UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2006

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

For the transition period from                                          to                                         

Commission File Number: 1-16463

PEABODY ENERGY CORPORATION

Exact name of registrant as specified in its charter)

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

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

(Registrant’s telephone number, including area code)

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

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

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

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

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

There were 264,734,471 shares of common stock with a par value of $0.01 per share outstanding at April 28, 2006.

 

 

INDEX

		Page
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Unaudited Condensed Consolidated Income Statements for the Quarters Ended March 31, 2006 and 2005			2
Condensed Consolidated Balance Sheets as of March 31, 2006 (unaudited) and December 31, 2005			3
Unaudited Condensed Consolidated Statements of Cash Flows for the Quarters Ended March 31, 2006 and 2005			4
Notes to Unaudited Condensed Consolidated Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
Item 3. Quantitative and Qualitative Disclosures About Market Risk			32
Item 4. Controls and Procedures			34
PART II. OTHER INFORMATION
Item 1. Legal Proceedings			34
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			35
Item 6. Exhibits			35
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of EVP/CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to 18 U.S.C. Section 1350
Certification of EVP/CFO Pursuant to 18 U.S.C. Section 1350

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

		Quarter Ended March 31,
		2006				2005
REVENUES
Sales		$	1,288,906			$	1,062,521
Other revenues			22,904				14,959
Total revenues			1,311,810				1,077,480
COSTS AND EXPENSES
Operating costs and expenses			1,022,342				912,979
Depreciation, depletion and amortization			80,964				75,953
Asset retirement obligation expense			7,215				9,195
Selling and administrative expenses			46,526				37,760
Other operating income:
Net gain on disposal of assets			(9,226	)			(31,122	)
Income from equity affiliates			(7,252	)			(8,088	)
OPERATING PROFIT			171,241				80,803
Interest expense			27,400				25,556
Interest income			(2,606	)			(1,373	)
INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS			146,447				56,620
Income tax provision			11,566				4,424
Minority interests			4,659				306
NET INCOME		$	130,222			$	51,890
EARNINGS PER SHARE:
Basic		$	0.49			$	0.20
Diluted		$	0.48			$	0.19
WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic			263,491,072				260,693,518
Diluted			269,358,728				266,801,306
DIVIDENDS DECLARED PER SHARE		$	0.06			$	0.0375

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

		(Unaudited)
		March 31, 2006				December 31, 2005
ASSETS
Current assets
Cash and cash equivalents		$	350,160			$	503,278
Accounts receivable, net of allowance for doubtful accounts of $10,855 at March 31, 2006 and $10,853 at December 31, 2005			238,867				221,541
Inventories			175,049				389,771
Assets from coal trading activities			77,638				146,596
Deferred income taxes			9,027				9,027
Other current assets			75,167				54,431
Total current assets			925,908				1,324,644
Property, plant, equipment and mine development, net of accumulated depreciation, depletion and amortization of $1,745,883 at March 31, 2006 and $1,627,856 at December 31, 2005			5,385,171				5,177,708
Investments and other assets			316,294				349,654
Total assets		$	6,627,373			$	6,852,006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt		$	77,906			$	22,585
Liabilities from coal trading activities			63,655				132,373
Accounts payable and accrued expenses			792,409				867,965
Total current liabilities			933,970				1,022,923
Long-term debt, less current maturities			1,332,526				1,382,921
Deferred income taxes			231,669				338,488
Asset retirement obligations			402,361				399,203
Workers’ compensation obligations			238,434				237,574
Accrued postretirement benefit costs			964,582				959,222
Other noncurrent liabilities			351,942				330,658
Total liabilities			4,455,484				4,670,989
Minority interests			12,793				2,550
Stockholders’ equity
Preferred Stock – $0.01 per share par value; 10,000,000 shares authorized, no shares issued or outstanding as of March 31, 2006 or December 31, 2005			—				—
Series Common Stock – $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of March 31, 2006 or December 31, 2005			—				—
Series A Junior Participating Preferred Stock - 1,500,000 shares authorized, no shares issued or outstanding as of March 31, 2006 or December 31, 2005			—				—
Common Stock – $0.01 per share par value; 400,000,000 shares authorized, 265,301,255 shares issued and 264,528,895 shares outstanding as of March 31, 2006 and 400,000,000 shares authorized, 263,879,762 shares issued and 263,357,402 shares outstanding as of December 31, 2005			2,650				2,638
Additional paid-in capital			1,523,662				1,497,454
Retained earnings			693,107				729,086
Accumulated other comprehensive loss			(44,931	)			(46,795	)
Treasury shares, at cost: 772,360 shares as of March 31, 2006 and 522,360 shares as of December 31, 2005			(15,392	)			(3,916	)
Total stockholders’ equity			2,159,096				2,178,467
Total liabilities and stockholders’ equity		$	6,627,373			$	6,852,006

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

		Quarter Ended March 31,
		2006				2005
Cash Flows from Operating Activities
Net income		$	130,222			$	51,890
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			80,964				75,953
Deferred income taxes			(12,864	)			1,252
Amortization of debt discount and debt issuance costs			1,815				1,795
Net gain on disposal of assets			(9,226	)			(31,122	)
Income from equity affiliates			(7,252	)			(8,088	)
Dividends received from equity affiliates			5,442				716
Stock compensation			4,102				404
Changes in current assets and liabilities, net of acquisitions:
Accounts receivable, net of sale			10,853				(18,680	)
Inventories			(29,918	)			(21,953	)
Net assets from coal trading activities			240				1,372
Other current assets			(15,708	)			(3,664	)
Accounts payable and accrued expenses			(97,991	)			37,800
Asset retirement obligations			22				1,534
Workers’ compensation obligations			860				1,933
Accrued postretirement benefit costs			5,360				3,874
Other, net			(17,869	)			2,911
Net cash provided by operating activities			49,052				97,927
Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development			(87,459	)			(46,950	)
Federal coal lease expenditures			(59,829	)			(63,540	)
Purchase of mining assets			—				(56,500	)
Additions to advance mining royalties			(2,250	)			(3,135	)
Acquisitions, net			(44,538	)			—
Proceeds from disposal of assets			11,488				47,731
Net cash used in investing activities			(182,588	)			(122,394	)
Cash Flows from Financing Activities
Payments of long-term debt			(12,906	)			(12,229	)
Common stock repurchase			(11,476	)			—
Dividends paid			(15,869	)			(9,772	)
Proceeds from stock options exercised			6,051				12,331
Tax benefit related to stock options exercised			13,096				—
Increase of securitized interests in accounts receivable			—				25,000
Distributions to minority interests			(1,000	)			(624	)
Proceeds from employee stock purchases			1,772				1,350
Proceeds from long-term debt			750				—
Net cash provided by (used in) financing activities			(19,582	)			16,056
Net decrease in cash and cash equivalents			(153,118	)			(8,411	)
Cash and cash equivalents at beginning of period			503,278				389,636
Cash and cash equivalents at end of period		$	350,160			$	381,225

See accompanying notes to unaudited condensed consolidated financial statements.

