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~~September 30, 2005~~to

Commission File ~~Number~~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~~
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.	þ ~~Yes~~	o No

~~Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).~~	þ ~~Yes~~	o No

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

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements.

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED INCOME STATEMENTS ~~OF OPERATIONS~~

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


	Quarter Ended						Nine Months Ended
	September 30,						September 30,							Quarter Ended March 31,
	2005			2004			2005			2004				2006			2005
REVENUES
Sales	$	1,191,282		$	895,156		$	3,343,620		$	2,538,189			$	1,288,906		$	1,062,521
Other revenues		32,228			23,833			66,156			69,864				22,904			14,959

Total revenues		1,223,510			918,989			3,409,776			2,608,053				1,311,810			1,077,480

COSTS AND EXPENSES
Operating costs and expenses		987,503			735,618			2,781,859			2,143,080				1,022,342			912,979
Depreciation, depletion and amortization		77,159			70,132			232,421			202,992				80,964			75,953
Asset retirement obligation expense		7,394			10,146			23,751			31,810				7,215			9,195
Selling and administrative expenses		57,009			33,623			135,440			93,559				46,526			37,760
Other operating income:
Net gain on disposal or exchange of assets		(47,577	)		(1,790	)		(95,151	)		(14,145	)
Net gain on disposal of assets															(9,226	)		(31,122	)
Income from equity affiliates		(8,863	)		(2,645	)		(29,541	)		(13,698	)			(7,252	)		(8,088	)
													��

OPERATING PROFIT		150,885			73,905			360,997			164,455				171,241			80,803
Interest expense		25,327			24,926			76,088			70,849				27,400			25,556
Early debt extinguishment gains		—			(556	)		—			(556	)
Interest income		(3,218	)		(1,084	)		(6,401	)		(3,212	)			(2,606	)		(1,373	)


INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS		128,776			50,619			291,310			97,374				146,447			56,620
Income tax provision (benefit)		14,714			6,933			29,300			(13,863	)
Income tax provision															11,566			4,424
Minority interests		722			247			1,526			900				4,659			306


INCOME FROM CONTINUING OPERATIONS		113,340			43,439			260,484			110,337
Loss from discontinued operations, net of income tax benefit of $1 and $1,893, respectively		—			(2	)		—			(2,839	)


NET INCOME	$	113,340		$	43,437		$	260,484		$	107,498			$	130,222		$	51,890


BASIC EARNINGS PER SHARE
Income from continuing operations	$	0.86		$	0.34		$	1.99		$	0.90
Loss from discontinued operations		—			—			—			(0.02	)
EARNINGS PER SHARE:
Basic														$	0.49		$	0.20
Diluted														$	0.48		$	0.19

Net income	$	0.86		$	0.34		$	1.99		$	0.88


WEIGHTED AVERAGE SHARES OUTSTANDING — BASIC		131,216,197			128,557,174			130,795,861			122,708,532


DILUTED EARNINGS PER SHARE
Income from continuing operations	$	0.84		$	0.33		$	1.95		$	0.88
Loss from discontinued operations		—			—			—			(0.02	)

Net income	$	0.84		$	0.33		$	1.95		$	0.86


WEIGHTED AVERAGE SHARES OUTSTANDING — DILUTED		134,260,988			131,558,064			133,855,704			125,641,992

WEIGHTED AVERAGE SHARES OUTSTANDING:
Basic															263,491,072			260,693,518
Diluted															269,358,728			266,801,306

DIVIDENDS DECLARED PER SHARE	$	0.095		$	0.0625		$	0.245		$	0.1875			$	0.06		$	0.0375

PEABODY ENERGY CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

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


	(Unaudited)						(Unaudited)
	September 30, 2005			December 31, 2004			March 31, 2006			December 31, 2005
ASSETS
Current assets
Cash and cash equivalents	$	478,741		$	389,636		$	350,160		$	503,278
Accounts receivable, less allowance for doubtful accounts of $19,995 at September 30, 2005 and $1,361 at December 31, 2004		236,538			193,784
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		368,850			323,609			175,049			389,771
Assets from coal trading activities		85,554			89,165			77,638			146,596
Deferred income taxes		15,050			15,461			9,027			9,027
Other current assets		84,430			42,947			75,167			54,431

Total current assets		1,269,163			1,054,602			925,908			1,324,644
Property, plant, equipment and mine development, net of accumulated depreciation, depletion and amortization of $1,543,759 at September 30, 2005 and $1,333,645 at December 31, 2004		5,014,029			4,781,431
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		371,603			342,559			316,294			349,654

Total assets	$	6,654,795		$	6,178,592		$	6,627,373		$	6,852,006


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current maturities of long-term debt	$	23,031		$	18,979		$	77,906		$	22,585
Liabilities from coal trading activities		67,398			63,565			63,655			132,373
Accounts payable and accrued expenses		809,956			691,600			792,409			867,965

Total current liabilities		900,385			774,144			933,970			1,022,923

Long-term debt, less current maturities		1,384,263			1,405,986			1,332,526			1,382,921
Deferred income taxes		419,621			393,266			231,669			338,488
Asset retirement obligations		398,979			396,022			402,361			399,203
Workers’ compensation obligations		233,127			227,476			238,434			237,574
Accrued postretirement benefit costs		945,670			939,503			964,582			959,222
Other noncurrent liabilities		333,790			315,694			351,942			330,658

