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 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)

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

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED INCOME STATEMENTS

(Dollars in thousands, except share and per share data)


	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

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except share and per share data)


	(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

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)


	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

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

MARCH 31, 2006

(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


⁽¹⁾		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.

⁽²⁾		Trading and Brokerage results included a charge for contract losses in the first quarter of 2005 primarily related to the breach of a coal supply contract by a producer (see Note 2).

⁽³⁾		First quarter 2005 Corporate and Other results included a $31.1 million gain on the sale of Penn Virginia Resource Partners, L.P. units (see Note 2).

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

Unaudited Supplemental Condensed Consolidated Statements of Operations

(Dollars in thousands)


	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	%

Adjusted EBITDA from our Western U.S. Mining operations increased $7.4 million during 2006 due to a margin per ton increase of $0.09, or 2.9%, and a sales volume increase of 1.1 million tons. The increase in Adjusted EBITDA was driven by our Powder River Basin operations, which improved by $12.6 million and earned 10.7% higher per ton margins while increasing volumes 7.2% in response to greater demand for our low-sulfur products. Improved revenues overcame increased unit costs that resulted from higher fuel costs, lower than anticipated volume due to rail difficulties and an increase in revenue-based royalties and production taxes. The improvements in the Powder River Basin helped overcome decreases in Adjusted EBITDA of $5.6 million related to our Colorado operations due to temporary geological issues and cost increases for power and labor. Adjusted EBITDA for our Southwest operations were similar to prior year results, but reflected improved results from higher volumes at two of our mines offset by lower volumes due to the termination of operations at the Black Mesa Mine in late 2005.

Eastern U.S. Mining operations’ Adjusted EBITDA increased $37.7 million, or 39.8%, compared to prior year primarily due to an increase in margin per ton of $2.35, or 32.2%. Appalachia operations’ Adjusted EBITDA increased $17.4 million, or 31.1%, as a result of sales price increases, partially offset by lower production at three of our mines due to a longwall move at one mine and geologic issues at the other two. Results in our Midwest operations were improved $20.3 million, or 52.2%, compared to prior year as benefits of higher volumes, product mix and prices were partially offset by higher costs due to higher fuel and explosives costs. The first quarter 2006 results also included $8.9 million of income from a settlement related to customer billings regarding coal quality.

Our Australian Mining operations’ Adjusted EBITDA increased $33.7 million in the current year, a 239.0% increase compared to prior year due to an increase of $18.97, or 274.9%, in margin per ton partially offset by a slight decrease in tons sold. Our Australian operations produce mostly (75% to 85%) high margin metallurgical coal. While current margins benefited from strong metallurgical coal sales prices, margin growth was limited by the impact of higher costs due to geological problems at our underground mine. Lower volumes also negatively impacted Adjusted EBITDA in 2006 due to shipping delays late in the quarter caused by cyclones.

Trading and Brokerage operations’ Adjusted EBITDA increased $38.0 million from the prior year. In 2005, we recognized a loss associated with the failure of a coal supplier to ship under a coal supply agreement in the first quarter of 2005 (see Note 2). In 2006, trading and brokerage results reflect improved brokerage margins and increased volumes.

Income Before Income Taxes And Minority Interests


	Quarter Ended			Quarter Ended			Increase (Decrease) to
	March 31,			March 31,			Income
	2006			2005			$			%
				(Dollars in thousands)
Total Segment Adjusted EBITDA	$	324,272		$	207,449		$	116,823			56.3	%
Corporate and Other Adjusted EBITDA		(64,852	)		(41,498	)		(23,354	)		(56.3	)%
Depreciation, depletion and amortization		(80,964	)		(75,953	)		(5,011	)		(6.6	)%
Asset retirement obligation expense		(7,215	)		(9,195	)		1,980			21.5	%
Interest expense		(27,400	)		(25,556	)		(1,844	)		(7.2	)%
Interest income		2,606			1,373			1,233			89.8	%

Income before income taxes and minority interests	$	146,447		$	56,620		$	89,827			158.6	%

