Edgar Filing: PEABODY ENERGY CORP

10-Q

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, 2008


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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

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 271,943,950 shares of common stock with a par value of $0.01 per share outstanding at August 1, 2008.

INDEX


		Page
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

Unaudited Condensed Consolidated Statement of Operations for the Three and Six Months Ended June 30, 2008 and 2007		1

Condensed Consolidated Balance Sheet as of June 30, 2008 (Unaudited) and December 31, 2007		2

Unaudited Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2008 and 2007		3

Notes to Unaudited Condensed Consolidated Financial Statements		4

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		37

Item 4. Controls and Procedures		40

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		40

Item 1A. Risk Factors		40

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		41

Item 4. Submission of Matters to a Vote of Security Holders		41

Item 6. Exhibits		41

SIGNATURE		42

EXHIBIT INDEX		43
EX-3.1
EX-10.1
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(Dollars in millions, except share and per share data)
Revenues
Sales	$	1,422.1		$	1,023.6		$	2,611.8		$	2,083.1
Other revenues		108.8			45.2			195.1			95.5

Total revenues		1,530.9			1,068.8			2,806.9			2,178.6

Costs and Expenses
Operating costs and expenses		1,048.5			823.1			2,062.2			1,669.8
Depreciation, depletion and amortization		93.6			88.5			187.6			170.4
Asset retirement obligation expense		9.2			3.8			16.0			9.5
Selling and administrative expenses		43.1			32.1			94.0			63.8
Other operating income:
Net gain on disposal or exchange of assets		(3.6	)		(53.0	)		(63.0	)		(54.4	)
Income from equity affiliates		(3.7	)		(4.3	)		(6.4	)		(6.5	)


Operating Profit		343.8			178.6			516.5			326.0
Interest expense		57.6			58.6			116.9			116.1
Interest income		(2.5	)		(1.5	)		(3.6	)		(4.3	)


Income From Continuing Operations Before Income Taxes and Minority Interests		288.7			121.5			403.2			214.2
Income tax provision		43.6			17.0			87.7			28.1
Minority interests		2.5			4.8			3.4			4.5


Income From Continuing Operations		242.6			99.7			312.1			181.6
Income (loss) from discontinued operations, net of tax		(9.2	)		8.0			(21.5	)		14.6

Net Income	$	233.4		$	107.7		$	290.6		$	196.2


Basic Earnings Per Share
Income from continuing operations	$	0.90		$	0.38		$	1.16		$	0.69
Income (loss) from discontinued operations		(0.04	)		0.03			(0.08	)		0.06

Net income	$	0.86		$	0.41		$	1.08		$	0.75

Weighted Average Shares Outstanding — Basic		269,991,967			263,479,042			269,598,425			263,256,691


Diluted Earnings Per Share
Income from continuing operations	$	0.89		$	0.37		$	1.15		$	0.68
Income (loss) from discontinued operations		(0.03	)		0.03			(0.08	)		0.05

Net income	$	0.86		$	0.40		$	1.07		$	0.73

Weighted Average Shares Outstanding — Diluted		272,664,395			268,712,309			272,404,861			268,457,302

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, 2008			December 31, 2007
	(Dollars in millions, except
	share and per share data)
ASSETS
Current assets
Cash and cash equivalents	$	74.8		$	45.3
Accounts receivable, net of allowance for doubtful accounts of $14.1 at June 30, 2008 and $11.9 at December 31, 2007		296.0			256.9
Inventories		296.3			264.7
Assets from coal trading activities		1,392.5			349.8
Deferred income taxes		98.6			98.6
Other current assets		456.6			295.2

Total current assets		2,614.8			1,310.5
Property, plant, equipment and mine development
Land and coal interests		7,251.1			7,197.1
Buildings and improvements		699.8			685.8
Machinery and equipment		1,377.4			1,258.9
Less accumulated depreciation, depletion and amortization		(1,985.8	)		(1,817.9	)

Property, plant, equipment and mine development, net		7,342.5			7,323.9
Investments and other assets		531.2			417.1

Total assets	$	10,488.5		$	9,051.5


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	135.9		$	134.4
Liabilities from coal trading activities		1,459.9			301.8
Accounts payable and accrued expenses		1,155.2			1,134.0

Total current liabilities		2,751.0			1,570.2

Long-term debt, less current maturities		3,122.7			3,138.7
Deferred income taxes		325.0			315.6
Asset retirement obligations		388.2			367.7
Accrued postretirement benefit costs		780.6			785.7
Other noncurrent liabilities		309.5			353.2

Total liabilities		7,677.0			6,531.1

Minority interests		4.0			0.7
Stockholders’ equity
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of June 30, 2008 or December 31, 2007		—			—
Series A Junior Participating Preferred Stock — 1,500,000 shares authorized, no shares issued or outstanding as of June 30, 2008 or December 31, 2007		—			—
Perpetual Preferred Stock — 750,000 shares authorized, no shares issued or outstanding as of June 30, 2008 or December 31, 2007		—			—
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of June 30, 2008 or December 31, 2007		—			—
Common Stock — $0.01 per share par value; 800,000,000 shares authorized, 274,916,296 shares issued and 271,875,929 shares outstanding as of June 30, 2008 and 272,911,564 shares issued and 270,066,621 shares outstanding as of December 31, 2007		2.7			2.7
Additional paid-in capital		1,811.6			1,750.7
Retained earnings		1,199.4			941.4
Accumulated other comprehensive loss		(87.3	)		(67.1	)
Treasury shares, at cost: 3,040,367 shares as of June 30, 2008 and 2,844,943 shares as of December 31, 2007		(118.9	)		(108.0	)

Total stockholders’ equity		2,807.5			2,519.7

Total liabilities and stockholders’ equity	$	10,488.5		$	9,051.5

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS


	Six Months Ended June 30,
	2008			2007
	(Dollars in millions)
Cash Flows From Operating Activities
Net income	$	290.6		$	196.2
Loss (income) from discontinued operations		21.5			(14.6	)

Income from continuing operations		312.1			181.6
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
Depreciation, depletion and amortization		187.6			170.4
Deferred income taxes		2.5			(4.5	)
Stock compensation		17.9			12.5
Amortization of debt discount and debt issuance costs		3.3			3.8
Net gain on disposal or exchange of assets		(63.0	)		(54.4	)
Income from equity affiliates		(6.4	)		(6.5	)
Revenue recovery on coal supply agreement		(56.9	)		—
Dividends received from equity affiliates		19.9			12.9
Changes in current assets and liabilities:
Accounts receivable, including securitization		(30.9	)		94.8
Inventories		(31.6	)		(31.8	)
Net assets from coal trading activities		(89.9	)		(27.0	)
Other current assets		(18.9	)		(7.9	)
Accounts payable and accrued expenses		65.8			(102.8	)
Asset retirement and employment related obligations		18.9			50.3
Distributions to minority interests		(1.5	)		(1.5	)
Other, net		(7.9	)		13.2

Net cash provided by continuing operations		321.0			303.1
Net cash used in discontinued operations		(56.7	)		(66.4	)

Net cash provided by operating activities		264.3			236.7

Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		(109.9	)		(261.8	)
Investment in Prairie State		(18.5	)		—
Federal coal lease expenditures		(123.4	)		(123.4	)
Proceeds from disposal of assets, net of notes receivable		28.1			13.2
Additions to advance mining royalties		(2.8	)		(2.0	)
Investments in equity affiliates and joint ventures		(2.6	)		(0.6	)

Net cash used in continuing operations		(229.1	)		(374.6	)
Net cash provided by discontinued operations		—			5.3

Net cash used in investing activities		(229.1	)		(369.3	)

Cash Flows From Financing Activities
Change in revolving line of credit		2.3			—
Payments of long-term debt		(18.6	)		(103.0	)
Dividends paid		(32.5	)		(31.8	)
Payment of debt issuance costs		—			(0.8	)
Excess tax benefit related to stock options exercised		26.8			12.6
Proceeds from stock options exercised		13.5			8.3
Proceeds from employee stock purchases		2.8			3.1

Net cash used in financing activities		(5.7	)		(111.6	)

Net increase (decrease) in cash and cash equivalents		29.5			(244.2	)
Cash and cash equivalents at beginning of period		45.3			326.5

Cash and cash equivalents at end of period	$	74.8		$	82.3

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2008

(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 Company classifies items within discontinued operations in the unaudited condensed consolidated statements of operations when the operations and cash flows of a particular component (defined as operations and cash flows that can be clearly distinguished, operationally and for financial reporting purposes, from the rest of the entity) of the Company have been (or will be) eliminated from the ongoing operations of the Company as a result of a disposal transaction, and the Company will no longer have any significant continuing involvement in the operations of that component. For more information on discontinued operations, see Note 3.

The accompanying condensed consolidated financial statements as of June 30, 2008 and for the three and six months ended June 30, 2008 and 2007, 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, 2007 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the six months ended June 30, 2008 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2008. Certain amounts in prior periods have been reclassified to conform to report classifications as of June 30, 2008 and for the three and six months ended June 30, 2008, with no effect on previously reported net income or stockholders’ equity.

(2) New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS No. 157 applies under accounting pronouncements that require or permit fair value measurements, but the standard does not require any new fair value measurements. In February 2008, the FASB amended SFAS No. 157 to exclude leasing transactions and to delay the effective date by one year for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. The Company adopted SFAS No. 157 on January 1, 2008. See Note 10 for further information.

In April 2007, the FASB issued FASB Staff Position (FSP) FASB Interpretation Number (FIN) 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 amends certain provisions of FIN 39, “Offsetting of Amounts Related to Certain Contracts,” and permits companies to offset fair value amounts recognized for cash collateral receivables or payables against fair value amounts recognized for net derivative positions executed with the same counterparty under the same master netting arrangement. Prior to the implementation of FSP FIN 39-1, all positions executed with common counterparties were presented gross in the appropriate balance sheet line items. Effective January 1, 2008, in accordance with the provisions of FSP FIN 39-1, the Company offset its asset and liability coal trading derivative positions and other corporate hedging activities on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract. The December 31, 2007 balances were adjusted to conform with the provisions of FSP FIN 39-1. See Note 4 for a presentation of the assets and liabilities from coal trading activities on a gross basis (pre-FSP FIN 39-1) and on a net basis (post-FSP FIN 39-1).

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 provides all entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 was effective for the Company for the fiscal year beginning January 1, 2008. SFAS No. 159 did not have an impact on the accompanying unaudited condensed consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes accounting and reporting standards for noncontrolling interests in partially-owned consolidated subsidiaries and the loss of control of subsidiaries. SFAS No. 160 requires noncontrolling interests (minority interests) to be reported as a separate component of equity. In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for the Company). Early adoption is not allowed. The Company does not expect the adoption of SFAS No. 160 to have a material effect on its results of operations or financial condition.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS No. 141(R)), which replaces SFAS No. 141. SFAS No. 141(R) changes the principles and requirements for the recognition and measurement of identifiable assets acquired, liabilities assumed, and any noncontrolling interest of an acquiree in the financial statements of an acquirer. This statement also provides guidance for the recognition and measurement of goodwill acquired in a business combination and related disclosure. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008 (January 1, 2009 for the Company).

