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, 2009

or

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

For the transition period from                      to                     

Commission File Number: 1-16463

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	13-4004153
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

701 Market Street, St. Louis, Missouri	63101-1826
(Address of principal executive offices)	(Zip Code)

(314) 342-3400

(Registrant’s telephone number, including area code)

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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
(Do not check if a smaller reporting company) Smaller reporting company o

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

There were 267,648,690 shares of common stock with a par value of $0.01 per share outstanding at July 31, 2009.

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, 2009 and 2008		1
Condensed Consolidated Balance Sheet as of June 30, 2009 (Unaudited) and December 31, 2008		2
Unaudited Condensed Consolidated Statement of Cash Flows for the Six Months Ended June 30, 2009 and 2008		3
Unaudited Consolidated Statement of Changes in Stockholders’ Equity for the Six Months Ended June 30, 2009		4
Notes to Unaudited Condensed Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
Item 3. Quantitative and Qualitative Disclosures About Market Risk		49
Item 4. Controls and Procedures		52
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		53
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		53
Item 4. Submission of Matters to a Vote of Security Holders		53
Item 6. Exhibits		54
SIGNATURE		55
EXHIBIT INDEX		56
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Dollars in millions, except per share data)
Revenues
Sales	$	1,209.3		$	1,418.9		$	2,496.3		$	2,599.4
Other revenues		131.6			108.0			304.7			193.6
Total revenues		1,340.9			1,526.9			2,801.0			2,793.0
Costs and Expenses
Operating costs and expenses		974.5			1,044.2			2,061.2			2,039.9
Depreciation, depletion and amortization		102.0			92.8			199.3			184.8
Asset retirement obligation expense		9.7			9.0			19.1			15.7
Selling and administrative expenses		46.3			43.1			93.5			94.0
Other operating (income) loss:
Net gain on disposal or exchange of assets		(10.1	)		(3.6	)		(13.4	)		(63.0	)
(Income) loss from equity affiliates		6.6			(3.7	)		10.7			(6.4	)
Operating profit		211.9			345.1			430.6			528.0
Interest expense		48.2			57.9			99.3			117.4
Interest income		(1.2	)		(2.5	)		(4.0	)		(3.6	)
Income from continuing operations before income taxes		164.9			289.7			335.3			414.2
Income tax provision		77.2			45.4			107.1			91.8
Income from continuing operations, net of income taxes		87.7			244.3			228.2			322.4
Income (loss) from discontinued operations, net of income taxes		(5.7	)		(8.5	)		29.0			(28.7	)
Net income		82.0			235.8			257.2			293.7
Less: Net income attributable to noncontrolling interests		2.8			2.5			8.0			3.4
Net income attributable to common stockholders	$	79.2		$	233.3		$	249.2		$	290.3
Income From Continuing Operations
Basic earnings per share	$	0.32		$	0.89		$	0.82		$	1.18
Diluted earnings per share	$	0.31		$	0.88		$	0.82		$	1.17
Net Income Attributable to Common Stockholders
Basic earnings per share	$	0.30		$	0.86		$	0.93		$	1.07
Diluted earnings per share	$	0.29		$	0.85		$	0.93		$	1.06
Dividends declared per share	$	0.06		$	0.06		$	0.12		$	0.12

See accompanying notes to unaudited condensed consolidated financial statements.

1

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	(Unaudited)
	June 30, 2009			December 31, 2008
	(Amounts in millions, except
	share and per share data)
ASSETS
Current assets
Cash and cash equivalents	$	446.0		$	449.7
Accounts receivable, net of allowance for doubtful accounts of $14.3 at June 30, 2009 and $24.8 at December 31, 2008		319.1			383.6
Inventories		447.5			277.7
Assets from coal trading activities, net		448.3			662.8
Deferred income taxes		—			1.7
Other current assets		197.0			195.8
Total current assets		1,857.9			1,971.3
Property, plant, equipment and mine development
Land and coal interests		7,511.2			7,354.7
Buildings and improvements		876.3			861.3
Machinery and equipment		1,296.9			1,265.8
Less accumulated depreciation, depletion and amortization		(2,371.1	)		(2,166.6	)
Property, plant, equipment and mine development, net		7,313.3			7,315.2
Investments and other assets		451.9			409.1
Total assets	$	9,623.1		$	9,695.6
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	16.4		$	17.0
Liabilities from coal trading activities, net		147.8			304.2
Deferred income taxes		4.0			—
Accounts payable and accrued expenses		1,143.6			1,535.0
Total current liabilities		1,311.8			1,856.2
Long-term debt, less current maturities		2,766.2			2,776.6
Deferred income taxes		232.1			21.5
Asset retirement obligations		430.7			422.6
Accrued postretirement benefit costs		773.0			766.1
Other noncurrent liabilities		511.9			733.1
Total liabilities		6,025.7			6,576.1
Stockholders’ equity
Preferred Stock — $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of June 30, 2009 or December 31, 2008		—			—
Series A Junior Participating Preferred Stock - 1,500,000 shares authorized, no shares issued or outstanding as of June 30, 2009 or December 31, 2008		—			—
Perpetual Preferred Stock - 750,000 shares authorized, no shares issued or outstanding as of June 30, 2009 or December 31, 2008		—			—
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of June 30, 2009 or December 31, 2008		—			—
Common Stock — $0.01 per share par value; 800,000,000 shares authorized, 276,184,369 shares issued and 267,544,069 shares outstanding as of June 30, 2009 and 275,211,240 shares issued and 266,644,979 shares outstanding as of December 31, 2008		2.8			2.8
Additional paid-in capital		2,040.4			2,020.2
Retained earnings		2,019.5			1,802.4
Accumulated other comprehensive loss		(151.7	)		(388.5	)
Treasury shares, at cost: 8,640,300 shares as of June 30, 2009 and 8,566,261
shares as of December 31, 2008		(320.9	)		(318.8	)
Peabody Energy Corporation’s stockholders’ equity		3,590.1			3,118.1
Noncontrolling interests		7.3			1.4
Total stockholders’ equity		3,597.4			3,119.5
Total liabilities and stockholders’ equity	$	9,623.1		$	9,695.6

See accompanying notes to unaudited condensed consolidated financial statements.

2

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2009			2008
	(Dollars in millions)
Cash Flows From Operating Activities
Net income	$	257.2		$	293.7
(Income) loss from discontinued operations, net of income taxes		(29.0	)		28.7
Income from continuing operations, net of income taxes		228.2			322.4
Adjustments to reconcile income from continuing operations, net of income taxes to net cash provided by operating activities:
Depreciation, depletion and amortization		199.3			184.8
Deferred income taxes		54.1			6.8
Stock compensation		17.3			17.9
Amortization of debt discount and debt issuance costs		3.9			3.2
Net gain on disposal or exchange of assets		(13.4	)		(63.0	)
(Income) loss from equity affiliates		10.7			(6.4	)
Revenue recovery on coal supply agreement		—			(56.9	)
Dividends received from equity affiliates		—			19.9
Changes in current assets and liabilities:
Accounts receivable, including securitization		71.2			(30.9	)
Inventories		(169.8	)		(31.6	)
Net assets from coal trading activities		33.9			(89.9	)
Other current assets		(28.4	)		(18.9	)
Accounts payable and accrued expenses		(189.1	)		65.8
Asset retirement obligations		15.4			11.6
Workers’ compensation obligations		1.4			3.4
Accrued postretirement benefit costs		6.1			3.9
Contributions to pension plans		(5.1	)		(1.4	)
Distributions to noncontrolling interests		(2.1	)		(1.5	)
Other, net		(11.0	)		(9.4	)
Net cash provided by continuing operations		222.6			329.8
Net cash provided by (used in) discontinued operations		6.8			(65.5	)
Net cash provided by operating activities		229.4			264.3
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		(82.2	)		(110.0	)
Investment in Prairie State Energy Campus		(24.5	)		(18.4	)
Federal coal lease expenditures		(123.6	)		(123.4	)
Proceeds from disposal of assets, net of notes receivable		35.4			28.1
Additions to advance mining royalties		(3.4	)		(2.8	)
Investments in equity affiliates and joint ventures		(10.0	)		(2.6	)
Net cash used in investing activities		(208.3	)		(229.1	)
Cash Flows From Financing Activities
Change in revolving line of credit		—			2.3
Payments of long-term debt		(6.0	)		(18.6	)
Dividends paid		(32.1	)		(32.5	)
Excess tax benefit related to stock options exercised		—			26.8
Proceeds from stock options exercised		0.6			13.5
Change in bank overdraft facility		10.4			—
Proceeds from employee stock purchases		2.3			2.8
Net cash used in financing activities		(24.8	)		(5.7	)
Net change in cash and cash equivalents		(3.7	)		29.5
Cash and cash equivalents at beginning of period		449.7			45.3
Cash and cash equivalents at end of period	$	446.0		$	74.8

See accompanying notes to unaudited condensed consolidated financial statements.

3

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

	Peabody Energy Corporation’s Stockholders’ Equity
											Accumulated
			Additional								Other						Total
	Common		Paid-in		Treasury			Retained			Comprehensive			Noncontrolling			Stockholders’
	Stock		Capital		Stock			Earnings			Loss			Interests			Equity
			(Dollars in millions)
December 31, 2008	$	2.8	$	2,020.2	$	(318.8	)	$	1,802.4		$	(388.5	)	$	1.4		$	3,119.5
Comprehensive income:
Net income		—		—		—			249.2			—			8.0			257.2
Increase in fair value of cash flow hedges (net of $154.2 tax provision)		—		—		—			—			238.9			—			238.9
Postretirement plans and workers’ compensation obligations (net of $1.3 tax benefit)		—		—		—			—			(2.1	)		—			(2.1	)
Comprehensive income									249.2			236.8			8.0			494.0
Dividends paid		—		—		—			(32.1	)		—			—			(32.1	)
Employee stock purchases		—		2.3		—			—			—			—			2.3
Share-based compensation		—		17.3		—			—			—			—			17.3
Stock options exercised		—		0.6		—			—			—			—			0.6
Shares relinquished		—		—		(2.1	)		—			—			—			(2.1	)
Distributions to noncontrolling interests		—		—		—			—			—			(2.1	)		(2.1	)
June 30, 2009	$	2.8	$	2,040.4	$	(320.9	)	$	2,019.5		$	(151.7	)	$	7.3		$	3,597.4

See accompanying notes to unaudited condensed consolidated financial statements.

4

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

June 30, 2009

(1) Basis of Presentation

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

     The accompanying condensed consolidated financial statements as of June 30, 2009 and for the three and six months ended June 30, 2009 and 2008, 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, 2008 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the six months ended June 30, 2009 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2009. Certain amounts in prior periods have been reclassified to conform to report classifications as of June 30, 2009 and for the three and six months ended June 30, 2009, with no material effect on previously reported net income or stockholders’ equity.

     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. See Note 3 for additional details related to discontinued operations.

     On August 6, 2009, the Company filed a Current Report on Form 8-K which included revisions to Items 6, 7, 7A and 15 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008, which the Company originally filed with the Securities and Exchange Commission (SEC) on February 27, 2009 (Original Filing) to reflect the impact on prior periods for accounting standards adopted as prescribed in 2009. The Company will then incorporate the revised financial statements by reference into an automatic shelf registration statement on Form S-3 the Company is planning to file with the SEC. The financial statement revisions relate to: (i) how the Company’s noncontrolling interests, formerly minority interests, are reflected in its financial statements, (ii) the allocation of the Company’s convertible debt between debt and equity components and the related impact on interest expense, and (iii) the presentation of the Company’s earnings-per-share calculations including the impacts of participating securities which, for the Company, relate to restricted stock grants.

     The revisions reflect the Company’s adoption of Statement of Financial Accounting Standards (SFAS) No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment to ARB 51”, Financial Accounting Standards Board (FASB) Staff Position (FSP) APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)” and FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”. As required, the Company adopted these standards effective January 1, 2009, and retrospectively applied the impact to its financial statements as described in Notes 1, 3, 7, 11, 12, 21, 22, and 23 to the Notes to Consolidated Financial Statements included in the Current Report on Form 8-K mentioned above.

(2) Newly Adopted Accounting Pronouncements and Accounting Pronouncements Not Yet Implemented

     Newly Adopted Accounting Pronouncements

     In May 2009, FASB issued SFAS No. 165, “Subsequent Events,” (SFAS No. 165), which establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. The Company evaluated subsequent events after the balance sheet date of June 30, 2009 through the filing of this report with the SEC on August 7, 2009.

5

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FSP FAS 107-1 and APB 28-1). FSP FAS 107-1 and APB 28-1 amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” to require disclosures in interim reporting periods and in financial statements for annual reporting periods of the fair value of all financial instruments for which it is practicable to estimate that value, whether recognized or not on the company’s balance sheet. FSP FAS 107-1 and APB 28-1 also amends APB Opinion No. 28, “Interim Financial Reporting,” to require entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments and describe changes in methods and significant assumptions, in both interim and annual financial statements. The Company adopted FSP FAS 107-1 and APB 28-1 on June 30, 2009. See Note 14 for further information.

     In April 2009, the FASB issued FSP No. FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (FSP FAS 157-4). FSP FAS 157-4 provides additional guidance for estimating fair value in accordance with SFAS No. 157 “Fair Value Measurements,” when the volume and level of activity for the asset or liability have significantly decreased. FSP FAS 157-4 also includes guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 amends SFAS No. 157 to require that a reporting entity: (1) disclose in interim and annual periods the inputs and valuation technique(s) used to measure fair value and a discussion of changes in valuation techniques and related inputs, if any, during the period, and (2) define the “major category” for any equity securities and debt securities to be based on the “major security types” (nature and risk of the security). The Company adopted FSP FAS 157-4 on June 30, 2009. While FSP FAS 157-4 had an impact on the Company’s disclosures, it did not affect the Company’s results of operations or financial condition.

     In June 2008, the FASB issued FSP No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (FSP EITF 03-6-1). FSP EITF 03-6-1, which became effective for the Company on January 1, 2009, addresses whether instruments granted in share-based payment awards that entitle their holders to receive nonforfeitable dividends or dividend equivalents before vesting should be considered participating securities and need to be included in the earnings allocation in computing earnings per share (EPS) under the “two-class method.” The two-class method is an earnings allocation formula that determines EPS for each class of common stock and participating security according to dividends declared (or accumulated) and participation rights in undistributed earnings. In accordance with FSP EITF 03-6-1, the Company’s unvested restricted stock awards are considered participating securities because they entitle holders to receive nonforfeitable dividends during the vesting term. In applying the two-class method, undistributed earnings are allocated between common shares and unvested restricted stock awards. The Company applied the two-class method of computing basic and diluted EPS for all periods presented. See Note 11 for additional information.

     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 SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 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 was effective for the Company for the fiscal year beginning January 1, 2009. While SFAS No. 161 had an impact on the Company’s disclosures, it did not affect the Company’s results of operations or financial condition. These additional disclosures are included in Note 14.

     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.” 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 was effective for the Company for the fiscal year beginning January 1, 2009. Prior period balances in this report have been adjusted to conform with the provisions of FSP APB 14-1. See the Company’s Current Report on Form 8-K filed with the SEC on August 6, 2009, which includes revisions to Item 15 of the Company’s Original Filing. The revisions reflect the adoption of FSP APB 14-1 applied retrospectively to the Company’s financial statements as described in Note 1 to the Consolidated Financial Statements included therein.

6

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     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 was effective for the Company for the fiscal year beginning January 1, 2009. Prior period balances in this report have been adjusted to conform with the provisions of SFAS No. 160. See the Company’s Current Report on Form 8-K filed with the SEC on August 6, 2009, which includes revisions to Item 15 of the Company’s Original Filing. The revisions reflect the adoption of SFAS No. 160 applied retrospectively to the Company’s financial statements.

     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 January 1, 2009. In April 2009, the FASB issued FSP No. FAS 141(R)-1, “Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies” (FSP 141(R)-1), to amend and clarify the initial recognition and measurement, subsequent measurement and accounting and related disclosures arising from contingencies in a business combination under SFAS No. 141(R). Under the new guidance, assets acquired and liabilities assumed in a business combination that arise from contingencies should be recognized at fair value on the acquisition date if fair value can be determined during the measurement period. If fair value cannot be determined, companies should typically account for the acquired contingencies using existing guidance. FSP 141(R)-1 is effective for business combinations with an acquisition date that is on or after the beginning of the first annual reporting period beginning January 1, 2009.