Income before income taxes and minority interests of $146.4 million for the current year is $89.8 million, or 158.6%, higher than prior year primarily due to improved segment Adjusted EBITDA as discussed above. Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our Venezuelan joint venture, net gains on asset disposals, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development, BTU conversion, and resource management. The $23.4 million increase in Corporate and Other Adjusted EBITDA (net expense) in 2006 compared to 2005 was largely due to lower gains on asset sales and higher selling and administrative costs. Lower net gains on asset sales in 2006 primarily related to a $31.1 million gain on the sale of Penn Virginia Resource Partners, L.P. (“PVR”) units in 2005. Selling and administrative expenses increased by $8.8 million primarily related to accruals for higher long-term performance-based incentive plans, the expensing of stock options required in the first quarter of 2006 and higher outside service costs primarily related to a significant upgrade in our enterprise resource planning system. To support continued growth and globalization of our businesses, we are converting our existing information systems across the major business processes to an integrated information technology system provided by SAP AG. The project began in the first quarter of 2006 and is expected to be completed in approximately two years. These increased costs compared to 2005 were partially offset by higher equity income of $2.5 million from our 25.5% interest in Carbones del Guasare and by lower costs associated with our suspended mine operations.

Depreciation, depletion and amortization increased $5.0 million in 2006 due to higher production and capital expenditures and lower amortization in 2006 of contract liabilities recorded as part of 2004 acquisitions.

Net Income


	Quarter Ended			Quarter Ended			Increase (Decrease) to
	March 31,			March 31,			Income
	2006			2005			$			%
				(Dollars in thousands)
Income before income taxes and minority interests	$	146,447		$	56,620		$	89,827			158.6	%

Income tax provision		(11,566	)		(4,424	)		(7,142	)		(161.4	)%
Minority interests		(4,659	)		(306	)		(4,353	)		(1,422.5	)%

Net income	$	130,222		$	51,890		$	78,332			151.0	%

Net income increased $78.3 million compared to the first quarter of 2005 due to the increase in income before income taxes and minority interests discussed above, partially offset by an increase in the income tax provision and minority interests. The increase in the income tax provision in 2006 is primarily a result of higher pre-tax income. Minority interests increased as a result of acquiring additional interest in a joint venture near the end of the first quarter of 2006.

Outlook

Events Impacting Near-Term Operations

Shipments from our Powder River Basin mines were impacted in the first quarter of 2006 by rail service disruptions related to ongoing operating issues in February and March. Rail carriers are expected to continue in-depth maintenance on their track beginning in the second quarter. We expect higher shipment levels from our PRB operations in 2006 compared with 2005, but are cautious about our ability to reach maximum shipment levels.

Our North Goonyella Mine in Australia has experienced difficult geologic conditions and experienced a roof fall that interrupted production for portions of late 2005 and the first quarter of 2006. Installation of new longwall equipment to maximize operating performance under these adverse geologic conditions has been delayed by one month and is expected to be finalized in May 2006. Shipments in the first quarter of 2006 were also delayed due to two cyclones in Eastern Australia. In May 2005, port authorities implemented a reduced port allocation that is aimed at improving the loading of vessels and reducing demurrage at the main port for our Australian coal operations. Although port congestion has been reduced, demurrage costs and unpredictable timing of vessel loading could continue to impact future results.

Outlook Overview

Our outlook for the coal markets remains positive. We believe strong coal markets will continue worldwide, driven by growth in the U.S., Asia and other industrialized economies that are increasing coal demand. The U.S. economy grew at an annual rate of 3.5% in 2005 as reported by the U.S. Commerce Department, and China’s economy grew 10.2% in the first quarter of 2006 as published by the National Bureau of Statistics of China. The U.S. Department of Energy’s National Energy Technology Laboratory reported that 140 coal-fueled generating plants have been announced or are in development in 41 states, the most at any time since the 1970s.

Strong demand for coal and coal-based electricity generation in the U.S. is being driven by the growing economy, low customer stockpiles, capacity constraints of nuclear generation and high prices of natural gas and oil. At March 31, 2006, customer stockpiles remained below average, and both natural gas and oil prices remained at high levels. Natural gas prices exited a very mild winter at forward prices of $7 to $10 per million Btu, and world oil and gas production struggles to keep pace with demand. The U.S. Energy Information Administration (“EIA”) projects that the high price of oil will lead to an increase in demand for unconventional sources of transportation fuel, including coal-to-liquids (“CTL”), and that coal will increase its share as a fuel for generation of electricity.

Demand for Powder River Basin coal is increasing, particularly for our ultra-low sulfur products. The Powder River Basin represents more than half of our production, and the published reference price for high-Btu, ultra-low sulfur Powder River Basin coal has increased substantially in the past year. We control approximately 3.5 billion tons of proven and probable reserves in the Southern Powder River Basin and we sold 34.0 million tons of coal from this region in the first quarter of 2006, an increase of 7.2% over the same period in the prior year.