PEABODY ENERGY CORPORATION

(1) Basis of Presentation

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

     Effective February 22, 2006, the Company implemented a two-for-one stock split on all shares of its common stock. The Company had a similar two-for-one stock split on March 30, 2005. All share and per share amounts in these unaudited condensed consolidated financial statements and related notes reflect the stock splits.

     The accompanying condensed consolidated financial statements as of March 31, 2006 and for the quarters ended March 31, 2006 and 2005, 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, 2005 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the quarter ended March 31, 2006 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, 2006. Certain amounts in prior periods have been reclassified to conform with the report classifications of the quarter ended March 31, 2006, with no effect on previously reported net income or stockholders’ equity.

(2) Significant Transactions and Events

     During the first quarter of 2005, the Company sold its remaining 0.838 million Penn Virginia Resource Partners, L.P. (“PVR”) units for net proceeds of $41.9 million and recognized a $31.1 million gain on the sale. Also in the first quarter of 2005, the Company recorded contract losses of approximately $34 million, primarily related to breach of a coal supply contract by a producer. The contractual dispute was fully resolved in the third quarter of 2005.

(3) Inventories

     Inventories consisted of the following (dollars in thousands):

		March 31,				December 31,
		2006				2005
Saleable coal		$	88,652			$	64,274
Materials and supplies			73,476				65,942
Raw coal			12,921				14,033
Advance stripping			—				245,522
Total		$	175,049			$	389,771

     Advance stripping consisted of the costs to remove overburden above an unmined coal seam as part of the surface mining process. In March 2005, the Emerging Issues Task Force (“EITF”) issued EITF Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry” (“EITF Issue No. 04-6”). EITF Issue No. 04-6 and its interpretations require stripping costs incurred during a period to be attributed only to the inventory costs of the coal that is extracted during that same period. The Company adopted EITF Issue No. 04-6 on January 1, 2006 and utilized the cumulative effect adjustment approach whereby the cumulative effect adjustment reduced retained earnings by $150.3 million, net of tax. Advance stripping costs will no longer be included as a separate component of inventory.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(4) Assets and Liabilities from Coal Trading Activities

     The Company’s coal trading portfolio included forward contracts as of March 31, 2006 and December 31, 2005. The fair value of coal trading derivatives and related hedge contracts as of March 31, 2006 and December 31, 2005 is set forth below (dollars in thousands):

		March 31, 2006								December 31, 2005
		Assets				Liabilities				Assets				Liabilities
Forward contracts		$	77,638			$	61,917			$	146,596			$	131,988
Other			—				1,738				—				385
Total		$	77,638			$	63,655			$	146,596			$	132,373

     Ninety-eight percent of the contracts in the Company’s trading portfolio as of March 31, 2006 were valued utilizing prices from over-the-counter market sources, adjusted for coal quality and traded transportation differentials, and 2% of the Company’s contracts were valued based on similar market transactions.

     As of March 31, 2006, the estimated future realization of the value of the Company’s trading portfolio was as follows:

Year of		Percentage
Expiration		of Portfolio
2006			70	%
2007			18	%
2008			12	%
			100	%

     At March 31, 2006, 50% of the Company’s credit exposure related to coal trading activities was with investment grade counterparties and 50% was with non-investment grade counterparties, which were primarily other coal producers. The Company’s coal trading operations traded 10.7 million tons and 9.2 million tons for the quarters ended March 31, 2006 and 2005, respectively.

(5) Earnings Per Share and Stockholders’ Equity

Weighted Average Shares Outstanding

     A reconciliation of weighted average shares outstanding follows:

		Quarter Ended March 31,
		2006				2005
Weighted average shares outstanding — basic			263,491,072				260,693,518
Dilutive impact of stock options			5,867,656				6,107,788
Weighted average shares outstanding — diluted			269,358,728				266,801,306

Common Stock Repurchase

     In July 2005, the Company’s Board of Directors authorized a share repurchase program of up to 5% of the then outstanding shares of its common stock, which are approximately 13.1 million shares. The repurchases may be made from time to time based on an evaluation of the Company’s outlook and general business conditions, as well as alternative investment and debt repayment options. In March 2006, the Company repurchased 250,000 of its common shares at a cost of $11.5 million.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Adoption of SFAS No. 123 (revised 2004), “Share-Based Payment”

     On December 16, 2004, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard (“SFAS”) No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123(R)”), which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”). SFAS No. 123(R) supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB Opinion No. 25”) and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS No. 123(R) is similar to the approach described in SFAS No. 123. However, SFAS No. 123(R) requires all share-based payments to employees, including employee stock options, to be recognized ratably over the vesting period in the income statement based on their fair values at the grant date.

     The Company adopted SFAS No. 123(R) on January 1, 2006 and used the modified prospective method, in which compensation cost is recognized beginning with the effective date (a) based on the requirements of SFAS No. 123(R) for all share-based payments granted or modified after the effective date and (b) based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the effective date. Prior to January 1, 2006, the Company had elected to apply APB Opinion No. 25 and related interpretations in accounting for its stock option plans, as permitted under SFAS No. 123 and SFAS No. 148 “Accounting for Stock-Based Compensation-Transition and Disclosure”. Accordingly, no compensation cost was recognized for its stock option plans prior to December 31, 2005, as the exercise price was equal to the market price of the Company’s stock on the date of the option grants. Beginning in 2006, SFAS No. 123(R) also requires that income tax benefits from stock options exercised be recorded as financing cash inflow and corresponding operating cash outflow (included with deferred income tax activity) on the statements of cash flows. The income tax benefit from stock option exercises during 2005 is included in operating cash flows, netted in deferred tax activity.

     As part of its share-based compensation program, the Company utilizes restricted stock, nonqualified stock options, an employee stock purchase plan and performance units (discussed further below). The Company began utilizing restricted stock as part of its equity-based compensation strategy in January 2005. Accounting for restricted stock awards was not changed by the adoption of SFAS No. 123(R). The Company recognized $1.0 million and $0.2 million of expense, net of taxes, for the quarters ended March 31, 2006 and 2005, respectively, related to restricted stock. For share-based payment instruments excluding restricted stock, the Company recognized $6.5 million (or $0.02 per diluted share) and $3.0 million (or $0.01 per diluted share) of expense, net of taxes, for the quarters ended March 31, 2006 and 2005, respectively. Had the Company applied the provisions of APB Opinion No. 25 during the quarter ended March 31, 2006, it would have recognized $6.0 million (or $0.02 per diluted share) of expense, net of taxes. As a result, the adoption of SFAS No. 123(R) did not have a material impact on the results of operations of the Company during the quarter ended March 31, 2006. Share-based compensation expense is recorded in selling and administrative expenses in the condensed consolidated income statements. The Company used the Black-Scholes option pricing model to determine the fair value of stock options and employee stock purchase plan share-based payments made before and after the adoption of SFAS No. 123(R). As of March 31, 2006, the total unrecognized compensation cost related to nonvested awards was $30.8 million, net of taxes, which is expected to be recognized over 4.8 years with a weighted-average period of 1.5 years.