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 expands the disclosure requirements for derivative instruments and hedging activities. This statement specifically requires entities to provide enhanced disclosures addressing the following: (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under FASB Statement No. 133 and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for the Company). While the Company is currently evaluating the impact SFAS No. 161 will have on its disclosures, the adoption of SFAS No. 161 will not affect the Company’s results of operations or financial condition.

In May 2008, the FASB issued FSP No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1). FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are not considered debt instruments within the scope of APB Opinion No. 14, “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants” (APB 14). FSP APB 14-1 also specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the issuer’s nonconvertible debt borrowing rate when recognizing interest cost in subsequent periods. FSP APB 14-1 is effective for fiscal years and interim periods beginning after December 15, 2008 (January 1, 2009 for the Company) and will require retrospective application for all periods presented. The Company is currently evaluating the effect of FSP APB 14-1 on its Convertible Junior Subordinated Debentures and it has not yet determined the impact of the standard on its results of operations or financial condition.

(3) Discontinued Operations and Assets Held for Sale

Patriot Coal Corporation

On October 31, 2007, the Company spun-off portions of its Eastern U.S. Mining operations business segment through a dividend of all outstanding shares of Patriot Coal Corporation (Patriot), which is now an independent public company traded on the New York Stock Exchange (symbol PCX). The spin-off included eight company-operated mines, two joint venture mines, and numerous contractor operated mines serviced by eight coal preparation facilities along with 1.2 billion tons of proven and probable coal reserves. Revenues, pretax income (loss) and the income tax provision (benefit) related to the spun-off operations were as follows:


	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008			2007
			(Dollars in millions)
Revenues	$	150.4	$	256.2	$	265.7		$	525.3
Income (loss) before income taxes and minority interests		0.6		15.3		(19.8	)		24.6
Income tax provision (benefit)		—		2.1		(8.1	)		3.7

Revenues from the spun-off operations are the result of supply agreements the Company entered into with Patriot to meet commitments under non-assignable pre-existing customer agreements sourced from Patriot mining operations. The Company makes no profit as part of these arrangements and only sources coal from Patriot to meet customer obligations. The loss from discontinued operations for the six months ended June 30, 2008 was primarily due to the first quarter write-off of a $19.4 million receivable following an adverse April 15, 2008 Supreme Court ruling related to excise tax refunds paid on export shipments from discontinued operations. See Note 11 for further discussions related to this receivable.

The Company had also entered into a transition services agreement to provide certain administrative and other services to Patriot for a period of six months ending April 30, 2008. Patriot exercised its option to extend this agreement to July 31, 2008. Under this agreement, the Company billed $1.4 million for transitional services for the first six months of 2008.

The assets and liabilities of the discontinued operations as of June 30, 2008 and December 31, 2007 are shown below:


	June 30, 2008		December 31, 2007
	(Dollars in millions)
Assets
Current assets
Other current assets	$	55.3	$	74.1

Total current assets		55.3		74.1

Total assets	$	55.3	$	74.1


Liabilities
Current liabilities
Accounts payable and accrued expenses	$	124.0	$	180.4

Total current liabilities		124.0		180.4
Noncurrent liabilities
Other noncurrent liabilities		17.8		33.2

Total liabilities	$	141.8	$	213.6

Other current assets included receivables from customers in relation to the supply agreements with Patriot, and accounts payable and accrued expenses included the amounts due to Patriot on these pass-through transactions. Also included in liabilities was an accrual for charges related to losses on firm purchase commitments that extend through 2010.

Assets Held for Sale

In June 2008, the Company committed to the divestiture of certain non-strategic mining assets. The Company expects to dispose of these assets at a price in the excess of their carrying value and to record a gain at the time of disposition, which is expected to occur in the third quarter of 2008. At June 30, 2008, the carrying amount of assets held for sale totaled $12.3 million and the carrying amount of liabilities associated with assets held for sale totaled $4.8 million.

(4) Assets and Liabilities from Coal Trading Activities

The fair value of assets and liabilities from coal trading activities is set forth below:


				December 31,
	June 30, 2008			2007
	(Dollars in millions)
Assets from coal trading activities	$	1,392.5		$	349.8
Liabilities from coal trading activities		1,459.9			301.8

Net value of coal trading positions	$	(67.4	)	$	48.0

The recent increase in coal pricing, volatility and trading volumes have significantly increased the relative value of the Company’s trading asset and liability portfolio. As of June 30, 2008, forward contracts made up 93.7% and 35.1% of the Company’s trading assets and liabilities, respectively; financial swaps represent most of the remaining balances. The value of coal trading positions included net mark-to-market liabilities on cash flow hedges of anticipated future sales of $273.3 million and $53.3 million as of June 30, 2008 and December 31, 2007, respectively. The net value of trading positions, including those designated as hedges of future cash flows, represents the fair value of the trading portfolio.

Of the coal trading derivatives and related hedge contracts in the Company’s trading portfolio as of June 30, 2008, 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 discussed in Note 2, the Company adopted FSP FIN 39-1 effective January 1, 2008. As a result, the Company offset its asset and liability coal trading derivative positions on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract. The effect of FSP FIN 39-1 on the Company’s trading asset and liability portfolio is set forth below:


	June 30, 2008						December 31, 2007
				(Dollars in millions)
	Pre-FSP FIN 39-1			Post-FSP FIN 39-1			Pre-FSP FIN 39-1		Post-FSP FIN 39-1
Assets from coal trading activities	$	4,564.5		$	1,392.5		$	966.6	$	349.8
Liabilities from coal trading activities		4,631.9			1,459.9			918.6		301.8

Net value of coal trading positions	$	(67.4	)	$	(67.4	)	$	48.0	$	48.0

As of June 30, 2008, the timing of the estimated future realization of the value of the Company’s trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2008		7	%
2009		62	%
2010		16	%
2011		12	%
2012		3	%

		100	%

At June 30, 2008, 33% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties and 67% was with non-investment grade counterparties, including unrated entities. The Company’s coal trading operations traded 33.8 million tons and 34.9 million tons for the three months ended June 30, 2008 and 2007, respectively, and 87.0 million tons and 66.4 million tons for the six months ended June 30, 2008 and 2007, respectively.

(5) Resource Management

In March 2008, the Company sold approximately 58 million tons of non-strategic coal reserves and surface lands located in Kentucky for $21.5 million cash proceeds and a note receivable of $54.9 million and recognized a gain of $54.0 million. The note receivable is expected to be paid in two installments. The first payment is due in December 2008 with the balance to be paid in June 2009. The non-cash portion of this transaction was excluded from the investing section of the unaudited condensed consolidated statement of cash flows.

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 coal reserves in West Virginia and Kentucky and $15.0 million in cash proceeds. The Company’s subsidiaries, including one subsidiary now owned by Patriot, received approximately 40 million tons of coal reserves. 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 unaudited condensed consolidated statement of cash flows.

(6) Inventories

Inventories as of June 30, 2008 and December 31, 2007 consisted of the following:


	June 30, 2008		December 31, 2007
	(Dollars in millions)
Materials and supplies	$	104.2	$	90.3
Raw coal		35.5		45.5
Saleable coal		156.6		128.9

Total	$	296.3	$	264.7

7) Comprehensive Income

The following table sets forth the after-tax components of comprehensive income for the three and six months ended June 30, 2008 and 2007:


	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
				(Dollars in millions)
Net income	$	233.4		$	107.7	$	290.6		$	196.2
Increase (decrease) in fair value of cash flow hedges, net of tax provision of $10.6 and $4.1 for the three months ended June 30, 2008 and 2007, respectively, and $14.3 and $12.9 for the six months ended June 30, 2008 and 2007, respectively.		(20.9	)		5.2		(26.6	)		19.4
Amortization of actuarial loss and prior service cost realized in net income, net of tax provision of $2.2 and $8.3 for the three months ended June 30, 2008 and 2007, respectively, and $4.2 and $11.7 for the six months ended June 30, 2008 and 2007, respectively.		3.3			12.4		6.4			20.0

Comprehensive income	$	215.8		$	125.3	$	270.4		$	235.6

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. The values of the Company’s cash flow hedging instruments are affected by changes in interest rates, crude oil and natural gas prices, and the U.S. dollar/Australian dollar exchange rate.

(8) Pension and Postretirement Benefit Costs

Net periodic pension (benefit) costs included the following components:


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
				(Dollars in millions)
Service cost for benefits earned	$	0.3		$	2.3		$	1.0		$	4.5
Interest cost on projected benefit obligation		12.7			12.0			25.4			24.0
Expected return on plan assets		(15.1	)		(14.1	)		(30.3	)		(28.2	)
Amortization of prior service cost, actuarial loss and other		—			4.2			0.2			8.4

Net periodic pension (benefit) costs	$	(2.1	)	$	4.4		$	(3.7	)	$	8.7

Net periodic postretirement benefit costs included the following components:


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
			(Dollars in millions)
Service cost for benefits earned	$	2.6	$	2.9	$	5.2	$	5.0
Interest cost on accumulated postretirement benefit obligation		13.5		12.4		27.1		24.7
Amortization of prior service cost and actuarial loss		4.5		5.3		9.0		9.9

Net periodic postretirement benefit costs	$	20.6	$	20.6	$	41.3	$	39.6

(9) 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 continuing operations before deducting early debt extinguishment costs, 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, 2008 and 2007 were as follows:


	Three Months Ended June 30,					Six Months Ended June 30,
	2008			2007		2008			2007
				(Dollars in millions)
Revenues:
Western U.S. Mining	$	644.4		$	495.1	$	1,235.9		$	979.6
Eastern U.S. Mining		294.7			256.6		561.5			513.6
Australian Mining		523.5			249.4		823.7			536.4
Trading and Brokerage		61.3			59.4		171.4			135.7
Corporate and Other		7.0			8.3		14.4			13.3

Total	$	1,530.9		$	1,068.8	$	2,806.9		$	2,178.6


Adjusted EBITDA:
Western U.S. Mining	$	188.0		$	137.3	$	341.7		$	276.5
Eastern U.S. Mining		37.7			49.6		70.7			99.3
Australian Mining		240.8			44.0		244.6			106.6
Trading and Brokerage		38.1			26.4		129.9			63.0
Corporate and Other ⁽¹⁾		(58.0	)		13.6		(66.8	)		(39.5	)

Total	$	446.6		$	270.9	$	720.1		$	505.9


(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 from continuing operations before income taxes and minority interests follows:


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
				(Dollars in millions)
Total Adjusted EBITDA	$	446.6		$	270.9		$	720.1		$	505.9

Depreciation, depletion and amortization		93.6			88.5			187.6			170.4
Asset retirement obligation expense		9.2			3.8			16.0			9.5
Interest expense		57.6			58.6			116.9			116.1
Interest income		(2.5	)		(1.5	)		(3.6	)		(4.3	)


Income from continuing operations before income taxes and minority interests	$	288.7		$	121.5		$	403.2		$	214.2

Total assets of the Trading and Brokerage segment have changed significantly since December 31, 2007 due to an increase in the Company’s trading asset portfolio as a result of recent increases in coal pricing, volatility and trading volumes. The total assets of the segment were $1.5 billion and $346.8 million as of June 30, 2008 and December 31, 2007, respectively. For further discussion of the Company’s trading portfolio, see Note 4.