Accounting Pronouncements Not Yet Implemented

     In June 2009, the FASB issued SFAS No. 167, “Amendments to FASB Interpretation No. 46(R)” (SFAS No. 167). SFAS No. 167, which modifies how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. SFAS No. 167 clarifies that the determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. SFAS No. 167 requires an ongoing reassessment of whether a company is the primary beneficiary of a variable interest entity. SFAS No. 167 also requires additional disclosures about a company’s involvement in variable interest entities and any significant changes in risk exposure due to that involvement. SFAS No. 167 is applicable for annual periods after November 15, 2009 (January 1, 2010 for the Company). The Company is currently evaluating the effect, if any, SFAS No. 167 will have on its results of operations and financial condition.

     In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets—an amendment of FASB Statement No. 140” (SFAS No. 166). SFAS No. 166 seeks to improve the relevance, representational faithfulness and comparability of the information that a reporting entity provides in its financial statements about a transfer of financial assets; the effects of a transfer on its financial position, financial performance and cash flows; and a transferor’s continuing involvement, if any, in transferred financial assets. SFAS No. 166 is effective for annual periods after November 15, 2009 (January 1, 2010 for the Company). The Company is currently evaluating the effect, if any, SFAS No. 166 will have on its results of operations and financial condition.

     In December 2008, the FASB issued FSP No. FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” (FSP FAS 132R-1). This FSP amends SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits,” to provide guidance and additional transparency on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan, including the concentrations of risk in those plans. The effective date of FSP FAS 132R-1 is for fiscal years and interim periods beginning after December 15, 2009 (January 1, 2010 for the Company). While the adoption of FSP FAS 132R-1 will have an impact on the Company’s disclosures, it will not affect the Company’s results of operations or financial condition.

7

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(3) Discontinued Operations

Patriot Coal Corporation

     On October 31, 2007, the Company spun-off portions of its formerly Eastern United States (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,
	2009			2008		2009		2008
	(Dollars in millions)
Revenues	$	71.6		$	150.4	$	139.9	$	265.7
Income (loss) before income taxes		(5.2	)		0.6		49.2		(19.8	)
Income tax provision (benefit)		(1.1	)		—		19.0		(8.1	)

     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. The loss from discontinued operations for the six months ended June 30, 2008 was primarily related to the write-off of a $19.4 million receivable related to excise taxes previously paid on export shipments produced from discontinued operations. As part of the Patriot spin-off, the Company retained a receivable for excise tax refunds on export shipments that had previously been ruled unconstitutional by the appellate court. The U.S. Supreme Court reversed the appellate court’s ruling on April 15, 2008, and the Company recorded the charge to discontinued operations.

     In October 2008, the Energy Improvement and Extension Act of 2008 was enacted, which contained provisions that allow for the refund of coal excise tax collected on coal exported from the U.S. between January 1, 1990 and the date of the legislation. The Company’s claim for refund was approved by the Internal Revenue Service (IRS) in 2009. During the three months ended March 31, 2009, the refund of approximately $35 million (net of income taxes) was recorded in “Income (loss) from discontinued operations, net of income taxes” in the unaudited condensed consolidated statement of operations. Approximately $58 million was received during the three months ended June 30, 2009 and is shown in net cash provided by discontinued operations in the unaudited condensed consolidated statements of cash flows.

8

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The assets and liabilities of these discontinued operations are shown below:

	June 30, 2009		December 31, 2008
	(Dollars in millions)
Assets
Current assets
Other current assets	$	54.1	$	51.0
Total current assets		54.1		51.0
Noncurrent assets
Investments and other assets		2.1		4.9
Total assets	$	56.2	$	55.9
Liabilities
Current liabilities
Accounts payable and accrued expenses	$	44.2	$	69.1
Total current liabilities		44.2		69.1
Noncurrent liabilities
Other noncurrent liabilities		5.4		12.8
Total liabilities	$	49.6	$	81.9

     “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.

     Other

     In December 2008, the Company sold its Baralaba Mine, a non-strategic Australian mine. Revenues related to these operations for the three and six months ended June 30, 2008 were $3.7 million and $7.4 million, respectively. Loss before income taxes related to these operations was $5.7 million for the three months ended June 30, 2008, and $9.7 million for the six months ended June 30, 2008. Income tax benefit for the three and six months ended June 30, 2008 was completely offset by valuation allowances recorded against the deferred tax assets created by the operating losses.

(4) Assets and Liabilities from Coal Trading Activities

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

	June 30, 2009						December 31, 2008
	(Dollars in millions)
	Gross Basis			Net Basis			Gross Basis			Net Basis
Assets from coal trading activities	$	1,388.4		$	448.3		$	1,969.7		$	662.8
Liabilities from coal trading activities		(1,048.1	)		(147.8	)		(1,548.5	)		(304.2	)
Subtotal		340.3			300.5			421.2			358.6
Net margin held (1)		(39.8	)		—			(62.6	)		—
Net value of coal trading positions	$	300.5		$	300.5		$	358.6		$	358.6

⁽¹⁾ Represents net margin held from counterparties that was netted in accordance with FSP FIN 39-1 and does not represent the Company’s total margin held or posted.

9

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     As of June 30, 2009, forward contracts made up 53% and 75% of the Company’s trading assets and liabilities, respectively; financial swaps represent most of the remaining balances. The fair value of coal trading positions designated as cash flow hedges of anticipated future sales was an asset of $152.2 million as of June 30, 2009 and an asset of $220.4 million as of December 31, 2008. 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, 2009, 96% were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials and 4% of the Company’s contracts were valued based on similar market transactions.

     As of June 30, 2009, the estimated future realization of the value of the Company’s trading portfolio was as follows:

Year of	Percentage of
Expiration	Portfolio
2009		67	%
2010		11	%
2011		21	%
2012		1	%
		100	%

     At June 30, 2009, 69% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties and 31% was with non-investment grade counterparties. The Company’s coal trading operations traded 59.6 million tons and 33.8 million tons for the three months ended June 30, 2009 and 2008, respectively, and 106.6 million tons and 87.0 million tons for the six months ended June 30, 2009 and 2008, 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 was paid in two installments, $30.0 million of which was received in December 2008 with the balance received 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 until the cash was received.

(6) Inventories

     Inventories as of June 30, 2009 and December 31, 2008 consisted of the following:

	June 30, 2009		December 31, 2008
	(Dollars in millions)
Materials and supplies	$	124.6	$	110.2
Raw coal		80.8		24.0
Saleable coal		242.1		143.5
Total	$	447.5	$	277.7

     Inventory increased during the six months ended June 30, 2009 primarily due to shipment deferrals in Australia resulting in higher metallurgical coal inventory.

10

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(7) Accounts Payable and Accrued Expenses

     Accounts payable and accrued expenses consisted of the following:

	June 30,		December 31,
	2009		2008
	(Dollars in millions)
Trade accounts payable	$	351.1	$	427.9
Accrued taxes other than income		171.9		170.7
Other accrued expenses		164.7		131.7
Accrued payroll and related benefits		94.1		120.1
Accrued health care		85.7		82.5
Commodity and foreign currency hedge contracts		73.1		261.1
Income taxes payable		57.4		142.7
Accrued royalties		53.2		77.7
Accrued interest		29.4		31.1
Workers’ compensation obligations		8.7		8.7
Accrued environmental		6.5		7.6
Other accrued benefits		3.6		4.1
Liabilities associated with discontinued operations		44.2		69.1
Total accounts payable and accrued expenses	$	1,143.6	$	1,535.0

(8) Income Taxes

     The income tax rate differed from the U.S. federal statutory rate as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Dollars in millions)
Federal statutory rate	$	57.7		$	101.4		$	117.4		$	145.0
Excess depletion		(18.1	)		(3.3	)		(34.8	)		(18.1	)
Foreign earnings rate differential		(8.2	)		(22.0	)		(23.6	)		(25.6	)
Remeasurement of foreign taxes		47.7			17.6			46.8			33.4
State income taxes, net of U.S. federal tax benefit		3.2			(1.7	)		2.0			1.4
Tax credits		(6.1	)		(3.4	)		(10.4	)		(6.2	)
Changes in valuation allowance		5.7			(46.0	)		6.5			(43.9	)
Changes in tax reserves		(3.5	)		0.8			3.1			1.0
Other, net		(1.2	)		2.0			0.1			4.8
Total provision	$	77.2		$	45.4		$	107.1		$	91.8

     The change in the deferred tax balances during the three and six months ended June 30, 2009 were driven by changes in the Company’s cash flow hedges, remeasurement of foreign income tax accounts and utilization of net operating loss carryforwards.

11

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(9) Comprehensive Income

     The following table sets forth the after-tax components of comprehensive income for the six months ended June 30, 2009:

			Net Actuarial
			Loss
			Associated with
			Postretirement			Prior Service						Total
	Foreign		Plans and			Cost Associated						Accumulated
	Currency		Workers’			with						Other
	Translation		Compensation			Postretirement			Cash Flow			Comprehensive
	Adjustment		Obligations			Plans			Hedges			Loss
	(Dollars in millions)
December 31, 2008	$	3.1	$	(220.4	)	$	(18.7	)	$	(152.5	)	$	(388.5	)
Net increase in value of cash flow hedges		—		—			—			135.3			135.3
Reclassification from other comprehensive income to earnings		—		5.9			0.8			103.6			110.3
Current period change		—		(8.8	)		—			—			(8.8	)
June 30, 2009	$	3.1	$	(223.3	)	$	(17.9	)	$	86.4		$	(151.7	)

     Comprehensive income differs from net income by the amount of unrealized gain or loss resulting from valuation changes of the Company’s cash flow hedges (which include fuel and explosives hedges, currency forwards, traded coal index contracts and interest rate swaps) and the change in actuarial loss and prior service cost. The values of the Company’s cash flow hedging instruments are primarily affected by changes in interest rates, crude oil, diesel fuel, natural gas and coal prices and the U.S. dollar/Australian dollar exchange rate. The change in the value of the cash flow hedges during 2009 was due to price increases in crude oil and diesel fuel and the strengthening of the Australian dollar against the U.S. dollar.

(10) Convertible Junior Subordinated Debentures

     As discussed in Note 2, the Company adopted FSP APB 14-1 on January 1, 2009. FSP APB 14-1 requires retrospective application. The following table illustrates the effect of FSP APB 14-1 on the Company’s balance sheet as of December 31, 2008:

			Increase (decrease)
			due to application of
	As previously stated		FSP APB 14-1			As adjusted
	(Dollars in millions)
Investments and other assets	$	417.5	$	(8.4	)	$	409.1
Deferred income taxes (long-term asset)		118.4		(118.4	)		—
Long-term debt, less current maturities		3,139.2		(362.6	)		2,776.6
Deferred income taxes (long-term liability)		—		21.5			21.5
Additional paid-in capital		1,804.8		215.4			2,020.2
Retained earnings		1,803.5		(1.1	)		1,802.4

     The following table illustrates the effect on the Company’s interest expense amount in the statement of operations:

	Three Months Ended		Six Months Ended
	June 30, 2008		June 30, 2008
	(Dollars in millions)
As previously stated	$	57.6	$	116.9
Increase due to application of FSP APB 14-1		0.3		0.5
As adjusted	$	57.9	$	117.4

12

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     For the periods presented, there was no change to the Company’s EPS figures related to the retrospective application of FSP APB 14-1.

     The following table illustrates the carrying amount of the equity and debt components of the Company’s Convertible Junior Subordinated Debentures (the Debentures) as of June 30, 2009 and December 31, 2008:

	June 30,			December 31,
	2009			2008
	(Dollars in millions)
Carrying amount of the equity component	$	215.4		$	215.4
Principal amount of the liability component		732.5			732.5
Unamortized discount		(361.8	)		(362.6	)
Net carrying amount	$	370.7		$	369.9

     The following tables illustrate the effective interest rate and the interest expense related to the Debentures:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Dollars in millions)						(Dollars in millions)
Effective interest rate		4.9	%		4.9	%		4.9	%		4.9	%
Interest expense — contractual interest coupon	$	8.7		$	8.7		$	17.4		$	17.4
Interest expense — amortization of debt discount		0.4			0.3			0.8			0.7

     The remaining period over which the discount will be amortized is 32.5 years as of June 30, 2009.

     For additional information describing the Company’s Debentures, including the conditions under which they are convertible, see Note 12 to the Notes to Consolidated Financial Statements included in the Company’s Current Report on Form 8-K filed with the SEC on August 6, 2009.

     There were no other significant changes to the Company’s long-term debt since December 31, 2008.

13

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(11) Earnings Per Share

     As discussed in Note 2, the Company adopted FSP EITF 03-6-1 on January 1, 2009 and began using the two-class method to compute basic and diluted EPS for all periods presented. The following illustrates the earnings allocation method utilized in the calculation of basic and diluted EPS.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(Dollars in millions, except share and per share amounts)
Basic earnings per share using two-class method:
Income from continuing operations, net of income taxes	$	87.7		$	244.3		$	228.2		$	322.4
Less: Net income attributable to noncontrolling interests		(2.8	)		(2.5	)		(8.0	)		(3.4	)
Income from continuing operations attributable to common stockholders before allocation of earnings to participating securities		84.9			241.8			220.2			319.0
Less: Earnings allocated to participating securities		(0.5	)		(1.3	)		(1.6	)		(1.6	)
Income from continuing operations attributable to common stockholders		84.4			240.5			218.6			317.4
Income (loss) from discontinued operations, net of income taxes		(5.7	)		(8.5	)		29.0			(28.7	)
Net income attributable to common stockholders (numerator)	$	78.7		$	232.0		$	247.6		$	288.7
Weighted average shares outstanding — basic (denominator)		265,356,468			269,991,967			265,305,755			269,598,425
Basic earnings per share attributable to common stockholders:
Income from continuing operations	$	0.32		$	0.89		$	0.82		$	1.18
Income (loss) from discontinued operations		(0.02	)		(0.03	)		0.11			(0.11	)
Net income	$	0.30		$	0.86		$	0.93		$	1.07
Diluted earnings per share using two-class method:
Income from continuing operations attributable to common stockholders before allocation of earnings to participating securities	$	84.9		$	241.8		$	220.2		$	319.0
Less: Earnings allocated to participating securities		(0.5	)		(1.3	)		(1.6	)		(1.6	)
Income from continuing operations attributable to common stockholders before the reallocation of earnings to participating securities		84.4			240.5			218.6			317.4
Reallocation of the earnings of participating securities		—			—			—			—
Income from continuing operations attributable to common stockholders		84.4			240.5			218.6			317.4
Income (loss) from discontinued operations, net of income taxes		(5.7	)		(8.5	)		29.0			(28.7	)
Net income attributable to common stockholders (numerator)	$	78.7		$	232.0		$	247.6		$	288.7
Weighted average shares outstanding — basic		265,356,468			269,991,967			265,305,755			269,598,425
Dilutive impact of share-based compensation (1)		1,766,161			1,913,858			1,782,691			2,083,299
Weighted average shares outstanding — diluted (denominator)		267,122,629			271,905,825			267,088,446			271,681,724
Diluted earnings per share attributable to common stockholders:
Income from continuing operations	$	0.31		$	0.88		$	0.82		$	1.17
Income (loss) from discontinued operations		(0.02	)		(0.03	)		0.11			(0.11	)
Net income	$	0.29		$	0.85		$	0.93		$	1.06

⁽¹⁾ Includes the dilutive impact of stock options, restricted stock awards, deferred stock units, employee stock purchase plan and performance units.

14

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(12) Pension and Postretirement Benefit Costs

     Net periodic pension benefit included the following components:

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Dollars in millions)
Service cost for benefits earned	$	0.3		$	0.3		$	0.7		$	1.0
Interest cost on projected benefit obligation		12.8			12.7			25.6			25.4
Expected return on plan assets		(15.2	)		(15.1	)		(30.4	)		(30.3	)
Amortization of prior service cost, actuarial loss and other		0.9			—			1.7			0.2
Net periodic pension benefit	$	(1.2	)	$	(2.1	)	$	(2.4	)	$	(3.7	)

     Net periodic postretirement benefit costs included the following components:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(Dollars in millions)
Service cost for benefits earned	$	2.5	$	2.6	$	5.2	$	5.2
Interest cost on accumulated postretirement benefit obligation		13.5		13.5		27.5		27.1
Amortization of prior service cost and actuarial loss		3.5		4.5		7.8		9.0
Net periodic postretirement benefit costs	$	19.5	$	20.6	$	40.5	$	41.3

(13) Segment Information

     The Company reports its operations primarily through the following reportable operating segments: Western U.S. Mining, Midwestern 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 net interest expense, income taxes, asset retirement obligation expense and depreciation, depletion and amortization.