     Stock Options

     For all employee and director stock options granted since 2000, the options vest ratably over three years and expire after 10 years from the date of the grant, subject to earlier termination in the event of an employee’s termination of service. Option grants are typically made in January of each year. The Company granted 0.5 million options during the quarter ended March 31, 2006. The fair value of each option grant is estimated on the date of grant using the Black-Sholes option-pricing model with the following weighted-average assumptions used for grants in 2006 and 2005, respectively; dividend yield of 0.8% and 1.0%; expected volatility (based on historical volatility) of 36% and 40%; risk-free interest rate of 4.3% and 3.6%; and an expected life of 5.3 years and 5.7 years. The Company recognized $1.2 million of expense, net of taxes, for the quarter ended March 31, 2006, related to stock options.

     Employee Stock Purchase Plan

     During 2001, the Company adopted an employee stock purchase plan. Eligible full-time and part-time employees are able to contribute up to 15% of their base compensation into this plan, subject to a limit of $25,000 per year. Employees are able to purchase Company common stock at a 15% discount to the lower of the fair market value of the Company’s common stock on the initial or ending dates of each six-month offering period. Offering periods begin on January 1 and July 1 of each year. The fair value of the six-month “look-back” option in the Company’s employee stock purchase plan is estimated by adding the fair value of 0.15 of a share of stock to the fair value of 0.85 of an option on a share of stock. The Company recognized $0.3 million of expense, net of taxes, for the quarter ended March 31, 2006, related to its employee stock purchase plan.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

     Performance Units

     Performance units, which are typically granted annually in January by the Company, vest over a three year measurement period, subject to the achievement of performance goals and stock price performance at the conclusion of the three years. Three performance unit grants were outstanding during 2005 (the 2003, 2004 and 2005 grants) and 2006 (the 2004, 2005 and 2006 grants). The payout related to the 2003 grant (which was settled in cash in February 2006) was based on the Company’s stock price performance compared to both an industry peer group and an S&P Index. The payouts related to the 2004 grant (which will be settled in cash in February 2007) and 2005 and 2006 grants (which will be settled in common stock in 2008 and 2009, respectively) are based 50% on stock price performance compared to both an industry peer group and an S&P Index (a “market condition” under SFAS No. 123(R)) and 50% on a return on capital target (a “performance condition” under SFAS No. 123(R)). The Company granted 0.2 million performance units during the quarter ended March 31, 2006. Under APB Opinion No. 25, all of the performance unit awards were accounted for as variable awards. Under SFAS No. 123(R), the awards settled in cash are accounted for as liability awards, and the awards settled in common stock are accounted for based on their grant date fair value. The performance condition awards were valued utilizing the grant date fair values of the Company’s stock adjusted for dividends forgone during the vesting period. The market condition awards were valued utilizing a Monte Carlo simulation which incorporates the total shareholder return hurdles set for each grant. The assumptions used in the valuations of the 2005 and 2006 grants, respectively: dividend yield of 0.8% and 1.0%; expected volatility of 36% and 40%; and risk-free interest rate of 4.25% and 3.25%. The Company recognized $5.0 million and $3.0 million of expense, net of taxes, for the quarters ended March 31, 2006 and 2005, respectively, related to performance units.

     As noted above, prior to adopting SFAS No. 123(R), the Company applied APB Opinion No. 25 and related interpretations to account for its equity incentive plans. The following table reflects 2005 pro forma net income and basic and diluted earnings per share had compensation cost been determined for the Company’s non-qualified and incentive stock options based on the fair value at the grant dates consistent with the methodology set forth under SFAS No. 123 (dollars in thousands, except per share data):

		Quarter Ended
		March 31, 2005
Net income:
As reported		$	51,890
Pro forma			50,566
Basic earnings per share:
As reported		$	0.20
Pro forma			0.19
Diluted earnings per share:
As reported		$	0.19
Pro forma			0.19

(6) Comprehensive Income

     The following table sets forth the after-tax components of comprehensive income for the quarters ended March 31, 2006, and 2005 (dollars in thousands):

		Quarter Ended March 31,
		2006				2005
Net income		$	130,222			$	51,890
Increase in fair value of cash flow hedges, net of tax provisions of $1,242 and $19,828 for the quarters ended March 31, 2006 and 2005, respectively			1,864				29,743
Comprehensive income		$	132,086			$	81,633

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

     Comprehensive income differs from net income by the amount of unrealized gain or loss resulting from valuation changes of the Company’s cash flow hedges (which include fuel and natural gas hedges, currency forwards, and interest rate swaps) during the period. Increases in interest rates and crude and heating oil prices during the quarters ended March 31, 2006 and 2005 resulted in increased valuations of these hedging instruments.

(7) Pension and Postretirement Benefit Costs

Components of Net Periodic Pension Costs

     Net periodic pension costs included the following components (dollars in thousands):

		Quarter Ended March 31,
		2006				2005
Service cost for benefits earned		$	3,059			$	2,963
Interest cost on projected benefit obligation			11,509				11,373
Expected return on plan assets			(13,647	)			(13,203	)
Amortization of prior service cost			(8	)			(4	)
Amortization of net loss			5,671				6,346
Net periodic pension costs			6,584				7,475
Curtailment charges			—				9,527
Total pension costs		$	6,584			$	17,002

     Curtailment

     The curtailment loss in the first quarter of 2005 resulted from the termination of operations at two of the three operating mines that participate in the Western Surface UMWA Pension Plan (the “Plan”) during 2005. The loss is actuarially determined and consists of an increase in the actuarial liability, the accelerated recognition of previously unamortized prior service cost and contractual termination benefits under the Plan resulting from the termination of operations.

     Contributions

     The Company previously disclosed in its financial statements for the year ended December 31, 2005 that it expected to contribute $6.6 million to its funded pension plans and make $1.3 million in expected benefit payments attributable to its unfunded pension plans during 2006. As of March 31, 2006, $0.3 million of expected benefit payments attributable to the unfunded pension plans have been made and no contributions have been made to the funded pension plans.

Components of Net Periodic Postretirement Benefit Costs

     Net periodic postretirement benefit costs included the following components (dollars in thousands):

		Quarter Ended March 31,
		2006				2005
Service cost for benefits earned		$	1,879			$	1,325
Interest cost on accumulated postretirement benefit obligation			18,464				18,175
Amortization of prior service cost			(1,334	)			(1,325	)
Amortization of actuarial losses			8,012				6,575
Net periodic postretirement benefit costs		$	27,021			$	24,750

     Cash Flows

     The Company previously disclosed in its financial statements for the year ended December 31, 2005, that it expected to pay $75.0 million attributable to its postretirement benefit plans during 2006. As of March 31, 2006, payments of $21.6 million attributable to the Company’s postretirement benefit plans have been made.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(8) 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.” Western U.S. Mining operations reflect the aggregation of the Powder River Basin, Southwest and Colorado operating segments, and Eastern U.S. Mining operations reflect the aggregation of the Appalachia and Midwest operating segments. The principal business of the Western U.S. Mining, Eastern U.S. Mining and Australian Mining segments is the mining, preparation and sale of steam coal, sold primarily to electric utilities, and metallurgical coal, sold to steel and coke producers. Western U.S. Mining operations are characterized by predominantly surface mining extraction processes, lower sulfur content and Btu of coal, and longer shipping distances from the mine to the customer. Conversely, Eastern U.S. Mining operations are characterized by a majority of underground mining extraction processes, higher sulfur content and Btu of coal, and shorter shipping distances from the mine to the customer. Geologically, Western operations mine bituminous and subbituminous coal deposits, and Eastern operations mine bituminous coal deposits. Australian Mining operations are characterized by surface and underground extraction processes, mining primarily low sulfur, metallurgical coal sold to an international customer base. The Trading and Brokerage segment’s principal business is the marketing, brokerage and trading of coal. “Corporate and Other” includes selling and administrative expenses, net gains on property disposals, costs associated with past mining obligations, joint venture earnings related to the Company’s 25.5% investment in a Venezuelan mine and revenues and expenses related to the Company’s other commercial activities such as coalbed methane, generation development and resource management.