(10) Fair Value Measurements

As discussed in Note 2, the Company adopted SFAS No. 157 effective January 1, 2008. Although the adoption of SFAS No. 157 did not materially impact the Company’s financial condition, results of operations or cash flows, additional disclosures related to fair value measurements are now required. SFAS No. 157 establishes a three-level fair value hierarchy that categorizes assets and liabilities measured at fair value based on the observability of the inputs utilized in the valuation. These levels include: Level 1, inputs are quoted prices in active markets for the identical assets or liabilities; Level 2, inputs other than quoted prices included in Level 1 that are directly or indirectly observable through market-corroborated inputs; and Level 3, inputs are unobservable, requiring the Company to make assumptions about pricing by market participants.

The following table sets forth as of June 30, 2008 the hierarchy of the Company’s net financial asset (liability) positions for which fair value is measured on a recurring basis:


	Level 1		Level 2			Level 3			Total
			(Dollars in millions)
Commodity swaps and options – coal trading activities	$	16.0	$	(833.9	)	$	(14.2	)	$	(832.1	)
Commodity swaps and options – commodities		—		165.5			—			165.5
Physical commodity purchase/sale contracts – coal trading activities		—		371.8			392.9			764.7
Interest rate swaps		—		3.0			—			3.0
Foreign currency forwards and options		—		199.5			—			199.5

Total assets (liabilities)	$	16.0	$	(94.1	)	$	378.7		$	300.6

For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including LIBOR yield curves, NYMEX indices and other market quotes. Below is a summary of the Company’s valuation techniques for Level 1 and 2 financial assets and liabilities:

	•		Commodity swaps and options – coal trading activities: generally valued based on unadjusted quoted prices in active markets (Level 1) or a valuation that is corroborated by the use of market-based pricing (Level 2).

	•		Commodity swaps and options – commodities: generally valued based on a valuation that is corroborated by the use of market-based pricing (Level 2).

	•		Physical commodity purchase/sale contracts – coal trading activities: purchases and sales at locations with significant market activity corroborated by market-based information (Level 2).

	•		Interest rate swaps: valued utilizing inputs obtained in quoted public markets (Level 2).

	•		Foreign currency forwards and options: valued based on quoted inputs from counterparties corroborated by market-based pricing (Level 2).

Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements, with limited price availability were classified in Level 3. These instruments or contracts are valued based on quoted inputs from brokers or counterparties, or reflect methodologies that consider historical relationships among similar commodities to derive the Company’s best estimate of fair value. The Company has consistently applied these valuation techniques in all periods presented, and believes it has obtained the most accurate information available for the types of derivative contracts held.

The following table summarizes the changes in the Company’s recurring Level 3 net financial assets for the six months ended June 30, 2008:


			Total gains or losses
			(realized/unrealized)
						Included in
						other			Purchases,
	January 1,		Included in			comprehensive			issuances and
	2008		earnings			income			settlements		June 30, 2008
	(Dollars in millions)
Physical commodity purchase/sale contracts – coal trading activities	$	127.2	$	268.4		$	(28.2	)	$	25.5	$	392.9
Commodity swaps and options – coal trading activities		1.5		(10.0	)		(5.7	)		—		(14.2	)

Total Level 3 net financial assets	$	128.7	$	258.4		$	(33.9	)	$	25.5	$	378.7

Total unrealized gains reflected in earnings related to net financial assets held as of January 1 and June 30, 2008 were $296.9 million for the six months ended June 30, 2008. Total unrealized gains reflected in earnings related to net assets held as of April 1 and June 30, 2008 were $263.4 million for the three months ended June 30, 2008. Unrealized gains and losses for the period from Level 3 items are offset by unrealized gains and losses on positions classified in Level 1 or 2, as well as positions that have been realized during the period. Gains and losses (realized and unrealized) included in earnings related to coal trading activities for Levels 1, 2, and 3 are reported in “Other revenues.” Gains and losses related to Level 2 foreign currency forwards and options and commodity swaps and options related to commodities hedging are reported in “Operating costs and expenses.” Interest rate swaps are reported in “Interest expense.”

(11) Commitments and Contingencies

Commitments

As of June 30, 2008, purchase commitments currently outstanding for capital expenditures were $36.2 million. Federal coal reserve lease payments due over the next 12 months are $178.6 million.

Contingencies

From time to time, the Company or its subsidiaries are involved in claims, lawsuits, arbitrations, and other legal or administrative proceedings arising in the ordinary course of business or related to indemnities or historical operations. The outcome of such matters is subject to numerous uncertainties. Based on current information, the Company believes it has recorded adequate reserves for these liabilities and that there is no individual case pending that is reasonably likely to have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company’s significant legal proceedings are discussed below.

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. One of the Company’s subsidiaries named as a defendant is now a subsidiary of Patriot. However, the Company is responsible for this litigation under the Separation Agreement entered into with Patriot in connection with the spin-off. 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 to allow parties to mediate. The mediation terminated without resolution and in March 2008 the Court lifted the stay and the litigation resumed.

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 be reasonably estimated. However, based on current information, 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. All of the parties have negotiated and signed a comprehensive settlement to fully resolve all of the underlying claims and demands and to dismiss the associated litigation with prejudice, which became final and binding upon all of the parties on June 30, 2008. As a result of the retiree heath care cost settlement, the Company recorded pre-tax earnings of approximately $54 million during the quarter ended June 30, 2008. The Company has a receivable for mine decommissioning costs of $89.9 million and $87.7 million as of June 30, 2008 and December 31, 2007, respectively and a receivable for retiree health care costs of $66.8 million as of June 30, 2008 included in “Investments and other assets” in the condensed consolidated balance sheets.

Gulf Power Company Litigation

On June 22, 2006, Gulf Power Company filed a breach of contract lawsuit against a Company subsidiary in the U.S. District Court, Northern District of Florida, contesting the force majeure declaration by the Company’s subsidiary under a coal supply agreement with Gulf Power Company and seeking damages for alleged past and future tonnage shortfalls of nearly 5 million tons under the agreement, which expired on December 31, 2007. In February 2008, the Court denied the Company’s motion to dismiss the Florida lawsuit or to transfer it to Illinois and retained jurisdiction over the case.

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, based on current information, 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. Gold Fields is currently 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 past 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. 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. In December 2007, the court dismissed the tribe’s medical monitoring claim. In July 2008, the court dismissed the tribe’s claim for interim and lost use damages under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) without prejudice to refile at the point the U.S. Environmental Protection Agency (EPA) selects a final remedy for the site. 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, based on current information, 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 Environmental Matters

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) at five national priority list sites based on the Superfund Amendments and Reauthorization Act of 1986. Claims were asserted at 12 additional sites, bringing the total to 17, 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 $41.5 million as of June 30, 2008 and $43.5 million as of December 31, 2007, $5.2 million and $7.1 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 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 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. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes these claims and litigation are likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

Other

Certain former subsidiaries of the Company previously paid black lung excise taxes to the Federal Black Lung Trust Fund (the Trust Fund) on export shipments. Collections of excise taxes on export shipments were ruled unconstitutional and as a result, the Company had a receivable for excise tax refunds paid on export shipments of $19.4 million as of December 31, 2007. In a January 2007 decision, a federal appellate court confirmed the Company’s position, ruling that coal companies are entitled to a refund of the Black Lung tax paid on export shipments for certain years and that they are also entitled to collect interest on the refund. On April 15, 2008, the U.S. Supreme Court reversed the appellate court’s decision ruling that companies are not entitled to a refund of the Black Lung tax paid on export shipments paid outside the Internal Revenue Service’s three-year statute of limitations. The Company recorded a charge to discontinued operations of $19.4 million in the first quarter of 2008 to eliminate the receivable as described in Note 3.

New York Office of the Attorney General Subpoena

The New York Office of the Attorney General sent a letter to the Company dated September 14, 2007. The letter referred to the Company’s “plans to build new coal-fired electric generating units,” and said that the “increase in CO₂ emissions from the operation of these units, in combination with Peabody Energy’s other coal-fired power plants, will subject Peabody Energy to increased financial, regulatory, and litigation risks.” The Company currently has no electricity generating capacity in place. The letter included a subpoena issued under New York state law, which seeks information and documents relating to the Company’s analysis of the risks associated with climate change and possible climate change legislation or regulations, and its disclosure of such risks to investors. The Company believes that it has made full and proper disclosure of these potential risks.

Alaskan Villages’ Claims

In February 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the United States District Court for the Northern District of California against the Company, several owners of electricity generating facilities and several oil companies. The plaintiffs are the governing bodies of a village in Alaska that they contend is being destroyed by erosion allegedly caused by global warming that the plaintiffs attribute to emissions of greenhouse gases by the defendants. The plaintiffs assert claims for nuisance, and allege that the defendants have acted in concert and are jointly and severally liable for the plaintiffs’ damages. The suit seeks damages for lost property values and for the cost of relocating the village, which cost is alleged to be $95 million to $400 million. The Company believes that this lawsuit is without merit and intends to defend against and oppose it vigorously, but cannot predict its outcome. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes this matter is likely to be resolved without a materially adverse effect on its financial condition, results of operations or cash flows.

(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.

The Company uses a combination of surety bonds, corporate guarantees (i.e. self bonds) and letters of credit to secure the Company’s financial obligations for reclamation, workers’ compensation, postretirement benefits, lease and other obligations. The total value of self bonding in place was $637.4 million as of June 30, 2008 and $640.6 million as of December 31, 2007. The total value of surety bonds in place was $793.5 million as of June 30, 2008 and $539.2 million as of December 31, 2007. The total amount of letters of credit was $405.7 million as of June 30, 2008 and $413.6 million as of December 31, 2007.

As of June 30, 2008, the Company owned a 37.5% 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, 2008, 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 Guaranty 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, 2008. As a result of these proceedings, TXU Europe Limited may be liquidated or otherwise reorganized in such a way as to relieve it of its obligations under its guarantee.

Other Guarantees

As part of arrangements through which the Company obtains exclusive sales representation agreements with small coal mining companies (the Counterparties), the Company issued financial guarantees on behalf of the Counterparties. These guarantees facilitate the Counterparties’ efforts to obtain bonding or financing.

In 2007, the Company purchased approximately 345 million tons of coal reserves and surface lands in the Illinois Basin. In conjunction with this purchase, the Company agreed to provide up to $64.8 million of reclamation and bonding commitments to a third-party coal company. The Company has recognized $61.8 million of these commitments as a liability as of June 30, 2008.