15

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     Operating segment results for the three and six months ended June 30, 2009 and 2008 were as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(Dollars in millions)
Revenues:
Western U.S. Mining	$	635.4		$	644.4		$	1,289.2		$	1,235.9
Midwestern U.S. Mining		339.8			286.9			650.5			547.6
Australian Mining		311.7			527.3			679.1			823.7
Trading and Brokerage		48.4			61.3			171.9			171.4
Corporate and Other		5.6			7.0			10.3			14.4
Total	$	1,340.9		$	1,526.9		$	2,801.0		$	2,793.0
Adjusted EBITDA:
Western U.S. Mining	$	152.1		$	188.0		$	335.3		$	341.7
Midwestern U.S. Mining		73.3			41.3			140.4			79.3
Australian Mining		125.1			237.5			208.3			244.5
Trading and Brokerage		35.5			37.9			101.0			129.7
Corporate and Other (1)		(62.4	)		(57.8	)		(136.0	)		(66.7	)
Total	$	323.6		$	446.9		$	649.0		$	728.5

⁽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, net of income taxes follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
				(Dollars in millions)
Total Adjusted EBITDA	$	323.6		$	446.9		$	649.0		$	728.5
Depreciation, depletion and amortization		102.0			92.8			199.3			184.8
Asset retirement obligation expense		9.7			9.0			19.1			15.7
Interest expense		48.2			57.9			99.3			117.4
Interest income		(1.2	)		(2.5	)		(4.0	)		(3.6	)
Income tax provision		77.2			45.4			107.1			91.8
Income from continuing operations, net of income taxes	$	87.7		$	244.3		$	228.2		$	322.4

(14) Risk Management and Fair Value Measurements

Risk Management — Non Coal Trading

     The Company is exposed to various types of risk in the normal course of business, including fluctuations in commodity prices, interest rates and foreign currency exchange rates. These risks are actively monitored in an effort to ensure compliance with the risk management policies of the Company. In most cases, commodity price risk (excluding coal trading activities) related to the sale of coal is mitigated through the use of long-term, fixed-price contracts rather than financial instruments. Commodity price risk (diesel fuel and explosives), interest rate risk and foreign currency exchange risk are discussed in detail below.

16

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Interest Rate Swaps

     The Company is exposed to interest rate risk on its fixed rate and variable rate long-term debt. The interest rate risk associated with the fair value of the Company’s fixed rate borrowings is managed using fixed-to-floating interest rate swaps to effectively convert a portion of the underlying cash flows on the debt into variable rate cash flows. The Company designates these swaps as fair value hedges, with the objective of hedging against changes in the fair value of the fixed rate debt that results from market interest rate changes. The interest rate risk associated with the Company’s variable rate borrowings is managed using floating-to-fixed interest rate swaps. The Company designates these swaps as cash flow hedges, with the objective of reducing the variability of cash flows associated with market interest rate changes.

Foreign Currency Risk

     The Company is exposed to foreign currency exchange rate risk on Australian dollar expenditures made in its Australian Mining segment. This risk is managed by entering into forward contracts and options that the Company designates as cash flow hedges, with the objective of reducing the variability of cash flows associated with forecasted Australian dollar expenditures.

Diesel Fuel and Explosives Hedges

     The Company is exposed to commodity price risk associated with diesel fuel in the U.S. and Australia and explosives in the U.S. Explosives costs, and a portion of the diesel fuel costs in Australia are included in the fees paid to the Company’s contract miners. This risk is managed through the use of fixed price contracts, cost plus contracts and derivatives, primarily swaps. The Company has generally designated the swap contracts as cash flow hedges, with the objective of reducing the variability of cash flows associated with the forecasted purchase of diesel fuel and explosives.

     The following summarizes the Company’s interest rate, foreign currency and commodity positions at June 30, 2009:

	Notional Amount by Year of Maturity
													2014 and
	Total		2009		2010		2011		2012		2013		thereafter
Interest Rate Swaps
Fixed-to-floating (dollars in millions)	$	50.0	$	—	$	—	$	—	$	—	$	50.0	$	—
Floating-to-fixed (dollars in millions)	$	186.0	$	—	$	—	$	120.0	$	—	$	—	$	66.0
Foreign Currency
A$:US$ forwards and options (A $ millions)	$	2,451.7	$	622.4	$	989.3	$	640.0	$	200.0	$	—	$	—
Commodity Contracts
Diesel fuel hedge contracts (million gallons)		150.2		49.2		64.4		31.4		5.2		—		—
U.S. explosives hedge contracts (million MMBtu)		4.4		1.5		2.9		—		—		—		—

	Account Classification by
	Cash flow		Fair value		Economic		Fair Value Asset
	hedge		hedge		hedge		(Liability)
							(Dollars in millions)
Interest Rate Swaps
Fixed-to-floating (dollars in millions)	$	—	$	50.0	$	—	$	1.0
Floating-to-fixed (dollars in millions)	$	186.0	$	—	$	—	$	(15.6	)
Foreign Currency
A$:US$ forwards and options (A $ millions)	$	2,451.7	$	—	$	—	$	26.3
Commodity Contracts
Diesel fuel hedge contracts (million gallons)		147.6		—		2.6	$	(82.6	)
U.S. explosives hedge contracts (million MMBtu)		4.2		—		0.2	$	(12.2	)

17

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Hedge Ineffectiveness

     The Company assesses both at inception and at least quarterly thereafter, whether the derivatives used in hedging activities are highly effective at offsetting the changes in the anticipated cash flows of the hedged item. The effective portion of the change in the fair value is recorded as a separate component of stockholders’ equity until the hedged transaction impacts reported earnings, whereby gains and losses are reclassified to the consolidated statement of operations in conjunction with the recognition of the underlying hedged item. The ineffective portion of the derivative’s change in fair value is recorded in the consolidated statement of operations. In addition, if the hedging relationship ceases to be highly effective, or it becomes probable that a forecasted transaction is no longer expected to occur, gains and losses on the derivative are recorded to the consolidated statements of operations.

     A measure of ineffectiveness is inherent in hedging future diesel fuel purchases with derivative positions based on crude oil or other mid-distillate commodities, especially given the recent volatility in the prices of refined products.

     The Company’s hedging of future explosives purchases is primarily through the use of derivative positions based on natural gas, which closely matches the contractual purchase price of explosives since price changes occur in a constant ratio of MMBtu per ton in the manufacture of explosives and generally carry a fixed surcharge.

     The table below shows the classification and amounts of gains and losses related to the Company’s non-trading hedges during the three months ended June 30, 2009:

		Gain (loss)		Gain (loss)			Gain (loss)			Gain (loss)
		recognized in		recognized in other			reclassified from			reclassified from
	Income Statement	income on non		comprehensive			other comprehensive			other comprehensive
	Classification Gains (Losses) -	designated		income on derivative			income into income			income into income
Financial Instrument	Realized	derivatives (1)		(effective portion)			(effective portion)			(ineffective portion)
			(Dollars in millions)
Interest rate swaps:
- Cash flow hedges	Interest expense	$	—	$	(1.0	)	$	(3.3	)	$	—
Diesel fuel hedge contracts:
- Cash flow hedges	Operating costs and expenses		—		51.8			(23.2	)		2.1
- Economic hedges	Operating costs and expenses		1.3		—			—			—
Explosives cash flow hedge contracts:
- Cash flow hedges	Operating costs and expenses		—		1.7			(4.8	)		—
- Economic hedges	Operating costs and expenses		1.2		—			—			—
Foreign currency cash flow forwards and options	Operating costs and expenses		—		260.1			(15.4	)		—
Total		$	2.5	$	312.6		$	(46.7	)	$	2.1

⁽¹⁾ Amounts relate to diesel fuel and explosives hedge derivatives that were de-designated during the three months ended March 31, 2009.

18

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The table below shows the classification and amounts of gains and losses related to the Company’s non-trading hedges during the six months ended June 30, 2009:

		Gain (loss)			Gain (loss)			Gain (loss)			Gain (loss)
		recognized in			recognized in other			reclassified from			reclassified from
	Income Statement	income on non			comprehensive			other comprehensive			other comprehensive
	Classification Gains (Losses) -	designated			income on derivative			income into income			income into income
Financial Instrument	Realized	derivatives (1)			(effective portion)			(effective portion)			(ineffective portion)
			(Dollars in millions)
Interest rate swaps:
- Cash flow hedges	Interest expense	$	—		$	0.1		$	(6.3	)	$	—
Diesel fuel hedge contracts:
- Cash flow hedges	Operating costs and expenses		—			41.3			(52.7	)		0.2
- Economic hedges	Operating costs and expenses		(0.7	)		—			—			—
Explosives cash flow hedge contracts:
- Cash flow hedges	Operating costs and expenses		—			(4.2	)		(10.3	)		—
- Economic hedges	Operating costs and expenses		(0.8	)		—			—			—
Foreign currency cash flow forwards and options	Operating costs and expenses		—			250.5			(59.6	)		—
Total		$	(1.5	)	$	287.7		$	(128.9	)	$	0.2

⁽¹⁾ Amounts relate to diesel fuel and explosives hedge derivatives that were de-designated during the three months ended March 31, 2009.

     Because the critical terms of the interest rate swaps and the respective debt instruments they hedge coincide, there was no hedge ineffectiveness recognized in the unaudited condensed consolidated statements of operations for these instruments during the three or six months ended June 30, 2009.

     As of June 30, 2009, the classification and amount of derivatives under SFAS No. 133 are as follows:

	Fair Value
	Current		Noncurrent		Current		Noncurrent
Financial Instrument	Assets		Assets (1)		Liabilities (2)		Liabilities (3)
	(Dollars in millions)
Interest rate swaps:
- Fair value hedges	$	—	$	1.0	$	—	$	—
- Cash flow hedges		—		—		—		15.6
Diesel fuel hedge contracts:
- Cash flow hedges		—		—		52.1		29.8
- Economic hedges		—		—		0.7		—
Explosives cash flow hedge contracts:
- Cash flow hedges		—		—		9.5		1.9
- Economic hedges		—		—		0.8		—
Foreign currency cash flow forwards and options		—		36.3		10.0		—
Total	$	—	$	37.3	$	73.1	$	47.3

(1)	All financial instruments in Noncurrent Assets are recorded in “Investments and other assets” in the condensed consolidated balance sheet.
(2)	All financial instruments in Current Liabilities are recorded in “Accounts payable and accrued expenses” in the condensed consolidated balance sheet.
(3)	All financial instruments in Noncurrent Liabilities are recorded in “Other noncurrent liabilities” in the condensed consolidated balance sheet.

     In accordance with SFAS No. 161, the Company elected the trading exemption which allows alternate disclosures for its coal trading transactions. For further information, see Risk Management — Coal Trading below.

19

Risk Management — Coal Trading

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The Company buys and sells coal, freight and emissions allowances, both in over-the-counter markets and on exchanges. Under SFAS No. 133, all derivative coal trading contracts are accounted for on a fair value basis (as defined by SFAS No. 157), except those for which the Company has elected to apply a normal purchases and normal sales exception. For certain derivative coal trading contracts, the Company establishes fair values using bid/ask price quotations obtained from multiple, independent third-party brokers to value coal, freight and emission allowance positions from the over-the-counter market. Prices from these sources are then averaged to obtain trading position values. While the Company does not anticipate any decrease in the number of third-party brokers or market liquidity, the Company could experience difficulty in valuing its market positions should the number of third-party brokers decrease or if market liquidity is reduced. For its exchange-based positions, the Company utilizes published settlement prices. Non-derivative coal contracts and derivative contracts for which the Company has elected to apply a normal purchases and normal sales exception are accounted for on an accrual basis. See Note 4 for information related to the maturity and valuation of its trading portfolio.

	Three Months Ended		Six Months Ended
Trading Revenue by Type of Instrument	June 30, 2009		June 30, 2009
	(Dollars in millions)
Commodity swaps and options	$	29.0	$	86.0
Physical commodity purchase / sale contracts		38.2		57.4
Total trading revenue	$	67.2	$	143.4

     Trading revenues are recorded in “Other revenues” in the accompanying unaudited condensed consolidated statement of operations and include realized and unrealized gains and losses on both derivative instruments and nonderivative instruments.

Hedge Ineffectiveness

     In some instances, the Company has designated an existing coal trading derivative as a hedge and, thus, the derivative has a non-zero fair value at hedge inception. The “off-market” nature of these derivatives, which is best described as an embedded financing element within the derivative, is a source of ineffectiveness. In other instances, the Company uses a coal trading derivative that settles at a time later than the occurrence of the cash flow being hedged. The hedge yields ineffectiveness to the extent that the derivative hedge contract is not highly effective in offsetting changes in the fair value of the hedged item.

Performance and Credit Risk

     The Company’s concentration of performance and credit risk is substantially with electric utilities, energy producers and energy marketers. The Company’s policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If the Company engages in a transaction with a counterparty that does not meet its credit standards, the Company seeks to protect its position by requiring the counterparty to provide an appropriate credit enhancement. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or the creation of customer trust accounts held for the Company’s benefit to serve as collateral in the event of a failure to pay. To reduce its credit exposure related to trading and brokerage activities, the Company seeks to enter into netting agreements with counterparties that permit the Company to offset receivables and payables with such counterparties and, to the extent required, will post or receive margin amounts associated with exchange-traded positions.

20

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     In addition to credit risk, performance risk includes the possibility that a counterparty fails to deliver or accept agreed production or trading volumes. When appropriate (as determined by its credit management function), the Company has taken steps to reduce its 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 or the creation of customer trust accounts held for the Company’s benefit to serve as collateral in the event of a failure to perform.

     The Company conducts its various hedging activities related to foreign currency, interest rate, and fuel and explosives exposures with a variety of highly-rated commercial banks. In light of the recent turmoil in the financial markets the Company continues to closely monitor counterparty creditworthiness.

     Certain of the Company’s derivative instruments require the parties to provide additional performance assurances whenever a material adverse event jeopardizes one party’s ability to perform under the instrument. In the event the Company were to sustain a material adverse event (using commercially reasonable standards), the counterparties could request collateralization on derivative instruments in net liability positions, which based on an aggregate fair value on June 30, 2009, could require the Company to post up to $133.2 million of collateral to its counterparties.

     Certain of the Company’s other derivative instruments require the parties to provide additional performance assurances whenever a credit downgrade occurs below a certain level as specified in each underlying contract. The terms of such instruments typically require additional collateralization on an incremental basis, which is commensurate with the severity of the credit downgrade. As of June 30, 2009, if a credit downgrade were to occur below a certain level, the Company could be required to post a maximum amount of $18.9 million of collateral to its counterparties based on the aggregate fair value of all derivative instruments with such features that are in a net liability position.

     The Company also has exchange-settled positions that require collateral to be posted for its entire net liability position. As of June 30, 2009, the Company has posted collateral of $13.5 million for its exchange-settled net liability position. The Company’s “Other current assets” at June 30, 2009 include $54.6 million of posted collateral in excess of its exchange-settled net liability position.

Fair Value Measurements

     In accordance with SFAS No. 157, the Company uses 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, or observable but cannot be market-corroborated, requiring the Company to make assumptions about pricing by market participants.

     The following table sets forth as of June 30, 2009 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	$	(1.3	)	$	183.9		$	—	$	182.6
Commodity swaps and options — other than coal		—			(94.8	)		—		(94.8	)
Physical commodity purchase/sale contracts — coal trading activities		—			115.5			2.4		117.9
Interest rate swaps		—			(14.6	)		—		(14.6	)
Foreign currency forwards and options		—			26.3			—		26.3
Total net financial assets (liabilities)	$	(1.3	)	$	216.3		$	2.4	$	217.4

21

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     For Level 1 and 2 financial assets and liabilities, the Company utilizes both direct and indirect observable price quotes, including LIBOR yield curves, New York Mercantile Exchange 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 — other than coal: 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 based on quoted inputs from counterparties corroborated with observable market data (Level 2).

• Foreign currency forwards and options: valued utilizing inputs obtained in quoted public markets (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 (liabilities):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Dollars in millions)
Beginning of period	$	(3.6	)	$	173.9		$	37.8		$	128.7
Total gains or losses (realized/unrealized):
Included in earnings		10.6			209.0			20.9			258.4
Included in other comprehensive income		1.9			(36.2	)		(10.3	)		(33.9	)
Purchases, issuances and settlements		(6.5	)		32.0			(38.7	)		25.5
Net transfers out		—			—			(7.3	)		—
End of period	$	2.4		$	378.7		$	2.4		$	378.7

     The following table summarizes the changes in unrealized gains (losses) relating to Level 3 net financial assets (liabilities) held both as of the beginning and the end of the period:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(Dollars in millions)
Changes in unrealized gains (1)	$	5.9	$	263.4	$	16.2	$	296.9

⁽¹⁾ For the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

22

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Fair Value — Other Financial Instruments

     The following methods and assumptions were used by the Company in estimating its fair value disclosures for other financial instruments as of June 30, 2009 and December 31, 2008:

• Cash and cash equivalents, accounts receivable and accounts payable and accrued expenses have carrying values which approximate fair value due to the short maturity or the financial nature of these instruments.