     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 quarters ended March 31, 2006 and 2005 are as follows (dollars in thousands):

		Quarter Ended March 31,
		2006				2005
Revenues:
Western U.S. Mining		$	432,090			$	404,436
Eastern U.S. Mining			514,463				424,892
Australian Mining			152,999				103,525
Trading and Brokerage			207,015				141,569
Corporate and Other			5,243				3,058
Total		$	1,311,810			$	1,077,480
Adjusted EBITDA (1) :
Western U.S. Mining		$	127,793			$	120,425
Eastern U.S. Mining			132,544				94,806
Australian Mining			47,756				14,086
Trading and Brokerage (2)			16,179				(21,868	)
Corporate and Other (3)			(64,852	)			(41,498	)
Total		$	259,420			$	165,951

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

     A reconciliation of adjusted EBITDA to consolidated income before income taxes and minority interests follows (dollars in thousands):

		Quarter Ended
		March 31,
		2006				2005
Total adjusted EBITDA		$	259,420			$	165,951
Depreciation, depletion and amortization			80,964				75,953
Asset retirement obligation expense			7,215				9,195
Interest expense			27,400				25,556
Interest income			(2,606	)			(1,373	)
Income before income taxes and minority interests		$	146,447			$	56,620

(9) Commitments and Contingencies

Oklahoma Lead Litigation

     Gold Fields Mining, LLC (“Gold Fields”), one of the Company’s subsidiaries, is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, a predecessor owner of the Company. 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. The Company has agreed to indemnify a former affiliate of Gold Fields for certain claims. 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 1.5% of the total amount of the ore mined in the county.

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

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

Navajo Nation

     On June 18, 1999, the Navajo Nation served three of the Company’s subsidiaries, including Peabody Western Coal Company (“Peabody Western”), with a complaint that had been filed in the U.S. District Court for the District of Columbia. The Navajo Nation has alleged 16 claims, including Civil Racketeer Influenced and Corrupt Organizations Act (“RICO”) violations and fraud. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. The plaintiff is seeking various remedies including actual damages of at least $600 million, which could be trebled under the RICO counts, punitive damages of at least $1 billion, a determination that Peabody Western’s two coal leases have terminated due to Peabody Western’s breach of these leases and a reformation of these leases to adjust the royalty rate to 20%. Subsequently, the court allowed the Hopi Tribe to intervene in this lawsuit and the Hopi Tribe is also seeking unspecified actual damages, punitive damages and reformation of its coal lease. On March 4, 2003, the U.S. Supreme Court issued a ruling in a companion lawsuit involving the Navajo Nation and the United States rejecting the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

     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 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 potential loss cannot be reasonably estimated. However, the Company believes this matter is likely to be resolved without a material adverse effect on the Company’s financial condition, results of operations or cash flows.

The Future of the Mohave Generating Station and Black Mesa Mine

     The Company had been supplying coal to the Mohave Generating Station pursuant to a long-term coal supply agreement through its Black Mesa Mine. The mine terminated operations on December 31, 2005, and the coal supply agreement expired on that date. As a part of the alternate dispute resolution referenced in the Navajo Nation litigation, Peabody Western has been participating in mediation with the owners of the Mohave Generating Station and the Navajo Generating Station and the two tribes to resolve the complex issues surrounding groundwater and other disputes involving the two generating stations. Resolution of these issues is critical to the operation of the Mohave Generating Station after December 31, 2005. There is no assurance that these issues will be resolved and even if they are resolved, the operator of the Mohave Generating Station has stated that the plant is not expected to resume operations until 2010. The Mohave plant was the sole customer of the Black Mesa Mine, which sold 4.6 million tons of coal in 2005. During 2005, the mine generated $29.8 million of Adjusted EBITDA, which represented 3.4% of the Company’s total 2005 Adjusted EBITDA of $870.4 million.

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 $76.7 million and $74.2 million included in “Investments and other assets” in the condensed consolidated balance sheets at March 31, 2006 and December 31, 2005, respectively.

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

West Virginia Flooding Litigation

     Three of the Company’s subsidiaries have been named in six separate complaints filed in Boone, Kanawha, Wyoming, and McDowell Counties, West Virginia seeking compensation for property damage and personal injury arising out of flooding that occurred in southern West Virginia during heavy rainstorms in July of 2001. These cases, along with approximately 50 similar cases not involving the Company’s subsidiaries, include approximately 3,500 plaintiffs and 77 defendants engaged in the extraction of natural resources. In the first quarter of 2006, the Company’s subsidiaries entered into a confidential settlement of these lawsuits, which did not have a material adverse impact on the Company’s financial condition, results of operations or cash flows. The Company’s insurance carrier has acknowledged the Company’s tender of these claims and the Company expects that the carrier will make the settlement payment when due.

Citizens Power

     In connection with the August 2000 sale of the Company’s former subsidiary, Citizens Power, the Company has indemnified the buyer, Edison Mission Energy, from certain losses resulting from specified power contracts and guarantees. During the period that the Company owned Citizens Power, Citizens Power guaranteed the obligations of two affiliates to make payments to third parties for power delivered under fixed-priced power sales agreements with terms that extend through 2008. Edison Mission Energy has stated and the Company believes there will be sufficient cash flow to pay the power suppliers, assuming timely payment by the power purchasers.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Environmental

     The Company is subject to federal, state and local environmental laws and regulations, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA” or “Superfund”), the Superfund Amendments and Reauthorization Act of 1986, the Clean Air Act, the Clean Water Act and the Conservation and Recovery Act. Superfund and similar state laws create liability for investigation and remediation in response to releases of hazardous substances in the environment and for damages to natural resources. Under that legislation and many state Superfund statutes, joint and several liability may be imposed on waste generators, site owners and operators and others regardless of fault. These regulations could require the Company to do some or all of the following:

	•		remove or mitigate the effects on the environment at various sites from the disposal or release of certain substances;
	•		perform remediation work at such sites; and
	•		pay damages for loss of use and non-use values.

     Environmental claims have been asserted against Gold Fields related to activities of Gold Fields or its former affiliates. Gold Fields has been named a potentially responsible party (“PRP”) based on CERCLA at five sites, and claims have been asserted at 18 other sites. 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 Gold Fields’ estimated share of responsibility.