Total liabilities		4,615,835			4,452,091			4,455,484			4,670,989
Minority interests		1,685			1,909			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 September 30, 2005 or December 31, 2004		—			—
Series Common Stock — $0.01 per share par value; 40,000,000 shares authorized, no shares issued or outstanding as of September 30, 2005 or December 31, 2004		—			—
Series A Junior Participating Preferred Stock — 1,500,000 shares authorized, no shares issued or outstanding as of September 30, 2005 or December 31, 2004		—			—
Common Stock — $0.01 per share par value; 400,000,000 shares authorized, 131,676,733 shares issued and 131,415,553 shares outstanding as of September 30, 2005 and 150,000,000 shares authorized, 129,829,134 shares issued and 129,567,954 shares outstanding as of December 31, 2004		1,316			1,298
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		1,491,038			1,437,319			1,523,662			1,497,454
Retained earnings		579,411			350,968			693,107			729,086
Unearned restricted stock awards		(6,323	)		(459	)
Accumulated other comprehensive loss		(24,251	)		(60,618	)		(44,931	)		(46,795	)
Treasury shares, at cost: 261,180 shares as of September 30, 2005 and December 31, 2004		(3,916	)		(3,916	)
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		2,037,275			1,724,592			2,159,096			2,178,467

Total liabilities and stockholders’ equity	$	6,654,795		$	6,178,592		$	6,627,373		$	6,852,006

PEABODY ENERGY CORPORATION

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)


	Nine Months Ended
	September 30,						Quarter Ended March 31,
	2005			2004			2006			2005
Cash Flows from Operating Activities
Net income	$	260,484		$	107,498		$	130,222		$	51,890
Loss from discontinued operations		—			2,839

Income from continuing operations		260,484			110,337
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		232,421			202,992			80,964			75,953
Deferred income taxes		28,406			(24,273	)		(12,864	)		1,252
Early debt extinguishment gains		—			(556	)
Amortization of debt discount and debt issuance costs		5,177			6,097			1,815			1,795
Net gain on disposal or exchange of assets		(95,151	)		(14,145	)
Net gain on disposal of assets								(9,226	)		(31,122	)
Income from equity affiliates		(29,541	)		(13,698	)		(7,252	)		(8,088	)
Dividends received from equity affiliates		6,082			5,164			5,442			716
Changes in current assets and liabilities:
Stock compensation								4,102			404
Changes in current assets and liabilities, net of acquisitions:
Accounts receivable, net of sale		(67,754	)		(5,476	)		10,853			(18,680	)
Inventories		(46,204	)		(56,565	)		(29,918	)		(21,953	)
Net assets from coal trading activities		7,444			(7,667	)		240			1,372
Other current assets		(18,625	)		(7,655	)		(15,708	)		(3,664	)
Accounts payable and accrued expenses		119,229			46,076			(97,991	)		37,800
Asset retirement obligations		(4,082	)		(5,238	)		22			1,534
Workers’ compensation obligations		6,943			6,335			860			1,933
Accrued postretirement benefit costs		6,167			(27,666	)		5,360			3,874
Contributions to pension plans		(6,275	)		(61,380	)
Other, net		17,448			(177	)		(17,869	)		2,911

Net cash provided by operating activities		422,169			152,505			49,052			97,927

Cash Flows from Investing Activities
Additions to property, plant, equipment and mine development		(346,703	)		(148,345	)		(87,459	)		(46,950	)
Federal coal lease expenditures								(59,829	)		(63,540	)
Purchase of mining assets		(56,500	)		—			—			(56,500	)
Additions to advance mining royalties		(9,061	)		(11,560	)		(2,250	)		(3,135	)
Acquisitions, net		—			(426,265	)		(44,538	)		—
Investment in joint venture		(2,000	)		—
Proceeds from disposal of assets		71,185			24,623			11,488			47,731

Net cash used in investing activities		(343,079	)		(561,547	)		(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		11,459			250,000			750			—
Payments of long-term debt		(15,621	)		(28,749	)
Net proceeds from equity offering		—			383,125
Proceeds from stock options exercised		19,958			19,274
Proceeds from employee stock purchases		3,010			2,343
Increase of securitized interests in accounts receivable		25,000			100,000
Payment of debt issuance costs		—			(8,922	)
Distributions to minority interests		(1,750	)		(818	)
Dividends paid		(32,041	)		(22,878	)

Net cash provided by financing activities		10,015			693,375
Net cash provided by (used in) financing activities								(19,582	)		16,056

Net increase in cash and cash equivalents		89,105			284,333
Net decrease in cash and cash equivalents								(153,118	)		(8,411	)
Cash and cash equivalents at beginning of period		389,636			117,502			503,278			389,636

Cash and cash equivalents at end of period	$	478,741		$	401,835		$	350,160		$	381,225

PEABODY ENERGY CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~SEPTEMBER 30, 2005~~MARCH 31, 2006

(1) Basis of Presentation

The ~~condensed~~ 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 ~~March 30, 2005,~~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 ~~split.~~splits.

