e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2007


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

For the transition period from to

Commission File Number: 1-16463

PEABODY ENERGY CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		13-4004153

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


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

(Address of principal executive offices)		(Zip Code)

(314) 342-3400

(Registrant’s telephone number, including area code)

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

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

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

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

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

There were 265,831,807 shares of common stock with a par value of $0.01 per share outstanding at November 5, 2007.

PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF EARNINGS


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Dollars in thousands, except share and per share data)
Revenues
Sales	$	1,431,855		$	1,223,274		$	4,022,705		$	3,805,838
Other revenues		61,761			41,714			158,134			87,348


Total revenues		1,493,616			1,264,988			4,180,839			3,893,186

Costs and Expenses
Operating costs and expenses		1,265,571			1,003,004			3,434,869			3,078,880
Depreciation, depletion and amortization		113,054			90,664			324,417			263,103
Asset retirement obligation expense		8,748			7,068			27,596			25,911
Selling and administrative expenses		43,698			31,488			129,328			118,793
Other operating income:
Net gain on disposal or exchange of assets		(23,610	)		(35,040	)		(158,975	)		(94,309	)
Income from equity affiliates		(2,959	)		(5,200	)		(9,443	)		(19,132	)


Operating Profit		89,114			173,004			433,047			519,940
Interest expense		58,872			26,392			176,686			79,130
Interest income		(4,955	)		(1,886	)		(13,984	)		(6,026	)


Income Before Income Taxes and Minority Interests		35,197			148,498			270,345			446,836
Income tax provision		5,967			2,657			37,736			10,905
Minority interests		(3,042	)		3,833			4,139			10,267


Net Income	$	32,272		$	142,008		$	228,470		$	425,664


Earnings Per Share
Basic	$	0.12		$	0.54		$	0.87		$	1.61
Diluted	$	0.12		$	0.53		$	0.85		$	1.58

Weighted Average Shares Outstanding
Basic		263,871,330			263,444,254			263,463,822			263,631,134
Effect of dilutive securities		5,069,600			5,378,427			5,172,597			5,689,667

Diluted		268,940,930			268,822,681			268,636,419			269,320,801


Dividends Declared Per Share	$	0.06		$	0.06		$	0.18		$	0.18

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEET


	(Unaudited)
	September 30, 2007			December 31, 2006
	(Dollars in thousands, except
	share and per share data)
ASSETS
Current assets
Cash and cash equivalents	$	216,314		$	326,511
Accounts receivable, net of allowance for doubtful accounts of $11,735 at September 30, 2007 and $11,144 at December 31, 2006		277,442			358,242
Inventories		267,194			237,602
Assets from coal trading activities		706,017			150,373
Deferred income taxes		106,967			106,967
Other current assets		208,158			116,863

Total current assets		1,782,092			1,296,558
Property, plant, equipment and mine development
Land and coal interests		7,434,846			7,127,385
Buildings and improvements		902,222			893,049
Machinery and equipment		1,702,581			1,516,765
Less accumulated depreciation, depletion and amortization		(2,207,312	)		(1,985,682	)

Property, plant, equipment and mine development, net		7,832,337			7,551,517
Goodwill		242,406			240,667
Investments and other assets		597,666			425,314

Total assets	$	10,454,501		$	9,514,056

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	63,174		$	95,757
Liabilities from coal trading activities		662,255			126,731
Accounts payable and accrued expenses		1,177,015			1,104,881

Total current liabilities		1,902,444			1,327,369
Long-term debt, less current maturities		3,152,967			3,201,992
Deferred income taxes		248,643			195,213
Asset retirement obligations		438,956			423,031
Workers’ compensation obligations		234,366			233,407
Accrued postretirement benefit costs		1,373,292			1,368,686
Other noncurrent liabilities		431,299			392,495

Total liabilities		7,781,967			7,142,193
Minority interests		29,662			33,337
Stockholders’ equity
Preferred Stock – $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of September 30, 2007 or December 31, 2006		—			—
Series A Junior Participating Preferred Stock – 1,500,000 shares authorized, no shares issued or outstanding as of September 30, 2007 or December 31, 2006		—			—
Perpetual Preferred Stock – 750,000 shares authorized, no shares issued or outstanding as of September 30, 2007 or December 31, 2006		—			—
Series Common Stock – $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of September 30, 2007 or December 31, 2006		—			—
Common Stock – $0.01 per share par value; 800,000,000 shares authorized, 268,214,559 shares issued and 265,505,673 shares outstanding as of September 30, 2007 and 266,554,157 shares issued and 263,846,839 shares outstanding as of December 31, 2006		2,682			2,666
Additional paid-in capital		1,617,794			1,572,614
Retained earnings		1,296,757			1,115,994
Accumulated other comprehensive loss		(170,598	)		(249,058	)
Treasury shares, at cost: 2,708,886 shares as of September 30, 2007 and 2,707,318 shares as of December 31, 2006		(103,763	)		(103,690	)

Total stockholders’ equity		2,642,872			2,338,526

Total liabilities and stockholders’ equity	$	10,454,501		$	9,514,056

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS


	Nine Months Ended September 30,
	2007			2006
	(Dollars in thousands)
Cash Flows From Operating Activities
Net income	$	228,470		$	425,664
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		324,417			263,103
Deferred income taxes		6,582			(74,753	)
Amortization of debt discount and debt issuance costs		5,511			5,146
Net gain on disposal or exchange of assets		(158,975	)		(94,309	)
Income from equity affiliates		(9,443	)		(19,132	)
Dividends received from equity affiliates		12,927			9,935
Stock compensation		18,797			12,687
Changes in current assets and liabilities, net of acquisitions:
Accounts receivable, including securitization		80,799			4,990
Inventories		(29,592	)		(36,312	)
Net assets from coal trading activities		(46,096	)		(1,169	)
Other current assets		(34,898	)		(26,458	)
Accounts payable and accrued expenses		49,767			(30,136	)
Asset retirement obligations		5,646			(5,476	)
Workers’ compensation obligations		1,142			2,738
Accrued postretirement benefit costs		32,534			16,191
Obligation to industry fund		7,636			(3,816	)
Other, net		(1,884	)		(14,595	)

Net cash provided by operating activities		493,340			434,298

Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		(428,863	)		(292,444	)
Federal coal lease expenditures		(178,193	)		(178,193	)
Proceeds from disposal of assets, net of notes receivable		137,562			53,308
Acquisitions, net (including acquisition of 19.99% of Excel Coal Limited)		—			(352,367	)
Investment in joint venture		(13,814	)		(1,471	)
Additions to advance mining royalties		(6,372	)		(6,650	)

Net cash used in investing activities		(489,680	)		(777,817	)

Cash Flows From Financing Activities
Change in revolving line of credit		25,000			312,000
Payments of long-term debt		(114,732	)		(483,320	)
Proceeds from long-term debt		—			440,750
Dividends paid		(47,709	)		(47,628	)
Excess tax benefit related to stock options exercised		13,017			30,775
Proceeds from stock options exercised		8,485			12,834
Proceeds from employee stock purchases		6,377			4,518
Distributions to minority interests		(3,521	)		(3,887	)
Payments of debt issuance costs		(774	)		(8,621	)
Common stock repurchase		—			(99,775	)

Net cash provided by (used in) financing activities		(113,857	)		157,646

Net decrease in cash and cash equivalents		(110,197	)		(185,873	)
Cash and cash equivalents at beginning of year		326,511			503,278

Cash and cash equivalents at end of year	$	216,314		$	317,405

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2007

(1) Basis of Presentation

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

The accompanying condensed consolidated financial statements as of September 30, 2007 and for the three and nine months ended September 30, 2007 and 2006, and the notes thereto, are unaudited. However, in the opinion of management, these financial statements reflect all normal, recurring adjustments necessary for a fair presentation of the results of the periods presented. The balance sheet information as of December 31, 2006 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the nine months ended September 30, 2007 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2007. Certain amounts in prior periods have been reclassified to conform to the report classifications as of September 30, 2007 and for the three and nine months ended September 30, 2007, with no effect on previously reported net income or stockholders’ equity.

(2) New Accounting Pronouncements

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

The Company adopted the provisions of FIN No. 48 on January 1, 2007 with no impact to retained earnings. At adoption, the Company had $135 million of unrecognized tax benefits in its condensed consolidated financial statements, and an additional $3 million has been added since January 1, 2007 resulting from tax positions taken during the current year. The Company does not expect significant increases or decreases to its unrecognized tax benefits within 12 months of this reporting date that would affect the Company’s effective tax rate, if recognized.

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

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

(3) Business Combinations and Acquisitions

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

The preliminary purchase accounting allocations related to the acquisition were recorded in the accompanying condensed consolidated financial statements as of, and for periods subsequent to, October 2006. The valuation of the net assets acquired is expected to be finalized once certain third-party appraisals are completed in the fourth quarter of 2007.

The following unaudited pro forma financial information presents the combined results of operations of the Company and Excel, on a pro forma basis, as though the companies had been combined as of the beginning of the period presented. The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and Excel constituted a single entity during this period. The Company expects to begin to realize the full benefit of the Excel acquisition when the mines under development are fully operational. Two of the development-stage mines began operations during the nine months ended September 30, 2007, and the remaining development-stage mine is expected to be fully commissioned in the fourth quarter of 2007.


	Three Months Ended		Nine Months Ended
	September 30, 2006		September 30, 2006
	(Dollars in thousands, except per share data)
Revenues:
As reported	$	1,264,988	$	3,893,186
Pro forma		1,363,332		4,188,218

Net income:
As reported	$	142,008	$	425,664
Pro forma		136,231		408,332

Basic earnings per share — net income:
As reported	$	0.54	$	1.61
Pro forma		0.52		1.55

Diluted earnings per share — net income:
As reported	$	0.53	$	1.58
Pro forma		0.51		1.52

(4) Assets and Liabilities from Coal Trading Activities


	September 30, 2007		December 31, 2006
	(Dollars in thousands)
Assets from Coal Trading Activities	$	706,017	$	150,373
Liabilities from Coal Trading Activities		662,255		126,731

Net assets from Coal Trading Activities	$	43,762	$	23,642

The Company’s coal trading portfolio included forward and swap contracts as of September 30, 2007 and December 31, 2006. Of the coal trading derivatives and related hedge contracts in the Company’s trading portfolio as of September 30, 2007, 97% were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials, and 3% of the Company’s contracts were valued based on similar market transactions. The recent increase in coal prices, particularly in our international markets, has significantly increased the relative value of our trading asset and liability portfolio. The net value of trading assets and liabilities represents the future realizable value of the trading portfolio.

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


Year of	Percentage
Expiration	of Portfolio
2007		22	%
2008		41	%
2009		31	%
2010		5	%
2011		1	%

		100	%

At September 30, 2007, 28% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties, 69% was with counterparties, primarily international, that are not rated and 3% was with non-investment grade counterparties. The Company’s coal trading operations traded 59.5 million tons and 19.8 million tons for the three months ended September 30, 2007 and 2006, respectively, and 125.9 million tons and 48.5 million tons for the nine months ended September 30, 2007 and 2006, respectively.