• Long-term debt fair value estimates are based on observed prices for securities with an active trading market when available, and otherwise on estimated borrowing rates to discount the cash flows to their present value. The 7.875% Senior Notes due 2026 and the Debentures due 2066 are net of unamortized note discount.

• Interest rate swaps are valued based on quoted inputs from counterparties corroborated with observable market data (Level 2).

     The carrying amounts and estimated fair values of the Company’s debt are summarized as follows:

	June 30, 2009				December 31, 2008
	Carrying		Estimated		Carrying		Estimated
	Amount		Fair Value		Amount		Fair Value
			(Dollars in millions)
Long-term debt	$	2,782.6	$	2,624.1	$	2,793.6	$	2,472.1

(15) Commitments and Contingencies

Commitments

     As of June 30, 2009, purchase commitments currently outstanding for capital expenditures were $62.1 million.

     From time to time, the Company or its subsidiaries are involved in legal proceedings arising in the ordinary course of business or related to indemnities or historical operations. The Company believes it has recorded adequate reserves for these liabilities and that there is no individual case pending that is likely to have a material adverse effect on the Company’s financial condition, results of operations or cash flows. The Company discusses its significant legal proceedings 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 litigation resumed. On April 6, 2009, the U.S. Supreme Court ruled against the Navajo Nation in a related case against the U.S. Government, and remanded that case to the lower court to dismiss the complaint. The U.S. Supreme Court said that none of the sources relied on by the Navajo Nation provided a basis for its breach-of-trust lawsuit against the U.S. Government, which undermines some of the claims the Navajo Nation asserts in its litigation against the Company.

23

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     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 the Company’s financial condition, results of operations or cash flows.

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 parties filed motions for summary judgment, which are pending before the court.

     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 several other companies are defendants in two property damage lawsuits arising from past operations near Picher, Oklahoma. The plaintiffs are seeking compensatory damages for diminution in property values and punitive damages. These cases were originally filed as putative class actions, but the court has denied class certification and the cases were subsequently amended to include a number of individual plaintiffs. In December 2003, the Quapaw Indian tribe and certain Quapaw land owners filed a lawsuit against Gold Fields, five other companies and the U.S. 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 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 U.S. 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.

24

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Environmental Claims and Litigation

     Environmental claims have been asserted against Gold Fields related to activities of Gold Fields or a former affiliate. Gold Fields or the former affiliate has been named a potentially responsible party (PRP) 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 13 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 $44.2 million as of June 30, 2009 and $45.3 million as of December 31, 2008, $6.5 million and $7.6 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 PRP’s 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. In September 2008, Gold Fields and other PRPs received letters from the U.S. Department of Justice and the EPA re-initiating settlement negotiations. Gold Fields continues to participate 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. Gold Fields has also been contacted by the State of Kansas (Kansas Department of Health and Environment) and is in negotiations for final resolution of natural resource damages claims at two sites. 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 the liabilities recorded in the condensed consolidated balance sheets. 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

     In addition, at times the Company become a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business in the U.S., Australia and other countries where the Company does business. Based on current information, the Company believes that the ultimate resolution of such other pending or threatened proceedings is not reasonably likely to have a material adverse effect on its financial position, results of operations or liquidity.

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 that 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.

25

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Alaskan Villages’ Claims

     In February 2008, the Native Village of Kivalina and the City of Kivalina filed a lawsuit in the U.S. 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 filed a motion to dismiss, which motion and motions to dismiss of the other defendants are pending before the court. 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.

(16) Guarantees and Financial Instruments with Off-Balance Sheet Risk

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

     The Company owns a 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, 2009, the Company’s maximum reimbursement obligation to the commercial bank was, in turn, supported by two letters 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 U.S.) and continues under this process as of June 30, 2009. 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.

     At June 30, 2009, the Company has a letter of credit of approximately $169 million Australian dollars (approximately $137 million U.S. dollars) for collateral for bank guarantees issued with respect to certain reclamation and performance obligations related to the mines acquired in the Excel Coal Limited acquisition.

26

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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 the event of default, the Company has multiple recourse options, including the ability to assume the loans and procure title and use of the equipment purchased through the loans. If default occurs, the Company has the ability and intent to exercise its recourse options, so the liability associated with the guarantee has been valued at zero. The aggregate amount guaranteed by the Company for all such Counterparties was $9.6 million at June 30, 2009 and $10.0 million at December 31, 2008. The Company’s obligations under the guarantees extend to July 2013.

     The Company has a liability recorded of $61.8 million as of June 30, 2009 and December 31, 2008 related to reclamation and bonding commitments associated with the purchase of approximately 427 million tons of coal reserves and surface lands in the Illinois Basin in 2007.

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

     Two of the Company’s affiliates collectively own a 5.06% undivided interest in the development of the Prairie State Energy Campus. The Company issued a guarantee on behalf of its affiliates for its proportionate share of obligations.

     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 Note 12 to the Notes to the Consolidated Financial Statements included in the Company’s Current Report on Form 8-K filed with the SEC on August 6, 2009. Supplemental guarantor/non-guarantor financial information is provided in Note 17.

     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. If Patriot is unable to satisfy the primary beneficiaries by June 30, 2011, they are then required to provide directly to the Company a letter of credit in the amount of the remaining obligation. The amount of letters of credit maintained by the Company securing Patriot obligations was $7.0 million at June 30, 2009 and December 31, 2008.

Accounts Receivable Securitization

     The Company has an accounts receivable securitization program through its wholly-owned, bankruptcy-remote subsidiary (Seller). Under the program, the Company contributes undivided interests in a pool of eligible trade receivables to the Seller, which then sells, 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. The Company utilizes proceeds from the sale of its accounts receivable as an alternative to other forms of debt, effectively reducing its overall borrowing costs. The funding cost of the securitization program was $2.3 million for the six months ended June 30, 2009 and $5.9 million for the six months ended June 30, 2008 and is included in interest expense in the unaudited condensed consolidated statement of operations. The Company continues to service the sold trade receivables but does not receive a servicing fee. The securitization program was renewed in May 2009 and extends to May 2012, while the letter of credit commitment that supports the commercial paper facility underlying the securitization program must be renewed annually.

27

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

     The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheets. The amount of undivided interests in accounts receivable sold to the Conduit was $242.8 million as of June 30, 2009 and $275.0 million as of December 31, 2008. The $32.2 million decrease in the accounts receivable securitization program for the six months ended June 30, 2009 is reflected in cash flows from operating activities in the unaudited condensed consolidated statement of cash flows. There was no change in the facility usage during the six months ended June 30, 2008.

     The Seller is a separate legal entity whose assets are available first and foremost to satisfy the claims of its creditors. Eligible receivables, as defined in the securitization agreement, consist of trade receivables from most of the Company’s U.S. subsidiaries, and are reduced for certain items such as past due balances and concentration limits. Of the eligible pool of receivables contributed to the Seller, undivided interests in only a portion of the pool are sold to the Conduit. The Company (the Seller) continues to own $73.3 million of receivables as of June 30, 2009, which represents collateral supporting the securitization program. The Seller’s interest in these receivables is subordinate to the Conduit’s interest in the event of default under the securitization agreement. If the Company defaulted under the securitization agreement or if its pool of eligible trade receivables decreased significantly, the Company could be prohibited from selling any additional receivables in the future under the agreement.

28

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(17) 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.

Unaudited Supplemental Condensed Consolidated Statements of Operations

	Three Months Ended June 30, 2009
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	764.3		$	549.6		$	27.0		$	1,340.9
Costs and expenses
Operating costs and expenses		39.7			513.9			393.9			27.0			974.5
Depreciation, depletion and amortization		—			70.9			31.1			—			102.0
Asset retirement obligation expense		—			8.6			1.1			—			9.7
Selling and administrative expenses		6.9			29.3			10.1			—			46.3
Other operating income:
Net gain on disposal or exchange of assets		—			(4.1	)		(6.0	)		—			(10.1	)
(Income) loss from equity affiliates		(144.3	)		1.7			4.9			144.3			6.6
Interest expense		47.9			7.9			12.2			(19.8	)		48.2
Interest income		(3.8	)		(3.8	)		(13.4	)		19.8			(1.2	)
Income from continuing operations before income taxes		53.6			139.9			115.7			(144.3	)		164.9
Income tax provision (benefit)		(33.5	)		29.4			81.3			—			77.2
Income from continuing operations, net of income taxes		87.1			110.5			34.4			(144.3	)		87.7
Loss from discontinued operations, net of income taxes		(7.9	)		2.2			—			—			(5.7	)
Net income		79.2			112.7			34.4			(144.3	)		82.0
Less: Net income attributable to noncontrolling interests		—			—			2.8			—			2.8
Net income attributable to common stockholders	$	79.2		$	112.7		$	31.6		$	(144.3	)	$	79.2

29

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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	$	—		$	1,191.6		$	365.0		$	(29.7	)	$	1,526.9
Costs and expenses
Operating costs and expenses		(53.6	)		755.0			372.5			(29.7	)		1,044.2
Depreciation, depletion and amortization		—			59.9			32.9			—			92.8
Asset retirement obligation expense		—			8.0			1.0			—			9.0
Selling and administrative expenses		6.9			37.4			(1.2	)		—			43.1
Other operating income:
Net gain on disposal or exchange of assets		—			(3.5	)		(0.1	)		—			(3.6	)
(Income) loss from equity affiliates		(234.8	)		1.2			(4.9	)		234.8			(3.7	)
Interest expense		53.9			20.2			14.2			(30.4	)		57.9
Interest income		(3.7	)		(20.7	)		(8.5	)		30.4			(2.5	)
Income (loss) from continuing operations before income taxes		231.3			334.1			(40.9	)		(234.8	)		289.7
Income tax provision (benefit)		(1.3	)		(7.9	)		54.6			—			45.4
Income (loss) from continuing operations, net of income taxes		232.6			342.0			(95.5	)		(234.8	)		244.3
Income (loss) from discontinued operations, net of income taxes		0.7			(3.4	)		(5.8	)		—			(8.5	)
Net income (loss)		233.3			338.6			(101.3	)		(234.8	)		235.8
Less: Net income attributable to noncontrolling interests		—			—			2.5			—			2.5
Net income (loss) attributable to common stockholders	$	233.3		$	338.6		$	(103.8	)	$	(234.8	)	$	233.3

30

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Statements of Operations

	Six Months Ended June 30, 2009
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Total revenues	$	—		$	1,951.6		$	955.4		$	(106.0	)	$	2,801.0
Costs and expenses
Operating costs and expenses		122.9			1,431.1			613.2			(106.0	)		2,061.2
Depreciation, depletion and amortization		—			143.4			55.9			—			199.3
Asset retirement obligation expense		—			17.2			1.9			—			19.1
Selling and administrative expenses		14.1			65.7			13.7			—			93.5
Other operating income:
Net gain on disposal or exchange of assets		—			(7.4	)		(6.0	)		—			(13.4	)
(Income) loss from equity affiliates		(358.7	)		3.3			7.4			358.7			10.7
Interest expense		97.8			24.8			16.7			(40.0	)		99.3
Interest income		(7.7	)		(18.3	)		(18.0	)		40.0			(4.0	)
Income from continuing operations before income taxes		131.6			291.8			270.6			(358.7	)		335.3
Income tax provision (benefit)		(87.4	)		70.4			124.1			—			107.1
Income from continuing operations, net of income taxes		219.0			221.4			146.5			(358.7	)		228.2
Income (loss) from discontinued operations, net of income taxes		30.2			(1.2	)		—			—			29.0
Net income		249.2			220.2			146.5			(358.7	)		257.2
Less: Net income attributable to noncontrolling interests		—			—			8.0			—			8.0
Net income attributable to common stockholders	$	249.2		$	220.2		$	138.5		$	(358.7	)	$	249.2

31

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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	$	—		$	2,116.3		$	738.6		$	(61.9	)	$	2,793.0
Costs and expenses
Operating costs and expenses		(91.1	)		1,419.9			773.0			(61.9	)		2,039.9
Depreciation, depletion and amortization		—			120.3			64.5			—			184.8
Asset retirement obligation expense		—			13.9			1.8			—			15.7
Selling and administrative expenses		9.3			81.1			3.6			—			94.0
Other operating income:
Net gain on disposal or exchange of assets		—			(62.9	)		(0.1	)		—			(63.0	)
(Income) loss from equity affiliates		(319.1	)		2.2			(8.6	)		319.1			(6.4	)
Interest expense		117.5			41.9			27.3			(69.3	)		117.4
Interest income		(7.5	)		(50.8	)		(14.6	)		69.3			(3.6	)
Income (loss) from continuing operations before income taxes		290.9			550.7			(108.3	)		(319.1	)		414.2
Income tax provision (benefit)		(11.1	)		56.8			46.1			—			91.8
Income (loss) from continuing operations, net of income taxes		302.0			493.9			(154.4	)		(319.1	)		322.4
Loss from discontinued operations, net of income taxes		(11.7	)		(7.2	)		(9.8	)		—			(28.7	)
Net income (loss)		290.3			486.7			(164.2	)		(319.1	)		293.7
Less: Net income attributable to noncontrolling interests		—			—			3.4			—			3.4
Net income (loss) attributable to common stockholders	$	290.3		$	486.7		$	(167.6	)	$	(319.1	)	$	290.3

32

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Balance Sheets

	June 30, 2009
	Parent		Guarantor			Non-Guarantor			Reclassifications/
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	76.6	$	4.4		$	365.0		$	—		$	446.0
Accounts receivable, net		0.3		67.1			251.7			—			319.1
Inventories		—		202.0			245.5			—			447.5
Assets from coal trading activities, net		—		153.1			295.2			—			448.3
Deferred income taxes		24.3		27.7			—			(52.0	)		—
Other current assets		54.3		47.9			94.8			—			197.0
Total current assets		155.5		502.2			1,252.2			(52.0	)		1,857.9
Property, plant, equipment and mine development
Land and coal interests		—		4,800.9			2,710.3			—			7,511.2
Buildings and improvements		—		756.0			120.3			—			876.3
Machinery and equipment		—		1,044.9			252.0			—			1,296.9
Less accumulated depreciation, depletion and amortization		—		(1,953.6	)		(417.5	)		—			(2,371.1	)
Property, plant, equipment and mine development, net		—		4,648.2			2,665.1			—			7,313.3
Deferred income taxes		85.9		—			—			(85.9	)		—
Investments and other assets		8,790.1		80.9			70.0			(8,489.1	)		451.9
Total assets	$	9,031.5	$	5,231.3		$	3,987.3		$	(8,627.0	)	$	9,623.1
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	—	$	—		$	16.4		$	—		$	16.4
Payables to (receivables from) affiliates, net		1,610.8		(1,668.1	)		57.3			—			—
Liabilities from coal trading activities, net		—		62.7			85.1			—			147.8
Deferred income taxes		—		—			56.0			(52.0	)		4.0
Accounts payable and accrued expenses		178.0		612.3			353.3			—			1,143.6
Total current liabilities		1,788.8		(993.1	)		568.1			(52.0	)		1,311.8
Long-term debt, less current maturities		2,635.3		0.2			130.7			—			2,766.2
Deferred income taxes		—		80.2			237.8			(85.9	)		232.1
Notes payable to (receviables from) affiliates, net		898.6		(816.4	)		(82.2	)		—			—
Other noncurrent liabilities		118.7		1,514.0			82.9			—			1,715.6
Total liabilities		5,441.4		(215.1	)		937.3			(137.9	)		6,025.7
Peabody Energy Corporation’s stockholders’ equity		3,590.1		5,446.4			3,042.7			(8,489.1	)		3,590.1
Noncontrolling interests		—		—			7.3			—			7.3
Total stockholders’ equity		3,590.1		5,446.4			3,050.0			(8,489.1	)		3,597.4
Total liabilities and stockholders’ equity	$	9,031.5	$	5,231.3		$	3,987.3		$	(8,627.0	)	$	9,623.1