The accompanying condensed consolidated financial statements as of ~~September 30, 2005~~March 31, 2006 and for the quarters ended March 31, 2006 and ~~nine months ended September 30,~~ 2005, ~~and 2004,~~ 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, ~~2004~~2005 has been derived from the Company’s audited consolidated balance sheet. The results of operations for the quarter ~~and nine months~~ ended ~~September 30, 2005~~March 31, 2006 are not necessarily indicative of the results to be expected for future quarters or for the year ending December 31, ~~2005.~~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) ~~New Pronouncements~~

After the March 17, 2005 Emerging Issues Task Force (“EITF”) meeting, the Task Force issued EITF Issue 04-6, “Accounting for Stripping Costs in the Mining Industry,” stating “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 are included as the “work-in-process” component of “Inventories” in the condensed consolidated balance sheets ($230.2 million and $197.2 million as of September 30, 2005 and December 31, 2004, respectively — see Note 6). This is consistent with the concepts embodied in Accounting Research Bulletin No. 43, “Restatement and Revision of Accounting Research Bulletins,” which provides that “the term inventory embraces goods awaiting sale . . . , goods in the course of production (work in process), and goods to be consumed directly or indirectly in production . . . .” At the June 15-16, 2005 EITF meeting, the Task Force clarified that the intended meaning of “inventory produced” is “inventory extracted.” Based on this clarification, stripping costs incurred during a period will be attributed only to the inventory costs of the coal that is extracted during that same period.

EITF Issue 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005 (January 1, 2006 for the Company), with early adoption permitted. At the June EITF meeting, the Task Force modified the transition provisions of EITF Issue 04-6, indicating that companies that adopt in periods beginning after June 29, 2005 may utilize a cumulative effect adjustment approach where the cumulative effect adjustment is recorded directly to retained earnings in the year of adoption. If the Company had implemented the cumulative effect adjustment approach at September 30, 2005, the entry to reduce retained earnings, net of tax, would have been $141.9 million. Alternatively, a company may recognize this change in accounting by restatement of its prior-period financial statements through retrospective application. The Company is currently evaluating which method of adoption it will use. The Company expects to adopt EITF Issue 04-6 on January 1, 2006.

The Financial Accounting Standards Board (“FASB”) issued FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations” in March of 2005. FIN 47 clarifies that an entity must record a liability for a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. This interpretation also clarifies the circumstances under which an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

years ending after December 15, 2005. The Company expects to adopt this interpretation on December 31, 2005. The adoption of this interpretation will not have a material impact on the Company’s financial condition, results of operations or cash flows.

The Securities and Exchange Commission has deferred the adoption date of Statement of Financial Accounting Standard (“SFAS”) No. 123R, “Share-Based Payment,” to the beginning of fiscal years that begin after June 15, 2005 (January 1, 2006 for calendar year companies). SFAS No. 123R requires the recognition of share-based payments, including employee stock options, in the income statement based on their fair values. The Company expects to adopt this standard on January 1, 2006. Based on stock option grants made in 2005 and currently anticipated for 2006, the Company estimates it will (assuming the modified prospective method is used) recognize stock option expense for the year ending December 31, 2006 of $4.5 million, net of taxes. The Company began utilizing restricted stock as part of its equity-based compensation strategy in January 2005. Based on the restricted stock grants made in 2005 and years prior, and those currently anticipated for 2006, the Company estimates it will recognize expense related to restricted stock of $1.0 million, net of taxes, in 2005 and $2.2 million, net of taxes, in 2006. The Company recognized expense for the nine months ended September 30, 2005 of $0.7 million, net of taxes, for restricted stock grants made in 2005 and years prior.

~~(3)~~ Significant Transactions and Events

~~Gains on Disposal or Exchange of Assets~~

In the third quarter of 2005, the Company exchanged certain idle steam coal reserves for steam and metallurgical coal reserves as part of a contractual dispute settlement. The exchange resulted in a $37.4 million gain as further discussed below and in Note 12. Also in the third quarter of 2005, the Company recognized a $6.2 million gain from an exchange transaction involving the acquisition of Illinois Basin coal reserves in exchange for coal reserves, cash, notes, and the Company’s 45% equity interest in a partnership. The exchanges were accounted for at fair value in accordance with the provisions of Accounting Principles Board (“APB”) Opinion No. 29, “Accounting for Nonmonetary Transactions,” as modified by SFAS No. 153, “Exchanges of Nonmonetary Assets — an amendment of APB Opinion No. 29” and EITF 01-2, “Interpretations of APB Opinion No. 29.”

In the second quarter of 2005, the Company recognized an aggregate $12.5 million gain from three property sales involving non-strategic coal assets and properties which included a reduction of asset retirement obligations of $9.2 million.

InDuring 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. InAlso in the first quarter of 2004, the Company sold 0.575 million PVR units for net proceeds of $18.5 million and recognized a $9.9 million gain on the sale. The sales of the PVR units were accounted for under SFAS No. 66, “Sales of Real Estate.” In December 2002, the Company entered into a transaction with PVR whereby the Company sold 120 million tons of coal reserves in exchange for $72.5 million in cash and 2.76 million units of the PVR master limited partnership. The Company’s subsidiaries leased back the coal and pay royalties as the coal is mined. No gain or loss was recorded at the inception of this transaction. At the time of the original transaction, a deferred gain from the sales of the reserves and units of $19.0 million remained and is being amortized over the minimum term of the leases. As of September 30, 2005, the deferred gain related to the PVR transactions was $17.4 million.

~~Contract Losses~~

~~During the first six months~~ of 2005, the Company recorded ~~net~~ contract losses of ~~$10.7~~approximately $34 million, primarily related to ~~the~~ breach of a coal supply contract by a producer. The estimated loss related to the supply contract breach reflected amounts accrued for estimated costs to obtain replacement coal in the current market (in excess of the estimated revenue expected to be earned on the brokerage sales).

~~In the third quarter of 2005, the Company completed settlement of the~~contractual dispute ~~and the related lawsuit~~ was dismissed (see further discussion in Note 12). Under the settlement, the Company received $10.0 million in cash, a new coal supply agreement that partially replaced the disputed coal supply agreement, and exchanged certain coal

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

properties. As a result of the final settlement and based on the fair values of the items exchanged in the overall settlement transaction, the Company further reduced its contract losses by $6.7 million and, as discussed above, recorded gains on assets exchanged of $37.4 millionfully resolved in the third quarter of 2005.