(5) Resource Management and Other Commercial Events

During August 2007, the Company purchased approximately 345 million tons of coal reserves and surface lands in the Illinois Basin. In conjunction with the purchase, the Company also agreed to provide up to $64.8 million of reclamation and bonding commitments to a third-party coal company. The Company has recognized the full amount of these commitments as a liability as of September 30, 2007. The non-cash portion of this transaction was excluded from the investing section of the statement of cash flows.

During September 2007, the Company sold approximately 172 million tons of coal reserves and surface lands to the Prairie State Energy Campus (Prairie State) equity partners. The Company recognized a gain totaling $17.8 million and received $84.2 million in cash proceeds associated with this transaction. See Note 12 for additional information regarding Prairie State.

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

In June 2007, the Company exchanged oil and gas rights and assets in more than 860,000 acres in the Illinois Basin, West Virginia, New Mexico and the Powder River Basin for approximately 40 million tons of high-Btu coal reserves in West Virginia and Kentucky and $15.0 million in cash proceeds. The Company’s subsidiaries received approximately 28 million tons of Pittsburgh seam coal reserves adjacent to the Company’s Federal No. 2 mining operation in West Virginia and more than 12 million tons of coal reserves in Western Kentucky. Based on the fair value of the coal reserves received, the Company recognized a $50.5 million gain on the exchange. The non-cash portion of this transaction was excluded from the investing section of the statement of cash flows.

During September 2006, the Company sold approximately 29 million tons of non-strategic coal reserves and surface lands located in Kentucky and West Virginia for proceeds of $34.6 million and recognized a gain of $30.0 million. In June 2006, the Company exchanged approximately 63 million tons of coal reserves at its Caballo mining operation for approximately 46 million tons of coal reserves contiguous with the Company’s North Antelope Rochelle mining operation. Based on the fair value of the coal reserves exchanged, the Company recognized a gain totaling $39.2 million. This non-cash transaction was excluded from the investing section of the statement of cash flows.

The Company recognized $24.3 million and $35.8 million during the three and nine months ended September 30, 2006, respectively, in gains related to the settlement of commitments by a third-party coal producer following a contract restructuring. These gains are included in “Other revenues” in the condensed consolidated income statements.

(6) Inventories

Inventories consisted of the following:


	September 30, 2007		December 31, 2006
	(Dollars in thousands)
Materials and supplies	$	97,152	$	85,243
Raw coal		48,998		42,693
Saleable coal		121,044		109,666

Total	$	267,194	$	237,602

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

(7) Long-Term Debt

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


	September 30,			December 31,
	2007			2006
	(Dollars in thousands)
Term Loan under Senior Unsecured Credit Facility	$	515,529		$	547,000
Convertible Junior Subordinated Debentures due 2066		732,500			732,500
7.375% Senior Notes due 2016		650,000			650,000
6.875% Senior Notes due 2013		650,000			650,000
7.875% Senior Notes due 2026		246,947			246,897
5.875% Senior Notes due 2016		218,090			231,845
5.0% Subordinated Note		—			59,504
Revolving Line of Credit		25,000			—
6.84% Series C Bonds due 2016		43,000			43,000
6.34% Series B Bonds due 2014		21,000			21,000
6.84% Series A Bonds due 2014		10,000			10,000
Capital lease obligations		95,076			96,869
Fair value of interest rate swaps		(11,445	)		(13,784	)
Other		20,444			22,918


Total	$	3,216,141		$	3,297,749

Long-Term Debt Repayments

During the nine months ended September 30, 2007, the Company repaid portions of its long-term debt, which included a $60.0 million retirement of its 5.0% Subordinated Note; a $31.5 million repayment of its outstanding balance of the Term Loan under the Senior Unsecured Credit Facility; an open-market purchase of $13.8 million in face value of its 5.875% Senior Notes; and capital lease payments totaling $7.0 million. As of September 30, 2007, the Revolving Credit Facility’s remaining available borrowing capacity under the Senior Unsecured Credit Facility was $1.35 billion.

Capital Lease Obligations

As of December 31, 2006, “Capital lease obligations” reflected an additional $40.2 million that was previously classified as “Accounts payable and accrued expenses” on the Company’s consolidated balance sheet in its Annual Report on Form 10-K for the fiscal year ended December 31, 2006. The reclassification relates to a capital lease transaction structure that was finalized during the three months ended March 31, 2007. The lease term is 7 years with annual payments of approximately $7.2 million over the term of the lease, and a balloon payment at maturity of approximately $11.2 million.

Interest Rate Swaps

During the nine months ended September 30, 2007, the Company entered into several fixed-to-floating interest rate swaps. The first group of three interest rate swaps had combined notional amounts totaling $200.0 million and was designated to hedge changes in fair value of the 6.875% Senior Notes due 2013. Under the swaps, the Company pays a floating rate that resets each March 15 and September 15 based upon the six-month LIBOR rate for a period of six years ending March 15, 2013 and receives a fixed rate of 6.875%. The second group of two interest rate swaps had combined notional amounts totaling $100.0 million and was designated to hedge changes in fair value of the 5.875% Senior Notes due 2016. Under the swaps, the Company pays a floating rate that resets each April 15 and October 15 based upon the six-month LIBOR rate for a period of nine years ending April 15, 2016 and receives a fixed rate of 5.875%.

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

(8) Comprehensive Income

The following table sets forth the after-tax components of comprehensive income for the three and nine months ended September 30, 2007 and 2006:


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007		2006			2007		2006
	(Dollars in thousands)
Net income	$	32,272	$	142,008		$	228,470	$	425,664
Increase (decrease) in fair value of cash flow hedges, net of tax provision (benefit) of $22,571 and ($11,080) for the three months ended September 30, 2007 and 2006, respectively, and $35,498 and ($967) for the nine months ended September 30, 2007 and 2006, respectively		32,116		(16,620	)		51,501		(1,450	)
Accumulated actuarial loss and prior service cost realized in net income, net of tax provision of $4,748 and $16,402 for the three and nine months ended September 2007		6,954		—			26,961		—

Comprehensive income	$	71,342	$	125,388		$	306,932	$	424,214

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

(9) Pension and Postretirement Benefit Costs

Net periodic pension costs included the following components:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(Dollars in thousands)
Service cost for benefits earned	$	1,550		$	3,058		$	6,050		$	9,175
Interest cost on projected benefit obligation		11,842			11,508			35,792			34,525
Expected return on plan assets		(14,075	)		(13,647	)		(42,225	)		(40,940	)
Amortization of actuarial loss and other		3,558			5,663			11,908			16,989

Net periodic pension costs	$	2,875		$	6,582		$	11,525		$	19,749

Net periodic postretirement benefit costs included the following components:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(Dollars in thousands)
Service cost for benefits earned	$	3,013		$	1,880		$	8,255		$	5,639
Interest cost on accumulated postretirement benefit obligation		21,511			18,465			64,394			55,391
Amortization of prior service cost		(165	)		(1,333	)		(1,172	)		(4,002	)
Amortization of actuarial loss		10,816			8,012			32,448			24,036

Net periodic postretirement benefit costs	$	35,175		$	27,024		$	103,925		$	81,064

The Company expects to pay approximately $89 million attributable to its postretirement benefit plans during the year ended December 31, 2007, which reflects an increase of approximately $6 million from its previously disclosed estimate in the notes to the financial statements of its Annual Report on Form 10-K for the fiscal year ended December 31, 2006. The increase primarily relates to greater than expected number of retirees, higher than anticipated utilization and revised estimates of the impact of the recently approved 2007 National Bituminous Coal Wage Agreement. As of September 30, 2007, payments of $68.2 million attributable to the Company’s postretirement benefit plans were made.

(10) Segment Information

The Company reports its operations primarily through the following reportable operating segments: “Western U.S. Mining,” “Eastern U.S. Mining,” “Australian Mining” and “Trading and Brokerage.” The Company’s chief operating decision maker uses Adjusted EBITDA as the primary measure of segment profit and loss. Adjusted EBITDA is defined as income from operations before deducting net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization.

Operating segment results for the three and nine months ended September 30, 2007 and 2006 were as follows:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Dollars in thousands)						(Dollars in thousands)
Revenues:
Western U.S. Mining	$	545,964		$	428,263		$	1,517,567		$	1,260,670
Eastern U.S. Mining		544,055			505,603			1,567,294			1,537,561
Australian Mining		313,990			191,517			861,365			562,408
Trading and Brokerage		76,235			132,957			211,686			515,514
Corporate and Other		13,372			6,648			22,927			17,033

Total	$	1,493,616		$	1,264,988		$	4,180,839		$	3,893,186


Adjusted EBITDA:
Western U.S. Mining	$	148,443		$	112,589		$	424,993		$	340,384
Eastern U.S. Mining		85,322			68,397			238,841			309,053
Australian Mining		11,017			75,248			115,460			188,932
Trading and Brokerage		19,513			39,347			82,858			76,725
Corporate and Other ⁽¹⁾		(53,379	)		(24,845	)		(77,092	)		(106,140	)

Total	$	210,916		$	270,736		$	785,060		$	808,954


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

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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Dollars in thousands)
Total Adjusted EBITDA	$	210,916		$	270,736		$	785,060		$	808,954

Depreciation, depletion and amortization		113,054			90,664			324,417			263,103
Asset retirement obligation expense		8,748			7,068			27,596			25,911
Interest expense		58,872			26,392			176,686			79,130
Interest income		(4,955	)		(1,886	)		(13,984	)		(6,026	)

Income before income taxes and minority interests	$	35,197		$	148,498		$	270,345		$	446,836

(11)

Commitments and Contingencies

Commitments

As of September 30, 2007, purchase commitments for capital expenditures were $92.3 million and federal coal reserve lease payments due over the next three years totaled $302.3 million.

Litigation Relating to Continuing Operations

Navajo Nation Litigation

On June 18, 1999, the Navajo Nation served three of the Company’s subsidiaries, including Peabody Western Coal Company (Peabody Western), with a complaint that had been filed in the U.S. District Court for the District of Columbia. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act (RICO) violations and fraud. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases have terminated due to Peabody Western’s breach of these leases and a reformation of these leases to adjust the royalty rate to 20%. Subsequently, the court allowed the Hopi Tribe to intervene in this lawsuit and the Hopi Tribe is also seeking unspecified actual damages, punitive damages and reformation of its coal lease. One of the Company’s subsidiaries named as a defendant is now a subsidiary of Patriot Coal Corporation (Patriot). However, the Company is responsible for this litigation under the Separation Agreement entered into with Patriot in connection with the spin-off. On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States rejecting the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments. On February 9, 2005, the U.S. District Court for the District of Columbia granted a consent motion to stay the litigation until further order of the court. Peabody Western, the Navajo Nation, the Hopi Tribe and the owners of the power plants served by the suspended Black Mesa mine and the Kayenta mine are in mediation with respect to this litigation and other business issues.