33

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Balance Sheets

	December 31, 2008
	Parent		Guarantor			Non-Guarantor			Reclassifications/
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in millions)
Assets
Current assets
Cash and cash equivalents	$	161.2	$	4.5		$	284.0		$	—		$	449.7
Accounts receivable, net		0.6		4.8			378.2			—			383.6
Inventories		—		173.7			104.0			—			277.7
Assets from coal trading activities, net		—		226.2			436.6			—			662.8
Deferred income taxes		43.7		21.7			—			(63.7	)		1.7
Other current assets		51.0		77.8			67.0			—			195.8
Total current assets		256.5		508.7			1,269.8			(63.7	)		1,971.3
Property, plant, equipment and mine development
Land and coal interests		—		4,655.5			2,699.2			—			7,354.7
Buildings and improvements		—		748.6			112.7			—			861.3
Machinery and equipment		—		1,016.1			249.7			—			1,265.8
Less accumulated depreciation, depletion and amortization		—		(1,806.7	)		(359.9	)		—			(2,166.6	)
Property, plant, equipment and mine development, net		—		4,613.5			2,701.7			—			7,315.2
Deferred income taxes		191.3		—			—			(191.3	)		—
Investments and other assets		8,439.1		375.2			8.0			(8,413.2	)		409.1
Total assets	$	8,886.9	$	5,497.4		$	3,979.5		$	(8,668.2	)	$	9,695.6
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	—	$	—		$	17.0		$	—		$	17.0
Payables to (receivables from) affiliates, net		1,610.5		(1,632.7	)		22.2			—			—
Liabilities from coal trading activities, net		—		109.3			194.9			—			304.2
Deferred income taxes		—		—			63.7			(63.7	)		—
Accounts payable and accrued expenses		376.7		725.9			432.4			—			1,535.0
Total current liabilities		1,987.2		(797.5	)		730.2			(63.7	)		1,856.2
Long-term debt, less current maturities		2,640.4		0.2			136.0			—			2,776.6
Deferred income taxes		—		20.1			192.7			(191.3	)		21.5
Notes payable to (receivables from) affiliates, net		819.2		(819.2	)		—			—			—
Other noncurrent liabilities		322.0		1,517.2			82.6			—			1,921.8
Total liabilities		5,768.8		(79.2	)		1,141.5			(255.0	)		6,576.1
Peabody Energy Corporation’s stockholders’ equity		3,118.1		5,576.6			2,836.6			(8,413.2	)		3,118.1
Noncontrolling interests		—		—			1.4			—			1.4
Total stockholders’ equity		3,118.1		5,576.6			2,838.0			(8,413.2	)		3,119.5
Total liabilities and stockholders’ equity	$	8,886.9	$	5,497.4		$	3,979.5		$	(8,668.2	)	$	9,695.6

34

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Unaudited Supplemental Condensed Consolidated Statements of Cash Flows

	Six Months Ended June 30, 2009
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in millions)
Cash Flows From Operating Activities
Net cash provided by (used in) continuing operations	$	(34.6	)	$	142.6		$	114.6		$	222.6
Net cash provided by (used in) discontinued operations		8.5			(1.7	)		—			6.8
Net cash provided by (used in) operating activities		(26.1	)		140.9			114.6			229.4
Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(59.5	)		(22.7	)		(82.2	)
Investment in Prairie State Energy Campus		—			(24.5	)		—			(24.5	)
Federal coal lease expenditures		—			(123.6	)		—			(123.6	)
Proceeds from disposal of assets, net of notes receivable		—			34.0			1.4			35.4
Additions to advance mining royalties		—			(3.3	)		(0.1	)		(3.4	)
Investment in equity affiliate		—			—			(10.0	)		(10.0	)
Net cash used in investing activities		—			(176.9	)		(31.4	)		(208.3	)
Cash Flows From Financing Activities
Payments of long-term debt		—			—			(6.0	)		(6.0	)
Dividends paid		(32.1	)		—			—			(32.1	)
Proceeds from stock options exercised		0.6			—			—			0.6
Change in bank overdraft facility		—			—			10.4			10.4
Proceeds from employee stock purchases		2.3			—			—			2.3
Transactions with affiliates, net		(29.3	)		35.9			(6.6	)		—
Net cash provided by (used in) financing activities		(58.5	)		35.9			(2.2	)		(24.8	)
Net change in cash and cash equivalents		(84.6	)		(0.1	)		81.0			(3.7	)
Cash and cash equivalents at beginning of period		161.2			4.5			284.0			449.7
Cash and cash equivalents at end of period	$	76.6		$	4.4		$	365.0		$	446.0

35

PEABODY ENERGY CORPORATION
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

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	)	$	276.3		$	79.3		$	329.8
Net cash used in discontinued operations		(56.7	)		(8.8	)		—			(65.5	)
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		—			(85.8	)		(24.2	)		(110.0	)
Investment in Prairie State Energy Campus		—			(18.4	)		—			(18.4	)
Federal coal lease expenditures		—			(123.4	)		—			(123.4	)
Proceeds from disposal of assets, net of notes receivable		—			27.8			0.3			28.1
Additions to advance mining royalties		—			(2.6	)		(0.2	)		(2.8	)
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) continuing operations		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

36

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:

• duration and severity of the global economic downturn and disruptions in the financial markets;

• ability to renew sales contracts;

• reductions and/or deferrals of purchases by major customers;

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

• transportation availability, performance and costs;

• 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, letters of credit, and insurance;

• changes in postretirement benefit and pension obligations and funding requirements;

• availability and access to capital markets on reasonable terms to fund growth and acquisitions;

• effects of acquisitions or divestitures;

• 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;

• demand for coal in United States and international power generation and steel production markets;

• coal’s market share of electricity generation;

• availability and cost of competing energy resources;

• successful implementation of business strategies;

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

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

• interest rate changes;

• litigation, including claims not yet asserted;

• terrorist attacks or threats;

• impacts of pandemic illnesses; and

• other factors, including those discussed in Legal Proceedings.

     When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (SEC) filings, including the more detailed discussion of these factors, as well as other factors that could affect our results, contained in Item 1A. “Risk Factors” of our Annual

37

Report on Form 10-K for the fiscal year ended December 31, 2008. 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 world’s largest private sector coal company, with majority interests in 30 coal operations located throughout all major United States (U.S.) coal producing regions, except Appalachia, and interests in coal operations in Australia and Venezuela.

     For the year ended December 31, 2008, 82% of our total sales (by volume) were to U.S. electricity generators, 16% were to customers outside the U.S. and 2% were to the U.S. industrial sector. In the U.S., we typically sell coal to utility customers under long-term contracts (those with terms longer than one year). Internationally, we sell coal to coal-based electricity generating stations and steel producing facilities. During 2008, approximately 90% of our worldwide sales (by volume) were under long-term contracts. As discussed more fully in Item 1A. Risk Factors of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008, our results of operations in the near-term could be negatively impacted by the current global economic downturn, deferral or cancellation of customer shipments, poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations and by reductions in or limitations on the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation.

     We conduct business through three principal operating segments: Western U.S. Mining, Midwestern U.S. Mining, and Australian Mining. In addition to our mining operations, we market, broker and trade coal through our Trading and Brokerage Segment.

     The long-term demand for oil and natural gas around the world is expected to lead to an increase in demand for unconventional sources of both fuels. We continue to explore Btu Conversion projects designed to expand the uses of coal through coal-to-liquids and coal gasification technologies. We are also participating in the advancement of clean coal technologies, including carbon capture and storage, in the U.S., China and Australia.

Results of Operations

     The results of operations for all periods presented reflect the assets, liabilities and results of operations from subsidiaries spun off as Patriot Coal Corporation (Patriot) as discontinued operations. We also have classified as discontinued operations certain non-strategic mining assets held for sale where we have committed to the divestiture of such assets and operations recently divested.

   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 net interest expense, income taxes, 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 (GAAP), in Note 13 to our unaudited condensed consolidated financial statements.

38

Three and Six Months Ended June 30, 2009 Compared to Three and Six Months Ended June 30, 2008

   Summary

     Year-to-date sales volume of 119.1 million tons was 1.4 million tons below prior year levels reflecting planned reductions in production to match lower demand, and lower customer shipments in Australia driven primarily by reduced demand due to the global economic downturn. Year-to-date revenues of $2.8 billion remained slightly above prior year levels while the second quarter revenues fell $186.0 million, or 12.2%, below the second quarter of the prior year, driven by the decrease in Australia’s metallurgical coal volumes, lower annual export contract pricing that commenced on April 1, 2009 and the second quarter 2008 revenue recovery on a long-term coal supply agreement. Partially offsetting the decreases was an increase in U.S. revenues per ton, reflecting higher priced Midwestern U.S. contracts signed in the prior year as well as a change in mix toward higher-priced Western U.S. coal products.

     Segment Adjusted EBITDA decreased $118.7 million for the three months ended June 30, 2009 and $10.2 million for the six months ended June 30, 2009, compared to the prior year primarily due to the reasons noted above. Also unfavorably impacting Segment Adjusted EBITDA were the following:

• Higher royalties and sales-related taxes due to higher Western U.S. coal pricing;

• Additional costs associated with three Australian longwall moves during the first quarter of 2009;

• Lower contributions from our Trading and Brokerage segment; and

• Increased repairs and maintenance costs related to unplanned dragline and shovel repairs in our Western U.S. operations.

     Partially offsetting the decreases to Segment Adjusted EBITDA were the second quarter 2008 outages associated with the construction of a coal loading and blending facility at our North Antelope Rochelle Mine and heavy rains in the second quarter of 2008 impacting rail performance in the Powder River Basin.

     Income from continuing operations, net of income taxes, decreased by $156.6 million for the three months ended June 30, 2009 and $94.2 million for the six months ended June 30, 2009 compared to the prior year due to the Segment Adjusted EBITDA items noted previously. Also unfavorably impacting income from continuing operations, net of income taxes are the following items:

• Lower gains on the sale or exchange of coal reserves and surface lands;

• Higher income tax provision resulting from the prior year release of a valuation allowance against a portion of our Australian net operating loss carryforwards due to an improved earnings outlook and the greater unfavorable impact from the remeasurement of non-U.S. tax accounts as a result of a weaker U.S. dollar versus the Australian dollar ($47.7 million for the three months ended June 30, 2009 as compared to $17.6 million for the three months ended June 30, 2008; $46.8 million for the six months ended June 30, 2009 as compared to $33.4 million for the six months ended June 30, 2008). These impacts were partially offset by lower tax expense due to lower pre-tax earnings;

• Lower income from equity affiliates; and

• Higher depreciation, depletion and amortization related to our El Segundo Mine (commissioned in June of 2008), capital additions, and increased depletion at our North Antelope Rochelle Mine due to the mining of higher value coal reserves.

     The above decreases to income from continuing operations, net of income taxes were partially offset by lower interest expense due to reduced debt balances.

39

   Tons Sold

     The following table presents tons sold by operating segment:

	Three Months Ended										Six Months Ended
	June 30,				Increase (Decrease)						June 30,				Increase (Decrease)
	2009		2008		Tons			%			2009		2008		Tons			%
	(Tons in millions)										(Tons in millions)
Western U.S. Mining		38.7		39.2		(0.5	)		(1.3	)%		79.5		81.5		(2.0	)		(2.5	)%
Midwestern U.S. Mining		8.3		7.8		0.5			6.4	%		16.1		15.1		1.0			6.6	%
Australian Mining		5.1		5.5		(0.4	)		(7.3	)%		9.6		11.0		(1.4	)		(12.7	)%
Trading and Brokerage		7.4		7.1		0.3			4.2	%		13.9		12.9		1.0			7.8	%
Total tons sold		59.5		59.6		(0.1	)		(0.2	)%		119.1		120.5		(1.4	)		(1.2	)%

   Revenues

     The following table presents revenues by operating segment:

	Three Months Ended				Increase (Decrease)						Six Months Ended				Increase (Decrease)
	June 30,				to Revenues						June 30,				to Revenues
	2009		2008		$			%			2009		2008		$			%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining	$	635.4	$	644.4	$	(9.0	)		(1.4	)%	$	1,289.2	$	1,235.9	$	53.3			4.3	%
Midwestern U.S. Mining		339.8		286.9		52.9			18.4	%		650.5		547.6		102.9			18.8	%
Australian Mining		311.7		527.3		(215.6	)		(40.9	)%		679.1		823.7		(144.6	)		(17.6	)%
Trading and Brokerage		48.4		61.3		(12.9	)		(21.0	)%		171.9		171.4		0.5			0.3	%
Corporate and Other		5.6		7.0		(1.4	)		(20.0	)%		10.3		14.4		(4.1	)		(28.5	)%
Total revenues	$	1,340.9	$	1,526.9	$	(186.0	)		(12.2	)%	$	2,801.0	$	2,793.0	$	8.0			0.3	%

     Year-to-date revenues of $2.8 billion remained slightly above prior year levels while the second quarter revenues fell $186.0 million, or 12.2%, below prior year. The primary drivers included the following:

• Australian Mining operations’ average sales price decreased from the prior year reflecting the lower annual export contract pricing that commenced April 1, 2009 (three months, 34.4%; six months, 4.9%). The price decreases were combined with volume decreases from the prior year (three months, 9.5%; six months, 13.3%) due to destocking of inventory and lower capacity utilization at steel customers; year-to-date metallurgical coal shipments of 1.9 million tons were 2.1 million tons below prior year.

• Western U.S. Mining operations’ average sales price increased over the prior year driven by a change of mix toward higher-priced Western coal products (three months, 4.3%; six months, 9.9%). Revenues were also higher due to increased shipments from our El Segundo Mine. These increases were partially offset by the prior year revenue recovery on a long-term coal supply agreement ($56.9 million).

• Midwestern U.S. Mining operations’ average sales price increased over the prior year (three months, 9.6%; six months, 11.3%) driven by the benefit of higher Illinois Basin prices and increased shipments, including purchased coal used to satisfy supply agreements.

• Trading and Brokerage operations’ revenues decreased during the three months ended June 30, 2009 as compared to the prior year due to lower price volatility and a general decline in market prices for coal compared to higher price volatility and an increase in market prices during the prior year.

40

   Segment Adjusted EBITDA

     The following table presents segment Adjusted EBITDA by operating segment:

					Increase (Decrease)										Increase (Decrease)
	Three Months Ended				to Segment Adjusted						Six Months Ended				to Segment Adjusted
	June 30,				EBITDA						June 30,				EBITDA
	2009		2008		$			%			2009		2008		$			%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining	$	152.1	$	188.0	$	(35.9	)		(19.1	)%	$	335.3	$	341.7	$	(6.4	)		(1.9	)%
Midwestern U.S. Mining		73.3		41.3		32.0			77.5	%		140.4		79.3		61.1			77.0	%
Australian Mining		125.1		237.5		(112.4	)		(47.3	)%		208.3		244.5		(36.2	)		(14.8	)%
Trading and Brokerage		35.5		37.9		(2.4	)		(6.3	)%		101.0		129.7		(28.7	)		(22.1	)%
Total Segment Adjusted EBITDA	$	386.0	$	504.7	$	(118.7	)		(23.5	)%	$	785.0	$	795.2	$	(10.2	)		(1.3	)%

     Our Australian Mining operations’ Adjusted EBITDA decreased $112.4 million for the three months ended June 30, 2009 compared to the prior year primarily due to volume decreases resulting from lower demand ($86.2 million) and lower annual export contract pricing ($63.4 million). Australian Mining operations’ Adjusted EBITDA decreased $36.2 million for the six months ended June 30, 2009 compared to 2008 due to the volume decreases resulting from lower demand ($96.5 million) and the additional costs associated with three first quarter 2009 longwall moves ($34.7 million), partially offset by increased pricing achieved primarily through the first quarter of 2009 ($96.9 million).

     Adjusted EBITDA from our Western U.S. Mining operations decreased from the prior year due to the following:

• the second quarter 2008 revenue recovery on a long-term coal supply agreement ($56.9 million);

• increased sales related costs (three months, $7.3 million; six months, $32.6 million);

• increased maintenance and repair costs primarily for unplanned dragline and shovel repairs, as well as repairs associated with a beltline fire at our North Antelope Rochelle Mine (three months, $16.6 million; six months, $19.8 million); and

• increased labor costs associated with additional headcount at our Colorado operations related to longwall development and increased continuous miner production in advance of the new longwall panel (three months, $6.5 million; six months, $11.9 million).

     Partially offsetting the above decreases was an overall increase in average sales prices across the region (three months, $61.8 million; six months, $136.6 million) and the second quarter 2008 outages related to the construction of a coal loading and blending facility and heavy rains in the second quarter of 2008 impacting rail performance in the Powder River Basin (three months, $16.2 million; six months, $16.0 million).