~~(4) Acquisition of Mining Assets~~

In March 2005, the Company purchased mining assets from Lexington Coal Company for $61.0 million, $59.0 million of which was paid on the closing date and up to $2.0 million is to be paid within 12 months of the close pending no outstanding claims related to the acquired mining assets. The purchased assets included $2.5 million of materials and supplies that were recorded in “Inventories” in the condensed consolidated balance sheet. The remaining purchased assets consisted of approximately 70 million tons of reserves, preparation plants, facilities and mining equipment that were recorded in “Property, plant, equipment and mine development” in the condensed consolidated balance sheet. The Company is using the acquired assets to open a new mine that is expected to produce 2 to 3 million tons per year, after it reaches full capacity, and to provide other synergies to existing properties. The new mine, which began production early in the third quarter, will supply coal under a new agreement with terms that can be extended through 2015 (and a minimum term through the end of 2008). The Company also recorded $21.6 million for the estimated asset retirement obligations associated with the acquired assets.

~~(5) Business Combinations~~

On April 15, 2004, the Company purchased, through two separate agreements, all of the equity interests in three coal operations from RAG Coal International AG. The combined purchase price, including related costs and fees, of $442.2 million was funded from the Company’s equity and debt offerings in March 2004. Net proceeds from the equity and debt offerings were $383.1 million and $244.7 million, respectively. The purchases included two mines in Queensland, Australia that collectively produce 7 to 8 million tons per year of metallurgical coal and the Twentymile Mine in Colorado, which produces 8 to 9 million tons per year of steam coal with a planned production expansion up to 12 million tons per year by 2008. The results of operations of the two mines in Queensland, Australia are included in the Company’s Australian Mining Operations segment and the results of operations of the Twentymile Mine are included in the Company’s Western U.S. Mining Operations segment. The acquisition was accounted for as a purchase.

The purchase accounting allocations related to the acquisition have been finalized and recorded in the accompanying condensed consolidated financial statements. The following table summarizes the fair values of the assets acquired and the liabilities assumed at the date of acquisition (dollars in thousands):

Accounts receivable $ 46,639
Materials and supplies 5,669
Coal inventory 11,543
Other current assets 6,234
Property, plant, equipment and mine development, net 463,567
Accounts payable and accrued expenses (48,688 )
Other noncurrent assets and liabilities, net (63,699 )

Total purchase price, net of cash received of $20,914 $ 421,265

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

The following unaudited pro forma financial information presents the combined results of operations of the Company and the operations acquired from RAG Coal International AG, on a pro forma basis, as though the companies had been combined as of the beginning of the period presented. The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the Company and the operations acquired from RAG Coal International AG constituted a single entity during this period (dollars in thousands, except per share data):

Nine Months Ended
September 30, 2004 *
Revenues:
As reported $ 2,608,053
Pro forma 2,733,415

Income from continuing operations:
As reported $ 110,337
Pro forma 107,696

Net income:
As reported $ 107,498
Pro forma 104,857

Basic earnings per share — net income:
As reported $ 0.88
Pro forma 0.82

Diluted earnings per share — net income:
As reported $ 0.86
Pro forma 0.80


*		During the first quarter of 2004, prior to the Company’s acquisition, the Australian underground mine acquired by the Company in April 2004 experienced a roof collapse on a portion of the active mine face, resulting in the temporary suspension of mining activities. Due to the inability to ship during a portion of this downtime, costs to return the mine to operations and shipping limits imposed as the result of unrelated restrictions of capacity at a third party loading facility, the Australian operation experienced a pro forma net loss in the quarter immediately prior to acquisition.

~~(6)~~(3) Inventories

Inventories consisted of the following (dollars in thousands):


	September 30,		December 31,		March 31,		December 31,
	2005		2004		2006		2005
Saleable coal					$	88,652	$	64,274
Materials and supplies	$	64,718	$	57,467		73,476		65,942
Raw coal		15,174		17,590		12,921		14,033
Advance stripping		230,154		197,225		—		245,522
Saleable coal		58,804		51,327

Total	$	368,850	$	323,609	$	175,049	$	389,771

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 ~~nine months ended September 30,~~valuations of the 2005 and ~~2004, respectively.~~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 ~~as if~~had compensation cost ~~had~~ 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				Nine Months Ended
	September 30,				September 30,				Quarter Ended
	2005		2004		2005		2004		March 31, 2005
Net income:
As reported	$	113,340	$	43,437	$	260,484	$	107,498	$	51,890
Pro forma		112,041		42,131		256,500		103,971		50,566

Basic earnings per share:
As reported	$	0.86	$	0.34	$	1.99	$	0.88	$	0.20
Pro forma		0.85		0.33		1.96		0.85		0.19

Diluted earnings per share:
As reported	$	0.84	$	0.33	$	1.95	$	0.86	$	0.19
Pro forma		0.83		0.32		1.92		0.83		0.19

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

~~Cash Flows~~

The Company disclosed in its financial statements for the year ended December 31, 2004 that it expected to pay $85.7 million attributable to its postretirement benefit plans during 2005. For the nine months ended September 30, 2005, payments of $63.6 million attributable to the Company’s postretirement benefit plans have been made, and the Company does not anticipate any significant changes to its original estimate for 2005.