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 the Company 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. For the descriptions of the Company’s (and its subsidiaries’) debt, see Part IV, Item 15 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. Supplemental guarantor/non-guarantor financial information is provided in Note 13.

As part of the Patriot spin-off, the Company agreed to maintain in force several letters of credit that secured Patriot obligations for certain employee benefits and workers’ compensation obligations. These letters of credit are to be released upon Patriot satisfying the beneficiaries with alternate letters of credit or insurance, which is expected to occur in 2008. If Patriot is unable to satisfy the primary beneficiaries by June 30, 2011, Patriot is required to provide directly to the Company a letter of credit for the amount of the remaining obligation. The amount of letters of credit securing Patriot obligations was $7.0 million and $136.8 million as of June 30, 2008 and December 31, 2007, respectively.

(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. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the Senior Note holders. 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, 2008
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	1,202.9		$	371.6		$	(43.6	)	$	1,530.9
Costs and expenses:
Operating costs and expenses		(51.5	)		700.9			442.7			(43.6	)		1,048.5
Depreciation, depletion and amortization		—			61.4			32.2			—			93.6
Asset retirement obligation expense		—			8.3			0.9			—			9.2
Selling and administrative expenses		6.9			37.4			(1.2	)		—			43.1
Other operating income (loss):
Net gain on disposal or exchange of assets		—			(3.5	)		(0.1	)		—			(3.6	)
(Income) loss from equity affiliates		(245.7	)		1.2			(4.9	)		245.7			(3.7	)
Interest expense		53.7			20.9			13.4			(30.4	)		57.6
Interest income		(3.9	)		(21.2	)		(7.8	)		30.4			(2.5	)

Income (loss) from continuing operations before income taxes and minority interests		240.5			397.5			(103.6	)		(245.7	)		288.7
Income tax provision (benefit)		(2.1	)		13.0			32.7			—			43.6
Minority interests		—			—			2.5			—			2.5

Income (loss) from continuing operations		242.6			384.5			(138.8	)		(245.7	)		242.6
Loss from discontinued operations, net of tax		(9.2	)		—			—			—			(9.2	)

Net income (loss)	$	233.4		$	384.5		$	(138.8	)	$	(245.7	)	$	233.4

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 millions)
Total revenues	$	—		$	783.6		$	311.3		$	(26.1	)	$	1,068.8
Costs and expenses:
Operating costs and expenses		(0.2	)		607.9			241.5			(26.1	)		823.1
Depreciation, depletion and amortization		—			62.7			25.8			—			88.5
Asset retirement obligation expense		—			2.4			1.4			—			3.8
Selling and administrative expenses		8.3			22.2			1.6			—			32.1
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(53.0	)		—			—			(53.0	)
(Income) loss from equity affiliates		(143.0	)		1.6			(5.9	)		143.0			(4.3	)
Interest expense		69.0			76.1			5.9			(92.4	)		58.6
Interest income		(4.2	)		(82.9	)		(6.8	)		92.4			(1.5	)

Income from continuing operations before income taxes and minority interests		70.1			146.6			47.8			(143.0	)		121.5
Income tax provision (benefit)		(29.6	)		37.3			9.3			—			17.0
Minority interests		—			—			4.8			—			4.8

Income from continuing operations		99.7			109.3			33.7			(143.0	)		99.7
Income from discontinued operations, net of tax		8.0			—			—			—			8.0

Net income	$	107.7		$	109.3		$	33.7		$	(143.0	)	$	107.7

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Six Months Ended June 30, 2008
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	2,144.1		$	738.6		$	(75.8	)	$	2,806.9
Costs and expenses:
Operating costs and expenses		(86.9	)		1,451.9			773.0			(75.8	)		2,062.2
Depreciation, depletion and amortization		—			123.0			64.6			—			187.6
Asset retirement obligation expense		—			14.2			1.8			—			16.0
Selling and administrative expenses		9.3			81.1			3.6			—			94.0
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(62.9	)		(0.1	)		—			(63.0	)
(Income) loss from equity affiliates		(331.4	)		2.2			(8.6	)		331.4			(6.4	)
Interest expense		117.0			42.7			26.5			(69.3	)		116.9
Interest income		(7.5	)		(51.5	)		(13.9	)		69.3			(3.6	)

Income (loss) from continuing operations before income taxes and minority interests		299.5			543.4			(108.3	)		(331.4	)		403.2
Income tax provision (benefit)		(12.6	)		54.2			46.1			—			87.7
Minority interests		—			—			3.4			—			3.4

Income (loss) from continuing operations		312.1			489.2			(157.8	)		(331.4	)		312.1
Loss from discontinued operations, net of tax		(21.5	)		—			—			—			(21.5	)

Net income (loss)	$	290.6		$	489.2		$	(157.8	)	$	(331.4	)	$	290.6

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 millions)
Total revenues	$	—		$	1,597.7		$	642.1		$	(61.2	)	$	2,178.6
Costs and expenses:
Operating costs and expenses		1.3			1,224.2			505.5			(61.2	)		1,669.8
Depreciation, depletion and amortization		—			120.2			50.2			—			170.4
Asset retirement obligation expense		—			7.8			1.7			—			9.5
Selling and administrative expenses		14.5			46.9			2.4			—			63.8
Other operating (income) loss:
Net (gain) loss on disposal or exchange of assets		—			(54.5	)		0.1			—			(54.4	)
(Income) loss from equity affiliates		(269.2	)		3.1			(9.6	)		269.2			(6.5	)
Interest expense		139.1			26.7			11.9			(61.6	)		116.1
Interest income		(8.9	)		(42.4	)		(14.6	)		61.6			(4.3	)

Income from continuing operations before income taxes and minority interests		123.2			265.7			94.5			(269.2	)		214.2
Income tax provision (benefit)		(58.4	)		67.6			18.9			—			28.1
Minority interests		—			—			4.5			—			4.5

Income from continuing operations		181.6			198.1			71.1			(269.2	)		181.6
Income from discontinued operations, net of tax		14.6			—			—			—			14.6

Net income	$	196.2		$	198.1		$	71.1		$	(269.2	)	$	196.2

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Balance Sheets


	June 30, 2008
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	16.8	$	4.2		$	53.8		$	—		$	74.8
Accounts receivable, net		9.4		(89.6	)		376.2			—			296.0
Inventories		—		161.9			134.4			—			296.3
Assets from coal trading activities		—		983.4			409.1			—			1,392.5
Deferred income taxes		—		98.6			—			—			98.6
Other current assets		274.7		121.2			60.7			—			456.6

Total current assets		300.9		1,279.7			1,034.2			—			2,614.8
Property, plant, equipment and mine development
Land and coal interests		—		4,676.0			2,575.1			—			7,251.1
Buildings and improvements		—		590.7			109.1			—			699.8
Machinery and equipment		—		1,128.7			248.7			—			1,377.4
Less accumulated depreciation, depletion and amortization		—		(1,700.3	)		(285.5	)		—			(1,985.8	)

Property, plant, equipment and mine development, net		—		4,695.1			2,647.4			—			7,342.5
Investments and other assets		7,998.5		(227.7	)		(4.5	)		(7,235.1	)		531.2

Total assets	$	8,299.4	$	5,747.1		$	3,677.1		$	(7,235.1	)	$	10,488.5


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	124.4	$	—		$	11.5		$	—		$	135.9
Payables and notes payable to affiliates, net		1,985.5		(2,196.9	)		211.4			—			—
Liabilities from coal trading activities		—		665.3			794.6			—			1,459.9
Accounts payable and accrued expenses		158.7		649.6			346.9			—			1,155.2

Total current liabilities		2,268.6		(882.0	)		1,364.4			—			2,751.0
Long-term debt, less current maturities		2,973.1		0.2			149.4			—			3,122.7
Deferred income taxes		141.5		(102.5	)		286.0			—			325.0
Other noncurrent liabilities		108.7		1,301.4			68.2			—			1,478.3

Total liabilities		5,491.9		317.1			1,868.0			—			7,677.0
Minority interests		—		—			4.0			—			4.0
Stockholders’ equity		2,807.5		5,430.0			1,805.1			(7,235.1	)		2,807.5

Total liabilities and stockholders’ equity	$	8,299.4	$	5,747.1		$	3,677.1		$	(7,235.1	)	$	10,488.5

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Balance Sheets


	December 31, 2007
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	6.9	$	4.0		$	34.4		$	—		$	45.3
Accounts receivable, net		9.2		7.1			240.6			—			256.9
Inventories		—		138.3			126.4			—			264.7
Assets from coal trading activities		—		222.1			127.7			—			349.8
Deferred income taxes		—		98.6			—			—			98.6
Other current assets		182.0		64.9			48.3			—			295.2

Total current assets		198.1		535.0			577.4			—			1,310.5
Property, plant, equipment and mine development
Land and coal interests		—		4,563.0			2,634.1			—			7,197.1
Buildings and improvements		—		577.0			108.8			—			685.8
Machinery and equipment		—		1,065.0			193.9			—			1,258.9
Less accumulated depreciation, depletion and amortization		—		(1,582.9	)		(235.0	)		—			(1,817.9	)

Property, plant, equipment and mine development, net		—		4,622.1			2,701.8			—			7,323.9
Investments and other assets		7,735.4		(320.6	)		4.1			(7,001.8	)		417.1

Total assets	$	7,933.5	$	4,836.5		$	3,283.3		$	(7,001.8	)	$	9,051.5


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	122.7	$	—		$	11.7		$	—		$	134.4
Payables and notes payable to affiliates, net		1,903.0		(2,074.7	)		171.7			—			—
Liabilities from coal trading activities		—		165.9			135.9			—			301.8
Accounts payable and accrued expenses		209.1		655.7			269.2			—			1,134.0

Total current liabilities		2,234.8		(1,253.1	)		588.5			—			1,570.2
Long-term debt, less current maturities		2,983.3		0.2			155.2			—			3,138.7
Deferred income taxes		65.7		(95.2	)		345.1			—			315.6
Other noncurrent liabilities		130.0		1,278.2			98.4			—			1,506.6

Total liabilities		5,413.8		(69.9	)		1,187.2			—			6,531.1
Minority interests		—		(4.1	)		4.8			—			0.7
Stockholders’ equity		2,519.7		4,910.5			2,091.3			(7,001.8	)		2,519.7

Total liabilities and stockholders’ equity	$	7,933.5	$	4,836.5		$	3,283.3		$	(7,001.8	)	$	9,051.5

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows


	Six Months Ended June 30, 2008
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	(25.8	)	$	267.5		$	79.3		$	321.0
Net cash used in discontinued operations		(56.7	)		—			—			(56.7	)

Net cash provided by (used in) operating activities		(82.5	)		267.5			79.3			264.3


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(85.7	)		(24.2	)		(109.9	)
Investment in Prairie State		—			(18.5	)		—			(18.5	)
Federal coal lease expenditures		—			(123.4	)		—			(123.4	)
Additions to advance mining royalties		—			(2.6	)		(0.2	)		(2.8	)
Proceeds from disposal of assets, net of notes receivable		—			27.8			0.3			28.1
Investments in equity affiliates and joint ventures		—			(2.6	)		—			(2.6	)