The outcome of this litigation, or the current mediation, is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot be reasonably estimated. However, based on current information, the Company believes this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

Salt River Project Agricultural Improvement and Power District — Mine Closing and Retiree Health Care

Salt River Project and the other owners of the Navajo Generating Station filed a lawsuit on September 27, 1996, in the Superior Court of Maricopa County in Arizona seeking a declaratory judgment that certain costs relating to final reclamation, environmental monitoring work and mine decommissioning and costs primarily relating to retiree health care benefits are not recoverable by the Company’s subsidiary, Peabody Western, under the terms of a coal supply agreement dated February 18, 1977. The contract expires in 2011. The trial court subsequently ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. The Company has recorded a receivable for mine decommissioning costs of $79.8 million and $76.8 million included in “Investments and other assets” in the condensed consolidated balance sheets as of September 30, 2007 and December 31, 2006, respectively.

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

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 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 will expire on December 31, 2007. We have filed a motion to dismiss the Florida lawsuit or to transfer it to Illinois. The parties are planning to mediate this lawsuit beginning in December 2007.

The outcome of this litigation is subject to numerous uncertainties. Based on the Company’s evaluation of the issues and their potential impact, the amount of any future loss cannot reasonably be estimated. However, based on current information, the Company believes this matter is likely to be resolved without a material adverse effect on its financial condition, results of operations or cash flows.

Claims and Litigation Relating to Indemnities or Historical Operations

Oklahoma Lead Litigation

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

Gold Fields and two other companies are defendants in two class action lawsuits allegedly involving past operations near Picher, Oklahoma. The plaintiffs have asserted claims predicated on allegations of intentional lead exposure by the defendants and are seeking compensatory damages, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. Gold Fields was also a defendant, along with other companies, in personal injury lawsuits that at one time involved over 50 individuals, arising out of the same lead mill operations. Gold Fields, along with the former affiliate, has settled most of the claims in the personal injury lawsuits and the remaining lawsuits have been dismissed with prejudice. In December 2003, the Quapaw Indian tribe and certain Quapaw land owners filed a lawsuit against Gold Fields, five other companies and the United States. The plaintiffs are seeking compensatory and punitive damages based on a variety of theories. Gold Fields has filed a third-party complaint against the United States, and other parties. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other companies regarding a possible natural resources damage claim. All of the lawsuits are pending in the U.S. District Court for the Northern District of Oklahoma.

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

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, the total of which have since been reduced to 12 by completion of work, transfer or regulatory inactivity. The number of PRP sites in and of itself is not a relevant measure of liability, because the nature and extent of environmental concerns varies by site, as does the estimated share of responsibility for Gold Fields or the former affiliate. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above were $41.7 million as of September 30, 2007 and $43.0 million as of December 31, 2006, $6.4 million and $14.4 million of which was reflected as a current liability, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable. In September 2005, Gold Fields and other PRPs received a letter from the U.S. Department of Justice alleging that the PRPs’ mining operations caused the Environmental Protection Agency (EPA) to incur approximately $125 million in residential yard remediation costs at Picher, Oklahoma and will cause the EPA to incur additional remediation costs relating to historical mining sites. Gold Fields has participated in the ongoing settlement discussions. Gold Fields believes it has meritorious defenses to these claims. Gold Fields is involved in other litigation in the Picher area, and the Company indemnified TXU Group with respect to a defendant as is more fully discussed under the “Oklahoma Lead Litigation” caption above. Significant uncertainty exists as to whether claims will be pursued against Gold Fields in all cases, and where they are pursued, the amount of the eventual costs and liabilities, which could be greater or less than this provision.

Other

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

In addition, at times the Company becomes a party to other claims, lawsuits, arbitration proceedings and administrative procedures in the ordinary course of business. 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. The letter referred to the Company’s “plans to build new coal-fired electric generating units,” and said that the “increase in CO2 emissions from the operation of these units, in combination with Peabody Energy’s other coal-fired power plants, will subject Peabody Energy to increase financial, regulatory, and litigation risks.” 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. The Company also currently has no electrical generating capacity in place.

(12) Guarantees

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

The Company’s wholly-owned subsidiary, Prairie State Generating Company, LLC (PSGC), had previously entered into a cost reimbursable Target Price Engineering, Procurement and Construction Agreement (Agreement) with Bechtel Power Corporation (Bechtel) related to the Prairie State mine mouth pulverized coal-fired generating facility. The Company provided an absolute and unconditional payment guarantee of all amounts due until financial closing by PSGC to Bechtel under the Agreement (Initial Owner Guarantee). On September 28, 2007, PSGC gave Bechtel notice to proceed to full scale construction of the facility. On that date, the Company’s ownership interest in PSGC was transferred to an Indiana non-profit corporation that is owned and controlled by a group of owners (Owners), including two of the Company’s affiliates. Contemporaneously with the transfer of PSGC’s membership interests, each Owner (including the Company’s affiliates) issued a guarantee to Bechtel for its proportionate share of PSGC’s obligations under the Agreement and the Company issued a guarantee to Bechtel for the Company’s two affiliates. The Initial Owner Guarantee was returned to the Company following the issuance of new guarantees by each Owner. The Company’s affiliates own approximately 28% of PSGC and have a contract to sell about 23% of PSGC or an equivalent amount of power to a third-party which is expected to close within six months and would reduce the Company’s ownership to 5.06%.

The Company has provided financial guarantees under certain long-term debt agreements entered into by its subsidiaries, and substantially all of the Company’s U.S. subsidiaries provide financial guarantees under long-term debt agreements entered into by the Company. The maximum amounts payable under the Company’s debt agreements are equal to the respective principal and interest payments. See Note 7 for the descriptions of the Company’s long-term debt. Supplemental guarantor/non-guarantor financial information is provided in Note 13.

(13) Supplemental Guarantor/Non-Guarantor Financial Information

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

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Three Months Ended September 30, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Total revenues	$	—		$	1,168,803		$	390,530		$	(65,717	)	$	1,493,616
Costs and expenses:
Operating costs and expenses		(4,053	)		969,045			366,296			(65,717	)		1,265,571
Depreciation, depletion and amortization		3,186			77,603			32,265			—			113,054
Asset retirement obligation expense		—			8,028			720			—			8,748
Selling and administrative expenses		8,568			35,721			(591	)		—			43,698
Other operating income (loss):
Net gain on disposal of assets		—			(23,529	)		(81	)		—			(23,610	)
(Income) loss from equity affiliates		(72,332	)		1,642			(4,601	)		72,332			(2,959	)
Interest expense		69,356			12,026			10,099			(32,609	)		58,872
Interest income		(4,240	)		(23,850	)		(9,474	)		32,609			(4,955	)

Income (loss) before income taxes and minority interests		(485	)		112,117			(4,103	)		(72,332	)		35,197
Income tax provision (benefit)		(32,757	)		46,291			(7,567	)		—			5,967
Minority interests		—			(557	)		(2,485	)		—			(3,042	)

Net income (loss)	$	32,272		$	66,383		$	5,949		$	(72,332	)	$	32,272

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Three Months Ended September 30, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Total revenues	$	—		$	1,003,291		$	286,245		$	(24,548	)	$	1,264,988
Costs and expenses:
Operating costs and expenses		(2,416	)		832,697			197,271			(24,548	)		1,003,004
Depreciation, depletion and amortization		—			75,983			14,681			—			90,664
Asset retirement obligation expense		—			6,772			296			—			7,068
Selling and administrative expenses		3,056			27,594			838			—			31,488
Other operating (income) loss:
Net gain on disposal of assets		—			(24,521	)		(10,519	)		—			(35,040	)
(Income) loss from equity affiliates		(167,786	)		1,147			(6,347	)		167,786			(5,200	)
Interest expense		41,109			13,690			3,284			(31,691	)		26,392
Interest income		(4,916	)		(21,758	)		(6,903	)		31,691			(1,886	)

Income (loss) before income taxes and minority interests		130,953			91,687			93,644			(167,786	)		148,498
Income tax provision (benefit)		(11,055	)		(5,508	)		19,220			—			2,657
Minority interests		—			—			3,833			—			3,833

Net income (loss)	$	142,008		$	97,195		$	70,591		$	(167,786	)	$	142,008

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Nine Months Ended September 30, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Total revenues	$	—		$	3,223,118		$	1,084,659		$	(126,938	)	$	4,180,839
Costs and expenses:
Operating costs and expenses		(6,989	)		2,636,792			932,004			(126,938	)		3,434,869
Depreciation, depletion and amortization		3,186			231,571			89,660			—			324,417
Asset retirement obligation expense		—			25,065			2,531			—			27,596
Selling and administrative expenses		23,054			104,461			1,813			—			129,328
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(158,375	)		(600	)		—			(158,975	)
(Income) loss from equity affiliates		(357,908	)		4,765			(14,208	)		357,908			(9,443	)
Interest expense		208,417			40,638			22,429			(94,798	)		176,686
Interest income		(13,118	)		(71,583	)		(24,081	)		94,798			(13,984	)

Income (loss) before income taxes and minority interests		143,358			409,784			75,111			(357,908	)		270,345
Income tax provision (benefit)		(85,112	)		124,466			(1,618	)		—			37,736
Minority interests		—			(557	)		4,696			—			4,139

Net income (loss)	$	228,470		$	285,875		$	72,033		$	(357,908	)	$	228,470

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations


	Nine Months Ended September 30, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Total revenues	$	—		$	2,992,171		$	978,810		$	(77,795	)	$	3,893,186
Costs and expenses:
Operating costs and expenses		(14,746	)		2,432,235			739,186			(77,795	)		3,078,880
Depreciation, depletion and amortization		—			222,127			40,976			—			263,103
Asset retirement obligation expense		—			25,249			662			—			25,911
Selling and administrative expenses		12,525			104,577			1,691			—			118,793
Other operating (income) loss:
Net gain on disposal or exchange of assets		—			(83,822	)		(10,487	)		—			(94,309	)
(Income) loss from equity affiliates		(498,763	)		2,607			(21,739	)		498,763			(19,132	)
Interest expense		121,232			42,234			10,197			(94,533	)		79,130
Interest income		(15,624	)		(63,628	)		(21,307	)		94,533			(6,026	)

Income (loss) before income taxes and minority interests		395,376			310,592			239,631			(498,763	)		446,836
Income tax provision (benefit)		(30,288	)		(2,716	)		43,909			—			10,905
Minority interests		—			—			10,267			—			10,267