~~(11)~~(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 ~~primarily~~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 ~~continuing~~ operations before deducting ~~early debt extinguishment costs,~~ net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization.

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

Operating segment results for the quarters ended March 31, 2006 and ~~nine months ended September 30,~~ 2005 ~~and 2004~~ are as follows (dollars in thousands):


	Quarter Ended						Nine Months Ended
	September 30,						September 30,						Quarter Ended March 31,
	2005			2004			2005			2004			2006			2005
Revenues:
Western U.S. Mining⁽¹⁾	$	403,214		$	373,629		$	1,184,445		$	1,021,660
Western U.S. Mining													$	432,090		$	404,436
Eastern U.S. Mining		452,825			344,938			1,315,480			1,057,169			514,463			424,892
Australian Mining		146,146			92,562			390,314			174,000			152,999			103,525
Trading and Brokerage		216,098			105,205			506,960			346,589			207,015			141,569
Corporate and Other		5,227			2,655			12,577			8,635			5,243			3,058

Total	$	1,223,510		$	918,989		$	3,409,776		$	2,608,053		$	1,311,810		$	1,077,480


Adjusted EBITDA:
Western U.S. Mining⁽¹⁾	$	104,213		$	113,874		$	330,277		$	297,631
Adjusted EBITDA⁽¹⁾:
Western U.S. Mining													$	127,793		$	120,425
Eastern U.S. Mining		96,865			54,911			287,569			182,332			132,544			94,806
Australian Mining		39,780			20,777			101,345			33,655			47,756			14,086
Trading and Brokerage⁽²⁾		26,132			16,053			19,703			36,728			16,179			(21,868	)
Corporate and Other⁽³⁾		(31,552	)		(51,432	)		(121,725	)		(151,089	)		(64,852	)		(41,498	)

Total	$	235,438		$	154,183		$	617,169		$	399,257		$	259,420		$	165,951

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 ~~Company’s subsidiary, COALTRADE, LLC (“COALTRADE”), filed~~state of Oklahoma on behalf of itself and several other parties sent a ~~lawsuit against Massey Coal Sales Company, Inc. (“Massey”)~~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 ~~Eastern~~Northern District of ~~Kentucky related~~Oklahoma.

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 ~~disputed~~long-term coal supply agreement through its Black Mesa Mine. The mine terminated operations on December 31, 2005, and ~~Massey~~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 ~~counterclaim.~~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 ~~quarter ended September 30, 2005,~~period that the Company ~~and Massey completed a settlement agreement and mutual release,~~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 ~~lawsuit was dismissed. See Note 3 for more details on~~Company believes there will be sufficient cash flow to pay the ~~negotiated settlement.~~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~~remove or mitigate the effects on the environment at various sites from the disposal or release of certain substances;

	•		~~Perform~~perform remediation work at such sites; and

	•		~~Pay~~pay damages for loss of use and non-use values.

Environmental claims have been asserted against ~~a subsidiary of the Company,~~ Gold Fields ~~Mining, LLC (“Gold Fields”),~~ related to activities of Gold Fields or its former ~~subsidiaries.~~affiliates. Gold Fields is a dormant, non-coal producing entity that was previously managed and owned by Hanson PLC, a predecessor owner of the Company. In the February 1997 spin-off of its energy businesses, 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

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~its past operations. The Company~~ has been named a potentially responsible party (“PRP”) based on CERCLA at five sites, and ~~other~~ claims have been asserted at 1718 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 ~~the Company’s~~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 ~~potentially responsible parties~~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 ~~or other potentially responsible third parties~~ in the estimation of liabilities recorded onin its ~~condensed~~ consolidated balance sheets. Undiscounted liabilities for environmental cleanup-related costs for all of the sites noted above totaled ~~$39.5~~$42.1 million at ~~September 30, 2005~~March 31, 2006 and ~~$40.5~~$42.5 million at December 31, ~~2004, $14.1~~2005, $23.2 million and ~~$15.1~~$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 ~~PRP’s~~PRPs received a letter from the U.S. Department of Justice ~~seeking to initiate settlement discussions relating to residential yard cleanup costs incurred by~~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.~~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 ~~1950’s~~1950s and mined, in accordance with lease agreements and permits, approximately ~~1.7%~~1.5% of the total amount of the ore mined in the county. The Department of Justice alleged that the PRPs’ mining operations caused the EPA to incur approximately $125 million in residential yard remediation costs and will cause the EPA to incur additional remediation costs relating to historic mining sites. 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 ~~below.~~

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. ~~The Company anticipates that the environmental remediation costs it has currently accrued will be paid by the end of 2010.~~

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 itthe Company has sent waste materials, may be subject to liability under Superfund and similar state laws.

~~Oklahoma Lead Litigation~~

Gold Fields and three other companies are defendants in two class action lawsuits filed in the U.S. District Court for the Northern District of Oklahoma (Betty Jean Cole, et al. v. Asarco Inc., et al. and Darlene Evans, et al. v. Asarco Inc., et al.). The plaintiffs have asserted nuisance and trespass claims predicated on allegations of intentional lead exposure by the defendants and are seeking compensatory damages for diminution of property value, punitive damages and the implementation of medical monitoring and relocation programs for the affected individuals. A predecessor of Gold Fields formerly operated two lead mills near Picher, Oklahoma prior to the 1950’s and mined, in accordance with lease agreements and permits, approximately 1.7% of the total amount of the ore mined in the county.