Net cash used in investing activities		—			(205.0	)		(24.1	)		(229.1	)


Cash Flows From Financing Activities
Change in revolving line of credit		2.3			—			—			2.3
Payments of long-term debt		(12.6	)		—			(6.0	)		(18.6	)
Dividends paid		(32.5	)		—			—			(32.5	)
Excess tax benefit related to stock options exercised		26.8			—			—			26.8
Proceeds from stock options exercised		13.5			—			—			13.5
Proceeds from employee stock purchases		2.8			—			—			2.8
Transactions with affiliates, net		92.1			(62.3	)		(29.8	)		—

Net cash provided by (used in) financing activities		92.4			(62.3	)		(35.8	)		(5.7	)


Net increase in cash and cash equivalents		9.9			0.2			19.4			29.5
Cash and cash equivalents at beginning of period		6.9			4.0			34.4			45.3

Cash and cash equivalents at end of period	$	16.8		$	4.2		$	53.8		$	74.8

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 millions)
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	(141.6	)	$	356.5		$	88.2		$	303.1
Net cash used in discontinued operations		(66.4	)		—			—			(66.4	)

Net cash provided by (used in) operating activities		(208.0	)		356.5			88.2			236.7


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(164.2	)		(97.6	)		(261.8	)
Federal coal lease expenditures		—			(123.4	)		—			(123.4	)
Proceeds from disposal of assets, net of notes receivable		—			13.0			0.2			13.2
Additions to advance mining royalties		—			(2.0	)		—			(2.0	)
Investments in joint ventures		—			(0.6	)		—			(0.6	)

Net cash used in continuing operations		—			(277.2	)		(97.4	)		(374.6	)
Net cash provided by discontinued operations		5.3			—			—			5.3

Net cash provided by (used in) investing activities		5.3			(277.2	)		(97.4	)		(369.3	)


Cash Flows From Financing Activities
Payments of long-term debt		(38.1	)		(60.0	)		(4.9	)		(103.0	)
Dividends paid		(31.8	)		—			—			(31.8	)
Payment of debt issuance costs		—			(0.8	)		—			(0.8	)
Excess tax benefit related to stock options exercised		12.6			—			—			12.6
Proceeds from stock options exercised		8.3			—			—			8.3
Proceeds from employee stock purchases		3.1			—			—			3.1
Transactions with affiliates, net		11.9			(8.3	)		(3.6	)		—

Net cash used in financing activities		(34.0	)		(69.1	)		(8.5	)		(111.6	)


Net increase (decrease) in cash and cash equivalents		(236.7	)		10.2			(17.7	)		(244.2	)
Cash and cash equivalents at beginning of period		272.2			3.7			50.6			326.5

Cash and cash equivalents at end of period	$	35.5		$	13.9		$	32.9		$	82.3

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,” “should,” “estimate,” or “plan” 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 and speak only as of the date of this report. 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;

	•		credit and performance risks associated with customers, suppliers, trading and financial counterparties;

	•		transportation availability, performance and costs, including demurrage;

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

	•		geologic, equipment and operational risks inherent to mining;

	•		impact of weather on demand, production and transportation;

	•		legislation, regulations and court decisions or other government actions;

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

	•		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;

	•		the effects of acquisitions or divestitures, including the spin-off of Patriot Coal Corporation (Patriot);

	•		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 our information systems;

	•		growth of U.S. and international coal and power markets;

	•		coal’s market share of electricity generation;

	•		the availability and cost of competing energy resources;

	•		future worldwide economic conditions;

	•		changes in postretirement benefit and pension obligations;

	•		successful implementation of business strategies;

	•		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 Note 11 to our unaudited condensed consolidated financial statements.

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, 2007 and in Part II, Item 1A. “Risk Factors” of this report. These forward-looking statements speak only as of the date on which such statements were made, and we undertake no 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 31 coal operations located throughout all major U.S. and Australian coal producing regions, except Appalachia. In the first half of 2008, we sold 121.0 million tons of coal. In 2007, we sold 237.4 million tons of coal. Production totaled 106.8 million tons for the six months ended June 30, 2008 and 213.7 million tons for the year ended December 31, 2007. Our 2007 U.S. sales represented 19% of all U.S. coal sales and were approximately 80% greater than the sales of our closest U.S. competitor.

Our customers are utilities, steel producers and industrial companies. Utilities accounted for 85% of our U.S. sales in 2007. Our international production is sold primarily into export metallurgical and thermal markets. Our international activities accounted for 13% of our sales by volume in 2007. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2007, approximately 87% of our sales were under long-term contracts.

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 Illinois and Indiana operations. The principal business of the Western and Eastern U.S. Mining segments is the mining, preparation and sale of steam coal, sold primarily to electric utilities.

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

Our Australian Mining operations are characterized by both surface and underground extraction processes, mining various qualities of low-sulfur, high Btu coal (metallurgical coal) as well as steam coal primarily sold to an international customer base with a small portion sold to Australian steel producers and power generators. Metallurgical coal is produced from four of our Australian mines. Metallurgical coal was approximately 15% of our revenue in 2007 and 18% of our revenue during the first six months of 2008.

Through our Trading and Brokerage segment, we sell coal produced by our diverse portfolio of operations, broker coal sales of other coal producers, both as principal and as agent, trade coal and freight contracts, and provide transportation-related services in support of our coal-trading strategy.

In the second quarter of 2008, our new El Segundo mine in New Mexico began shipping and is expected to produce 6 million tons of coal per year. In Australia, we continued to ramp up activities, including expansion of a coal preparation facility at our Wambo mines. We also increased our interest in Dominion Terminal Associates, a coal transloading facility in Newport News, Virginia, to 37.5%. This facility has a rated throughput capacity of approximately 20 million tons of coal per year and ground storage capacity of approximately 1.7 million tons.

We own 5.06% of the 1,600-megawatt Prairie State Energy Campus that is under construction in Washington County, Illinois and we are pursuing various development options related to the Thoroughbred Energy Campus site in Muhlenberg County, Kentucky.

Results of Operations

We have classified as discontinued operations and are excluding from the operating results for all periods presented portions of the Eastern U.S. Mining operations business segment that were included in the spin-off of Patriot and certain non-strategic assets that are classified as held for sale. See Note 3 to the unaudited condensed consolidated financial statements included in Part I for additional information.

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 continuing operations before deducting early debt extinguishment costs, net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management to measure our segments’ operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under generally accepted accounting principles, in Note 9 to our unaudited condensed consolidated financial statements.

Three and Six Months Ended June 30, 2008 Compared to Three and Six Months Ended June 30, 2007

Summary

Strong global coal demand has recently outpaced supply all over the world, resulting in significant increases in reference coal price indices in the first six months of 2008. These supply and demand dynamics have resulted in increased volumes in the first six months of 2008 at each of our operating regions. From a price perspective, we have also realized price increases in each region. In the U.S., the price increases realized have not been as significant as in Australia, since most of our 2008 U.S. production was committed at prices negotiated prior to 2008. However, at our Australian operations, a significant portion of our export thermal and metallurgical coal portfolio reprices annually. In the second quarter, we obtained contractual commitments for export thermal coal at prices that were more than double last year and for export metallurgical coal at prices that were triple last year’s levels. Supplementing the price and volume increases was an agreement to recover postretirement healthcare and reclamation costs and higher Trading and Brokerage revenues. In total, revenue increases were $462.1 million (43.2%) and $628.3 million (28.8%) for the three and six months ended June 30, 2008, respectively, as compared to the prior year.

Segment Adjusted EBITDA increased $247.3 million (96.1%) and $241.5 million (44.3%) for the three and six months ended June 30, 2008, respectively, as compared to the prior year primarily due to the increases noted above. Partially offsetting these results were the following:

	•		Increased commodity and material and supply costs across all regions driven by higher energy costs, in addition to higher maintenance costs;

	•		Increased sales related costs due to higher coal pricing;

	•		Outages to install a new blending and loading facility at our largest mine;

	•		Flooding in the Midwestern United States which negatively impacted sales volume at our Eastern U.S. mines and railroad performance in the Powder River Basin; and

	•		Continued port and rail issues, as well as the effects of weather conditions in the first quarter of 2008, limiting our Australian sales volume.

Income from continuing operations increased by $142.9 million (143.3%) and $130.5 million (71.9%) for the three and six months ended June 30, 2008, respectively, as compared to the prior year due to the Segment Adjusted EBITDA items noted previously, partially offset by the following:

•

Higher income tax expense associated with higher pre-tax income and the foreign currency impact on deferred taxes due to the remeasurement of Australian dollar deferred taxes into U.S. dollars, partially offset by the release of the valuation allowance against a portion of our Australia net operating loss carryforwards;

	•		Higher depreciation, depletion and amortization primarily from production volume and asset depreciation at our newly completed mines in Australia, and increased volume in the Powder River Basin; and

	•		Lower gains in the second quarter, as compared to prior year, for the sale or exchange of coal reserves and surface lands due to the timing of such transactions. Gains for the six months ended June 30, 2008 as compared to prior year are slightly higher.

Tons Sold

The following table presents tons sold by operating segment for the three and six months ended June 30, 2008 and 2007:


	Three Months Ended									Six Months Ended
	June 30,				Increase					June 30,				Increase
	2008		2007		Tons		%			2008		2007		Tons		%
	(Tons in millions)									(Tons in millions)
Western U.S. Mining		39.2		38.4		0.8		2.1	%		81.5		76.2		5.3		7.0	%
Eastern U.S. Mining		8.0		7.7		0.3		3.9	%		15.6		15.5		0.1		0.6	%
Australian Mining		5.5		4.8		0.7		14.6	%		11.0		9.8		1.2		12.2	%
Trading and Brokerage		7.1		6.1		1.0		16.4	%		12.9		10.6		2.3		21.7	%

Total tons sold		59.8		57.0		2.8		4.9	%		121.0		112.1		8.9		7.9	%

Revenues

The following table presents revenues for the three and six months ended June 30, 2008 and 2007:


	Three Months Ended				Increase (Decrease)						Six Months Ended				Increase
	June 30,				to Revenues						June 30,				to Revenues
	2008		2007		$			%			2008		2007		$		%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining	$	644.4	$	495.1	$	149.3			30.2	%	$	1,235.9	$	979.6	$	256.3		26.2	%
Eastern U.S. Mining		294.7		256.6		38.1			14.8	%		561.5		513.6		47.9		9.3	%
Australian Mining		523.5		249.4		274.1			109.9	%		823.7		536.4		287.3		53.6	%
Trading and Brokerage		61.3		59.4		1.9			3.2	%		171.4		135.7		35.7		26.3	%
Corporate and Other		7.0		8.3		(1.3	)		(15.7	)%		14.4		13.3		1.1		8.3	%

Total revenues	$	1,530.9	$	1,068.8	$	462.1			43.2	%	$	2,806.9	$	2,178.6	$	628.3		28.8	%

Total revenues increased for the quarter and six months ended June 30, 2008 compared to the prior year across all operating segments. The primary drivers of the increases included the following:

	•		An increase in average sales price at our Australian Mining operations (quarter – 83.6%; six months – 36.3%) reflecting higher contract pricing that began in the second quarter, partially offset by carryover volumes at prior year pricing. Carryover commitments were primarily shipped early in the second quarter and were substantially complete by June 30, 2008. U.S. Mining operations’ average sales price increased over the prior year (quarter – 21.9%; six months – 13.7%) driven by increased demand.