Net income (loss)	$	425,664		$	313,308		$	185,455		$	(498,763	)	$	425,664

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Balance Sheets


	September 30, 2007
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Assets
Current assets
Cash and cash equivalents	$	136,319	$	23,950		$	56,045		$	—		$	216,314
Accounts receivable		2,022		(228,392	)		503,812			—			277,442
Inventories		—		151,314			115,880			—			267,194
Assets from coal trading activities		—		706,017			—			—			706,017
Deferred income taxes		—		106,967			—			—			106,967
Other current assets		109,844		40,247			58,067			—			208,158

Total current assets		248,185		800,103			733,804			—			1,782,092
Property, plant, equipment and mine development - at cost		—		7,314,618			2,725,031			—			10,039,649
Less accumulated depreciation, depletion and amortization		—		(1,933,233	)		(274,079	)		—			(2,207,312	)
Goodwill		—		—			242,406			—			242,406
Investments and other assets		7,731,477		153,810			14,985			(7,302,606	)		597,666

Total assets	$	7,979,662	$	6,335,298		$	3,442,147		$	(7,302,606	)	$	10,454,501


Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long-term debt	$	50,297	$	(3,545	)	$	16,422		$	—		$	63,174
Payables and notes payable to affiliates, net		2,092,882		(2,596,418	)		503,536			—			—
Liabilities from coal trading activities		—		662,255			—			—			662,255
Accounts payable and accrued expenses		55,250		827,091			294,674			—			1,177,015

Total current liabilities		2,198,429		(1,110,617	)		814,632			—			1,902,444
Long-term debt, less current maturities		2,976,324		11,635			165,008			—			3,152,967
Deferred income taxes		73,046		(16,719	)		192,316			—			248,643
Other noncurrent liabilities		88,991		2,296,665			92,257			—			2,477,913

Total liabilities		5,336,790		1,180,964			1,264,213			—			7,781,967
Minority interests		—		—			29,662			—			29,662
Stockholders’ equity		2,642,872		5,154,334			2,148,272			(7,302,606	)		2,642,872

Total liabilities and stockholders’ equity	$	7,979,662	$	6,335,298		$	3,442,147		$	(7,302,606	)	$	10,454,501

Peabody Energy Corporation
Supplemental Condensed Consolidated Balance Sheets


	December 31, 2006
	Parent		Guarantor			Non-Guarantor
	Company		Subsidiaries			Subsidiaries			Eliminations			Consolidated
	(Dollars in thousands)
Assets
Current assets
Cash and cash equivalents	$	272,226	$	3,652		$	50,633		$	—		$	326,511
Accounts receivable		—		41,199			317,043			—			358,242
Inventories		—		146,920			90,682			—			237,602
Assets from coal trading activities		—		150,373			—			—			150,373
Deferred income taxes		—		106,967			—			—			106,967
Other current assets		54,007		41,221			21,635			—			116,863

Total current assets		326,233		490,332			479,993			—			1,296,558
Property, plant, equipment and mine development — at cost		—		6,964,886			2,572,313			—			9,537,199
Less accumulated depreciation, depletion and amortization		—		(1,794,823	)		(190,859	)		—			(1,985,682	)
Goodwill		—		—			240,667			—			240,667
Investments and other assets		7,178,608		34,195			77,897			(6,865,386	)		425,314

Total assets	$	7,504,841	$	5,694,590		$	3,180,011		$	(6,865,386	)	$	9,514,056


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

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

Total liabilities		5,166,315		1,057,231			918,647			—			7,142,193
Minority interests		—		—			33,337			—			33,337
Stockholders’ equity		2,338,526		4,637,359			2,228,027			(6,865,386	)		2,338,526

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

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows


	Nine Months Ended September 30, 2007
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in thousands)
Cash Flows From Operating Activities
Net cash provided by (used in) operating activities	$	(226,165	)	$	835,432		$	(115,927	)	$	493,340


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(283,678	)		(145,185	)		(428,863	)
Federal coal lease expenditures		—			(178,193	)		—			(178,193	)
Proceeds from disposal of assets, net of notes receivable		—			135,616			1,946			137,562
Investment in joint venture		—			(13,814	)		—			(13,814	)
Additions to advance mining royalties		—			(6,372	)		—			(6,372	)

Net cash used in investing activities		—			(346,441	)		(143,239	)		(489,680	)


Cash Flows From Financing Activities
Change in revolving line of credit		25,000			—			—			25,000
Payments of long-term debt		(44,608	)		(62,373	)		(7,751	)		(114,732	)
Dividends paid		(47,709	)		—			—			(47,709	)
Excess tax benefit related to stock options exercised		13,017			—			—			13,017
Proceeds from stock options exercised		8,485			—			—			8,485
Proceeds from employee stock purchases		6,377			—			—			6,377
Distributions to minority interests		—			—			(3,521	)		(3,521	)
Payments of debt issuance costs		—			(774	)		—			(774	)
Transactions with affiliates, net		129,696			(405,546	)		275,850			—

Net cash provided by (used in) financing activities		90,258			(468,693	)		264,578			(113,857	)

Net increase (decrease) in cash and cash equivalents		(135,907	)		20,298			5,412			(110,197	)
Cash and cash equivalents at beginning of year		272,226			3,652			50,633			326,511

Cash and cash equivalents at end of year	$	136,319		$	23,950		$	56,045		$	216,314

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows


	Nine Months Ended September 30, 2006
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Consolidated
	(Dollars in thousands)
Cash Flows From Operating Activities
Net cash provided by (used in) operating activities	$	(122,583	)	$	355,578		$	201,303		$	434,298


Cash Flows From Investing Activities
Additions to property, plant, equipment and mine development		—			(236,941	)		(55,503	)		(292,444	)
Federal coal lease expenditures		—			(118,364	)		(59,829	)		(178,193	)
Proceeds from disposal of assets, net of notes receivable		—			52,827			481			53,308
Acquisitions, net (including acquisition of 19.99% of Excel Coal Limited)		—			—			(352,367	)		(352,367	)
Additions to advance mining royalties		—			(4,761	)		(1,889	)		(6,650	)
Investment in joint venture		—			(1,471	)		—			(1,471	)

Net cash used in investing activities		—			(308,710	)		(469,107	)		(777,817	)


Cash Flows From Financing Activities
Change in revolving line of credit		312,000			—			—			312,000
Payments of long-term debt		(450,180	)		(10,591	)		(22,549	)		(483,320	)
Proceeds from long-term debt		440,000			—			750			440,750
Dividends paid		(47,628	)		—			—			(47,628	)
Common stock repurchase		(99,775	)		—			—			(99,775	)
Excess tax benefit related to stock options exercised		30,775			—			—			30,775
Payments of debt issuance costs		(8,621	)		—			—			(8,621	)
Proceeds from stock options exercised		12,834			—			—			12,834
Proceeds from employee stock purchases		4,518			—			—			4,518
Distributions to minority interests		—			—			(3,887	)		(3,887	)
Transactions with affiliates, net		(266,689	)		(35,041	)		301,730			—

Net cash provided by (used in) financing activities		(72,766	)		(45,632	)		276,044			157,646


Net increase (decrease) in cash and cash equivalents		(195,349	)		1,236			8,240			(185,873	)
Cash and cash equivalents at beginning of year		494,232			2,471			6,575			503,278

Cash and cash equivalents at end of year	$	298,883		$	3,707		$	14,815		$	317,405

(14) Subsequent Event

On October 10, 2007, the Company’s Board of Directors approved a spin-off of portions of its Eastern U.S. Mining operations business segment, including coal assets and operations in West Virginia and Kentucky. The spin-off was accomplished on October 31, 2007 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). Prior to the spin-off, the Company received necessary regulatory approvals including a favorable private letter ruling on the tax-free nature of the transaction from the Internal Revenue Service, and a declaration of effectiveness for Patriot’s registration statement on Form 10 with the Securities and Exchange Commission (SEC). Distribution of the Patriot stock to the Company’s stockholders occurred on October 31, 2007, at a ratio of one share of Patriot stock for every 10 shares of Peabody stock held on the record date of October 22, 2007. The Company’s end-of-year results will reflect Patriot as a discontinued operation. Refer to the Company’s current report on Form 8-K filed with the SEC on November 6, 2007 for additional details.

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

Cautionary Notice Regarding Forward-Looking Statements

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

Without limiting the foregoing, all statements relating to our future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding are forward-looking statements and speak only as of the date of this report. These forward-looking statements are based on numerous assumptions that we believe are reasonable, but are subject to a wide range of uncertainties and business risks and actual results may differ materially from those discussed in these statements. Among the factors that could cause actual results to differ materially are:

	•		ability to renew sales contracts;

	•		reductions of purchases by major customers;

	•		transportation performance and costs, including demurrage;

	•		geology, equipment and other risks inherent to mining;

	•		weather;

	•		legislation, regulations and court decisions;

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

	•		changes in postretirement benefit and pension obligations;

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

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

	•		replacement of coal reserves;

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

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

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

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

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

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

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

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

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

	•		growth of domestic and international coal and power markets;

	•		coal’s market share of electricity generation;

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

	•		future worldwide economic conditions;

	•		successful implementation of business strategies;

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

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

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

	•		interest rate changes;

	•		litigation, including claims not yet asserted;

	•		terrorist attacks or threats;

	•		impacts of pandemic illnesses; and

	•		other factors, including those discussed in Legal Proceedings.

When considering these forward-looking statements, you should keep in mind the cautionary statements in this document and in our other Securities and Exchange Commission (SEC) filings, including the more detailed discussion of these factors, as well as other factors that could affect our results, contained in Item 1A. Risk Factors of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 and this Quarterly Report on Form 10-Q. We do not undertake any obligation to update these statements, except as required by federal securities laws.

Overview

We are the largest private sector coal company in the world, with majority interests in 40 coal operations located throughout all major U.S. coal producing regions and internationally in Australia and Venezuela. In the first nine months of 2007, we sold 191.9 million tons of coal, and in 2006, we sold 247.6 million tons of coal with domestic sales representing 22% of all U.S. coal sales that year. The spin-off of Patriot Coal Corporation (Patriot) on October 31, 2007 included portions of our Eastern U.S. Mining operations business segment, with coal assets and operations in West Virginia and Kentucky. Patriot included 10 active operations that sold 17.1 million tons of coal year to date. See the “Outlook” section for an additional discussion of the spin-off.

Based on Energy Information Administration (EIA) estimates, demand for coal in the United States was approximately 1.1 billion tons in 2006. Domestic coal consumption is expected to grow at an average rate of 1.8% per year through 2030 when U.S. coal demand is forecasted to be 1.8 billion tons. Coal-fueled generation is used in most cases to meet baseload electricity requirements. Electricity growth is expected to average 1.5% annually through 2030. In 2006, coal’s share of electricity generation was approximately 50%, a share that the EIA projected will grow to 57% by 2030.