Gold Fields is also a defendant, along with other companies, in five individual lawsuits arising out of the same lead mill operations. In July 2004, two lawsuits were filed, one in the U.S. District Court for the Northern District of Oklahoma and one in Ottawa County, Oklahoma (subsequently removed to the U.S. District Court for the Northern District of Oklahoma), on behalf of 48 individuals against Gold Fields and three other companies (Billy Holder, et al. v. Asarco Inc., et al.). Plaintiffs in these actions are seeking compensatory and punitive damages for

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

~~alleged personal injuries from lead exposure. Previously scheduled trials for individual plaintiffs have been postponed.~~

In December 2003, the Quapaw Indian tribe and certain Quapaw owners of interests in land filed a class action lawsuit against Gold Fields and five other companies in the U.S. District Court for the Northern District of Oklahoma. The plaintiffs are seeking compensatory and punitive damages based on public and private nuisance, trespass, strict liability, natural resource damage claims under CERCLA, and claims under the Resource Conservation and Recovery Act. Gold Fields has denied liability to the plaintiffs, has filed counterclaims against the plaintiffs seeking indemnification and contribution and has filed a third-party complaint against the United States, owners of interests in chat and real property in the Picher area. In February 2005, the state of Oklahoma on behalf of itself and several other parties sent a notice to Gold Fields and other PRP’s alleging that they had concluded that there is a reasonable probability of making a successful claim against the PRP’s for damages to natural resources. Gold Fields believes it has meritorious defenses to these claims.

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 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 the Company’s subsidiaries, Peabody Holding Company, Inc., Peabody Coal Company and 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 and tortious interference with contractual relationships. The complaint alleges that the defendants jointly participated in unlawful activity to obtain favorable coal lease amendments. Plaintiff also alleges that defendants interfered with the fiduciary relationship between the United States and the Navajo Nation. 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 for the Kayenta and Black Mesa mines have terminated due to Peabody Western’s breach of these leases and a reformation of the two coal leases to adjust the royalty rate to 20%. On March 15, 2001, the court allowed the Hopi Tribe to intervene in this lawsuit. The Hopi Tribe has asserted seven claims including fraud and is seeking various remedies including 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. The court rejected the Navajo Nation’s allegation that the United States breached its trust responsibilities to the Tribe in approving the coal lease amendments and was liable for money damages.

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 customers purchasing coal from the Black Mesa and Kayenta mines 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 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.

~~California Public Utilities Commission Proceedings Regarding the Future of the Mohave Generating Station~~

Peabody Western has a long-term coal supply agreement with the owners of the Mohave Generating Station that expires on December 31, 2005. Southern California Edison (the majority owner and operator of the plant) is involved in a California Public Utilities Commission proceeding related to the operation of the Mohave plant beyond 2005 or a temporary or permanent shutdown of the plant. Southern California Edison has stated to the Commission that the Mohave plant is not likely to return to service as a coal-fueled resource until 2010 at the earliest if the plant is shut down at December 31, 2005. There is a dispute with the Hopi Tribe regarding the use of groundwater in the transportation of the coal by pipeline from Peabody Western’s Black Mesa Mine to the Mohave

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

plant. 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 the groundwater dispute and other disputes involving the two generating stations. Resolution of these issues is critical to the continuation of the operation of the Mohave Generating Station and the renewal of the coal supply agreement after December 31, 2005. There is no assurance that the issues critical to the continued operation of the Mohave plant will be resolved. The owners of the Mohave Generating Station entered into a consent decree with the Grand Canyon Trust, the Sierra Club, and the National Parks and Conservation Association that required the owners to install scrubbers by December 31, 2005 if the Mohave plant was to operate beyond that date. In a letter dated May 25, 2005, the Grand Canyon Trust, the Sierra Club, and the National Parks and Conservation Association rejected a request by the Navajo Nation and the Hopi Tribe to extend the December 31, 2005 deadline and therefore, the Mohave plant will suspend operation on December 31, 2005. The Company has issued Worker Adjustment and Retraining Notification (“WARN”) Act notices to its employees at the Black Mesa Mine regarding layoffs at the end of 2005. The Mohave plant is the sole customer of the Black Mesa Mine, which sold 3.5 million tons of coal in the first nine months of 2005 and 4.7 million tons during the year ended December 31, 2004. During the first nine months of 2005, the mine generated $20.3 million of Adjusted EBITDA (reconciled to its most comparable measure under generally accepted accounting principles in Note 11), which represented 3.3% of the Company’s total of $617.2 million. In 2004, the mine contributed $25.2 million of Adjusted EBITDA, or 4.5% of the Company’s total Adjusted EBITDA of $559.2 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.

Peabody Western filed a motion to compel arbitration of these claims, which was granted in part by the trial court. Specifically, the trial court ruled that the mine decommissioning costs were subject to arbitration but that the retiree health care costs were not subject to arbitration. This ruling was subsequently upheld on appeal. As a result, Peabody Western, Salt River Project and the other owners of the Navajo Generating Station will arbitrate the mine decommissioning costs issue and will litigate the retiree health care costs issue. The Company has recorded a receivable for mine decommissioning costs of $72.3 million and $68.6 million included in “Investments and other assets” in the condensed consolidated balance sheets at September 30, 2005 and December 31, 2004, 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 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.

Other

In addition, ~~to the matters described above,~~ 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 iswill not ~~likely to~~ have a material ~~adverse~~ effect on the financial ~~condition,~~position, results of operations or ~~cash flows~~liquidity of the Company.