	•		Increased demand also led to higher volumes across our U.S. operating segments, which overcame slightly lower volumes at some of our Eastern U.S. surface operations due to heavy rains in the Midwest in the first and second quarters. Volume at our Western U.S. operations increased 2.1% and 7.0% for the quarter and six month periods, respectively. Year-over-year increases were limited in the second quarter by two outages at our largest Powder River Basin mine for construction of a new blending and loading facility.

	•		Australia’s volumes increased from strong demand and additional production from recently completed mines, which was partially offset from lower volumes from our existing Australian mines due to continued port and rail constraints and heavy rainfall and flooding in Queensland during the first quarter of 2008.

	•		Trading and Brokerage operations’ revenues increased for the three and six months compared to the prior year due to an increase of trading positions allowing us to capture the market movements derived from the strengthening of both domestic and international coal markets.

	•		Approximately $54 million impact, net of current year activity, related to an agreement to recover postretirement healthcare and reclamation costs. The agreement is discussed in detail in Note 11 to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report.

Segment Adjusted EBITDA

The following table presents segment Adjusted EBITDA for the three and six months ended June 30, 2008 and 2007:


					Increase (Decrease)										Increase (Decrease)
	Three Months Ended				to Segment						Six Months Ended				to Segment
	June 30,				Adjusted EBITDA						June 30,				Adjusted EBITDA
	2008		2007		$			%			2008		2007		$			%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining	$	188.0	$	137.3	$	50.7			36.9	%	$	341.7	$	276.5	$	65.2			23.6	%
Eastern U.S. Mining		37.7		49.6		(11.9	)		(24.0	)%		70.7		99.3		(28.6	)		(28.8	)%
Australian Mining		240.8		44.0		196.8			447.3	%		244.6		106.6		138.0			129.5	%
Trading and Brokerage		38.1		26.4		11.7			44.3	%		129.9		63.0		66.9			106.2	%

Total Segment Adjusted EBITDA	$	504.6	$	257.3	$	247.3			96.1	%	$	786.9	$	545.4	$	241.5			44.3	%

Adjusted EBITDA from our Western U.S. Mining operations increased during the second quarter and six months primarily driven by an overall increase in average sales prices across the region (quarter – $88.7 million; six months – $158.4 million) and higher volumes in the region due to increased demand and greater throughput as a result of capital improvements. Also contributing to the increase during the second quarter was a recovery of postretirement healthcare and reclamation costs discussed above. Partially offsetting the pricing and volume contributions were higher per ton costs experienced by our Western U.S. Mining operations (quarter – $2.32; six months – $1.76). The cost increases were primarily due to higher sales related costs, higher material, supply and labor costs, higher repair and maintenance costs in the Powder River Basin and increased commodity costs, net of hedging activities, driven by fuel and explosives pricing. Lower volumes associated with the two outages for the commissioning of a new blending and loading system mentioned above also negatively impacted Adjusted EBITDA in the second quarter 2008 as compared to the prior year.

Eastern U.S. Mining operations’ Adjusted EBITDA decreased during the second quarter and first six months of 2008 compared to the prior year. Increases in average sales price (quarter – $32.4 million; six months – $16.1 million) were offset by cost increases resulting from higher costs for commodities, net of hedging activities, driven by higher fuel and explosives prices as well as higher materials, supplies and labor costs. Heavy rains and flooding in the Midwest affected sales volume at some of our mines. Also affecting the Eastern U.S. Mining segment was the decrease in revenues from coal sold to synthetic fuel plants (quarter – $8.2 million; six months – $16.1 million) due to the producers exiting the synthetic fuel market after expiration of federal tax credits at the end of 2007.

Our Australian Mining operations’ Adjusted EBITDA increased during the second quarter and six months compared to the prior year primarily due to new contract pricing (quarter – $233.0 million; six months – $211.6 million) and higher overall volumes as a result of strong export demand and contributions from our recently completed mines. These increases were partially offset by higher fuel costs, higher costs associated with two longwall moves in 2008 and an increase in overburden expenses. Further decreasing Australian results was the impact of Australian dollar/U.S. dollar exchange rates, net of hedging activities.

Trading and Brokerage operations’ Adjusted EBITDA increased during the quarter and six months due to an increase in trading activity, high coal price volatility and the continued strengthening of global coal markets.

Income From Continuing Operations Before Income Taxes and Minority Interests


	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2008			2007			$			%			2008			2007			$			%
	(Dollars in millions)												(Dollars in millions)
Total Segment Adjusted EBITDA	$	504.6		$	257.3		$	247.3			96.1	%	$	786.9		$	545.4		$	241.5			44.3	%
Corporate and Other Adjusted EBITDA		(58.0	)		13.6			(71.6	)		(526.5	)%		(66.8	)		(39.5	)		(27.3	)		69.1	%
Depreciation, depletion and amortization		(93.6	)		(88.5	)		(5.1	)		(5.8	)%		(187.6	)		(170.4	)		(17.2	)		(10.1	)%
Asset retirement obligation expense		(9.2	)		(3.8	)		(5.4	)		(142.1	)%		(16.0	)		(9.5	)		(6.5	)		(68.4	)%
Interest expense		(57.6	)		(58.6	)		1.0			1.7	%		(116.9	)		(116.1	)		(0.8	)		(0.7	)%
Interest income		2.5			1.5			1.0			66.7	%		3.6			4.3			(0.7	)		(16.3	)%

Income from continuing operations before income taxes and minority interests	$	288.7		$	121.5		$	167.2			137.6	%	$	403.2		$	214.2		$	189.0			88.2	%

Income from continuing operations before income taxes and minority interests for the second quarter and first six months of 2008 were higher than the prior year primarily due to the higher Total Segment Adjusted EBITDA discussed above, partially offset by lower Corporate and Other Adjusted EBITDA, higher depreciation, depletion and amortization and higher asset retirement obligation expense.

Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our joint ventures, net gains on asset disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development, and Btu conversion. The decrease in Corporate and Other Adjusted EBITDA during the second quarter and first six months of 2008 compared to 2007 included the following:

	•		Higher selling and administrative expenses primarily driven by costs associated with the transition to a new enterprise resource planning system and an increase in performance-based incentive costs.

	•		Lower second quarter 2008 gains of $49.6 million on asset sales and exchanges as compared to the prior year.

Depreciation, depletion and amortization was higher for the second quarter and six months compared to the prior year because of asset depreciation at our recently completed Australian mines and increased depletion at all of our mining operations due to the volume increases.

Asset retirement obligation expense increased for the quarter and six months as compared to the prior year primarily due to estimated increases for ongoing reclamation costs due to fuel and fertilizer increases.

Net Income


	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2008			2007			$			%			2008			2007			$			%
	(Dollars in millions)												(Dollars in millions)
Income from continuing operations before income taxes and minority interests	$	288.7		$	121.5		$	167.2			137.6	%	$	403.2		$	214.2		$	189.0			88.2	%
Income tax provision		(43.6	)		(17.0	)		(26.6	)		156.5	%		(87.7	)		(28.1	)		(59.6	)		(212.1	)%
Minority interests		(2.5	)		(4.8	)		2.3			47.9	%		(3.4	)		(4.5	)		1.1			24.4	%

Income from continuing operations		242.6			99.7			142.9			143.3	%		312.1			181.6			130.5			71.9	%
Income (loss) from discontinued operations, net of tax		(9.2	)		8.0			(17.2	)		(215.0	)%		(21.5	)		14.6			(36.1	)		(247.3	)%

Net income	$	233.4		$	107.7		$	125.7			116.7	%	$	290.6		$	196.2		$	94.4			48.1	%

Net income increased during the three and six months ended June 30, 2008 compared to the prior year due to the increase in income from continuing operations before incomes taxes and minority interests discussed above. The higher pre-tax earnings drove an increase in the income tax provision (quarter – $58.5 million; six months – $66.1 million), which was also affected by the foreign currency impact on the remeasurement of non-U.S. deferred taxes as a result of the weakening of the U.S. dollar (quarter – $17.6 million; six months – $33.4 million). These tax increases were partially offset by the release of a valuation allowance against a portion of our Australia net operating loss carryforwards during the second quarter ($45.3 million) as a result of significantly higher projected earnings resulting from higher contract pricing that was secured during the second quarter. Net income was also impacted by lower income from discontinued operations during 2008 as compared to the prior year. In the first quarter, income from discontinued operations decreased $18.9 million mainly due to the write-off of an excise tax refund receivable as a result of an April 2008 Supreme Court ruling (see Notes 3 and 11 to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report). The second quarter decrease in income from discontinued operations is primarily due to the Patriot operation results in 2007 for which there is no income in 2008.

Outlook

Events Impacting Near-Term Operations

Global coal markets serving both steel production and electricity generation continue to tighten, marked by growing demand and declining inventories. Seaborne metallurgical coal contract price negotiations for deliveries through March 2009 have been largely concluded, with realizations of $300 per metric ton benchmark price for Australia’s high-quality hard coking coal and $125 per metric ton benchmark price for Newcastle thermal coal. Strong demand since the settlements has resulted in spot prices above $300 per tonne for high-quality hard coking coal and as high as $175 to $200 per tonne for thermal.

In the second quarter, we priced approximately 11 million tons of Australia metallurgical and thermal coal through March 2009, based on reference coal prices. As of July 10, 2008, our unpriced Australian metallurgical coal volumes include 6 to 7 million tons for the last three quarters of 2009 and 10 to 11 million tons for 2010. Unpriced Australian thermal coal volumes include 6 to 7 million tons for the last three quarters of 2009 and 12 to 13 million tons for 2010.

While Australia’s coal chain has largely recovered from flooding in the first quarter, our two primary shipping points, Dalrymple Bay Coal Terminal and Port of Newcastle, continue to experience lengthy vessel queues. With demand likely to continue to outpace rail and port capacity for a number of years despite planned expansion, these transportation challenges could result in delayed shipments and demurrage charges.

In the U.S., coal consumption has risen an estimated 13 million tons in 2008 and U.S. generator stockpiles, which are already 17% below prior-year levels on a days-use basis, are being reduced at a rate of 2 to 3 million tons per week. Stockpile reductions are likely to accelerate through the third quarter, due to seasonal use and growing exports, and are expected to be at or below targeted levels by the end of summer.

As of July 10, 2008, we have 35 to 40 million tons of U.S. coal unpriced for 2009, and 90 to 100 million tons unpriced for 2010. More than 90% of our unpriced U.S. volumes are in the Powder River Basin and Illinois Basin. Illinois Basin pricing has doubled in the last six months while the Powder River Basin markets continue to set new records for volume and pricing.