Metallurgical coal continues to sell at a significant premium to steam coal, and metallurgical markets remain strong as global steel production grew 5.4% in the first quarter of 2006. We expect to capitalize on the strong global market for metallurgical coal primarily through production and sales of metallurgical coal from our Appalachia operations and our Australian operations. In response to growing international markets, we are establishing a European trading desk.

We are targeting 2006 production of 230 million to 240 million tons and total sales volume of 255 million to 265 million tons, including 12 to 14 million tons of metallurgical coal. As of March 31, 2006, our unpriced volumes for produced tonnage were 5 to 10 million tons, 70 to 80 million tons and 135 to 145 million tons for 2006, 2007 and 2008, respectively.

Management expects strong market conditions and operating performance to overcome external cost pressures, geologic conditions and uncertain port and rail performance. We are experiencing increases in operating costs related to fuel, explosives, steel, tires, contract mining and healthcare, and have taken measures to mitigate the increases in these costs. In addition, historically low long-term interest rates also have a negative impact on expenses related to our actuarially determined, employee-related liabilities. We may also encounter poor geologic conditions, lower third party contract miner or brokerage source performance or unforeseen equipment problems that limit our ability to produce at forecasted levels. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. See “Cautionary Notice Regarding Forward-Looking Statements” for additional considerations 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 6.875% Senior Notes, 5.875% Senior Notes and Senior Secured Credit Facility covenants. We expect to fund all of our capital expenditure requirements with cash generated from operations, and during 2005 and the first quarter of 2006 have had no borrowings outstanding under our $900.0 million revolving line of credit, which we use primarily for standby letters of credit. This provides us with available borrowing capacity ($490.1 million as of March 31, 2006) to use to fund strategic acquisitions or meet other financing needs. We were in compliance with all of the covenants of the Senior Secured Credit Facility, the 6.875% Senior Notes and the 5.875% Senior Notes as of March 31, 2006.

Net cash provided by operating activities was $49.1 million in the first quarter of 2006 compared to $97.9 million in the first quarter of 2005. The decrease was primarily related to the timing of working capital needs partially offset by stronger operational performance in 2006.

Net cash used in investing activities was $182.6 million during the first quarter of 2006 compared to $122.4 million used in 2005. The increase reflects higher capital expenditures, the acquisition of an additional interest in a joint venture, and lower proceeds from the disposal of assets in 2006. The additional capital expenditures included longwall equipment and mine development at our Australian mines, longwall replacement at our Twentymile mine, the opening of new mines and upgrading of existing mines in the Midwest and Appalachia, and the purchase of expansion equipment. Many of these projects began in the fourth quarter of 2005. In the first quarter of 2005, we acquired mining assets, including 70 million tons of Illinois and Indiana coal reserves, surface properties and equipment, from Lexington Coal Company for $61.0 million with cash used in investing activities including $56.5 million of the outlay as it related to reserves and equipment. Proceeds from the disposal of assets in 2005 primarily reflects the sale of our remaining 0.838 million PVR units, while the 2006 proceeds primarily reflect the sale of non-strategic land and coal reserves.

Net cash used in financing activities was $19.6 million during the first quarter of 2006 compared to cash provided by financing activities of $16.1 million in the prior year. In 2006, we repurchased 250,000 shares of our common stock under a Board approved repurchase program, utilizing $11.5 million. The 2006 activity compared to 2005 reflects higher dividend payments of $6.1 million, lower proceeds from the exercise of stock options of $6.3 million, and a $13.1 million tax benefit related to stock option exercises

included in financing activity based on the newly adopted accounting standard for share-based compensation (see “Newly Adopted Accounting Pronouncements” below for more discussion about the adoption of this standard). In 2005, this tax benefit related to stock option exercises was included in operating activities. The 2005 activity also reflects an increase in the usage of our accounts receivable securitization program by $25.0 million.

In the first quarter of 2006, Moody’s Investor Services upgraded our corporate rating to Ba1 from Ba2 and the senior unsecured rating to Ba2 from Ba3, citing our leading coal reserve position, cost efficiency and profitability, financial policies, financial strength, business diversity and size. These security ratings reflect the views of the rating agency only. An explanation of the significance of these ratings may be obtained from the rating agency. Such ratings are not a recommendation to buy, sell or hold securities, but rather an indication of creditworthiness. Any rating can be revised upward or downward or withdrawn at any time by a rating agency if it decides that the circumstances warrant the change. Each rating should be evaluated independently of any other rating.