~~Accounts receivable in the condensed consolidated balance sheets as of September 30, 2005 and December~~At March 31, 2004, includes $19.4 and $18.1 million, respectively, of receivables billed between 2001 and 2005 related to legal fees incurred in the Company’s defense of the Navajo lawsuit discussed above. The billings have been disputed by two customers, who have withheld payment. The Company believes these billings were made properly under the coal supply agreement with each customer. The billings were consistent with past practice, when litigation costs related to legal or regulatory issues were billed under the contracts and paid by the customers. The Company is in litigation with these customers to resolve this issue. In the second quarter of 2005, the trial court in one of the cases dismissed the Company’s claim, and the Company has appealed that decision. Although the Company believes it has meritorious grounds for appeal and has not yet litigated the other claim, the Company has recognized an

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

allowance against both disputed receivables, which resulted in a charge of $13.4 million in the second quarter of 2005 and $16.2 million in the nine months ended September 30, 2005. The receivable balance, net of the allowance, was zero and $18.1 million at September 30, 2005 and December 31, 2004, respectively.

~~At September 30, 2005,~~2006, purchase commitments for capital expenditures were approximately ~~$332.0~~$140.9 million and federal coal reserve lease payments due over the next three years total $598.1 million.

~~(13) 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 September 30, 2005
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
Total revenues $ — $ 959,278 $ 287,688 $ (23,456 ) $ 1,223,510
Costs and expenses:
Operating costs and expenses (12,025 ) 779,477 243,507 (23,456 ) 987,503
Depreciation, depletion and amortization — 68,853 8,306 — 77,159
Asset retirement obligation expense — 8,049 (655 ) — 7,394
Selling and administrative expenses 1,288 53,753 1,968 — 57,009
Other operating income:
Net gain on disposal or exchange of assets — (47,516 ) (61 ) — (47,577 )
Income from equity affiliates — (3,803 ) (5,060 ) — (8,863 )
Interest expense 39,163 13,607 5,463 (32,906 ) 25,327
Interest income (6,255 ) (22,942 ) (6,927 ) 32,906 (3,218 )

Income (loss) before income taxes and minority interests (22,171 ) 109,800 41,147 — 128,776
Income tax provision (benefit) (18,545 ) 24,474 8,785 — 14,714
Minority interests — 722 — — 722

Net income (loss) $ (3,626 ) $ 84,604 $ 32,362 $ — $ 113,340

1813

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

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

Quarter Ended September 30, 2004
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
Total revenues $ — $ 784,385 $ 150,642 $ (16,038 ) $ 918,989
Costs and expenses:
Operating costs and expenses (1,874 ) 633,143 120,387 (16,038 ) 735,618
Depreciation, depletion and amortization — 63,221 6,911 — 70,132
Asset retirement obligation expense — 9,615 531 — 10,146
Selling and administrative expenses 354 32,279 990 — 33,623
Other operating income:
Net (gain) loss on disposal or exchange of assets — (1,795 ) 5 — (1,790 )
Income from equity affiliates — (2,645 ) — — (2,645 )
Interest expense 37,201 13,470 1,184 (26,929 ) 24,926
Early debt extinguishment gains (556 ) — — — (556 )
Interest income (4,594 ) (17,965 ) (5,454 ) 26,929 (1,084 )

Income (loss) before income taxes and minority interests (30,531 ) 55,062 26,088 — 50,619
Income tax provision (benefit) (11,875 ) 9,870 8,938 — 6,933
Minority interests — 247 — — 247

Income (loss) from continuing operations (18,656 ) 44,945 17,150 — 43,439
Loss from discontinued operations, net of taxes — (2 ) — — (2 )

Net income (loss) $ (18,656 ) $ 44,943 $ 17,150 $ — $ 43,437

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

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

Nine Months Ended September 30, 2005
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
Total revenues $ — $ 2,723,601 $ 750,258 $ (64,083 ) $ 3,409,776
Costs and expenses:
Operating costs and expenses (19,416 ) 2,228,185 637,173 (64,083 ) 2,781,859
Depreciation, depletion and amortization — 208,239 24,182 — 232,421
Asset retirement obligation expense — 23,251 500 — 23,751
Selling and administrative expenses 2,836 128,109 4,495 — 135,440
Other operating income:
Net gain on disposal or exchange of assets — (94,994 ) (157 ) — (95,151 )
Income from equity affiliates — (13,445 ) (16,096 ) — (29,541 )
Interest expense 114,939 41,337 16,824 (97,012 ) 76,088
Interest income (16,349 ) (67,657 ) (19,407 ) 97,012 (6,401 )

Income (loss) before income taxes and minority interests (82,010 ) 270,576 102,744 — 291,310
Income tax provision (benefit) (47,764 ) 57,013 20,051 — 29,300
Minority interests — 1,526 — — 1,526

Net income (loss) $ (34,246 ) $ 212,037 $ 82,693 $ — $ 260,484

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

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

Nine Months Ended September 30, 2004
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
Total revenues $ — $ 2,290,416 $ 367,048 $ (49,411 ) $ 2,608,053
Costs and expenses:
Operating costs and expenses (1,883 ) 1,875,566 318,808 (49,411 ) 2,143,080
Depreciation, depletion and amortization — 189,746 13,246 — 202,992
Asset retirement obligation expense — 30,768 1,042 — 31,810
Selling and administrative expenses 910 90,210 2,439 — 93,559
Other operating income:
Net gain on disposal or exchange of assets — (13,791 ) (354 ) — (14,145 )
Income from equity affiliates — (13,698 ) — — (13,698 )
Interest expense 107,367 73,497 2,515 (112,530 ) 70,849
Early debt extinguishment gains (556 ) — — — (556 )
Interest income (47,584 ) (53,746 ) (14,412 ) 112,530 (3,212 )