     The Company’s policy is to accrue environmental cleanup-related costs of a non-capital nature when those costs are believed to be probable and can be reasonably estimated. The quantification of environmental exposures requires an assessment of many factors, including the nature and extent of contamination, the timing, extent and method of the remedial action, changing laws and regulations, advancements in environmental technologies, the quality of information available related to specific sites, the assessment stage of each site investigation, preliminary findings and the length of time involved in remediation or settlement. The Company also assesses the financial capability and proportional share of costs of other PRPs and, where allegations are based on tentative findings, the reasonableness of the Company’s apportionment. The Company has not anticipated any recoveries from insurance carriers in the estimation of liabilities recorded in its consolidated balance sheets. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above totaled $42.1 million at March 31, 2006 and $42.5 million at December 31, 2005, $23.2 million and $23.6 million of which was reflected as a current liability, respectively. These amounts represent those costs that the Company believes are probable and reasonably estimable. In September 2005, Gold Fields and other PRPs received a letter from the U.S. Department of Justice alleging that the 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 historic mining sites. Gold Fields has participated in the ongoing settlement discussions. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950s and mined, in accordance with lease agreements and permits, approximately 1.5% of the total amount of the ore mined in the county. Gold Fields believes it has meritorious defenses to these claims. Gold Fields is involved in other litigation in the Picher area, and the Company has agreed to indemnify one of the defendants in this litigation as 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.

     Although waste substances generated by coal mining and processing are generally not regarded as hazardous substances for the purposes of Superfund and similar legislation, some products used by coal companies in operations, such as chemicals, and the disposal of these products are governed by the statute. Thus, coal mines currently or previously owned or operated by the Company, and sites to which the Company has sent waste materials, may be subject to liability under Superfund and similar state laws.

Other

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

     At March 31, 2006, purchase commitments for capital expenditures were approximately $140.9 million and federal coal reserve lease payments due over the next three years total $598.1 million.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(10) Guarantees

     In the normal course of business, the Company is a party to the following guarantees:

     The Company owns a 30.0% interest in a partnership that leases a coal export terminal from the Peninsula Ports Authority of Virginia under a 30-year lease that permits the partnership to purchase the terminal at the end of the lease term for a nominal amount. The partners have severally (but not jointly) agreed to make payments under various agreements which in the aggregate provide the partnership with sufficient funds to pay rents and to cover the principal and interest payments on the floating-rate industrial revenue bonds issued by the Peninsula Ports Authority, and which are supported by letters of credit from a commercial bank. As of March 31, 2006, the Company’s maximum reimbursement obligation to the commercial bank is in turn supported by a letter of credit totaling $42.8 million.

     The Company has guaranteed the performance of Asset Management Group (“AMG”) under its coal purchase contract with a third party, which has terms extending through December 31, 2006. Default occurs if AMG does not deliver specified monthly tonnage amounts to the third party. In the event of a default, the Company would assume AMG’s obligation to ship coal at agreed prices for the remaining term of the contract. As of March 31, 2006, the maximum potential future payments under this guarantee are approximately $3.0 million, based on recent spot coal prices. As a matter of recourse in the event of a default, the Company has access to cash held in escrow and the ability to trigger an assignment of AMG’s assets to the Company. Based on these recourse options and the remote probability of non-performance by AMG due to its prior operating history, the Company has valued the liability associated with the guarantee at zero.

     As part of arrangements through which the Company obtains exclusive sales representation agreements with small coal mining companies (the “Counterparties”), the Company issued financial guarantees on behalf of the Counterparties. These guarantees facilitate the Counterparties’ efforts to obtain bonding or financing. The Company also guaranteed bonding for a partnership in which it formerly held an interest as part of an exchange in which the Company obtained strategic Illinois Basin coal reserves. The total amount guaranteed by the Company was $6.3 million, and the fair value of the guarantees recognized as a liability was $0.4 million as of March 31, 2006. The Company’s obligations under the guarantees extend to September 2015. In March 2006, the Company issued a guarantee for certain equipment lease arrangements on behalf of one of the sales representation parties with maximum potential future payments totaling $3.3 million and with lease terms that extend to April 2010. The Company has multiple recourse options in the event of default, including the ability to assume the lease and procure use of the equipment or to settle the lease and take title to the assets. If default occurs, the Company has the ability and intent to exercise its recourse options, so the liability associated with the guarantee has been valued at zero.

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

     The Company has provided financial guarantees under certain long-term debt agreements entered into by its subsidiaries, and substantially all of the Company’s subsidiaries provide financial guarantees under long-term debt agreements entered into by the Company. The maximum amounts payable under the Company’s debt agreements are equal to the respective principal and interest payments. Supplemental guarantor/non-guarantor financial information is provided in Note 11.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(11) Supplemental Guarantor/Non-Guarantor Financial Information

     In accordance with the indentures governing the 6.875% Senior Notes due 2013 and the 5.875% Senior Notes due 2016, certain wholly-owned U.S. subsidiaries of the Company have fully and unconditionally guaranteed the 6.875% Senior Notes and the 5.875% Senior Notes, on a joint and several basis. Separate financial statements and other disclosures concerning the Guarantor Subsidiaries are not presented because management believes that such information is not material to the holders of the 6.875% Senior Notes and the 5.875% Senior Notes. The following unaudited condensed historical financial statement information is provided for the Guarantor/Non-Guarantor Subsidiaries.

Peabody Energy Corporation

		Quarter Ended March 31, 2006
		Parent				Guarantor				Non-Guarantor
		Company				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Total revenues		$	—			$	1,065,989			$	272,388			$	(26,567	)		$	1,311,810
Costs and expenses:
Operating costs and expenses			(4,950	)			835,630				218,229				(26,567	)			1,022,342
Depreciation, depletion and amortization			—				71,727				9,237				—				80,964
Asset retirement obligation expense			—				7,005				210				—				7,215
Selling and administrative expenses			4,546				41,305				675				—				46,526
Other operating (income) loss:
Net gain on disposal of assets			—				(9,015	)			(211	)			—				(9,226	)
(Income) loss from equity affiliates			—				150				(7,402	)			—				(7,252	)
Interest expense			40,092				15,502				3,589				(31,783	)			27,400
Interest income			(5,902	)			(20,979	)			(7,508	)			31,783				(2,606	)
Income (loss) before income taxes and minority interests			(33,786	)			124,664				55,569				—				146,447
Income tax provision (benefit)			(9,724	)			9,809				11,481				—				11,566
Minority interests			—				5,295				(636	)			—				4,659
Net income (loss)		$	(24,062	)		$	109,560			$	44,724			$	—			$	130,222

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Operations
(Dollars in thousands)