     Midwestern U.S. Mining operations’ Adjusted EBITDA increased over the prior year primarily due to an increase in the average sales price (three months, $31.8 million; six months, $68.1 million) and increased shipments, including purchased coal used to satisfy supply agreements.

     Trading and Brokerage operations’ Adjusted EBITDA decreased compared to prior year primarily due to lower price volatility and a general decline in market prices for coal compared to higher price volatility and an increase in market prices during the prior year.

41

     Income From Continuing Operations Before Income Taxes

     The following table presents income from continuing operations before income taxes:

	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2009			2008			$			%			2009			2008			$			%
	(Dollars in millions)												(Dollars in millions)
Total Segment Adjusted EBITDA	$	386.0		$	504.7		$	(118.7	)		(23.5	)%	$	785.0		$	795.2		$	(10.2	)		(1.3	)%
Corporate and Other Adjusted EBITDA		(62.4	)		(57.8	)		(4.6	)		(8.0	)%		(136.0	)		(66.7	)		(69.3	)		(103.9	)%
Depreciation, depletion and amortization		(102.0	)		(92.8	)		(9.2	)		(9.9	)%		(199.3	)		(184.8	)		(14.5	)		(7.8	)%
Asset retirement obligation expense		(9.7	)		(9.0	)		(0.7	)		(7.8	)%		(19.1	)		(15.7	)		(3.4	)		(21.7	)%
Interest expense		(48.2	)		(57.9	)		9.7			16.8	%		(99.3	)		(117.4	)		18.1			15.4	%
Interest income		1.2			2.5			(1.3	)		(52.0	)%		4.0			3.6			0.4			11.1	%
Income from continuing operations before income taxes	$	164.9		$	289.7		$	(124.8	)		(43.1	)%	$	335.3		$	414.2		$	(78.9	)		(19.0	)%

     Income from continuing operations before income taxes for the three and six months was lower than the prior year primarily due to the lower Total Segment Adjusted EBITDA discussed above, lower Corporate and Other Adjusted EBITDA, and increased depreciation, depletion and amortization, partially offset by a decline in interest expense resulting from lower average borrowings on the revolving credit facility and lower interest rates.

     Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our joint ventures, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as generation development and Btu Conversion development costs. The decrease of $69.3 million in Corporate and Other Adjusted EBITDA during the six months ended June 30, 2009 compared to 2008 was due to the following:

• Lower net gains on disposals or exchanges of assets ($49.6 million). Net gains on disposals or exchanges during the six months ended June 30, 2009 were $13.4 million compared to $63.0 million in the prior year, which included a $54.0 million gain from the sale of non-strategic coal reserves and surface lands located in Kentucky.

• Lower equity income ($17.1 million) primarily from our 25.5% interest in Carbones del Guasare (owner and operator of the Paso Diablo Mine in Venezuela), which is primarily the result of lower productivity and higher costs due to ongoing labor issues.

     Depreciation, depletion and amortization was higher compared to the prior year (three months, $9.2 million; six months, $14.5 million) due to:

• Increased asset depreciation associated with the completion of our El Segundo Mine (commissioned in June 2008) and significant capital additions at our North Antelope Rochelle Mine; and

• Increased asset depletion in the Powder River Basin due to the impact of mining higher value coal reserves, partially offset by lower depletion at certain other mines resulting from lower production.

42

   Net Income Attributable to Common Stockholders

     The following table presents net income attributable to common stockholders:

	Three Months Ended						Increase (Decrease)						Six Months Ended						Increase (Decrease)
	June 30,						to Income						June 30,						to Income
	2009			2008			$			%			2009			2008			$			%
	(Dollars in millions)												(Dollars in millions)
Income from continuing operations before income taxes	$	164.9		$	289.7		$	(124.8	)		(43.1	)%	$	335.3		$	414.2		$	(78.9	)		(19.0	)%
Income tax provision		(77.2	)		(45.4	)		(31.8	)		(70.0	)%		(107.1	)		(91.8	)		(15.3	)		(16.7	)%
Income from continuing operations, net of income taxes		87.7			244.3			(156.6	)		(64.1	)%		228.2			322.4			(94.2	)		(29.2	)%
Income (loss) from discontinued operations		(5.7	)		(8.5	)		2.8			32.9	%		29.0			(28.7	)		57.7			201.0	%
Net income		82.0			235.8			(153.8	)		(65.2	)%		257.2			293.7			(36.5	)		(12.4	)%
Less: Net income attributable to noncontrolling interests		2.8			2.5			(0.3	)		(12.0	)%		8.0			3.4			(4.6	)		(135.3	)%
Net income attributable to common stockholders	$	79.2		$	233.3		$	(154.1	)		(66.1	)%	$	249.2		$	290.3		$	(41.1	)		(14.2	)%

     Net income attributable to common stockholders was lower for both periods compared to the prior year due to the decrease in pretax income discussed above and a higher income tax provision that was driven by the prior year release of a valuation allowance ($45.3 million for the three and six months) and the greater impact from the remeasurement of non-U.S. tax accounts as a result of the weakening U.S. dollar (three months, $30.1 million; six months, $13.3 million). These tax provision increases were partially offset by lower pre-tax earnings (three months, $43.3 million; six months, $27.2 million). Favorably impacting net income attributable to common stockholders is a $57.7 million (pretax) increase in income from discontinued operations for the six months ended June 30, 2009 primarily due to the excise tax refund receivable recorded during the three months ended March 31, 2009. See Note 3 to the unaudited condensed consolidated financial statements for more information related to the excise tax refund.

Outlook

     Near-Term Outlook

     The ongoing global economic downturn has reduced gross domestic product expectations in all major world economies, and is expected to temper pricing and the growth of coal demand in the near term. The Asia-Pacific markets continue to outpace the U.S. and European markets in economic growth and therefore electricity generation and steel production. Year-to-date through June 2009, global steel production has declined 21% versus the comparable prior year period. Of major steel producing nations, only China is outpacing prior-year levels, with all other nations running 35% below 2008 on average. In the U.S., the American Iron and Steel Institute reported capacity utilization rates have improved since the start of the year, exceeding 50% in mid-July 2009. We estimate lower steel production will reduce 2009 seaborne metallurgical coal demand by 35 to 40 million metric tonnes. In response to declines in demand, metallurgical coal producers have been reducing planned production levels.

     During the second quarter of 2009, we reached agreement with metallurgical coal customers for 90 percent of 2009 volumes with prices ranging from $129 per tonne for high-quality hard coking coal to the upper $80s per tonne for pulverized coal injection (PCI) coal and above $100 per tonne for semi-hard coals. In completed negotiations, we retained much of the value associated with hard coking coal commitments carried over from settled agreements in the fiscal year ended March 31, with the value expected to be realized in deliveries from 2009 through the first quarter of 2012. Negotiations are still occurring with some customers regarding 2009 volumes and treatment of more than $100 million in the 2008 carryover commitments. We also priced 3.8 million tons of export thermal coal commitments for 2009 from Australian operations, in line with benchmark pricing

     As of July 21, 2009, we had 5 to 7 million tons of Australia metallurgical coal unpriced for 2010, along with 7 to 8 million tons of unpriced export thermal coal. Unpriced 2010 volumes are primarily planned for deliveries over the last three quarters of 2010.

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     In the U.S., we estimate reduced electricity generation, industrial use and exports could lead to 115 to 125 million tons of lower coal demand in 2009 to rebalance supply and demand. Reduced U.S. coal demand reflects lower gross domestic product estimates due to the recession. Year-to-date, coal-based electricity generation demand is estimated to have declined 9% from the prior year, or approximately 45 million tons. The reduced coal generation contributed to an increase in utility inventory levels during the second quarter of 2009. Lower natural gas prices in the U.S. and Europe are also expected to reduce demand for coal and lead to lower U.S. exports. U.S. coal production is adjusting to changes in demand, with second quarter U.S. coal production declining nearly 25 million tons below 2008 levels, which represents nearly 100 million tons of reductions on an annualized basis if production remains at these levels.

     In January 2009, we announced 10 million tons of planned Powder River Basin production cuts for 2009 to better match production with expected demand. In April 2009, we announced plans to reduce 2009 U.S. production another 5 million tons across our U.S. operations. Our U.S. production is sold out for 2009 and 10 to 20 million tons remain unpriced for 2010.

     We continue to target full-year 2009 production of 185 to 190 million tons in the U.S. and 20 to 23 million tons in Australia. Total 2009 sales are expected to be in a range of 225 to 245 million tons. In the past, we have achieved production levels that are relatively consistent with our projections. We may adjust our production levels further in response to changes in market demand.

     We continue to manage costs and operating performance to mitigate external cost pressures, geologic conditions and potential shipping delays resulting from adverse port and rail performance. To mitigate the external cost pressures, we have instituted a company-wide initiative to instill best practices at all operations. We may have higher per ton costs as a result of lower production levels due to market-driven changes in demand. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage 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 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2008 for additional considerations regarding our outlook.

     We rely on ongoing access to the worldwide financial markets for capital, insurance, hedging and investments through a wide variety of financial instruments and contracts. To the extent these markets are not available or increase significantly in cost, this could have a negative impact on our ability to meet our business goals. Similarly many of our customers and suppliers rely on the availability of the financial markets to secure the necessary financing and financial surety (letters of credit, performance bonds, etc.) to complete transactions with us. To the extent customers and suppliers are not able to secure this financial support, it could have a negative impact on our results of operations and/or counterparty credit exposure.

     Long-Term Outlook

     While the current global economic conditions create near-term uncertainty, our long-term global outlook remains positive. Coal has been the fastest-growing fuel for each of the past six years, with consumption growing nearly twice as fast as total energy use.

     The International Energy Agency’s World Energy Outlook estimates world primary energy demand will grow 45% between 2006 and 2030, with demand for coal rising 61%. China and India alone account for more than half of the expected incremental energy demand. Currently, 180 gigawatts of coal-fueled electricity generating plants are under construction around the world, representing nearly 700 million tons of annual coal demand expected to come online in the next several years. In the U.S., 17 gigawatts of new coal-based generating capacity are under construction representing approximately 70 million tons of annual coal demand when they come online over the next three to four years.

     We believe that Btu Conversion applications such as coal-to-gas (CTG) and coal-to-liquids (CTL) plants represent an 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, which is estimated to add 70 million tons of annual U.S. coal demand by 2030. In addition, China and India are developing CTG and CTL facilities.

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     In April 2009, the U.S. Environmental Protection Agency (EPA) published for public comment its proposed finding that atmospheric concentrations of greenhouse gases endanger public health and welfare within the meaning of the Clean Air Act and that emissions of greenhouse gases from new motor vehicles and new motor vehicle engines are contributing to air pollution which is endangering public health and welfare within the meaning of the Clean Air Act. The proposed finding, if finalized, would not by itself impose any regulatory requirements and does not contain any specific targets for reducing greenhouse gases. While the EPA’s proposed finding is technically limited to greenhouse gas emissions from new motor vehicles and new motor vehicle engines, a final endangerment finding by the EPA may lead to endangerment findings under other Clean Air Act programs, including those that relate directly to emissions from stationary sources.

     In May 2009, legislation was introduced in Australia’s Parliament to establish a national emissions trading market, called the Carbon Pollution Reduction Scheme (CPRS). If enacted, the CPRS would set a cap on greenhouse gas emissions in Australia and issue permit allowances up to the cap limit. The proposed legislation would delay the CPRS start date to July 2011 due to the impacts of the global recession. The CPRS was passed by Australia’s House of Representatives on June 4, 2009, but requires approval from both houses of parliament before becoming law.

     In June 2009, the U.S. House of Representatives passed legislation which calls for an economy-wide, greenhouse gas cap-and-trade system and other complementary measures. Similar legislation may be considered by the U.S. Senate later in 2009. While it is possible that the U.S. will adopt some form of mandatory greenhouse gas legislation in the future, the timing and specific requirements of any such legislation are highly uncertain.

     Enactment of laws and passage of regulations regarding greenhouse gas emissions by the U.S. or some of its states or by other countries, or other actions to limit carbon dioxide emissions, could result in electricity generators switching from coal to other fuel sources. The potential financial impact on us of future regulation will depend primarily upon the degree to which any such regulation forces electricity generators to diminish their reliance on coal as a fuel source. That, in turn, will depend on a number of factors, including the specific requirements imposed by any such regulation.

     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 and the Australian COAL21 Fund, and through our participation in the Power Systems Development Facility, the PowerTree Carbon Company LLC, the Midwest Geopolitical Sequestration Consortium and the Asia-Pacific Partnership for Clean Development and Climate. In addition, we are the only non-Chinese equity partner in GreenGen, a planned near-zero emissions coal-fueled power plant with carbon capture and storage which is under development in China. We are also a founding member of Global Carbon Capture and Storage Institute, an international initiative to accelerate commercialization of CCS technologies through development of 20 integrated, industrial-scale demonstration projects.

     Clean coal technology development is being accelerated by the American Recovery and Reinvestment Act of 2009 (the Act), which was signed into law by President Obama in February 2009. The Act targets $3.4 billion for U.S. Department of Energy fossil fuel programs, including $1 billion for CCS research; $800 million for the Clean Coal Power Initiative, a 10-year program supporting commercial CCS; and $50 million for geology research.

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. GAAP requires 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 Current Report on Form 8-K filed with the SEC on August 6, 2009 describes the critical accounting policies and estimates used in the preparation of our financial statements.

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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 credit and nonperformance risk in the fair value measurement by analyzing the counterparty’s exposure balance, credit rating and average default rate, net of any counterparty credit enhancements (e.g., collateral), as well as our own credit rating for financial derivative liabilities.

     We evaluate the quality and reliability of the assumptions and data used to measure fair value in the three hierarchy Levels 1, 2 and 3, as prescribed by SFAS No. 157 (see Note 4 and Note 14 to our unaudited condensed consolidated financial statements 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. Indicators of less liquid markets are those with periods of low trade activity or when broker quotes reflect wide pricing spreads. Generally, these instruments or contracts are valued using internally generated models that include forward pricing curve quotes from one to three reputable brokers. Our valuation techniques also include basis adjustments for heat rate, sulfur and ash content, port and freight costs, and credit and nonperformance risk. We validate our valuation inputs with third-party information and settlement prices from other sources where available.

     We have consistently applied these valuation techniques in all periods presented, and believe we have obtained the most accurate information reasonably available for the types of derivative contracts held. Valuation changes from period to period for each level will increase or decrease depending on: (i) the relative change in fair value for positions held, (ii) new positions added, (iii) realized amounts for completed trades, and (iv) transfers between levels. Our coal trading strategies utilize various swaps and derivative physical contracts, which are categorized by level in the table below. Periodic changes in fair value for purchase and sale positions, which are executed to lock in coal trading spreads, occur in each level and therefore the overall change in value of our coal-trading platform requires consideration of valuation changes across all levels.

     Net assets (liabilities) related to coal trading activities at June 30, 2009 and December 31, 2008 are as follows:

	June 30,			December 31,			Increase
	2009			2008			(Decrease)
	(Dollars in millions)
Level 1	$	(1.3	)	$	(17.0	)	$	15.7
Level 2		299.4			337.8			(38.4	)
Level 3		2.4			37.8			(35.4	)
Total	$	300.5		$	358.6		$	(58.1	)

     Our coal-trading platform includes positions designed to secure forward pricing for some of our production (i.e. cash flow hedges wherein the effective portion of the change in the fair value is recorded as a separate component of stockholders’ equity until the hedged transaction occurs) as well as positions designed to generate current period trading results. Movement in the overall coal trading portfolio since December 31, 2008 is primarily due to relatively flat trading volumes. The fair value of coal trading positions designated as cash flow hedges of anticipated future sales was an asset of $152.2 million as of June 30, 2009 and an asset of $220.4 million as of December 31, 2008 (primarily classified as Level 2). As of June 30, 2009, the estimated realization of our aggregate coal trading portfolio of $300.5 million is 67% in 2009 and 78% by the end of 2010.

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Level 3 Net Financial Asset (Liability) Detail

     The Level 3 net financial assets (liabilities) as of June 30, 2009 and December 31, 2008 are as follows:

	June 30, 2009			December 31, 2008
	(Dollars in millions)
Commodity swaps and options — coal trading activities	$	—		$	(1.1	)
Physical commodity purchase/sale contracts — coal trading activities		2.4			38.9
Total net financial assets	$	2.4		$	37.8
Total net financial assets (liabilities) measured at fair value	$	217.4		$	(129.2	)
Percent of Level 3 net financial assets to total net financial assets (liabilities) measured at fair value		1.1	%	Not meaningful (1)

⁽¹⁾ Percentage of Level 3 net financial assets compared to total net financial liabilities is not meaningful due to overall liability position as of December 31, 2008.