Our primary U.S. customers are domestic utilities, which accounted for 87% of our sales in 2006. Internationally, we sell our metallurgical coal to industrial customers and steam coal to utility customers in the Pacific Rim. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2006, approximately 90% of our sales were under long-term contracts. Excluding the effect of the Patriot spin-off, we have 15 to 20 million tons of planned U.S. production remaining unpriced for 2008 and 80 to 90 million tons unpriced for 2009. We have 11 to 13 million tons of Australian coal production available for pricing in 2008, more than half of which is metallurgical coal. We have 17 to 20 million tons of Australian coal unpriced for 2009, approximately half of which is metallurgical coal.

As discussed more fully in Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, our results of operations in the near-term could be negatively impacted by poor weather conditions, unforeseen geologic conditions, equipment problems at mining locations, and by the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections. See the Outlook section for discussion of near-term and long-term impacts to our business.

We conduct business through four principal operating segments: Western U.S. Mining, Eastern U.S. Mining, Australian Mining, and Trading and Brokerage. Our Western U.S. Mining operations consist of our Powder River Basin, Southwest and Colorado operations, and our Eastern U.S. Mining operations consist of our Appalachia and Midwest operations. The principal business of the Western U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to U.S. electric utilities. The principal business of the Eastern U.S. Mining segment is the mining, preparation and sale of steam coal, sold primarily to electric utilities, as well as the mining of metallurgical coal, sold to steel and coke producers, located in the United States, Europe and South America.

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

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

We own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela. The Paso Diablo Mine produces approximately 6 to 8 million tons of steam coal annually for export to the United States and Europe. During the first nine months of 2007, our interest in Carbones del Guasare contributed $14.2 million to segment Adjusted EBITDA in “Corporate and Other Adjusted EBITDA” and paid a dividend of $12.9 million. At September 30, 2007, our investment in Paso Diablo was $61.4 million. Each of our mining operations is described in Item 1. Business, of our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

Metallurgical coal is produced primarily from four of our Australian mines and two of our U.S. operations, both of which are being divested as part of the Patriot spin-off. Metallurgical coal was approximately 5% of our total sales volume and approximately 3% of U.S. sales volume in 2006.

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

We continue to pursue the development of coal-fueled generating projects in areas of the U.S. where electricity demand is strong and where there is access to land, water, transmission lines and low-cost coal. The projects involve mine-mouth generating plants using our surface lands and coal reserves. Our ultimate role in these projects could take numerous forms, including, but not limited to, equity partner, contract miner or coal sales. On October 1, 2007, we announced that the Prairie State Energy Campus equity partners have completed their respective financial closings and given Bechtel Power Corporation final notice to proceed to full-scale construction for the 1,600-megawatt Prairie State Energy Campus in Washington County, Illinois. The plant could begin generating electricity in the 2011 to 2012 timeframe. Our affiliates own approximately 28% of Prairie State Generating Company, LLC (PSGC) and have a contract to sell about 23% of PSGC or an equivalent amount of power to a third-party which is expected to close within six months and would reduce our ownership to 5.06%. In August 2007, the U.S. Court of Appeals for the Seventh Circuit unanimously affirmed the issuance of Prairie State Energy Campus’ air permit and in October 2007 the court unanimously rejected a request for a rehearing of its prior decision.

The EIA projects that the high price of oil will lead to an increase in demand for unconventional sources of transportation fuel, including Btu conversion technologies, and that coal will increase its share as a fuel for generation of electricity. We are exploring several Btu conversion projects, which are designed to expand the uses of coal through various technologies, and we are continuing to explore options, particularly as they relate to Btu conversion technologies such as coal-to-liquids and coal-to-gas. On July 23, 2007, we announced an agreement with ConocoPhillips to explore development of a commercial scale coal-to-substitute natural gas (SNG) facility in the Midwest. The project would be developed as a mine-mouth facility at a location where we have access to large reserves and existing infrastructure. The facility would be designed to annually produce 50 billion to 70 billion cubic-feet of pipeline quality SNG from more than 3.5 million tons of Midwest coal and petroleum coke.

Results of Operations

Adjusted EBITDA

The discussion of our results of operations below includes references to and analyses of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from operations before deducting net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management primarily as a measure of our segments’ operating performance. Because Adjusted EBITDA is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies. Adjusted EBITDA is reconciled to its most comparable measure, under generally accepted accounting principles, in Note 10 to our unaudited condensed consolidated financial statements.

Three and Nine Months Ended September 30, 2007 Compared to Three and Nine Months Ended September 30, 2006

Summary

Higher average sales prices primarily in the Powder River Basin and increased volumes primarily in Australian Mining operations contributed to increases in revenues during the three and nine months ended September 30, 2007 compared to the prior year.

Segment Adjusted EBITDA decreased for the three months compared to the prior year primarily due to the following:

	•		Transitional geology issues at several mines in our Eastern U.S. Mining operations;

	•		The effects of currency translation related to the weaker U.S. dollar against the strong Australian dollar;

	•		Disruption of the coal chain, including port congestion at our two primary Australian shipping points, Dalrymple Bay Coal Terminal and the Port of Newcastle, was caused by record demand and severe flooding in Newcastle during the second quarter. This led to significant queuing of vessels, which resulted in delayed shipments and increased demurrage charges;

Partially offsetting these unfavorable events were the contribution from new mines in Australia and higher prices in our U.S. Mining operations.

Segment Adjusted EBITDA for the nine months was affected by the factors noted above, in addition to being negatively impacted by certain capital project delays in our Western U.S. and Australian mining operations and adverse weather conditions in the first half of the year in our Australian mining operations.

Net income decreased for the three months ended September 30, 2007 compared to the prior year. The reasons for this decrease include the following:

	•		Higher depreciation, depletion and amortization primarily from our newly acquired mines in Australia; and

	•		Additional interest expense associated with approximately $1.7 billion in debt issued in the second half of 2006 to finance the acquisition of Excel Coal Limited (Excel). We expect to begin to realize the full benefit of the Excel acquisition when the mines under development are fully operational and the transportation logistics chain improves. Two of the development-stage mines began operations in the first nine months of 2007, and the remaining development-stage mine has started production and is expected to be fully commissioned in the fourth quarter of 2007.

Net Income for the nine months was affected by the factors noted above, but was partially offset by higher gains from asset disposals or exchanges in the United States.

Tons Sold


	Three Months Ended				2007 from 2006					Nine Months Ended				2007 from 2006
	September 30,				Increase					September 30,				Increase (Decrease)
	2007		2006		Tons		%			2007		2006		Tons			%
	(Tons in millions)									(Tons in millions)
Western U.S. Mining Operations		42.7		40.4		2.3		5.7	%		118.9		119.0		(0.1	)		(0.1	)%
Eastern U.S. Mining Operations		13.9		13.7		0.2		1.5	%		40.5		41.5		(1.0	)		(2.4	)%
Australian Mining Operations		6.2		2.3		3.9		169.6	%		16.2		6.6		9.6			145.5	%
Trading and Brokerage Operations		5.7		4.4		1.3		29.5	%		16.3		15.8		0.5			3.2	%

Total tons sold		68.5		60.8		7.7		12.7	%		191.9		182.9		9.0			4.9	%

Revenues


	Three Months Ended				Increase (Decrease)						Nine Months Ended				Increase (Decrease)
	September 30,				to Revenues						September 30,				to Revenues
	2007		2006		$			%			2007		2006		$			%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining Operations	$	546.0	$	428.3	$	117.7			27.5	%	$	1,517.6	$	1,260.7	$	256.9			20.4	%
Eastern U.S. Mining Operations		544.1		505.6		38.5			7.6	%		1,567.3		1,537.5		29.8			1.9	%
Australian Mining Operations		314.0		191.5		122.5			64.0	%		861.3		562.4		298.9			53.1	%
Trading and Brokerage Operations		76.2		133.0		(56.8	)		(42.7	)%		211.7		515.5		(303.8	)		(58.9	)%
Other		13.3		6.6		6.7			101.5	%		22.9		17.1		5.8			33.9	%

Total revenues	$	1,493.6	$	1,265.0	$	228.6			18.1	%	$	4,180.8	$	3,893.2	$	287.6			7.4	%

Total revenues and total sales increased for the three and nine months ended September 30, 2007 compared to the prior year. The primary causes of the increases in these periods included the following:

	•		Higher volumes in Australia due to sales from operations acquired in October 2006 (quarter – 4.1 million tons; nine months – 9.8 million tons);

	•		An increase of over 20% in average sales prices, for both periods, in our Western U.S. Mining operations (mainly reflecting a sales realization increase of approximately 29% of our premium Powder River Basin product for each period presented). These pricing increases in the Powder River Basin were the primary drivers of the overall increase in total sales for the quarter and nine months;

	•		Higher average sales prices experienced in our Eastern U.S. Mining operations from favorable contract pricing, partially offset by coal quality issues (quarter – 6.5%, nine months – 4.6%); and

	•		Higher revenues from synthetic fuel plants (quarter — $10.4 million; nine months - $29.3 million) in the current period as customers had idled those plants in the prior year’s third quarter.

The increases in volumes and prices discussed above were partially offset in the quarter and nine month periods by the following:

•

Continued shift towards trading contracts versus brokerage contracts in our Trading and Brokerage operations. Trading and Brokerage operations’ sales decreased in the quarter and nine months as the amount of brokerage business was reduced and replacement business was in the form of traded contracts. Contracts for trading activity are recorded at net margin in other revenues, whereas contracts for brokerage activity are recorded at gross sales price to revenues and operating costs. While the shift to trading contracts reduced total sales, there was no impact to Adjusted EBITDA. Higher trading gains resulted from increased international volumes and

			favorable international pricing (quarter — $7.1 million; nine months — $22.4 million) and a $16.2 million benefit from monetization of in-the-money contracts with third-party coal producers in the first half of year partially offset the revenue impact of our shift toward traded contracts;

	•		Lower volumes in the first nine months in Eastern U.S Mining operations related to geology issues, partially offset in the third quarter by stronger seaborne thermal market U.S. exports;

	•		Lower average sales prices in our Australian Mining operations related to lower metallurgical contract pricing (quarter — 24%; nine months — 21%) (the seaborne market fiscal year began April 1) and a significant change in sales mix resulting in higher thermal export and domestic product sales; and

	•		Volumes were unfavorably impacted at some of our Australian Mining operations as a result of damaged rails and further amplified port and rail congestion throughout the nine months, in addition to adverse weather events in the second quarter that affected production (excluding the impact of recently acquired mines).