		Quarter Ended March 31, 2005
		Parent				Guarantor				Non-Guarantor
		Company				Subsidiaries				Subsidiaries				Eliminations				Consolidated
Total revenues		$	—			$	898,848			$	197,820			$	(19,188	)		$	1,077,480
Costs and expenses:
Operating costs and expenses			(2,883	)			755,402				179,648				(19,188	)			912,979
Depreciation, depletion and amortization			—				68,957				6,996				—				75,953
Asset retirement obligation expense			—				8,761				434				—				9,195
Selling and administrative expenses			596				36,797				367				—				37,760
Other operating (income) loss:
Net (gain) loss on disposal of assets			—				(31,131	)			9				—				(31,122	)
Income from equity affiliates			—				(3,148	)			(4,940	)			—				(8,088	)
Interest expense			37,448				14,071				5,522				(31,485	)			25,556
Interest income			(4,922	)			(21,742	)			(6,194	)			31,485				(1,373	)
Income (loss) before income taxes and minority interests			(30,239	)			70,881				15,978				—				56,620
Income tax provision (benefit)			(11,112	)			14,762				774				—				4,424
Minority interests			—				306				—				—				306
Net income (loss)		$	(19,127	)		$	55,813			$	15,204			$	—			$	51,890

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Balance Sheets
(Dollars in thousands)

		March 31, 2006
		Parent				Guarantor				Non-Guarantor
		Company				Subsidiaries				Subsidiaries				Eliminations				Consolidated
ASSETS
Current assets
Cash and cash equivalents		$	346,600			$	(216	)		$	3,776			$	—			$	350,160
Accounts receivable, net			2,508				44,523				191,836				—				238,867
Inventories			—				144,287				30,762				—				175,049
Assets from coal trading activities			—				77,638				—				—				77,638
Deferred income taxes			—				9,027				—				—				9,027
Other current assets			23,731				44,958				6,478				—				75,167
Total current assets			372,839				320,217				232,852				—				925,908
Property, plant, equipment and mine development — at cost			—				6,330,808				800,246				—				7,131,054
Less accumulated depreciation, depletion and amortization			—				(1,651,334	)			(94,549	)			—				(1,745,883	)
Investments and other assets			5,130,359				151,314				61,848				(5,027,227	)			316,294
Total assets		$	5,503,198			$	5,151,005			$	1,000,397			$	(5,027,227	)		$	6,627,373
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt		$	11,250			$	65,484			$	1,172			$	—			$	77,906
Payables and notes payable to affiliates, net			1,897,564				(2,405,336	)			507,772				—				—
Liabilities from coal trading activities			—				63,655				—				—				63,655
Accounts payable and accrued expenses			23,220				658,611				110,578				—				792,409
Total current liabilities			1,932,034				(1,617,586	)			619,522				—				933,970
Long-term debt, less current maturities			1,293,149				37,710				1,667				—				1,332,526
Deferred income taxes			14,189				205,286				12,194				—				231,669
Other noncurrent liabilities			38,640				1,911,424				7,255				—				1,957,319
Total liabilities			3,278,012				536,834				640,638				—				4,455,484
Minority interests			—				13,344				(551	)			—				12,793
Stockholders’ equity			2,225,186				4,600,827				360,310				(5,027,227	)			2,159,096
Total liabilities and stockholders’ equity		$	5,503,198			$	5,151,005			$	1,000,397			$	(5,027,227	)		$	6,627,373

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation
Supplemental Condensed Consolidated Balance Sheets
(Dollars in thousands)

		December 31, 2005
		Parent				Guarantor				Non-Guarantor
		Company				Subsidiaries				Subsidiaries				Eliminations				Consolidated
ASSETS
Current assets
Cash and cash equivalents		$	494,232			$	2,500			$	6,546			$	—			$	503,278
Accounts receivable, net			4,260				78,544				138,737				—				221,541
Inventories			—				329,116				60,655				—				389,771
Assets from coal trading activities			—				146,596				—				—				146,596
Deferred income taxes			—				9,027				—				—				9,027
Other current assets			21,817				23,347				9,267				—				54,431
Total current assets			520,309				589,130				215,205				—				1,324,644
Property, plant, equipment and mine development — at cost			—				6,081,631				723,933				—				6,805,564
Less accumulated depreciation, depletion and amortization			—				(1,541,834	)			(86,022	)			—				(1,627,856	)
Investments and other assets			4,971,500				302,450				53,087				(4,977,383	)			349,654
Total assets		$	5,491,809			$	5,431,377			$	906,203			$	(4,977,383	)		$	6,852,006
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt		$	10,625			$	11,034			$	926			$	—			$	22,585
Payables and notes payable to affiliates, net			1,875,361				(2,346,153	)			470,792				—				—
Liabilities from coal trading activities			—				132,373				—				—				132,373
Accounts payable and accrued expenses			24,560				732,317				111,088				—				867,965
Total current liabilities			1,910,546				(1,470,429	)			582,806				—				1,022,923
Long-term debt, less current maturities			1,312,521				69,014				1,386				—				1,382,921
Deferred income taxes			12,903				304,740				20,845				—				338,488
Other noncurrent liabilities			11,282				1,908,158				7,217				—				1,926,657
Total liabilities			3,247,252				811,483				612,254				—				4,670,989
Minority interests			—				1,946				604				—				2,550
Stockholders’ equity			2,244,557				4,617,948				293,345				(4,977,383	)			2,178,467
Total liabilities and stockholders’ equity		$	5,491,809			$	5,431,377			$	906,203			$	(4,977,383	)		$	6,852,006

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows
(Dollars in thousands)

		Quarter Ended March 31, 2006
		Parent				Guarantor				Non-Guarantor
		Company				Subsidiaries				Subsidiaries				Consolidated
Cash Flows from Operating Activities
Net cash provided by (used in) operating activities		$	(46,395	)		$	48,042			$	47,405			$	49,052
Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development			—				(69,939	)			(17,520	)			(87,459	)
Federal coal lease expenditures			—				—				(59,829	)			(59,829	)
Additions to advance mining royalties			—				(2,250	)			—				(2,250	)
Acquisitions, net			—				(44,538	)			—				(44,538	)
Proceeds from disposal of assets			—				11,071				417				11,488
Net cash used in investing activities			—				(105,656	)			(76,932	)			(182,588	)
Cash Flows from Financing Activities
Payments of long-term debt			(2,500	)			(10,183	)			(223	)			(12,906	)
Proceeds from stock options exercised			6,051				—				—				6,051
Tax benefit related to stock options exercised			13,096				—				—				13,096
Proceeds from employee stock purchases			1,772				—				—				1,772
Distributions to minority interests			—				(1,000	)			—				(1,000	)
Dividends paid			(15,869	)			—				—				(15,869	)
Common stock repurchase			(11,476	)			—				—				(11,476	)
Proceeds from long-term debt			—				—				750				750
Transactions with affiliates, net			(92,311	)			66,081				26,230				—
Net cash provided by (used in) financing activities			(101,237	)			54,898				26,757				(19,582	)
Net decrease in cash and cash equivalents			(147,632	)			(2,716	)			(2,770	)			(153,118	)
Cash and cash equivalents at beginning of period			494,232				2,500				6,546				503,278
Cash and cash equivalents at end of period		$	346,600			$	(216	)		$	3,776			$	350,160

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

Peabody Energy Corporation
Unaudited Supplemental Condensed Consolidated Statements of Cash Flows
(Dollars in thousands)