Contractual Obligations

At March 31, 2006, we had $140.9 million of purchase obligations for capital expenditures and $598.1 million of obligations related to federal coal reserve lease payments. At March 31, 2006, total capital expenditures for 2006 are expected to range from $450 million to $525 million, excluding federal coal reserve lease payments. Approximately 60% of projected 2006 capital expenditures relates to replacement, improvement, or expansion of existing mines, particularly in Appalachia and the Midwest. Approximately $9 million of the expenditures relate to safety equipment that will be utilized to comply with recently issued federal and state regulations. The remainder of the expenditures relate to growth initiatives such as increasing capacity in the Powder River Basin. We anticipate funding these capital expenditures primarily 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 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.

In March 2000, we established an accounts receivable securitization program. Under the program, undivided interests in a pool of eligible trade receivables that have been contributed to our wholly-owned, bankruptcy-remote subsidiary are sold, without recourse, to a multi-seller, asset-backed commercial paper conduit (“Conduit”). Purchases by the Conduit are financed with the sale of highly rated commercial paper. We used proceeds from the sale of the accounts receivable to repay long-term debt, effectively reducing our overall borrowing costs. The securitization program is scheduled to expire in September 2009, and the maximum amount of undivided interests in accounts receivable that may be sold to the Conduit is $225.0 million. The securitization transactions have been recorded as sales, with those accounts receivable sold to the Conduit removed from the consolidated balance sheet. The amount of undivided interests in accounts receivable sold to the Conduit was $225.0 million as of March 31, 2006 and December 31, 2005.

In March 2006, we issued a guarantee for certain equipment lease arrangements with maximum potential future payments totaling $3.3 million and with lease terms that extend to April 2010. There were no other material changes to our off-balance sheet arrangements during the quarter ended March 31, 2006. See Note 10 to our unaudited condensed consolidated financial statements included in this report for a discussion of our guarantees. All off-balance sheet arrangements are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our 2005 Annual Report on Form 10-K.

Newly Adopted Accounting Pronouncements

We adopted EITF Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry,” on January 1, 2006 and utilized the cumulative effect adjustment approach whereby a cumulative effect adjustment reduced retained earnings by $150.3 million, net of tax. EITF Issue No. 04-6 states “that stripping costs incurred during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred.” Advance stripping costs include those costs necessary to remove overburden above an unmined coal seam as part of the surface mining process and prior to the adoption were included as the “work-in-process” component of “Inventories” in the consolidated balance sheet. 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, and therefore, advance stripping costs will no longer be included as a separate component of inventory.

On January 1, 2006, we adopted 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.” We 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. SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their fair values. 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.

Prior to January 1, 2006, we applied APB Opinion No. 25 and related interpretations in accounting for our 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 our stock option plans prior to December 31, 2005, as the exercise price was equal to the market price of our stock on the date of the option grants.

For share-based payment instruments excluding restricted stock, we 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 we applied the provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees” during the quarter ended March 31, 2006, we 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 our results of operations during the quarter ended March 31, 2006. 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). We began utilizing restricted stock as part of our equity-based compensation strategy in January 2005. Accounting for restricted stock awards was not changed by the adoption of SFAS 123(R). See Note 5 to our unaudited condensed consolidated financial statements for further discussion of our share-based compensation plans.

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, that we may assume at any point in time.

We account for coal trading using the fair value method, which requires us to reflect financial instruments with third parties, such as forwards, options and swaps, at market value in our consolidated financial statements. Our trading portfolio included forwards at March 31, 2006 and December 31, 2005.

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 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. 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, 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 three months ended March 31, 2006, the actual low, high and average values at risk for our coal trading portfolio were $0.7 million, $2.1 million and $1.4 million, respectively. As of March 31, 2006, the timing of the estimated future realization of the value of our trading portfolio was as follows:


Year of	Percentage
Expiration	of Portfolio
2006		70	%
2007		18	%
2008		12	%
		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 energy producers and marketers and electric utilities. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor the credit extended. 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 the creation of customer trust accounts held for our benefit to serve as collateral in the event of a failure to pay. To reduce our credit exposure related to trading and brokerage activities, we seek to enter into netting agreements with counterparties that permit us to offset receivables and payables with such counterparties. Counterparty risk with respect to interest rate swap and foreign currency forwards and options transactions is not considered to be significant based upon the creditworthiness of the participating financial institutions.