Segment Adjusted EBITDA


					Increase (Decrease)										Increase (Decrease)
	Three Months Ended				to Segment						Nine Months Ended				to Segment
	September 30,				Adjusted EBITDA						September 30,				Adjusted EBITDA
	2007		2006		$			%			2007		2006		$			%
	(Dollars in millions)										(Dollars in millions)
Western U.S. Mining Operations	$	148.4	$	112.6	$	35.8			31.8	%	$	425.0	$	340.4	$	84.6			24.9	%
Eastern U.S. Mining Operations		85.3		68.4		16.9			24.7	%		238.8		309.0		(70.2	)		(22.7	)%
Australian Mining Operations		11.0		75.2		(64.2	)		(85.4	)%		115.5		188.9		(73.4	)		(38.9	)%
Trading and Brokerage Operations		19.5		39.3		(19.8	)		(50.4	)%		82.9		76.7		6.2			8.1	%

Total Segment Adjusted EBITDA	$	264.2	$	295.5	$	(31.3	)		(10.6	)%	$	862.2	$	915.0	$	(52.8	)		(5.8	)%

Adjusted EBITDA from our Western U.S. Mining operations increased during the third quarter and nine months primarily related to an overall increase in average sales prices from our Powder River Basin operations, including a 29% increase in prices for our premium Powder River Basin product. Partially offsetting higher average sales prices were higher costs associated with equipment repairs and maintenance and higher add-on taxes and royalties driven by higher sales prices, for both periods presented, and adverse weather conditions and capital project delays in the first half of the year.

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

Our Australian Mining operations’ Adjusted EBITDA decreased during the third quarter and nine months compared to the prior year primarily due to lower pricing on metallurgical coal contracts; rail and port congestion at Dalrymple Bay Coal Terminal and the Port of Newcastle; higher congestion-related demurrage costs (quarter — $24.3 million; nine months — $46.9 million); and approximately $30 million of higher costs resulting from the weakening U.S. dollar (losses of approximately $86 million were offset by hedging gains of about $56 million). Dalrymple Bay Coal Terminal has been experiencing queues of over 34 vessels (approximately a 23-day queue) down from 50 vessels in the second quarter (approximately a 34-day queue). Partially offsetting these decreases were contributions from our newly acquired mines for both periods presented and a $6.3 million insurance recovery on a business interruption claim in the first half of 2007. Our newly acquired mines experienced shipping difficulties and damaged rail lines resulting from a storm late in the second quarter. The Port of Newcastle was closed for several days in June due to a storm, with up to 79 vessels in the queue (a 35 — 40 day queue). Queues at Newcastle have recently been reduced to 38 vessels (16-day queue).

Trading and Brokerage operations’ Adjusted EBITDA decreased during the third quarter and increased during the nine months. During the three and nine months ended September 30, 2006, we recognized proceeds of $24.3 million and $35.8 million, respectively related to the settlement of commitments by a third-party coal producer. Higher international trading gains, resulting from higher volumes and pricing due to strong supply/demand fundamentals and tightened seaborne market conditions, more than matched the settlement gains of the prior year through the first half of 2007, but not during the third quarter.

Income Before Income Taxes and Minority Interests


	Three Months Ended						Increase (Decrease)						Nine Months Ended						Increase (Decrease)
	September 30,						to Income						September 30,						to Income
	2007			2006			$			%			2007			2006			$			%
	(Dollars in millions)												(Dollars in millions)
Total Segment Adjusted EBITDA	$	264.2		$	295.5		$	(31.3	)		(10.6	)%	$	862.2		$	915.0		$	(52.8	)		(5.8	)%
Corporate and Other Adjusted EBITDA		(53.3	)		(24.8	)		(28.5	)		(114.9	)%		(77.1	)		(106.0	)		28.9			27.3	%
Depreciation, depletion and amortization		(113.1	)		(90.6	)		(22.5	)		(24.8	)%		(324.5	)		(263.2	)		(61.3	)		(23.3	)%
Asset retirement obligation expense		(8.7	)		(7.1	)		(1.6	)		(22.5	)%		(27.6	)		(25.9	)		(1.7	)		(6.6	)%
Interest expense		(58.9	)		(26.4	)		(32.5	)		(123.1	)%		(176.7	)		(79.1	)		(97.6	)		(123.4	)%
Interest income		5.0			1.9			3.1			163.2	%		14.0			6.0			8.0			133.3	%

Income before income taxes and minority interests	$	35.2		$	148.5		$	(113.3	)		(76.3	)%	$	270.3		$	446.8		$	(176.5	)		(39.5	)%

Income before income taxes and minority interests for the three and nine months ended September 30, 2007 was lower than the prior year primarily due to higher net expense in Corporate and Other Adjusted EBITDA, higher interest expense and higher depreciation, depletion and amortization.

Corporate and Other Adjusted EBITDA results includes selling and administrative expenses, equity income from our joint ventures, net gains on disposal or exchange of assets, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development, Btu conversion and resource management. Our Corporate and Other Adjusted EBITDA decreased for the three months ended September 30, 2007 and increased for the nine months ended September 30, 2007. The primary reasons for the change in these periods included the following:

•

Lower net gains on disposals or exchanges of assets of $11.4 million for the quarter and higher net gains on disposals or exchanges of assets of $64.7 million for the nine months. Activity for the third quarter and nine months included a gain of $17.8 million on the sale of approximately 172 million tons of coal reserves to the Prairie State equity partners. Our 2007 activity also included a gain of $50.5 million on the exchange of our coalbed methane and oil and gas rights in the Illinois Basin, West Virginia, New Mexico and the Powder River Basin for high-Btu coal reserves located in West Virginia and Kentucky and cash proceeds. In addition, for the nine months ended September 30, 2007, we had gains totaling $78.5 million from sales of non-strategic coal reserves and surface lands located in Kentucky. Net gains on disposals or exchanges of assets in the prior year included a $39.2 million gain on exchange of coal reserves in June 2006 and a $30.0 million gain on sale of non-strategic coal reserves and surface lands located in Kentucky and West Virginia in September 2006 (see Note 5 to our unaudited condensed consolidated financial statements);

	•		Higher cost reimbursement and partner fees for the Prairie State Energy Campus project, including retroactive reimbursements, primarily related to the entrance of new project partners (quarter — $9.0 million; nine months — $22.1 million);

	•		Lower equity income (quarter — $1.8 million; nine months — $7.8 million) from our 25.5% interest in Carbones del Guasare (owner and operator of the Paso Diablo Mine in Venezuela), which primarily resulted from trucking issues experienced earlier in the year, a temporary shortage of explosives, and delays in receiving equipment, which impacted operations;

	•		Higher past mining obligation expenses (quarter — $12.6 million; nine months — $33.1 million) resulting from increased healthcare costs and additional multiemployer pension and retiree healthcare funding in accordance with 2006 legislation and requirements under the 2007 National Bituminous Coal Wage Agreement; and

	•		Higher selling and administrative expenses during the quarter and year to date periods resulted from the implementation of a new enterprise resource planning system and other corporate development initiatives.

Depreciation, depletion and amortization increased (quarter — $22.5 million; nine months - $61.3 million) primarily related to the addition of recently acquired Australian operations.

Interest expense increased (quarter — $32.5 million; nine months — $97.6 million) primarily due to approximately $1.7 billion in new debt issued in the second half of 2006 to finance the acquisition of Excel.

Net Income


	Three Months Ended						Increase (Decrease)						Nine Months Ended						Increase (Decrease)
	September 30,						to Income						September 30,						to Income
	2007			2006			$			%			2007			2006			$			%
	(Dollars in millions)												(Dollars in millions)
Income before income taxes and minority interests	$	35.2		$	148.5		$	(113.3	)		(76.3	)%	$	270.3		$	446.8		$	(176.5	)		(39.5	)%
Income tax provision		(5.9	)		(2.7	)		(3.2	)		(118.5	)%		(37.7	)		(10.9	)		(26.8	)		(245.9	)%
Minority interests		3.0			(3.8	)		6.8			178.9	%		(4.1	)		(10.2	)		6.1			59.8	%

Net income	$	32.3		$	142.0		$	(109.7	)		(77.3	)%	$	228.5		$	425.7		$	(197.2	)		(46.3	)

Net income decreased during the three and nine months ended September 30, 2007 compared to the prior year due to the decrease in income before income taxes discussed above, a higher income tax provision and an increase in minority interests. The income tax provision was higher for the quarter and nine months primarily due to a prior year reduction in tax reserves totaling $35.3 million related to the favorable finalization of former parent companies’ federal tax audits. Minority interests increased primarily from the absorption of losses in excess of the minority interest capital contribution at one of our mines, partially offset by lower earnings allocable to partners.

Outlook

Events Impacting Near-Term Operations

On October 10, 2007, our Board of Directors approved a spin-off of portions of our Eastern U.S. Mining operations business segment, including coal assets and operations in West Virginia and Kentucky. The spin-off was accomplished on October 31, 2007 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). Prior to the spin-off, we received necessary regulatory approvals including a favorable private letter ruling on the tax-free nature of the transaction from the Internal Revenue Service, and a declaration of effectiveness for Patriot’s registration statement on Form 10 with the SEC. Distribution of the Patriot stock to our stockholders occurred on October 31, 2007, at a ratio of one share of Patriot stock for every 10 shares of our stock held on the record date of October 22, 2007. We estimate an after-tax charge of $150 million will be incurred in conjunction with the distribution. Our end-of-year results will reflect Patriot as a discontinued operation. Refer to our current report on Form 8-K filed with the SEC on November 6, 2007 for additional details.

Global coal markets continued to reflect high demand and pricing, with prices strengthening in the international and domestic markets in early 2007. China’s economy grew 11.5% year-over-year through September 30, 2007 as published by the National Bureau of Statistics of China, while the U.S. economy increased at an annual rate of 3.9% during the same period based on latest reports by the U.S. Commerce Department.

Operationally, we experienced improved performance in the U.S., ongoing coal chain issues and a weakening U.S. dollar in Australia, and lower realized metallurgical coal prices for the current year. We anticipate our Australian Mining operations will continue to be impacted by higher costs due to demurrage. The port congestion and significant queuing of

vessels at Dalrymple Bay Coal Terminal and the Port of Newcastle has improved more than 35% and approximately 49%, respectively, since the end of the second quarter yet remain above targeted levels. Through third quarter, congestion at these coal export terminals led to mandatory reductions of throughput entitlements for coal shippers, ranging from 17-27% for 2007. In the U.S., the coal market is working through higher-than-average customer stockpiles, with coal demand estimated to increase approximately 2% in 2007 and production expected to decrease 2.7%. Excluding the effect of the Patriot spin-off, we expect full year 2007 sales targets of 235 to 245 million tons and production targets of 215 to 220 million tons. Excluding the effect of the Patriot spin-off, we have 15 to 20 million tons of planned U.S. production remaining unpriced for 2008 and 80 to 90 million tons unpriced for 2009. We have 11 to 13 million tons of Australian coal production available for pricing in 2008, more than half of which is metallurgical coal. We have 17 to 20 million tons of Australian coal unpriced for 2009, approximately half of which is metallurgical coal.