     The following table summarizes the changes in our recurring Level 3 net financial assets (liabilities):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
	(Dollars in millions)
Beginning of period	$	(3.6	)	$	173.9		$	37.8		$	128.7
Total gains or losses (realized/unrealized):
Included in earnings		10.6			209.0			20.9			258.4
Included in other comprehensive income		1.9			(36.2	)		(10.3	)		(33.9	)
Purchases, issuances and settlements		(6.5	)		32.0			(38.7	)		25.5
Net transfers out		—			—			(7.3	)		—
End of period	$	2.4		$	378.7		$	2.4		$	378.7

     The following table summarizes the changes in unrealized gains relating to Level 3 net financial assets (liabilities) held both as of the beginning and the end of the period:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(Dollars in millions)
Changes in unrealized gains (1)	$	5.9	$	263.4	$	16.2	$	296.9

(1) For the periods presented, unrealized gains and losses from Level 3 items are combined with unrealized gains and losses on positions classified in Level 1 or 2, as well as other positions that have been realized during the applicable periods.

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, federal coal lease payments, 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 and share repurchases, among other restricted items, are subject to limitations imposed in the covenants of our 5.875% and 6.875% Senior Notes and Convertible Junior Subordinated Debentures. We generally fund our capital expenditure requirements with cash generated from operations.

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     We believe our available borrowing capacity and operating cash flows will be sufficient in the near term. As of June 30, 2009 we had cash and cash equivalents of $446.0 million and $1.5 billion of available borrowing capacity under our Senior Unsecured Credit Facility, net of outstanding letters of credit. The Senior Unsecured Credit Facility matures on September 15, 2011.

     In Australia, we have a bank overdraft facility that has a total capacity of approximately $15 million Australian dollars (approximately $12 million U.S. dollars). As of June 30, 2009, we had approximately $2 million of available capacity under this facility.

     Net cash provided by operating activities from continuing operations decreased $107.2 million compared to the prior year primarily due to the timing of cash flows from our working capital, primarily driven by higher inventory stockpiles and foreign income tax payments related to prior year earnings. During the six months ended June 30, 2009, we made funding contributions of $5.1 million to our pension plans and expect to make approximately $28 million through the remainder of 2009.

     The increase in cash provided by discontinued operations of $72.3 million was due to approximately $58 million of cash received related to coal excise tax refunds in the second quarter of 2009. See Note 3 to the unaudited condensed consolidated financial statements for more information related to the excise tax refund.

     Net cash used in investing activities decreased $20.8 million compared to the prior year due to lower capital spending of $21.7 million in 2009 as the prior year included spending associated with the development of our El Segundo Mine, partially offset by current year spending on the development of our new Bear Run Mine.

     Net cash used in financing activities increased $19.1 million compared to the prior year as the prior year included $39.7 million of increased proceeds and tax benefits associated with stock options exercised, partially offset by a $12.6 million decrease in payments of long-term debt and $10.4 million from the utilization of our Australian bank overdraft facility in the current year.

     Our total indebtedness as of June 30, 2009 and December 31, 2008, consisted of the following:

	June 30,		December 31,
	2009		2008
	(Dollars in millions)
Term Loan under the Senior Unsecured Credit Facility	$	490.3	$	490.3
Convertible Junior Subordinated Debentures due 2066		370.7		369.9
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		247.1		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		18.0		18.0
6.84% Series A Bonds due 2014		10.0		10.0
Capital lease obligations		75.4		81.2
Fair value hedge adjustment		9.2		15.1
Other		0.8		1.0
Total	$	2,782.6	$	2,793.6

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   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 2009 are expected to be between $400 million to $450 million, excluding federal coal reserve lease payments. These planned expenditures relate to sustaining capital at our existing mines, development of our Bear Run Mine in the Midwest (approximately $100 million), and the funding our Prairie State Energy Campus investment (approximately $60 million).

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 unaudited condensed consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

     Under our accounts receivable securitization program, undivided interests in a pool of eligible trade receivables contributed to our wholly-owned, bankruptcy-remote subsidiary are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (Conduit). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We utilize proceeds from the sale of our accounts receivable as an alternative to other forms of debt, effectively reducing our overall borrowing costs. The securitization program and the underlying facilities were renewed in May 2009 and expire in May 2012. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the unaudited condensed consolidated balance sheets. The amount of undivided interests in accounts receivable sold to the Conduit was $242.8 million as of June 30, 2009 and $275.0 million as of December 31, 2008.

     There were no other material changes to our off-balance sheet arrangements during the three months ended June 30, 2009. See Note 16 to our unaudited condensed consolidated financial statements 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 Current Report on Form 8-K filed with the SEC on August 6, 2009.

Newly Adopted Accounting Pronouncements and Accounting Pronouncements Not Yet Implemented

     See Note 2 to the unaudited condensed consolidated financial statements for a discussion concerning newly adopted accounting pronouncements and accounting pronouncements not yet implemented.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     The potential for changes in the market value of our coal and freight trading, emission allowances, crude oil, diesel fuel, natural gas, explosives, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading and freight portfolio is evaluated using a value at risk analysis (VaR), which is described below. VaR analysis is not used to evaluate our non-trading interest rate, diesel fuel, explosives 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.

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Coal Trading Activities and Related Commodity Price Risk

     We engage in over-the-counter and direct trading of coal, ocean freight and fuel-related commodities to support our coal-related activities. 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 VaR 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 unaudited condensed consolidated financial statements. Our trading portfolio included forwards and swaps as of June 30, 2009 and December 31, 2008.

     We perform a VaR analysis on our coal trading portfolio, which includes over-the-counter, exchange-settled and brokerage trading of coal. The use of VaR allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. VaR 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 VaR model is based on a variance/co-variance approach. This captures our exposure related to option, swap and forward positions. Our VaR 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 VaR estimates during the liquidation period. Our volatility calculation incorporates an exponentially weighted moving average algorithm based on the previous 60 market days, which makes our volatility more representative of recent market conditions, while still reflecting an awareness of historical price movements.

     The use of VaR allows management to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. We use historical data to estimate price volatility as an input to VaR. Given our reliance on historical data, we believe VaR is reasonably effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. 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 VaR 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 VaR measure. The results of these analyses are used to supplement the VaR methodology and identify additional market-related risks. An inherent limitation of VaR is that past changes in market risk factors may not produce accurate predictions of future market risk.

     During the six months ended June 30, 2009, the actual low, high, and average VaR for our coal trading portfolio were $6.7 million, $15.9 million, and $10.6 million, respectively. Our VaR decreased over the prior year due to less price volatility and lower overall prices in the U.S. and international coal markets.

     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 primarily with electric utilities, energy producers and energy marketers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to regularly monitor the credit extended. If we engage in a transaction with a counterparty that does not meet our credit standards, we seek to protect our position by requiring the counterparty to provide an appropriate credit enhancement. 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 agreements that include netting language with counterparties that permit us to offset receivables and payables with such counterparties and, to the extent required, will post or receive margin amounts associated with exchange-traded positions.

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     In addition to credit risk, performance risk includes the possibility that a counterparty fails to deliver or accept 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 or the creation of customer trust accounts held for our benefit to serve as collateral in the event of failure to perform.

     We conduct our various hedging activities related to foreign currency, interest rate management, and fuel and explosives exposures with a variety of highly-rated commercial banks. In light of the recent turmoil in the financial markets we continue to closely monitor counterparty creditworthiness.

Foreign Currency Risk

     We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2009 targets hedging approximately 70% of our anticipated Australian dollar-denominated operating expenditures. The accounting for these derivatives is discussed in Note 14 to our unaudited condensed consolidated financial statements. Assuming we had no hedges in place, our exposure in operating costs and expenses due to a five-cent change in the Australian dollar/U.S. dollar exchange rate is approximately $85 million for the next 12 months. However, taking into consideration hedges currently in place, our net exposure to the same rate change is approximately $27 million for the next 12 months. The chart at the end of Item 3 shows the notional amount of our forward contracts as of June 30, 2009.

Interest Rate Risk

     Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed-rate debt as a percent of net debt through the use of various hedging instruments, which are discussed in detail in Note 14 to our unaudited condensed consolidated financial statements. As of June 30, 2009, after taking into consideration the effects of interest rate swaps, we had $2.4 billion of fixed-rate borrowings and $0.4 billion of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of approximately $4 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 decrease of approximately $113 million in the estimated fair value of these borrowings.

Other Non-trading Activities — Commodity Price Risk

   Long-term Coal Contracts

     We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements (those with terms longer than one year), rather than through the use of derivative instruments. We sold 90% of our worldwide sales volume under long-term coal supply agreements during 2008.

   Diesel Fuel and Explosives Hedges

     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, which are primarily swap contracts with financial institutions.

     Notional amounts outstanding under fuel-related, derivative swap contracts are noted in the chart at the end of Item 3. We expect to consume 125 to 130 million gallons of fuel in the next 12 months. Assuming we had no hedges in place, a $10 dollar per barrel change in the price of crude oil (the primary component of a refined diesel fuel product) would increase or decrease our annual fuel costs by approximately $31 million based on our expected usage. However, taking into consideration hedges currently in place, our net exposure to the price of crude oil is approximately $11 million.

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     Notional amounts outstanding under explosives-related swap contracts are noted in the chart at the end of Item 3. We expect to consume 335,000 to 345,000 tons of explosives in the next 12 months in the U.S. Explosives costs in Australia are generally included in the fees paid to our contract miners. Assuming we had no hedges in place, a price change in natural gas (often a key component in the production of explosives) of one dollar per million MMBtu would result in an increase or decrease in our annual explosives costs of approximately $6 million based on our expected usage. However, taking into consideration hedges currently in place, our net exposure to the price of natural gas is approximately $3 million.

     The following summarizes our interest rate, foreign currency and commodity positions at June 30, 2009:

	Notional Amount by Year of Maturity
													2014 and
	Total		2009		2010		2011		2012		2013		thereafter
Interest Rate Swaps
Fixed-to-floating (dollars in millions)	$	50.0	$	—	$	—	$	—	$	—	$	50.0	$	—
Floating-to-fixed (dollars in millions)	$	186.0	$	—	$	—	$	120.0	$	—	$	—	$	66.0
Foreign Currency
A$:US$ forwards and options (A$ millions)	$	2,451.7	$	622.4	$	989.3	$	640.0	$	200.0	$	—	$	—
Commodity Contracts
Diesel fuel hedge contracts (million gallons)		150.2		49.2		64.4		31.4		5.2		—		—
U.S. explosives hedge contracts (million MMBtu)		4.4		1.5		2.9		—		—		—		—

	Account Classification by
	Cash flow		Fair value		Economic		Fair Value Asset
	hedge		hedge		hedge		(Liability)
							(Dollars in millions)
Interest Rate Swaps
Fixed-to-floating (dollars in millions)	$	—	$	50.0	$	—	$	1.0
Floating-to-fixed (dollars in millions)	$	186.0	$	—	$	—	$	(15.6	)
Foreign Currency
A$:US$ forwards and options (A$ millions)	$	2,451.7	$	—	$	—	$	26.3
Commodity Contracts
Diesel fuel hedge contracts (million gallons)		147.6		—		2.6	$	(82.6	)
U.S. explosives hedge contracts (million MMBtu)		4.2		—		0.2	$	(12.2	)

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, 2009, 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.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

     See Note 15 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 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 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. In addition, our Board of Directors had previously authorized our Chairman and Chief Executive Officer to repurchase up to $100 million of our common stock outside the share repurchase program. In October 2008, our Board of Directors amended the share repurchase program to increase the total authorized amount to $1 billion. The amended repurchase program does not have an expiration date and may be discontinued at any time. As of June 30, 2009, there was $700.4 million available for share repurchases under the program. There were no share repurchases under this program during the three months ended June 30, 2009.

							Maximum Dollar
							Value that May
					Total Number of		Yet Be Used to
	Total				Shares Purchased		Repurchase Shares
	Number of		Average		as Part of Publicly		Under the Publicly
	Shares		Price per		Announced		Announced Program
Period	Purchased(1)		Share		Program		(In Millions)
April 1 through April 30, 2009		6,977	$	26.00		—	$	700.4
May 1 through May 31, 2009		220		30.45		—		700.4
June 1 through June 30, 2009		2,158		35.53		—		700.4
Total		9,355	$	28.30		—

⁽¹⁾ Represents 9,355 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 7, 2009. The shares of common stock eligible to vote were based on a record date of March 13, 2009. Five directors were elected to serve for a one-year term expiring in 2010. A tabulation of the votes for these directors is set forth below:

	For		Withheld
Gregory H. Boyce		195,648,237		24,422,278
William E. James		198,156,879		21,913,636
Robert B. Karn III		151,841,796		68,228,719
M. Frances Keeth		218,009,520		2,060,995
Henry E. Lentz		145,469,707		74,600,808

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     The terms of office of the following directors also continued after the annual meeting of shareholders: William A. Coley, William C. Rusnack, John F. Turner, Sandra Van Trease and Alan H. Washkowitz.

     Shareholders also ratified Ernst & Young LLP as our independent registered public accounting firm for 2009 and reapproved the material terms of the performance measures under our 2004 Long-Term Equity Incentive 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		214,502,930		5,389,086		178,499
Reapproval of the material terms of the performance measures under our 2004 Long-Term Equity Incentive Plan		209,951,469		9,506,381		608,559

Item 6. Exhibits.

     See Exhibit Index at page 56 of this report.

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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, 2009	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)

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EXHIBIT INDEX

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

Exhibit
No.	Description of Exhibit
3.1	Third Amended and Restated Certificate of Incorporation of the Registrant, as amended (Incorporated by reference to Exhibit 3.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2008).
3.2	Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed on September 16, 2008).
10.1	Seventh Amendment to Amended and Restated Receivables Purchase Agreement, dated as of May 12, 2009, by and among P&L Receivables Company, LLC, Peabody Energy Corporation, the various Sub-Servicers listed on the signature pages thereto, 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 and as LC Bank (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on May 18, 2009).
10.2*	Form of Performance Unit Award Agreement under the Registrant’s 2004 Long-Term Equity Incentive Plan.
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.
101**	Interactive Data File (Form 10-Q for the quarterly period ended June 30, 2009 furnished in XBRL). Users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections. The financial information contained in the XBRL-related documents is “unaudited” and “unreviewed.”

*	Filed herewith.
**	Submitted herewith.

56

EX-10.2

Exhibit 10.2

PERFORMANCE UNITS AGREEMENT

     THIS AGREEMENT, effective January 5, 2009 (the “Grant Date”), is made by and between PEABODY ENERGY CORPORATION, a Delaware corporation (the “Company”), and the undersigned employee of the Company or a Subsidiary (as defined below) or an Affiliate (as defined below) of the Company (the “Grantee”).

     WHEREAS, the Company wishes to afford the Grantee the opportunity to participate in future increases in Company value;

     WHEREAS, the Company wishes to carry out the Plan (as hereinafter defined), the terms of which are hereby incorporated by reference and made a part of this Agreement; and

     WHEREAS, the Committee (as hereinafter defined) appointed to administer the Plan has determined that it would be to the advantage and best interest of the Company and its stockholders to grant the Performance Units provided for herein to the Grantee as an incentive for increased efforts during his or her term of office with the Company or its Subsidiaries or Affiliates, and has advised the Company thereof and instructed the undersigned officer to issue said Performance Units;

     NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereby agree as follows:

ARTICLE I
DEFINITIONS

     Whenever the following terms are used in this Agreement, they shall have the meanings specified below. Capitalized terms not otherwise defined in this Agreement shall have the meanings specified in the Plan.

     Section 1.1 — “Affiliate” shall mean any other Person directly or indirectly controlling, controlled by, or under common control with the Company. For the purposes of this definition, the term “control” (including, with correlative meanings, the terms “controlling”, “controlled by” and “under common control with”), as applied to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of that Person, whether through the ownership of voting securities, by contract or otherwise.

     Section 1.2 — “Board of Directors” or “Board” shall mean the Board of Directors of the Company.

     Section 1.3 — “Cause” shall mean “Cause” as defined in the Grantee’s employment agreement with the Company.