We are targeting 2008 production of 220 to 240 million tons and total sales volume of 240 to 260 million tons, both of which include 22 to 24 million tons in Australia. We expect improvements in U.S. and Australia operating results from the higher prices discussed above, partially offset by ongoing commodity cost pressures and challenges to coal chain logistics.

Long-term Outlook

Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide due to tight global supplies and strong demand. Longer term, new coal plants are being developed in every region in the world including the Middle East. China alone added 96,000 megawatts of new coal-fueled plant capacity in 2007 and is expected to add more than 80,000 megawatts in 2008; combined, this would equal more than half the installed capacity of the United States. In the U.S., coal demand growth is expected to continue with the build-out of new coal-fueled plants, with nearly 30 units under construction and another 11 under late-stage development, representing more than 90 million tons of annual demand.

We believe that coal-to-gas (CTG) and coal-to-liquids (CTL) plants represent a significant avenue for potential long-term industry growth. The Energy Information Administration continues to project an increase in demand for unconventional sources of transportation fuel, including CTL, and CTL technologies are receiving support in the U.S. from both political parties. China and India are developing CTG and CTL facilities.

Management continues to manage costs and operating performance to mitigate external cost pressures, geologic conditions and potentially adverse port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel, tires, contract mining and healthcare, and have taken measures to mitigate the increases in these costs, including a company-wide initiative to instill best practices at all operations. In addition, historically low long-term interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. 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” in our Annual Report on Form 10-K for the year ended December 31, 2007 and in Part II, Item 1A. “Risk Factors” of this report for additional considerations regarding our outlook.

Global climate change continues to attract considerable public and scientific attention. Enactment of laws and passage of regulations regarding greenhouse gas emissions by the United States or some of its states or by other countries, or other actions to limit carbon dioxide emissions, could result in electric generators switching from coal to other fuel sources. We continue to support clean coal technology development and voluntary initiatives addressing global climate change through our participation as a founding member of the FutureGen Alliance, through our commitment to the Australian COAL21 Fund, and through our participation in the Power Systems Development Facility, the PowerTree Carbon Company LLC, and the Asia-Pacific Partnership for Clean Development and Climate. In addition, we are the only non-Chinese equity partner in GreenGen, the first near-zero emissions coal-fueled power plant with carbon capture and storage which is under development in China.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Generally accepted accounting principles require that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2007 Annual Report on Form 10-K describes the critical accounting policies and estimates used in the preparation of our financial statements. As discussed in Note 2 and Note 10, we adopted Statement of Financial Accounting Standard No. 157 effective January 1, 2008 for financial assets and liabilities for which fair value is measured and reported on a recurring basis. Other than this change, there have been no significant changes in our critical accounting policies and estimates during the six months ended June 30, 2008.

Fair Value Measurements

We use various methods to determine the fair value of financial assets and liabilities using market-quoted inputs for valuation or corroboration as available. We utilize market data or assumptions that market participants would use in pricing the particular asset or liability, including assumptions about inherent risk. We primarily apply the market approach for recurring fair value measurements utilizing the best available information.

We consider nonperformance risk in the valuation of derivative instruments by analyzing the credit standing of counterparties and considering any counterparty credit enhancements (e.g., collateral). The impact of credit standing, as well as any potential credit enhancements, has been factored into the fair value measurement of both financial derivative assets and financial derivative liabilities.

We evaluate the quality and reliability of the assumptions and data used to measure fair value in the three hierarchy levels, Level 1, 2 and 3, as prescribed by Statement of Financial Accounting Standard No. 157 (see Note 10 for additional information). Commodity swaps and options and physical commodity purchase/sale contracts transacted in less liquid markets or contracts, such as long-term arrangements, with limited price availability were classified in Level 3. These instruments or contracts are valued based on quoted inputs from brokers or counterparties, or reflect methodologies that consider historical relationships among similar commodities to derive our best estimate of fair value. We have consistently applied these valuation techniques in all periods presented, and believe we have obtained the most accurate information available for the types of derivative contracts held. The Level 3 net financial assets as of June 30, 2008 are as follows:


	Net financial
	assets
	(Dollars in millions)
Physical commodity purchase/sale contracts – coal trading activities	$	392.9
Commodity swaps and options – coal trading activities		(14.2	)

Total	$	378.7


Total Level 3 net financial assets measured at fair value	$	300.6

Percent of Level 3 net financial assets to total net financial assets measured at fair value		126	%

A portion of our trading portfolio includes derivative contracts for U.S. domestic physical coal purchases and offsetting financial swap contracts to sell that coal into the European traded markets that are collectively designed as “economic hedges” to secure a margin. Because the respective fair values of these physical coal purchases and financial swap contracts are determined at two different market prices, unrealized gains and losses are recognized in earnings in the periods prior to the delivery of coal or settlement of derivatives to the extent these market prices do not move in tandem (i.e. the fair value of a derivative in one market does not correlate with the change in fair value of a derivative in another market). As of June 30, 2008, we had recorded in our Trading and Brokerage results cumulative unrealized losses of $76.5 million related to these economic hedges.

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 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 generally fund all of our capital expenditure requirements with cash generated from operations.

Net cash provided by operating activities from continuing operations for the six months ended June 30, 2008 increased $17.9 million compared to the prior year. The increase was primarily related to a current year increase in operating cash flows generated from our Australian mining operations and the timing of cash flows for working capital.

Net cash used in investing activities from continuing operations decreased $145.5 million for the six months ended June 30, 2008 compared to the prior year. The decrease reflects lower capital spending of $133.4 million in 2008 and an increase in cash proceeds of $14.9 million related to asset disposals. Capital expenditures in 2008 included development at our El Segundo mine, which started producing subbituminious medium sulfur coal in late June 2008, a state-of-the-art blending and loading system at our North Antelope Rochelle Mine, an expansion project at one of our underground mines in the Midwest, expansion of a coal preparation facility at our Wambo mines, and spending on continuing development work for our interest in the Prairie State Generating Station.

Net cash used in financing activities decreased $105.9 million for the six months ended June 30, 2008 compared to the prior year. The decrease is primarily a result of lower debt repayments. During the first six months of 2008, we made scheduled debt repayments of $18.6 million including a $12.6 million payment on our Term Loan under the Senior Unsecured Credit Facility. In the first six months of 2007, we made debt repayments of $103.0 million that included a $60.0 million retirement of our 5.0% Subordinated Note; $24.9 million prepayment on our outstanding balance of the Term Loan under the Senior Unsecured Credit Facility; a $13.8 million open-market purchase of 5.875% Senior Notes; and capital lease payments of $4.3 million.

Our total indebtedness as of June 30, 2008 and December 31, 2007, consisted of the following:


	June 30,		December 31,
	2008		2007
	(Dollars in millions)
Term Loan under the Senior Unsecured Credit Facility	$	496.5	$	509.1
Revolving Credit Facility		100.0		97.7
Convertible Junior Subordinated Debentures due 2066		732.5		732.5
7.375% Senior Notes due 2016		650.0		650.0
6.875% Senior Notes due 2013		650.0		650.0
7.875% Senior Notes due 2026		247.0		247.0
5.875% Senior Notes due 2016		218.1		218.1
6.84% Series C Bonds due 2016		43.0		43.0
6.34% Series B Bonds due 2014		21.0		21.0
6.84% Series A Bonds due 2014		10.0		10.0
Capital lease obligations		86.8		92.2
Fair value hedge adjustment		3.4		1.6
Other		0.3		0.9

Total	$	3,258.6	$	3,273.1

As of June 30, 2008, the Revolving Credit Facility’s remaining available borrowing capacity under the Senior Unsecured Credit Facility, net of outstanding letters of credit, was $1.3 billion.

Interest Rate Swaps

We have entered into various interest rate swaps in previous years, including the following: a series of 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; a series of fixed-to-floating interest rate swaps with combined notional amounts totaling $100.0 million that were designated to hedge changes in fair value of the 5.875% Senior Notes due 2016; 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.

Included in the fair value hedge adjustment was $2.6 million related to the remaining portion of a $5.2 million payment received in conjunction with a previous interest rate swap termination in September of 2006. This payment is being amortized to interest expense through the maturity of the 6.875% Senior Notes.

In addition, we have three additional swaps, with a combined notional amount of $200.0 million, that were terminated during the six months ended June 30, 2008. The combined settlement amount of $6.9 million was recorded as an adjustment to the fair value hedge adjustment and will be amortized to interest expense over the remaining maturity period of the 6.875% Senior Notes.

Third-party Security Ratings

The ratings for our Senior Unsecured Credit Facility and our Senior Unsecured Notes are as follows: Moody’s has issued a Ba1 rating, Standard & Poor’s a BB rating and Fitch has issued a BB+ rating. The ratings on our Convertible Junior Subordinated Debentures are as follows: Moody’s has issued a Ba3 rating, Standard & Poor’s a B rating and Fitch has issued a BB- rating. These security ratings reflected the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. 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.

Capital Expenditures

Total capital expenditures for 2008 are expected to range from $350 million to $400 million, excluding federal coal reserve lease payments. These expenditures relate to equipment replacement and improvement or expansion of existing mines, particularly in Australia and the El Segundo mine development in New Mexico.

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 use a combination of surety bonds, corporate guarantees (i.e. self bonds) and letters of credit to secure our financial obligations for reclamation, workers’ compensation, postretirement benefits, leases and other obligations. The total value of self bonding in place was $637.4 million as of June 30, 2008 and $640.6 million as of December 31, 2007. The total value of surety bonds in place was $793.5 million as of June 30, 2008 and $539.2 million as of December 31, 2007. The total amount of letters of credit was $405.7 million as of June 30, 2008 and $413.6 million as of December 31, 2007.

Under our accounts receivable securitization program, undivided interests in a pool of eligible trade receivables contributed to our wholly-owned, bankruptcy-remote subsidiary are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (Conduit). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We utilize proceeds from the sale of our accounts receivable as an alternative to other forms of debt, effectively reducing our overall borrowing costs. The securitization program is scheduled to expire in September 2009. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the condensed consolidated balance sheets. The amount of undivided interests in accounts receivable sold to the Conduit was $275.0 million as of June 30, 2008 and December 31, 2007.

As part of the Patriot spin-off, we agreed to maintain in force several letters of credit that secured Patriot obligations for certain employee benefits and workers’ compensation obligations. These letters of credit are to be released upon Patriot satisfying the beneficiaries with alternate letters of credit or insurance, which is expected to occur in 2008. If Patriot is unable to satisfy the primary beneficiaries by June 30, 2011, they are then required to provide directly to us a letter of credit in the amount of the remaining obligation. The amount of letters of credit securing Patriot obligations was $7.0 million and $136.8 million as of June 30, 2008 and December 31, 2007.

There were no other material changes to our off-balance sheet arrangements during the six months ended June 30, 2008. 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, 2007.