The majority of our United Mine Workers of America (UMWA)-represented eastern workforce operated under a five-year labor agreement expiring December 31, 2011. This contract replaced a contract that had expired on December 31, 2006 and mirrors the 2007 National Bituminous Coal Wage Agreement. The UMWA-represented workforce at our Highland underground mine operated under a separate, recently signed contract expiring on December 31, 2011. As a result of the spin-off of Patriot, our subsidiaries are no longer a signatory to these agreements. The impact of these new labor agreements resulted in higher wage, pension, and retiree healthcare costs of approximately $27 million for 2007.

In April 2007, a new labor agreement was ratified for our hourly workforce at the Willow Lake underground mine, which is represented by the International Brotherhood of Boilermakers. The new four-year labor agreement expires on April 15, 2011. The UMWA-represented workforce at our Arizona mine operates under a recently signed, six-year labor agreement expiring September 2, 2013. The Construction Forestry Mining and Energy Union-represented workforce at one of our underground Australian mines operates under a recently signed, three-year labor agreement. The impact of these new labor agreements will result in higher wage, pension, and retiree healthcare costs of approximately $30 million. New labor agreements are being negotiated at two of our Australian mines.

Long-term Outlook

Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide as long as growth continues in the U.S., Asia and other undeveloped economies that are increasing demand for electricity generation and steelmaking. We estimate that more than 115 gigawatts of new coal-fueled electricity generating capacity is under construction around the world. In the United States, we have identified a growing number of coal plants that are new, under construction or in late-stage development. Eleven coal units have begun construction in 2007. A total of 45 units are new, under construction or in late-stage development in 21 states, representing 23,900 MW of capacity and 100 million tons of annual coal use.

Coal prices continue to strengthen. Internationally, Australian thermal coal prices have increased during 2007, recently exceeding $80 per metric tonne for spot sales of seaborne shipments. The spot prices for metallurgical coal have also increased recently in 2007, suggesting higher 2008 contract pricing. Both China and India increased net imports of coal in 2007 to satisfy growth in electricity generation and steel production. Russia is predicting a decline in its coal exports due to continued domestic demand. We expect to capitalize on the strong global market for metallurgical and thermal coal from sales of our Australian production. Also, in response to growing international markets, we established an international trading group in 2006 and added a trading office in Europe in early 2007, which expands our trading activities to four continents. U.S. coal markets showed signs of strengthening, with 68% and 40% improvements in published prices for 2009 deliveries over prompt levels at the beginning of 2007 for reference Powder River Basin and Central Appalachian coal products, respectively.

By early 2008, we expect to have dramatically reshaped our global platform, with major enhancements to our flagship Powder River Basin operations, expansion in Australia, the completion of the Patriot spin-off and a larger global trading presence. Capital projects are targeted for the expansion of our international platform in Australia, including the ramp-up of our Wilpinjong Mine, North Wambo Underground Mine and Millennium Mine. We are the second-largest shareholder in the Newcastle Coal Infrastructure Group (NCIG), which is in the early stages of development for a dedicated port facility. The port would provide Peabody with additional dedicated throughput of more than 5 million tons per year in the first phase over existing Newcastle throughput. We expect a final determination on whether to proceed with construction in the first half of 2008.

Demand for Powder River Basin coal remains strong, particularly for our ultra-low sulfur products. The Powder River Basin represents more than half of our production. We control approximately 3.5 billion tons of proven and probable reserves in the Southern Powder River Basin. Our major 2007 projects include the installation of a new dragline system at our North Antelope Rochelle Mine in the Powder River Basin, which is expected to reduce fuel usage and costs, the completion of a new in-pit conveyor system and progress on a new coal blending and loadout facility also at North Antelope Rochelle, which is expected to increase capacity and improve blending capabilities.

Coal-to-gas (CTG) and coal-to-liquids (CTL) plants represent an emerging opportunity for long-term industry growth. The EIA continues to project an increase in demand for unconventional sources of transportation fuel, including CTL. CTG and CTL facilities are being built and operated outside the United States as alternatives to high-priced conventional oil and gas.

Global climate change continues to attract considerable public and scientific attention. 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 through our participation in the Power Systems Development Facility, the PowerTree Carbon Company LLC, and the Asia-Pacific Partnership.

As noted in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, considerable and increasing government attention in the United States and other countries is being paid to global climate change and to reducing greenhouse gas emissions, including emissions from coal-fired power plants. During 2007, additional legislation to reduce greenhouse gas emissions has been proposed in Congress. Passage of regulations regarding greenhouse gas emissions or other actions to limit carbon dioxide emissions could result in fuel switching, from coal to other fuel sources, by electric generators.

Management continues to focus on cost control and operating performance to mitigate external cost pressures, geologic conditions and potentially adverse port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel, tires, contract mining, labor and healthcare, and have taken measures to mitigate the increases in these costs, including a company-wide initiative to instill best practices at all operations. In addition, low long-term interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. In spite of our efforts to manage controllable costs, we expect a year-over-year increase in these costs. We may also encounter poor geologic conditions, lower third-party contract miner or brokerage source performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See “Cautionary Notice Regarding Forward-Looking Statements” and Item 1A. Risk Factors in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 and this Quarterly Report on Form 10-Q for additional cautionary factors regarding our outlook.

Liquidity and Capital Resources

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

Net cash provided by operating activities for the nine months ended September 30, 2007 increased $59.0 million compared to the prior year primarily related to higher usage of our accounts receivable securitization program of $55.8 million during 2007.

Net cash used in investing activities decreased $288.1 million for the nine months ended September 30, 2007 compared to the prior year. The decrease related to higher proceeds of $84.3 million from disposals and exchanges of assets, net of notes receivable, and activities in 2006 that included the 19.99% investment in Excel for $307.8 million and the acquisition of an additional interest in a joint venture for $44.5 million. Partially offsetting these items were higher capital spending of $136.4 million in 2007 and an additional $13.2 million investment to acquire a larger share of a majority-owned joint venture in 2007, an increase over prior year of $12.3 million. Capital expenditures in 2007 included mine development at our recently acquired Australian mines, the completion of an in–pit conveyor system, progress on a coal blending and loadout facility at one of our Western mines and the purchase of coal reserves and surface lands in the Illinois Basin.

Net cash used for financing activities increased $271.5 million compared to the prior year. The increase primarily related to changes within our long-term debt including borrowings for the initial 19.99% acquisition of Excel. In September 2006, we entered into a $2.75 billion Senior Unsecured Credit Facility, which consisted of a $1.8 billion Revolving Credit Facility and a $950.0 million Term Loan Facility. In September 2006, we borrowed $312.0 million under the Revolving Credit Facility. In 2007, we repaid $112.3 million of debt that included a $60.0 million retirement of our 5.0% Subordinated Note; a $31.5 million repayment on the outstanding balance of our Term Loan under the Senior Unsecured Credit Facility; a $13.8 million open-market purchase of 5.875% Senior Notes; and capital lease payments totaling $7.0 million. Also contributing to the increase in net cash used in financing activities were lower tax benefit related to stock option exercises in 2007. Partially offsetting these items were payments for common stock repurchases of $99.8 million in the prior year.

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


	September 30,			December 31,
	2007			2006
	(Dollars in thousands)
Term Loan under Senior Unsecured Credit Facility	$	515,529		$	547,000
Convertible Junior Subordinated Debentures due 2066		732,500			732,500
7.375% Senior Notes due 2016		650,000			650,000
6.875% Senior Notes due 2013		650,000			650,000
7.875% Senior Notes due 2026		246,947			246,897
5.875% Senior Notes due 2016		218,090			231,845
5.0% Subordinated Note		—			59,504
Revolving Line of Credit		25,000			—
6.84% Series C Bonds due 2016		43,000			43,000
6.34% Series B Bonds due 2014		21,000			21,000
6.84% Series A Bonds due 2014		10,000			10,000
Capital lease obligations		95,076			96,869
Fair value of interest rate swaps		(11,445	)		(13,784	)
Other		20,444			22,918


Total	$	3,216,141		$	3,297,749

As of September 30, 2007, the Revolving Credit Facility’s remaining available borrowing capacity under the Senior Unsecured Credit Facility was $1.35 billion.

Interest Rate Swaps

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

During the nine months ended September 30, 2007, we entered into several fixed-to-floating interest rate swaps. The first group of three interest rate swaps had combined notional amounts totaling $200.0 million and was designated to hedge changes in fair value of the 6.875% Senior Notes due 2013. Under the swaps, we pay a floating rate that resets each March 15 and September 15 based upon the six-month LIBOR rate for a period of six years ending March 15, 2013 and receives a fixed rate of 6.875%. The second group of two interest rate swaps had combined notional amounts totaling $100.0 million and was designated to hedge changes in fair value of the 5.875% Senior Notes due 2016. Under the swaps, we pay a floating rate that resets each April 15 and October 15 based upon the six-month LIBOR rate for a period of nine years ending April 15, 2016 and receives a fixed rate of 5.875%.

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

Currency Position

We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. The asset value of our currency hedge portfolio was $164.9 million and $64.1 million as of September 30, 2007 and December 31, 2006, respectively. The value of our currency hedge portfolio has increased during the nine months ended September 30, 2007 as a result of additional hedge positions purchased during the year, net of settlements, and due to an increase of $0.09 in the U.S. dollar rate required to purchase an Australian dollar during the year. As of September 30, 2007, we have hedged 86.9% of our remaining estimated Australian dollar requirements for 2007 and 78.4% of estimated 2008 requirements at average rates no greater than US$0.8013/A$ and US$0.7881/A$, respectively.

Contractual Obligations

We do not expect any of the $138 million of unrecognized tax benefits reported in our condensed consolidated financial statements to require cash settlement within the next year. Beyond that, we are unable to make reasonably reliable estimates of periodic cash settlements with respect to such unrecognized tax benefits.

As of September 30, 2007, we had $92.3 million of purchase obligations for capital expenditures and $302.3 million of obligations related to federal coal reserve lease payments due over the next three years. Total capital expenditures for 2007 are now expected to range from $500 to $550 million, excluding capital projects associated with the Patriot spin-off, the Prairie State Energy Campus project and federal coal reserve lease payments. Contractor escalations, materials, currency impact and project delays in Australia and the Powder River Basin have led to higher capital costs. Additionally, we added a new preparation plant project at one of our Western mines to improve coal quality and purchased coal reserves and surface lands in the Illinois Basin. Capital expenditures relate to replacement, improvement, or expansion of existing mines and growth initiatives. Capital expenditures were funded through operating cash flow.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, indemnifications, financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds and our accounts receivable securitization. Liabilities related to these arrangements are not reflected in our condensed consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

Our wholly-owned subsidiary, Prairie State Generating Company, LLC (PSGC), had previously entered into a cost reimbursable Target Price Engineering, Procurement and Construction Agreement (Agreement) with Bechtel Power Corporation (Bechtel) related to the Prairie State mine mouth pulverized coal-fired generating facility. We provided an absolute and unconditional payment guarantee of all amounts due until financial closing by PSGC to Bechtel under the Agreement (Initial Owner Guarantee). On September 28, 2007, PSGC gave Bechtel notice to proceed to full scale construction of the facility. On that date, our ownership interest in PSGC was transferred to an Indiana non-profit corporation that is owned and controlled by a group of owners (Owners), including two of our affiliates. Contemporaneously with the transfer of PSGC’s membership interests, each Owner (including our affiliates) issued a guarantee to Bechtel for its proportionate share of PSGC’s obligations under the Agreement and we issued a guarantee to Bechtel for our two affiliates. The Initial Owner Guarantee was returned to us following the issuance of new guarantees by each Owner. Our affiliates own approximately 28% of PSGC and have a contract to sell about 23% of PSGC or an equivalent amount of power to a third-party which is expected to close within six months and would reduce our ownership to 5.06%. We currently expect that reimbursements from partners will substantially offset 2007 project expenditures.