Foreign Currency Risk

We utilize currency forwards to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for 2006 involves hedging approximately 75% of our anticipated, non-capital Australian dollar-denominated expenditures. As of March 31, 2006, we had in place forward contracts designated as cash flow hedges with notional amounts outstanding totaling A$968.9 million of which A$354.9 million, A$348.0 million, A$221.0 million and A$45.0 million will expire in 2006, 2007, 2008, and 2009 respectively. Our current expectation for the remainder of 2006 non-capital, Australian dollar-denominated cash expenditures is approximately $475 million. A change in the Australian dollar/U.S. dollar exchange rate of US$0.01 (ignoring the effects of hedging) would result in an increase or decrease in our “Operating costs and expenses” of $6.3 million per year.

Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. To achieve these objectives, we manage fixed rate debt as a percent of net debt through the use of various hedging instruments. As of March 31, 2006, after taking into consideration the effects of interest rate swaps, we had $835.4 million of fixed-rate borrowings and $542.8 million of variable-rate borrowings outstanding. A one percentage point increase in interest rates would result in an annualized increase to interest expense of $5.4 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 $50.7 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 2005 and 2004. As of March 31, 2006, we had 5 to 10 million tons, 70 to 80 million tons and 135 to 145 million tons for 2006, 2007 and 2008, respectively, of expected production (including steam and metallurgical coal production) available for sale or repricing at market prices. We have an annual metallurgical coal production capacity of 12 to 14 million tons.

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. In addition, we utilize derivative contracts to hedge our commodity price exposure. As of March 31, 2006, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of fuel and explosives.

Notional amounts outstanding under fuel-related contracts, scheduled to expire through 2007, were 36.0 million gallons of heating oil and 18.3 million gallons of crude oil. In addition, we have previously secured fixed price contracts for 7.6 million gallons of fuel. Overall, we have fixed prices for approximately 57% of our anticipated diesel fuel requirements in 2006. We expect to consume 95 to 100 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 $2.3 million.

Notional amounts outstanding under explosives-related swap contracts, scheduled to expire through 2008, were 1.5 million mmbtu of natural gas. We expect to consume 280,000 to 290,000 tons of explosives per year. Through our natural gas hedge contracts, we have fixed prices for approximately 14% of our anticipated explosives requirements for the remainder of 2006. 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 $0.5 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 identified and communicated to senior management on a timely basis. Under the direction of the Chief Executive Officer and Executive Vice President and Chief Financial Officer, management has evaluated our disclosure controls and procedures as of March 31, 2006 and has concluded that the disclosure controls and procedures were effective.

Additionally, during the most recent fiscal quarter, there have been no changes to our internal control over financial reporting that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings.

See Note 9 to the unaudited condensed consolidated financial statements included in Part I, Item 1 of this report relating to certain legal proceedings brought against us by the Navajo Nation, the Hopi and Quapaw Tribes, two class action lawsuits brought on behalf of the residents of the towns of Cardin, Quapaw and Picher, Oklahoma and natural resource damage claims asserted by Oklahoma and several other parties, which information is incorporated by reference herein.

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 (incorporated by reference to Exhibit 3.1 of the Registrant’s Form S-1 Registration Statement No. 333-55412).

3.2		Certificate of Amendment of Third Amended and Restated Certificate of Incorporation of Peabody Energy Corporation (Incorporated by reference to Exhibit 3.3 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, filed on August 8, 2005).

3.3		Amended and Restated By-Laws of the Registrant (Incorporated by reference to Exhibit 3.2 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004, filed on March 16, 2005).

4.1		6⁷/₈% Senior Notes Due 2013 Eighth Supplemental Indenture, dated as of January 20, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.14 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005, filed on March 6, 2006).

4.2		5⁷/₈% Senior Notes Due 2016 Sixth Supplemental Indenture, dated as of January 20, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as trustee (Incorporated by reference to Exhibit 4.21 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2005, filed on March 6, 2006).

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 Executive Vice President and 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 Executive Vice President and Chief Financial Officer.


*		Filed herewith.


	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


					Total Number of
	Total				Shares Purchased		Maximum Number
	Number of		Average		as Part of Publicly		of Shares that May
	Shares		Price per		Announced		Yet Be Purchased
Period	Purchased		Share		Program		Under the Program
January 1 through January 31, 2006		—		—		—		13,105,563
February 1 through February 28, 2006		—		—		—		13,105,563
March 1 through March 31, 2006		250,000	$	45.93		250,000		12,855,563

Total		250,000	$	45.93		250,000



	PEABODY ENERGY CORPORATION

Date: May 9, 2006	By:	/s/ RICHARD A. NAVARRE

		Richard A. Navarre
		Executive Vice President and Chief Financial Officer
		(On behalf of the registrant and as Principal Financial Officer)

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