     Section 1.4 — “Change of Control” shall mean, for purposes of this Agreement and notwithstanding the definition set forth in the Plan:

     (a) any Person (other than a Person holding securities representing ten percent (10%) or more of the combined voting power of the Company’s outstanding securities as of May 22, 2001, the Company, any trustee or other fiduciary holding securities under an employee benefit plan of the Company, or any corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of stock of the Company), becomes the beneficial owner, directly or indirectly, of securities of the Company representing more than fifty percent (50%) of the combined voting power of the Company’s then-outstanding securities (provided, however, that if any Person is considered to own more than fifty percent (50%) of the total voting power of the stock of the Company, the acquisition of additional stock by the same Person is not considered to cause a change in the control of the Company);

     (b) during any period of twelve (12) consecutive months, a majority of the members of the Company’s Board is replaced by directors whose appointment or election is not endorsed by a majority of the members of the Board before the date of the appointment or election;

     (c) consummation of any merger, consolidation, plan of arrangement, reorganization or similar transaction or series of transactions in which the Company is involved, other than such a transaction or series of transactions which would result in the shareholders of the Company immediately prior thereto continuing to own (either by remaining outstanding or by being converted into voting securities of the surviving entity) more than fifty percent (50%) of the combined voting power of the securities of the Company or such surviving entity (or the parent, if any) outstanding immediately after such transaction(s) in substantially the same proportions as their ownership immediately prior to such transaction(s); or

     (d) the consummation of a sale or disposition by the Company of Company assets that have a Total Gross FMV (as defined below) equal to or greater than eighty-five percent (85%) of the Total Gross FMV of all of the assets of the Company immediately before such sale or disposition (provided, however, that a transfer of assets by the Company is not treated as a change in the ownership of such assets if the assets are transferred to: (A) a shareholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock; (B) an entity of which the Company owns, directly or indirectly, 50% or more of the total value or voting power; (C) a Person, or more than one Person acting as a group, that owns, directly or indirectly, fifty percent (50%) or more of the total value or voting power of all the outstanding stock of the Company; or (D) an entity of which a Person or group described in clause (C) above owns, directly or indirectly, at least fifty percent (50%) of the total value or voting power).

     As used in this Section, the term “Person” (including a “group”) has the meaning provided under Section 13(d) or 14(d) of the Securities Exchange Act of 1934, as amended (or any successor section thereto).

     As used in this Section, the term “Total Gross FMV” means the value of the assets of the Company, or the value of the assets being disposed of, determined by the Committee without regard to any liabilities associated with such assets.

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     Section 1.5 — “Committee” shall mean the Compensation Committee of the Company, duly appointed by the Board as the Administrator under Section 2 of the Plan.

     Section 1.6 — “Common Stock” shall mean the common stock of the Company, par value $0.01.

     Section 1.7 — “Determination Date” shall mean the earliest to occur of the following events: (i) December 31, 2011; (ii) a Termination of Employment on account of death or Disability; or (iii) a Change of Control.

     Section 1.8 — “FMV per Share” shall mean the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date; notwithstanding the foregoing, in the event of a Change of Control, “FMV per Share” shall mean the per share value of equity based on amounts paid in the Change of Control.

     Section 1.9 — “Good Reason” shall mean “Good Reason” as defined in the Grantee’s employment agreement with the Company.

     Section 1.10 — “Incentive Amount” shall mean the amount payable to the Grantee hereunder with respect to the Performance Units, if any, as calculated under Article IV.

     Section 1.11 — “Performance Units” shall mean the units granted on a performance basis under this Agreement. The value of each Performance Unit shall be equal to the FMV per Share as of the relevant Determination Date (as defined below).

     Section 1.12 — “Person” shall mean an individual, partnership, corporation, business trust, joint stock company, trust, unincorporated association, joint venture, governmental authority or other entity of whatever nature.

     Section 1.13 — “Plan” shall mean the Peabody Energy Corporation 2004 Long-Term Equity Incentive Plan, as amended from time to time.

     Section 1.14 — Pronouns - The masculine pronoun shall include the feminine and neuter, and the singular the plural, where the context so indicates.

     Section 1.15 — “Retirement” shall mean the Grantee’s retirement from the Company on or after age fifty-five (55) with at least ten (10) years of service with the Company.

     Section 1.16 — “Subsidiary” shall mean any corporation in an unbroken chain of corporations beginning with the Company, if each of the corporations, or group of commonly controlled corporations, other than the last corporation in the unbroken chain then owns stock possessing fifty percent (50%) or more of the total combined voting power of all classes of stock in one of the other corporations below it in such chain.

     Section 1.17 — “Termination of Employment” shall mean a termination of the Grantee’s employment with the Company, a Subsidiary or an Affiliate (regardless of the reason therefor) that constitutes a “separation from service” as defined in Section 409A of the Internal Revenue Code of 1986, as amended, or applicable regulations or other guidance issued thereunder (“Section 409A”).

3

ARTICLE II
GRANT OF PERFORMANCE UNITS

     Section 2.1 — Grant of Performance Units. For good and valuable consideration, the Company hereby grants to the Grantee the number of Performance Units set forth on the signature page hereof upon the terms and subject to the conditions set forth in this Agreement.

     Section 2.2 — No Obligation of Employment. Nothing in this Agreement or in the Plan shall confer upon the Grantee any right to continue in the employ of the Company or any Subsidiary or Affiliate or interfere with or restrict in any way the rights of the Company and its Subsidiaries or Affiliates, which are hereby expressly reserved, to terminate the employment of the Grantee at any time for any reason whatsoever, with or without Cause.

     Section 2.3 — Adjustments in Performance Units. In the event that shares of Common Stock are, from time to time, changed into or exchanged for a different number or kind of shares of the Company or other securities of the Company by reason of a merger, consolidation, recapitalization event, reclassification, stock split, stock dividend, combination of shares, or otherwise, the Committee shall make an appropriate and equitable adjustment in the number and kind of Performance Units, or other consideration payable hereunder, and the applicable FMV per Share. Any such adjustment made by the Committee shall be final and binding upon the Grantee, the Company and all other interested persons.

ARTICLE III
VESTING AND FORFEITURE OF PERFORMANCE UNITS

     Section 3.1 — Performance Units. Unless otherwise provided in this Article III, the Performance Units shall vest on the fifteenth (15^th) day of each calendar month, in equal monthly increments, during the period beginning on the Grant Date and ending on the Determination Date (the “Performance Cycle”).

     Section 3.2 — Effect of Certain Events. Notwithstanding the foregoing Section 3.1, during the Performance Cycle:

     (a) upon a Termination of Employment on account of the Grantee’s death or Disability, all of the Performance Units shall become immediately vested and the Grantee shall become entitled to the Incentive Amount calculated and payable pursuant to Article IV hereof with respect to the Performance Units that are vested as of the date of Termination of Employment;

     (b) upon the earliest of (i) a Termination of Employment on account of Retirement, (ii) a Termination of Employment by the Company without Cause, or by the Grantee for Good Reason, or (iii) a Change of Control, the Performance Units shall cease to vest, any and all Performance Units that remain unvested on the date of such Termination of Employment or Change of Control shall terminate immediately, and the Grantee shall become entitled to the Incentive Amount calculated and payable pursuant to Article IV hereof with respect to the Performance Units that are vested as of the date of such Termination of Employment or Change of Control, as applicable; and

4

     (c) upon the earlier of (i) a Termination of Employment by the Company for Cause, and (ii) a Termination of Employment by the Grantee without Good Reason, all Performance Units (whether or not they are vested) shall terminate and the Grantee shall not be entitled to any Incentive Amount hereunder.

ARTICLE IV
CALCULATION AND PAYMENT OF INCENTIVE AMOUNT

     Section 4.1 — Calculation of Incentive Amount. The Incentive Amount, if any, payable to the Grantee hereunder shall be calculated as of the Determination Date. The Incentive Amount shall equal the number of Performance Units that are vested as of the Determination Date pursuant to Article III hereof, multiplied by the FMV per Share as of the Determination Date, and further multiplied by the applicable percentage determined as of the Determination Date based on the matrix below (the “Applicable Percentage”):

Applicable Percentage

 

75%ile		100	%		110	%		130	%		140	%		152	%		176	%		188	%		200	%
70%ile		92	%		102	%		122	%		132	%		144	%		168	%		180	%		192	%
65%ile		84	%		94	%		114	%		124	%		136	%		160	%		172	%		184	%
60%ile		76	%		86	%		106	%		116	%		128	%		152	%		164	%		176	%
55%ile		68	%		78	%		98	%		108	%		120	%		144	%		156	%		168	%
50%ile		60	%		70	%		90	%		100	%		112	%		136	%		148	%		160	%
45%ile		53	%		63	%		83	%		93	%		105	%		129	%		141	%		153	%
40%ile		47	%		57	%		77	%		87	%		99	%		123	%		135	%		147	%
35%ile		40	%		50	%		70	%		80	%		92	%		116	%		128	%		140	%
	35%ile			40%ile			50%ile			55%ile			60%ile			70%ile			75%ile			80%ile

3 Year Cumulative TSR – Peer Group

where:

“3 Year Cumulative TSR – Peer Group” represents the Company’s average total shareholder return (based on the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date compared to the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately following the Grant Date) expressed as a percentage of an industry peer group index, which peer group shall include such companies as shall be selected by the Committee in its sole discretion before the awards to which the 3 Year Cumulative TSR – Peer Group applies are granted; and

5

“3 Year Cumulative TSR – S&P 500” represents the Company’s average total shareholder return (based on the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date compared to the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately following the Grant Date) expressed as a percentage of the Standard & Poor’s 500 Index.

     Notwithstanding the foregoing, in the event that the Company’s average total shareholder return as of the Determination Date (based on the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately preceding the Determination Date compared to the average of the closing prices of the shares of Common Stock for the four (4) weeks immediately following the Grant Date) is negative, (i) no Incentive Amount shall be paid hereunder if the 3 Year Cumulative TSR – Peer Group (as defined above) is less than fifty percent (50%) as of the Determination Date, and (ii) the Applicable Percentage shall not exceed one hundred fifty percent (150%) if the 3 Year Cumulative TSR – Peer Group (as defined above) equals or exceeds fifty percent (50%) as of the Determination Date.

     Section 4.2 — Form and Time of Payment.

     (a) General. Subject to Section 4.3, the Incentive Amount shall be paid to the Grantee in Common Stock (except as otherwise provided below in this Section 4.2) as soon as administratively feasible but not later than the ninetieth (90th) day following the Determination Date. The number of shares of Common Stock to be distributed to the Grantee shall equal the quotient of (i) the Incentive Amount, divided by (ii) the Fair Market Value of one share of Common Stock on the payment date. Notwithstanding the foregoing, if the Determination Date is triggered by a Change of Control, the Incentive Amount (calculated in accordance with Section 4.1 using the per share value of equity based on amounts paid in the Change of Control) shall be paid to the Grantee in cash as soon as administratively feasible but not later than the ninetieth (90th) day following the Determination Date.

     (b) Specified Employee. If the Determination Date is triggered by a Termination of Employment other than due to death and the Grantee is a “specified employee” (as such term is defined in Section 409A, but generally meaning one of the Company’s key employees within the meaning of Code Section 416(i)), the Incentive Amount shall be paid to the Grantee six (6) months after the Determination Date.

     Section 4.3 — Conditions to Issuance of Stock Certificates. If the Incentive Amount is to be distributed in shares of Common Stock as provided in Section 4.2 and the Committee reasonably anticipates, in accordance with Treasury Regulation Section 1.409A-2(b)(7)(ii)), that issuing Common Stock within the 90-day period following the Determination Date will violate federal securities laws or other applicable laws, the Company may delay issuing such Common Stock, provided that the Company issues such Common Stock on the earliest date on which the Committee reasonably anticipates that such issuance will not violate federal securities laws or other applicable laws.

6

     Section 4.4 — Stockholder Rights. The Grantee shall not be, or have any of the rights or privileges of, a stockholder of the Company in respect of any shares of Common Stock deliverable hereunder unless and until certificates representing such shares shall have been issued by the Company to the Grantee.

ARTICLE V
MISCELLANEOUS

     Section 5.1 — Administration. The Committee has the power to interpret the Plan and this Agreement and to adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith and to interpret or revoke any such rules. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Grantee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or the Performance Units. In its absolute discretion, the Board of Directors may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan and this Agreement.

     Section 5.2 — Performance Units Not Transferable. Neither the Performance Units nor any interest or right therein or part thereof shall be liable for the debts, contracts or engagements of the Grantee or his or her successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition is voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect; provided, however, that this Section 5.2 shall not prevent transfers by will or by the applicable laws of descent and distribution.

     Section 5.3 — Withholding. No later than the date as of which an amount payable hereunder first becomes includible in the Grantee’s gross income for tax purposes, the Grantee shall pay to the Company, or make arrangements satisfactory to the Company regarding the payment of, any applicable withholding taxes. Any payment under Section 4.2 shall be conditioned upon the Grantee’s compliance with this Section 5.3.

     Section 5.4 — Notices. Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Grantee shall be addressed to him or her at the address given beneath his or her signature hereto. By a notice given pursuant to this Section 5.4, either party may hereafter designate a different address for notices to be given to him, her or it. Any notice which is required to be given to the Grantee shall, if the Grantee is then deceased, be given to the Grantee’s personal representative if such representative has previously informed the Company of his, her or its status and address by written notice under this Section 5.4. Any notice shall be deemed duly given when enclosed in a properly sealed envelope or wrapper addressed as aforesaid, deposited (with postage prepaid) in a post office or branch post office regularly maintained by the United States Postal Service.

     Section 5.5 — Titles. Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.

7

     Section 5.6 — Applicability of Plan. The Performance Units and the shares of Common Stock issued to the Grantee, if any, shall be subject to all of the terms and provisions of the Plan, to the extent applicable to the Performance Units and such shares. In the event of any conflict between this Agreement and the Plan, the terms of the Plan shall control.

     Section 5.7 — Amendment.

     (a) This Agreement may be amended only by a writing executed by the parties hereto that specifically states that it is amending this Agreement.

     (b) This Agreement is intended to comply with Section 409A and shall, to the extent practicable, be construed in accordance therewith. If either party to this Agreement reasonably determines that any amount payable pursuant to this Agreement would result in adverse tax consequences under Section 409A, then such party shall deliver written notice of such determination to the other party, and the parties hereby agree to work in good faith to amend this Agreement so it complies with the requirements of Section 409A and preserves as nearly as possible the original intent and economic effect of the affected provisions.

     Section 5.8 — Dispute Resolution. Any dispute or controversy arising under or in connection with this Agreement shall be resolved by arbitration in St. Louis, Missouri. Arbitrators shall be selected, and arbitration shall be conducted, in accordance with the rules of the American Arbitration Association. The Company shall pay or reimburse any legal fees in connection with such arbitration in the event that the Grantee prevails on a material element of his or her claim or defense. Payments or reimbursements of legal fees made under this Section 5.8 that are provided during one calendar year shall not affect the amount of such payments or reimbursements provided during a subsequent calendar year, payments or reimbursements under this Section 5.8 may not be exchanged or substituted for another form of compensation to the Grantee, and any such reimbursement or payment will be paid within sixty (60) days after the Grantee prevails, but in no event later than the last day of the Grantee’s taxable year following the taxable year in which he incurred the expense giving rise to such reimbursement or payment. This Section 5.8 shall remain in effect throughout the Grantee’s employment with the Company and for a period of five (5) years following the Grantee’s Termination of Employment.

     Section 5.9 — Governing Law. The laws of the State of Delaware shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.

[SIGNATURE PAGE FOLLOWS]

8

     IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto.

GRANTEE	PEABODY ENERGY CORPORATION
	By
[Grantee]
	Its
Address
Grantee’s Taxpayer Identification	Aggregate number of Performance
Number:	Units granted hereunder:
-                    -

9

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Gregory H. Boyce, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Peabody Energy Corporation (“the registrant”);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 7, 2009

/s/ Gregory H. Boyce

Gregory H. Boyce

Chairman and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Michael C. Crews, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Peabody Energy Corporation (“the registrant”);
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 7, 2009

/s/ Michael C. Crews

Michael C. Crews

Executive Vice President and Chief

Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)

I, Gregory H. Boyce, Chairman and Chief Executive Officer of Peabody Energy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2009 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2)	information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Peabody Energy Corporation.

Dated: August 7, 2009

/s/ Gregory H. Boyce

Gregory H. Boyce

Chairman and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
(18 U.S.C. SECTION 1350)

I, Michael C. Crews, Executive Vice President and Chief Financial Officer of Peabody Energy Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2009 (the “Periodic Report”) which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and
(2)	information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Peabody Energy Corporation.

Dated: August 7, 2009

/s/ Michael C. Crews

Michael C. Crews

Executive Vice President and Chief

Financial Officer