		Quarter Ended March 31, 2005
		Parent				Guarantor				Non-Guarantor
		Company				Subsidiaries				Subsidiaries				Consolidated
Cash Flows from Operating Activities
Net cash provided by (used in) operating activities		$	(60,981	)		$	139,021			$	19,887			$	97,927
Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development			—				(36,108	)			(10,842	)			(46,950	)
Federal coal lease expenditures			—				—				(63,540	)			(63,540	)
Purchase of mining assets			—				(56,500	)			—				(56,500	)
Additions to advance mining royalties			—				(3,130	)			(5	)			(3,135	)
Proceeds from disposal of assets			—				47,728				3				47,731
Net cash used in investing activities			—				(48,010	)			(74,384	)			(122,394	)
Cash Flows from Financing Activities
Payments of long-term debt			(1,250	)			(10,638	)			(341	)			(12,229	)
Proceeds from stock options exercised			12,331				—				—				12,331
Proceeds from employee stock purchases			1,350				—				—				1,350
Increase of securitized interests in accounts receivable			—				—				25,000				25,000
Distributions to minority interests			—				(624	)			—				(624	)
Dividends paid			(9,772	)			—				—				(9,772	)
Transactions with affiliates, net			56,465				(81,993	)			25,528				—
Net cash provided by (used in) financing activities			59,124				(93,255	)			50,187				16,056
Net decrease in cash and cash equivalents			(1,857	)			(2,244	)			(4,310	)			(8,411	)
Cash and cash equivalents at beginning of period			373,066				3,496				13,074				389,636
Cash and cash equivalents at end of period		$	371,209			$	1,252			$	8,764			$	381,225

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

Cautionary Notice Regarding Forward-Looking Statements

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

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

	•		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;
	•		economic strength and political stability of countries in which we have operations or serve customers;
	•		weather;
	•		transportation performance and costs, including demurrage;
	•		ability to renew sales contracts;
	•		successful implementation of business strategies;
	•		legislation, regulations and court decisions;
	•		new environmental requirements affecting the use of coal including mercury and carbon dioxide related limitations;
	•		variation in revenues related to synthetic fuel production;
	•		changes in postretirement benefit and pension obligations;
	•		negotiation of labor contracts, employee relations and workforce availability;
	•		availability and costs of credit, surety bonds and letters of credit;
	•		the effects of changes in currency exchange rates;
	•		price volatility and demand, particularly in higher-margin products and in our trading and brokerage businesses;
	•		risks associated with customer contracts, including credit and performance risk;
	•		availability and costs of key supplies or commodities such as diesel fuel, steel, explosives and tires;
	•		reductions of purchases by major customers;
	•		geology, equipment and other risks inherent to mining;
	•		terrorist attacks or threats;
	•		performance of contractors, third party coal suppliers or major suppliers of mining equipment or supplies;
	•		replacement of coal reserves;
	•		risks associated with our BTU conversion or generation development initiatives;
	•		implementation of new accounting standards and Medicare regulations;
	•		inflationary trends, including those impacting materials used in our business;
	•		the effect of interest rate changes;
	•		litigation, including claims not yet asserted;
	•		the effects of acquisitions or divestitures;
	•		impacts of pandemic illness;
	•		changes to contribution requirements to multi-employer benefit funds; 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 2005 Annual Report on Form 10-K. 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 34 active coal operations located throughout all major U.S. coal producing regions and internationally in Australia. In the first quarter of 2006, we sold 61.4 million tons of coal. In 2005, we sold 239.9 million tons of coal that accounted for an estimated 21.5% of all U.S. coal sales, and were more than 69% greater than the sales of our closest domestic competitor and 49% more than our closest international competitor. Based on Energy Information Administration (“EIA”) estimates, demand for coal in the United States was more than 1.1 billion tons in 2005. Domestic consumption of coal is expected to grow at a rate of 1.7% per year through 2030 when U.S. coal demand is forecasted to be 1.8 billion tons. The EIA expects demand for coal use at coal-to-liquids (“CTL”) plants to grow to 190 million tons by 2030. Coal-fueled generation is used in most cases to meet baseload electricity requirements, and coal use generally grows at the approximate rate of electricity growth, which is expected to average 1.6% annually through 2025. Coal production located west of the Mississippi River is projected to provide most of the incremental growth as Western production increases to an estimated 63% share of total production in 2030. In 2004, coal’s share of electricity generation was approximately 51%, a share that the EIA projects will grow to 57% by 2030.

     Our primary customers are U.S. utilities, which accounted for 87% of our sales in 2005. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During 2005, approximately 90% of our sales were under long-term contracts. As of March 31, 2006, our unpriced volumes for 2006 were 5 to 10 million tons on expected production of 230 to 240 million tons and total sales of 255 to 265 million tons. As discussed more fully in Item 1A, Risk Factors, in our 2005 Annual Report on Form 10-K, our results of operations in the near term could be negatively impacted by poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations, and by the availability of transportation for coal shipments. On a long-term basis, our results of operations could be impacted by our ability to secure or acquire high-quality coal reserves, find replacement buyers for coal under contracts with comparable terms to existing contracts, or the passage of new or expanded regulations that could limit our ability to mine, increase our mining costs, or limit our customers’ ability to utilize coal as fuel for electricity generation. In the past, we have achieved production levels that are relatively consistent with our projections.

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

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

     Australian Mining operations are characterized by both surface and underground extraction processes, mining primarily low-sulfur, high Btu coal sold to an international customer base. Metallurgical coal is produced primarily from two of our Australian mines and two of our U.S. mines. Metallurgical coal is approximately 4% of our total sales volume and approximately 2% of U.S. sales volume.

     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. Each of our mining operations is described in Item 1, Business, of our 2005 Annual Report on Form 10-K.

     In addition to our mining operations, which comprised 85% of revenues in 2005, we also generate revenues from brokering and trading coal (15% of revenues), and by realizing value from our vast natural resource position by selling non-core land holdings and mineral interests to generate additional cash flows as well as other ventures described below.

     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 lessor. The projects we are currently pursuing are as follows: the 1,500-megawatt Prairie State Energy Campus in Washington County, Illinois; the 1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky; and the 300-megawatt Mustang Energy Campus near Grants, New Mexico. The plants, assuming all necessary permits and financing are obtained and following selection of partners and sale of a majority of the output of each plant, could be operational following a four-year construction phase. In April 2006, we received a decision affirming the air permit for our Thoroughbred Energy Campus. This milestone allows us to continue advancing the development of that campus.

     During 2005, we engaged in several BTU conversion projects which are designed to expand the uses of coal through various technologies. We are a founding member of the FutureGen Industrial Alliance, a non-profit company that is partnering with the U.S. Department of Energy to facilitate the design, construction and operation of the world’s first near-zero emission coal-fueled power plant. FutureGen is expected to demonstrate advanced coal-based technologies to generate electricity and also produce hydrogen to power fuel cells for transportation and other energy needs. The technology is also expected to integrate the capture of carbon emissions with carbon sequestration, helping to address the issue of climate change as energy demand continues to grow worldwide. We also entered into an agreement to acquire a 30% interest in Econo-Power International Corporation (“EPIC™”), which owns and markets modular coal gasifiers for industrial applications. The EPIC Clean Coal Gasification System™ uses air-blown gasifiers to convert coal into a synthetic gas that is ideal for industrial applications. We are in discussions with ArcLight Capital Partners, LLC to advance project development of a commercial-scale coal gasification project in Illinois that would transform coal into pipeline-quality synthetic natural gas. The initial project would be designed with ConocoPhillips’ “E-Gas™” Technology. When completed, the plant would be one of the largest coal-to-natural-gas plants in the United States and would require at least three million tons of Illinois Basin coal per year to fuel two gasifier trains that could produce more than 35 billion cubic feet of synthetic natural gas annually.

