non-profit corporation that will be owned and controlled by a group of owners (Owners), including one or more of our affiliates. We provided an absolute and unconditional payment guarantee of all amounts due until financial closing by PSGC to Bechtel under the Agreement (Initial Owner Guarantee). Following the transfer of PSGC’s membership interests, each Owner will issue a guarantee to Bechtel for its proportionate share of PSGC’s obligations under the Agreement. We will provide a guarantee to Bechtel for the proportionate share of our affiliates that will ultimately (together with the other Owners) control PSGC and own a proportionate share in the facility. Our Initial Owner Guarantee will terminate (other than for claims then existing) following the transfer of PSGC’s membership interest to the Indiana non-profit corporation controlled by the Owners. We currently expect that reimbursements from partners will substantially offset 2007 project expenditures and that construction will commence shortly after financial closing.

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.

We have an established accounts receivable securitization program through our wholly-owned, bankruptcy-remote subsidiary. In May 2007, we amended our accounts receivable securitization program and increased the purchase limit from $225.0 million to $275.0 million. The amount of undivided interests in accounts receivable sold to the Conduit was $231.5 million as of June 30, 2007 and $219.2 million as of December 31, 2006.

There were no other material changes to our off-balance sheet arrangements during the six months ended June 30, 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. At adoption, we had $135 million of unrecognized tax benefits in our condensed consolidated financial statements, and an additional $3 million has been added since January 1, 2007 resulting from tax positions taken during the current year. We do not expect 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 are 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, which 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 June 30, 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 six months ended June 30, 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		6,380
Average		1,759		3,569

As of June 30, 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		28	%
2008		45	%
2009		22	%
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 Australian dollar-denominated operating expenditures. As of June 30, 2007, we had in place forward contracts designated as cash flow hedges with notional amounts outstanding totaling A$864.6 million of which A$279.4 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$664.9 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 $6.6 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 Note 7 to our condensed consolidated financial statements. As of June 30, 2007, after taking into consideration the effects of interest rate swaps, we had $2.27 billion of fixed-rate borrowings and $923.4 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $9.2 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 June 30, 2007, we had derivative contracts outstanding that are designated as hedges of anticipated purchases of fuel and explosives.

Notional amounts outstanding under fuel-related, derivative swap contracts were 103.2 million gallons of crude oil scheduled to expire through 2010 and 8.0 million gallons of heating oil scheduled to expire through 2007. At June 30, 2007, we had outstanding option contracts designated as a collar of crude oil prices with notional amounts of 21.7 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 6.8 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 47% 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 $0.3 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 June 30, 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 risk factors listed below should be read in conjunction with the risk factors outlined in Part I, Item 1A of our 2006 Annual Report on Form 10-K.

The implementation of our new enterprise resource planning system carries certain risks, including the potential for business interruption, and the associated adverse impact.

To support the continued growth and globalization of our businesses, we are converting our existing information systems across major business processes to an integrated information technology system. The U.S. implementation will begin in the second-half of 2007. We have made extensive plans to support effective implementation of this information technology system. Such a major undertaking carries the additional risk of unforeseen issues and interruptions. The extent to which we successfully convert our information technology systems and address unforeseen issues will have direct bearing on our ability to perform certain day-to-day functions.

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. As of June 30, 2007, there were 10.9 million shares available for repurchase. There were no share repurchases during the three months ended June 30, 2007 under the share repurchase program.


					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⁽¹⁾		Share		Program		Under the Program
April 1 through April 30, 2007		—	$	—		—		10,920,605
May 1 through May 31, 2007		—		—		—		10,920,605
June 1 through June 30, 2007		983		49.94		—		10,920,605

Total		983	$	49.94		—


⁽¹⁾		Includes 983 shares withheld to cover the withholding taxes upon the vesting of restricted stock.

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

Peabody Energy Corporation’s annual meeting of stockholders was held on May 1, 2007. The shares of common stock eligible to vote were based on a record date of March 9, 2007. Five Class III directors were elected to serve for three-year terms expiring in 2010. A tabulation of votes for each director is set forth below:


	For		Withheld
William A. Coley		178,241,630		57,034,955
Irl F. Engelhardt		177,733,410		57,543,175
William C. Rusnack		177,778,772		57,497,813
John F. Turner		170,033,420		65,243,165
Alan H. Washkowitz		169,576,436		65,700,149

The terms of office of the following directors continued after the annual meeting of stockholders: Gregory H. Boyce, B.R. Brown, Henry Givens, Jr., William E. James, Robert B. Karn III, Henry E. Lentz, James R. Schlesinger, Blanche M. Touhill, and Sandra A. Van Trease.

Stockholders also voted to ratify Ernst & Young LLP as our independent registered public accounting firm for 2007 and a shareholder proposal submitted by the AFL-CIO Reserve Fund to declassify the Board for the purpose of director elections. The result of the vote on each of these matters is set forth below:


							Broker
	For		Against		Abstentions		Non-votes
Ratification of independent registered public accounting firm		232,858,440		1,081,291		1,331,512		—
Stockholder proposal regarding declassification of Board		151,112,313		38,145,218		1,687,028		44,332,026

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

On July 31, 2007, our Board of Directors approved an amendment to our by-laws for purposes of implementing a majority voting standard in uncontested director elections in place of the current plurality voting standard. Consequently, in uncontested director elections, each director to be elected by stockholders will be elected by the vote of the majority of the votes cast (as defined in our by-laws) at any meeting of stockholders for the election of directors at which a quorum is present. In contested elections, a plurality voting standard will apply, based on shares present in person or represented by proxy and voting for nominees in the election.

Item 6. Exhibits.

See Exhibit Index at page 41 of this report.

SIGNATURE

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


	PEABODY ENERGY CORPORATION

Date: August 8, 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, filed on August 7, 2006).

3.2		Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.2 of the Registrant’s Current Report on Form 8-K filed on August 2, 2007).

4.1*		6⁷/₈% Senior Notes Due 2013 Fourteenth Supplemental Indenture, dated as of June 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee.

4.2*		5⁷/₈% Senior Notes Due 2016 Eighteenth Supplemental Indenture, dated as of June 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee.

4.3*		7³/₈% Senior Notes due 2016 Nineteenth Supplemental Indenture, dated as of June 14, 2007 among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee.

4.4*		7⁷/₈% Senior Notes due 2026 Twentieth Supplemental Indenture, dated as of June 14, 2007, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and U.S. Bank National Association, as trustee.

10.1*		Peabody Investments Corp. Supplemental Employee Retirement Account.

10.2*		Second Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 15, 2007, by and among the Seller, the Registrant, the Sub-Servicers named therein, Market Street Funding LLC, as Issuer, and PNC Bank, National Association, as Administrator.

10.3*		Target Price Engineering, Procurement and Construction Agreement, dated as of June 19, 2007, between Prairie State Generating Company, LLC and Bechtel Power Corporation (Confidential treatment was requested for portions of this exhibit, and such portions were omitted from this exhibit and were filed separately with the Securities and Exchange Commission).

10.4		Letter Agreement, dated as of May 4, 2007, by and between the Registrant and Richard M. Whiting, including the form of new employment agreement between Mr. Whiting and Patriot Coal Corporation (Incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on May 18, 2007).

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.