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

There were no other material changes to our off-balance sheet arrangements during the nine months ended September 30, 2007. See Note 12 to our unaudited condensed consolidated financial statements included in this report for a discussion of our guarantees. Our off-balance sheet arrangements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006.

Newly Adopted Accounting Pronouncements

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

We adopted the provisions of FIN No. 48 on January 1, 2007 with no impact to retained earnings. At adoption, we had $135 million of unrecognized tax benefits in our condensed consolidated financial statements, and an additional $3 million has been added since January 1, 2007 resulting from tax positions taken during the current year. We do not expect significant increases or decreases to our unrecognized tax benefits within 12 months of this reporting date that would affect our effective tax rate, if recognized.

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

The potential for changes in the market value of our coal trading, interest rate and currency portfolios is referred to as “market risk.” Market risk related to our coal trading portfolio is evaluated using a value at risk analysis (described below). Value at risk analysis is not used to evaluate our non-trading interest rate and currency portfolios. A description of each market risk category is set forth below. We attempt to manage market risks through diversification, controlling position sizes and executing hedging strategies. Due to lack of quoted market prices and the long term, illiquid nature of the positions, we have not quantified market risk related to our non-trading, long-term coal supply agreement portfolio.

Coal Trading Activities and Related Commodity Price Risk

We engage in over-the-counter and direct trading of coal. These activities give rise to commodity price risk, which represents the potential loss that can be caused by an adverse change in the market value of a particular commitment. We actively measure, monitor and adjust traded position levels to remain within risk limits prescribed by management. For example, we have policies in place that limit the amount of total exposure, in value at risk terms, which we may assume at any point in time.

We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, options and swaps, at market value in our condensed consolidated financial statements. Our trading portfolio included forwards and swaps as of September 30, 2007 and December 31, 2006.

We perform a value at risk analysis on our coal trading portfolio, which includes over-the-counter and brokerage trading of coal. The use of value at risk allows us to quantify in dollars, on a daily basis, the price risk inherent in our trading portfolio. Value at risk represents the potential loss in value of our mark-to-market portfolio due to adverse market movements over a defined time horizon (liquidation period) within a specified confidence level. Our value at risk model is based on the industry standard variance/co-variance approach. This captures our exposure related to both option and forward positions. Our value at risk model assumes a 5 to 15-day holding period and a 95% one-tailed confidence interval. This means that there is a one in 20 statistical chance that the portfolio would lose more than the value at risk estimates during the liquidation period.

The use of value at risk allows management to aggregate pricing risks across products in the portfolio, compare risk on a consistent basis and identify the drivers of risk. Due to the subjectivity in the choice of the liquidation period, reliance on historical data to calibrate the models and the inherent limitations in the value at risk methodology, we perform regular stress and scenario analysis to estimate the impacts of market changes on the value of the portfolio. Additionally, back-testing is regularly performed to monitor the effectiveness of our value at risk measure. The results of these analyses are used to supplement the value at risk methodology and identify additional market-related risks.

We use historical data to estimate our value at risk and to better reflect current asset and liability volatilities. Given our reliance on historical data, we believe value at risk is effective in estimating risk exposures in markets in which there are not sudden fundamental changes or shifts in market conditions. An inherent limitation of value at risk is that past changes in market risk factors may not produce accurate predictions of future market risk. Value at risk should be evaluated in light of this limitation.

During the nine months ended September 30, 2007, the actual low, high, and average values at risk for our coal trading portfolio were as follows:


	Domestic		International
	(Dollars in thousands)
Low	$	741	$	496
High		3,541		6,380
Average		1,927		3,724

As of September 30, 2007, the timing of the estimated future realization of the value of our trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2007		22	%
2008		41	%
2009		31	%
2010		5	%
2011		1	%

		100	%

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

Credit Risk

Our concentration of credit risk is substantially with electric utilities, energy marketers and industrial customers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor the credit extended. In the event that we engage in a transaction with a counterparty that does not meet our credit standards, we will protect our position by requiring the counterparty to provide appropriate credit enhancement. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers or counterparties whose credit has deteriorated and who may pose a higher risk of failure to perform under their contractual obligations. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or other similar instruments. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into agreements with counterparties that permit us to offset receivables and payables with such counterparties. Counterparty risk with respect to interest rate swap and foreign currency forwards and options transactions is not considered to be significant based upon the creditworthiness of the participating financial institutions.

Foreign Currency Risk

We utilize currency forwards and options to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2007 targets hedging approximately 70% of our anticipated Australian dollar-denominated operating expenditures. As of September 30, 2007, we had in place hedge instruments designated as cash flow hedges with notional amounts outstanding totaling A$1.83 billion of which A$284.3 million, A$1.08 billion, A$436.7 million and A$28.8 million will expire in 2007, 2008, 2009, and 2010, respectively. Our expectation for our remaining 2007 Australian dollar-denominated operating cash expenditures is approximately A$327.0 million. Our exposure in our “Operating costs and expenses”, assuming we had no hedges in place, due to a $0.01 change in the Australian dollar/U.S. dollar exchange rate is approximately $14 million for 2008. However, taking into consideration hedges currently in place, our net exposure to the same rate change is about $3.0 million in 2008.

Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed-rate debt as a percent of net debt through the use of various hedging instruments, which are discussed in Note 7 to our condensed consolidated financial statements. As of September 30, 2007, after taking into consideration the effects of interest rate swaps, we had $2.27 billion of fixed-rate borrowings and $941.6 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $9.4 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 $0.2 million decrease in the estimated fair value of these borrowings.

Other Non-trading Activities

We manage our commodity price risk for our non-trading, long-term coal contract portfolio through the use of long-term coal supply agreements, rather than through the use of derivative instruments. We sold 90% of our sales volume under long-term coal supply agreements during 2006.

Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage this risk, we use a combination of forward contracts with our suppliers and financial derivative contracts, primarily swap contracts with financial institutions. As of September 30, 2007, we had derivative contracts outstanding that are designated as hedges of anticipated purchases of fuel and explosives.

Notional amounts outstanding under fuel-related, derivative swap contracts were 100.1 million gallons of crude oil scheduled to expire through 2010 and 4.5 million gallons of heating oil scheduled to expire through 2007. At September 30, 2007, we had outstanding option contracts designated as a collar of crude oil prices with notional amounts of 10.4 million gallons, expiring through 2007. We expect to consume 100 to 105 million gallons of fuel per year. On a per gallon basis, based on this usage, a change in fuel prices of one cent per gallon (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of approximately $1 million per year. Alternatively, a one dollar per barrel change in the price of crude oil would increase or decrease our annual fuel costs (ignoring the effects of hedging) by approximately $2.4 million.

Notional amounts outstanding under explosives-related swap contracts, scheduled to expire through 2010, were 6.5 mmbtu of natural gas. We expect to consume 315,000 to 325,000 tons of explosives per year. Through our natural gas hedge contracts, we have fixed prices for approximately 47% of our anticipated explosives requirements for the remainder of 2007. Based on our expected usage, a change in natural gas prices of ten cents per mmbtu (ignoring the effects of hedging) would result in an increase or decrease in our operating costs of approximately $0.6 million per year.

Item 4. Controls and Procedures.

Our disclosure controls and procedures are designed to, among other things, provide reasonable assurance that material information, both financial and non-financial, and other information required under the securities laws to be disclosed is accumulated and communicated to senior management, including the Chief Executive Officer and Chief Financial Officer, on a timely basis. Under the direction of the Chief Executive Officer and Chief Financial Officer, management has evaluated our disclosure controls and procedures as of September 30, 2007 and has concluded that the disclosure controls and procedures were adequate and effective as of such date.

In August 2007, we implemented SAP, a new enterprise resource planning system, for our domestic operations. As a result, we have updated our internal controls as necessary to accommodate the modifications to our business processes and accounting procedures. There have not been any other significant changes in our internal controls over financial reporting during the most recent quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 11 to the unaudited condensed consolidated financial statements included in Part I. Item 1 of this report relating to certain legal proceedings, which information is incorporated by reference herein.

Item 1A. Risk Factors.

The risk factors listed below should be read in conjunction with the risk factors outlined in Part I, Item 1A of our 2006 Annual Report on Form 10-K.

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

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

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

In July 2005, our Board of Directors authorized a share repurchase program of up to 5% of the then outstanding shares of our common stock, approximately 13.1 million shares. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. As of September 30, 2007, there were 10.9 million shares available for repurchase. There were no share repurchases during the three months ended September 30, 2007 under the share repurchase program.

Item 6. Exhibits.

See Exhibit Index on page 40 of this report.

EXHIBIT INDEX

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


Exhibit
No.		Description of Exhibit

3.1		Third Amended and Restated Certificate of Incorporation of the Registrant, as amended (Incorporated by reference to Exhibit 3.1 of the Registrant’s Quarterly Report on Form 10-Q for the period ended June 30, 2006, filed on August 7, 2006).

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

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

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

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

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


*		Filed herewith.


	PEABODY ENERGY CORPORATION
Date: November 9, 2007	By:	/s/ RICHARD A. NAVARRE
		Richard A. Navarre
		Chief Financial Officer and Executive Vice President of Corporate Development (On behalf of the registrant and as Principal Financial Officer)


	Page
PART I – FINANCIAL INFORMATION

Item 1. Financial Statements.

Unaudited Condensed Consolidated Statement of Earnings for the Three and Nine Months Ended September 30, 2007 and 2006		1

Condensed Consolidated Balance Sheet as of September 30, 2007 (unaudited) and December 31, 2006		2

Unaudited Condensed Consolidated Statement of Cash Flows for the Nine Months Ended September 30, 2007 and 2006		3

Notes to Unaudited Condensed Consolidated Financial Statements		4

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 3. Quantitative and Qualitative Disclosures About Market Risk		35

Item 4. Controls and Procedures		37

PART II – OTHER INFORMATION

Item 1. Legal Proceedings		38

Item 1A. Risk Factors		38

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

Item 6. Exhibits		38

SIGNATURE

EXHIBIT INDEX
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906