     Effective January 1, 2006, Gregory H. Boyce became our President and Chief Executive Officer after we completed an orderly succession planning process. Irl F. Engelhardt, our former Chief Executive Officer, remains employed as Chairman of the Board.

     Effective February 22, 2006, we implemented a two-for-one stock split on all shares of our common stock. All share and per share amounts in this quarterly report on Form 10-Q reflect this split. In July 2005, our Board of Directors authorized a share repurchase program of up to 5% of the outstanding shares of our common stock. The repurchases may be made from time to time based on an evaluation of our outlook and general business conditions, as well as alternative investment and debt repayment options. In March 2006, we purchased 250,000 of our common shares at a cost of $11.5 million. On January 23, 2006, our Board of Directors authorized a 26% increase in our dividend, to $0.06 per share, to shareholders of record on February 7, 2006.

Results of Operations

Adjusted EBITDA

     The discussion of our results of operations below includes references to, and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing 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 8 to our unaudited condensed consolidated financial statements.

Quarter Ended March 31, 2006 Compared to Quarter Ended March 31, 2005

Summary

     Our first quarter 2006 revenues of $1.31 billion increased 21.7% over the first quarter of the prior year. Revenues were driven higher by improved pricing in nearly all of our mining operations as well as demand-driven increases in volumes in the Powder River Basin and Midwest. For the quarter, Segment Adjusted EBITDA of $324.3 million was a 56.3% increase over the prior year, primarily due to increases in sales prices at our U.S. and Australian Mining Operations. Net income was $130.2 million in 2006, or $0.48 per share, an increase of 151.0% over 2005 net income of $51.9 million, or $0.19 per share.

     Our 2006 results were impacted by the opening of one new mine and the expansion of an existing mine in the Midwest in late 2005, both of which were developed from reserves acquired in the first quarter of 2005, and one new mine in Australia, of which we own a 62.5% interest. Also impacting our 2006 results are the termination of operations at our Black Mesa and Seneca mines, which occurred in late 2005.

Tons Sold

     The following table presents tons sold by operating segment for the quarters ended March 31, 2006 and 2005:

		Quarter Ended March 31,								Increase (Decrease)
		2006				2005				Tons				%
						(Tons in millions)
Western U.S. Mining Operations			39.8				38.7				1.1				2.8	%
Eastern U.S. Mining Operations			13.7				13.0				0.7				5.4	%
Australian Mining Operations			1.9				2.0				(0.1	)			(5.0	%)
Trading & Brokerage Operations			6.0				5.4				0.6				11.1	%
Total			61.4				59.1				2.3				3.9	%

Revenues

     The following table presents revenues for the quarters ended March 31, 2006 and 2005:

		Quarter Ended				Quarter Ended				Increase
		March 31,				March 31,				to Revenues
		2006				2005				$				%
		(Dollars in thousands)
Sales		$	1,288,906			$	1,062,521			$	226,385				21.3	%
Other revenues			22,904				14,959				7,945				53.1	%
Total revenues		$	1,311,810			$	1,077,480			$	234,330				21.7	%

     In the first quarter of 2006, our revenues were $1.31 billion, increasing by $234.3 million, or 21.7%, compared to prior year. This increase in revenues was primarily caused by demand-driven increases to sales prices in all regions, but particularly in the metallurgical coal markets of Appalachia and Australia.

     Sales increased 21.3% to $1.29 billion in 2006, reflecting increases in every operating segment. Western U.S. Mining sales increased $27.7 million, Eastern U.S. Mining sales were $89.0 million higher, sales in Australian Mining improved $49.7 million and sales from our brokerage operations increased $60.0 million. Sales increased on improved pricing in every operating segment and through higher volumes in our Powder River Basin operations and our international brokerage business. Our average sales price per ton increased 15.3% in the first quarter of 2006 compared to the prior year due to increased demand for all of our coal products, but particularly in the regions where we produce metallurgical coal. Prices for metallurgical coal and our ultra-low sulfur Powder River Basin coal have been the subject of increasing demand. We sell metallurgical coal from our Eastern U.S. and Australian Mining operations. We sell ultra-low sulfur Powder River Basin coal from our Western U.S. Mining operations.

     The increase in Eastern U.S. Mining operations’ sales was primarily due to improved pricing for both steam and metallurgical coal from the region. Sales in Appalachia increased $38.4 million, or 18.5% and sales in the Midwest increased $50.6 million, or 24.2%. On average, prices in our Eastern U.S. Mining operations increased 14.5% to $37.47 per ton and, as discussed above, were mainly driven by increases in metallurgical coal prices. Production increased in the Midwest mainly due to the newly developed mines mentioned above. First quarter 2006 production in Appalachia was lower than prior year due to a longwall move and the development of a metallurgical mine in the region, which extended from late 2005 to February 2006. Sales increased in our Western U.S. Mining operations due to higher demand-driven prices and volumes at our Powder River Basin operations, partially offset by the impacts of the termination of operations at our Black Mesa and Seneca mines in late 2005. Overall, prices in our Western U.S. Mining operations increased 3.8% to $10.86 per ton. In the West, sales increased mainly in the Powder River Basin, which improved $46.5 million due to increased sales prices and volumes. Powder River Basin production and sales volumes were up as a result of increasingly strong demand for the mines’ low-sulfur product, which continues to expand its market area geographically. Powder River Basin operations overcame railroad service disruptions caused by ongoing operational issues on the main shipping line out of the basin in early 2006. Sales from our Australian Mining operations were $49.7 million, or 48.2%, higher than in 2005. The increase in Australian sales was due primarily to a 63.4% increase in per ton sales prices to $82.88 per ton, largely due to higher international metallurgical coal prices. Brokerage operations’ sales increased $60.0 million in 2006 compared to prior year due to an increase in average per ton prices and higher international brokerage volumes.

     Other revenues increased $7.9 million, or 53.1%, compared to prior year primarily due to proceeds from the buy-out of a coal purchase contract and higher trading results.

Segment Adjusted EBITDA

     Our total segment Adjusted EBITDA was $324.3 million for the first quarter of 2006, compared with $207.4 million in the prior year, detailed as follows.

										Increase to
		Quarter Ended				Quarter Ended				Segmented Adjusted
		March 31,				March 31,				EBITDA
		2006				2005				$				%
		(Dollars in thousands)
Western U.S. Mining Operations		$	127,793			$	120,425			$	7,368				6.1	%
Eastern U.S. Mining Operations			132,544				94,806				37,738				39.8	%
Australian Mining Operations			47,756				14,086				33,670				239.0	%
Trading and Brokerage Operations			16,179				(21,868	)			38,047				n/a
Total Segment Adjusted EBITDA		$	324,272			$	207,449			$	116,823				56.3	%