Newly Adopted Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS No. 157 applies under accounting pronouncements that require or permit fair value measurements, and therefore does not require any new fair value measurements. In February 2008, the FASB amended SFAS No. 157 to exclude leasing transactions and to delay the effective date by one year for nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. We adopted SFAS No. 157 on January 1, 2008.

In April 2007, the FASB issued FASB Staff Position (FSP) FASB Interpretation Number (FIN) 39-1, “Amendment of FASB Interpretation No. 39” (FSP FIN 39-1). FSP FIN 39-1 amends certain provisions of FIN 39, “Offsetting of Amounts Related to Certain Contracts,” and permits companies to offset fair value amounts recognized for cash collateral receivables or payables against fair value amounts recognized for net derivative positions executed with the same counterparty under the same master netting arrangement. Prior to the implementation of FSP FIN 39-1, all positions executed with common counterparties were presented gross in the appropriate balance sheet line items. Effective January 1, 2008, in accordance with the provisions of FSP FIN 39-1, we offset our asset and liability coal trading derivative positions and other corporate hedging activities on a counterparty-by-counterparty basis if the contractual agreement provides for the net settlement of contracts with the counterparty in the event of default or termination of any one contract. The December 31, 2007 balances were adjusted to conform with the provisions of FSP FIN 39-1. See Note 4 to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report for a presentation of the assets and liabilities from coal trading activities on a gross basis (pre-FSP FIN 39-1) and on a net basis (post-FSP FIN 39-1).

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 provides all entities with an option to report selected financial assets and liabilities at fair value. SFAS No. 159 was effective for us for the fiscal year beginning January 1, 2008. SFAS No. 159 did not have an impact on our unaudited condensed consolidated financial statements.

Accounting Pronouncements Not Yet Implemented

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—an amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes accounting and reporting standards for noncontrolling interests in partially-owned consolidated subsidiaries and the loss of control of subsidiaries. SFAS No. 160 requires noncontrolling interests (minority interests) to be reported as a separate component of equity. In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008 (January 1, 2009 for us). Early adoption is not allowed. We do not expect the adoption of SFAS No. 160 to have a material effect on our results of operations or financial condition.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 expands the disclosure requirements for derivative instruments and hedging activities. This statement specifically requires entities to provide enhanced disclosures addressing the following: (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under FASB Statement No. 133 and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008 (January 1, 2009 for us). While we are currently evaluating the impact SFAS No. 161 will have on our disclosures, the adoption of SFAS No. 161 will not affect our results of operations or financial condition.

In May 2008, the FASB issued FSP No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” (FSP APB 14-1). FSP APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are not considered debt instruments within the scope of APB Opinion No. 14, “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants” (APB 14). FSP APB 14-1 also specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the issuer’s nonconvertible debt borrowing rate when recognizing interest cost in subsequent periods. FSP APB 14-1 is effective for fiscal years and interim periods beginning after December 15, 2008 (January 1, 2009 for us) and will require retrospective application for all periods presented. We are currently evaluating the effect of FSP APB 14-1 on our Convertible Junior Subordinated Debentures and have not yet determined the impact of the standard on our results of operations or financial condition.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The potential for changes in the market value of our coal and freight trading, crude oil, natural gas, 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, crude oil, natural gas or currency hedging 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 and ocean freight. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure, in value at risk terms, that we may assume at any point in time.

We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, options and swaps, at market value in our condensed consolidated financial statements. Our trading portfolio included forwards and swaps as of June 30, 2008 and December 31, 2007.

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 option, swap 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 price volatility as an input to 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, 2008, the combined actual low, high, and average values at risk for our coal trading portfolio were $8.5 million, $26.8 million, and $19.9 million, respectively. Our value at risk increased over the prior year due to greater price volatility in the Eastern U.S. and international coal markets.

As of June 30, 2008, the timing of the estimated future realization of the value of our trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2008		7	%
2009		62	%
2010		16	%
2011		12	%
2012		3	%

		100	%

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

Performance and Credit Risk

Our concentration of performance and credit risk is substantially with energy producers and marketers and electric utilities. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor the credit extended. If we engage in a transaction with a counterparty that does not meet our credit standards, we protect our position by requiring the counterparty to provide appropriate credit enhancement. In general, increases in coal price volatility and our own trading activity resulted in greater exposure to our coal-trading counterparties during 2008.

In addition to credit risk, performance risk includes the possibility that a counterparty fails to deliver agreed production or trading volumes. When appropriate (as determined by our credit management function), we have taken steps to reduce our exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties. Counterparty risk with respect to interest rate swap and foreign currency forward and option transactions is not considered to be significant based upon the creditworthiness of the participating financial institutions.

Foreign Currency Risk

We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2008 targets hedging at least approximately 80% of our anticipated Australian dollar-denominated operating expenditures. As of June 30, 2008, we had in place forward contracts and options designated as cash flow hedges with notional amounts outstanding totaling A$2.2 billion of which A$560.4 million, A$806.7 million, A$658.8 million and A$170.0 million will expire in 2008, 2009, 2010 and 2011, respectively. Our expectation for Australian dollar-denominated operating cash expenditures over the next 12 months is approximately A$1.4 billion. Assuming we had no hedges in place, our exposure in “Operating costs and expenses” due to a $0.01 change in the Australian dollar/U.S. dollar exchange rate is approximately $13.6 million for the next 12 months. However, taking into consideration hedges currently in place, our net exposure to the same rate change is approximately $3.7 million for the next 12 months.

Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed-rate debt as a percent of net debt through the use of various hedging instruments. As of June 30, 2008, after taking into consideration the effects of interest rate swaps, we had $2.5 billion of fixed-rate borrowings and $796.7 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $8.0 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 $320.6 million decrease in the estimated fair value of these borrowings.

Other Non-trading Activities

We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 87% of our sales volume under long-term coal supply agreements during 2007.

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, 2008, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel and explosives.

Notional amounts outstanding under fuel-related, derivative swap contracts were 143.8 million gallons of crude oil scheduled to expire through 2011. We expect to consume 125 to 135 million gallons of fuel in 2008. Through our crude oil hedge contracts, we have fixed prices for approximately 85% of our remaining 2008 anticipated diesel fuel requirements for U.S. mining operations. Based on our expected usage, 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 $3.1 million.

Notional amounts outstanding under explosives-related swap contracts, scheduled to expire through 2010, were 7.6 million mmbtu of natural gas. In our Powder River Basin operations, we expect to consume 195,000 to 205,000 tons of explosives per year. Through our natural gas hedge contracts, we have fixed prices for approximately 92% of our remaining 2008 anticipated explosives requirements for our Powder River Basin operations. Based on our expected usage, a change in natural gas prices of one dollar per mmbtu (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of approximately $3.6 million per year.

In our Eastern and Southwestern U.S. Mining operations, we expect to consume 140,000 to 145,000 tons of explosives in 2008. Our explosives supply contracts in our Eastern and Southwestern U.S. Mining operations cannot be hedged with natural gas or other traded commodity contracts.

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 principal executive officer and principal financial officer, on a timely basis. Our Chief Executive Officer and our Chief Financial Officer have evaluated our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as of June 30, 2008, and have concluded that such controls and procedures are effective to provide reasonable assurance that the desired control objectives were achieved.

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.

Except as set forth below, there have been no material changes to the risk factors disclosed under Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007 (the “Form 10-K”). The information below updates, and should be read in conjunction with, the risk factors and information disclosed under Item 1A. “Risk Factors” in the Form 10-K.

The following new risk factor replaces the first risk factor disclosed under Item 1A. “Risk Factors” in the Form 10-K.

We may not be able to achieve some or all of the strategic objectives that we expect to achieve in connection with the spin-off of Patriot.

Among the strategic objectives we expect to achieve in connection with the spin-off of Patriot are: improved operating and geologic risk; enhanced management and capital focus on large, long-lived surface mines; reduction in per-ton capital requirements; reduction in legacy liabilities; focus of our asset base toward high-growth, high-margin markets worldwide; and retention of leading Eastern U.S. access through our trading, brokerage and agency business. To the extent that we are unsuccessful in achieving some or all of these strategic objectives, it could have a material adverse effect on our business or results of operations.

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, 2008, there were approximately 10.9 million shares available for repurchase under this program. There were no share repurchases under this program during the three months ended June 30, 2008.


					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, 2008		5,602	$	52.35		—		10,920,605
May 1 through May 31, 2008		—		—		—		10,920,605
June 1 through June 30, 2008		1,266		75.43		—		10,920,605

Total		6,868	$	56.60		—


⁽¹⁾		Includes 6,868 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 shareholders was held on May 8, 2008. The shares of common stock eligible to vote were based on a record date of March 14, 2008. One Class I director was elected to serve for a three-year term expiring in 2011. A tabulation of the votes for this director is set forth below:


	For		Withheld
Sandra A. Van Trease		215,077,164		4,301,400

The terms of office of the following directors continued after the annual meeting of shareholders: Gregory H. Boyce, William A. Coley, William E. James, Robert B. Karn III, Henry E. Lentz, William C. Rusnack, Blanche M. Touhill, John F. Turner and Alan H. Washkowitz.

Shareholders also voted to ratify Ernst & Young LLP as the Company’s independent registered public accounting firm for 2008, approve a proposal to declassify our Board of Directors and approve our 2008 Management Annual Incentive Compensation Plan. The result of the vote on each of these matters is set forth below:


	For		Against		Abstentions
Ratification of independent registered public accounting firm		215,444,973		1,495,076		2,438,511

Declassification of the Company’s Board of Directors		215,682,174		1,249,312		2,447,076

Approval of the Company’s 2008 Management Annual Incentive Compensation Plan		211,630,753		5,245,843		2,501,965

Item 6. Exhibits.

See Exhibit Index at page 43 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 7, 2008	By:	/s/ MICHAEL C. CREWS
		Michael C. Crews
		Executive Vice President and Chief Financial Officer (On behalf of the registrant and as Principal Financial Officer)

EXHIBIT INDEX

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


Exhibit
No.		Description of Exhibit

3.1*		Third Amended and Restated Certificate of Incorporation of the Registrant, as amended.

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).

10.1*		Fifth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of April 11, 2008, by and among the Seller, the Registrant, the Sub-Servicers named therein, Market Street Funding LLC (as successor to Market Street Funding Corporation), as Issuer, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator.

10.2*		Sixth Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 13, 2008, by and among the Seller, the Registrant, the Sub-Servicers named therein, Market Street Funding LLC (as successor to Market Street Funding Corporation), as Issuer, all LC Participants listed on the signature pages thereto, and PNC Bank, National Association, as Administrator.

10.3		Peabody Energy Corporation 2008 Management Annual Incentive Compensation Plan (Incorporated by reference to Appendix B to the Registrant’s Proxy Statement for the 2008 Annual Meeting of Shareholders, filed on March 27, 2008).

10.4		Indemnification Agreement dated as of June 19, 2008 by and between Peabody Energy Corporation and Michael C. Crews (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed July 29, 2008).

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.