Income (loss) before income taxes and minority interests (58,254 ) 111,864 43,764 — 97,374
Income tax provision (benefit) (34,056 ) 9,594 10,599 — (13,863 )
Minority interests — 900 — — 900

Income (loss) from continuing operations (24,198 ) 101,370 33,165 — 110,337
Loss from discontinued operations, net of taxes — (2,839 ) — — (2,839 )

Net income (loss) $ (24,198 ) $ 98,531 $ 33,165 $ — $ 107,498

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

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

September 30, 2005
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
ASSETS

Current assets
Cash and cash equivalents $ 470,663 $ 2,182 $ 5,896 $ — $ 478,741
Accounts receivable 5,225 127,647 103,666 — 236,538
Inventories — 312,492 56,358 — 368,850
Assets from coal trading activities — 85,554 — — 85,554
Deferred income taxes — 15,050 — — 15,050
Other current assets 42,446 29,476 12,508 — 84,430

Total current assets 518,334 572,401 178,428 — 1,269,163
Property, plant, equipment and mine development — 5,954,792 602,996 — 6,557,788
Less accumulated depreciation, depletion and amortization — (1,470,169 ) (73,590 ) — (1,543,759 )
Investments and other assets 4,752,269 366,773 50,155 (4,797,594 ) 371,603

Total assets $ 5,270,603 $ 5,423,797 $ 757,989 $ (4,797,594 ) $ 6,654,795

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities
Current maturities of long-term debt $ 10,000 $ 12,149 $ 882 $ — $ 23,031
Payables and notes payable to affiliates, net 1,779,560 (2,236,025 ) 456,465 — —
Liabilities from coal trading activities — 67,398 — — 67,398
Accounts payable and accrued expenses 15,362 700,786 93,808 — 809,956

Total current liabilities 1,804,922 (1,455,692 ) 551,155 — 900,385
Long-term debt, less current maturities 1,313,896 68,715 1,652 — 1,384,263
Deferred income taxes 29,494 366,033 24,094 — 419,621
Other noncurrent liabilities 16,524 1,887,877 7,165 — 1,911,566

Total liabilities 3,164,836 866,933 584,066 — 4,615,835
Minority interests — 1,685 — — 1,685
Stockholders’ equity 2,105,767 4,555,179 173,923 (4,797,594 ) 2,037,275

Total liabilities and stockholders’ equity $ 5,270,603 $ 5,423,797 $ 757,989 $ (4,797,594 ) $ 6,654,795

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

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

December 31, 2004
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Eliminations Consolidated
ASSETS

Current assets
Cash and cash equivalents $ 373,066 $ 3,496 $ 13,074 $ — $ 389,636
Accounts receivable 1,611 86,748 105,425 — 193,784
Inventories — 290,863 32,746 — 323,609
Assets from coal trading activities — 89,165 — — 89,165
Deferred income taxes — 15,050 411 — 15,461
Other current assets 19,737 15,971 7,239 — 42,947

Total current assets 394,414 501,293 158,895 — 1,054,602
Property, plant, equipment and mine development — 5,686,143 428,933 — 6,115,076
Less accumulated depreciation, depletion and amortization — (1,289,947 ) (43,698 ) — (1,333,645 )
Investments and other assets 4,808,202 4,151 33,836 (4,503,630 ) 342,559

Total assets $ 5,202,616 $ 4,901,640 $ 577,966 $ (4,503,630 ) $ 6,178,592

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities
Current maturities of long-term debt $ 5,000 $ 12,971 $ 1,008 $ — $ 18,979
Payables and notes payable to affiliates, net 2,022,037 (2,357,000 ) 334,963 — —
Liabilities from coal trading activities — 63,565 — — 63,565
Accounts payable and accrued expenses 20,120 599,253 72,227 — 691,600

Total current liabilities 2,047,157 (1,681,211 ) 408,198 — 774,144
Long-term debt, less current maturities 1,338,465 65,228 2,293 — 1,405,986
Deferred income taxes 5,250 386,351 1,665 — 393,266
Other noncurrent liabilities 18,658 1,852,684 7,353 — 1,878,695

Total liabilities 3,409,530 623,052 419,509 — 4,452,091
Minority interests — 1,909 — — 1,909
Stockholders’ equity 1,793,086 4,276,679 158,457 (4,503,630 ) 1,724,592

Total liabilities and stockholders’ equity $ 5,202,616 $ 4,901,640 $ 577,966 $ (4,503,630 ) $ 6,178,592

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

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

Nine Months Ended September 30, 2005
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Consolidated
Cash Flows from Operating Activities

Net cash provided by (used in) operating activities $ (114,649 ) $ 469,136 $ 67,682 $ 422,169

Cash Flows from Investing Activities

Additions to property, plant, equipment and mine development — (173,109 ) (173,594 ) (346,703 )
Purchase of mining assets — (56,500 ) — (56,500 )
Additions to advance mining royalties — (9,061 ) — (9,061 )
Investment in joint venture — (2,000 ) — (2,000 )
Proceeds from disposal of assets — 69,353 1,832 71,185

Net cash used in investing activities — (171,317 ) (171,762 ) (343,079 )

Cash Flows from Financing Activities

Proceeds from long-term debt — 11,459 — 11,459
Payments of long-term debt (3,750 ) (11,104 ) (767 ) (15,621 )
Proceeds from stock options exercised 19,958 — — 19,958
Proceeds from employee stock purchases 3,010 — — 3,010
Increase of securitized interests in accounts receivable — — 25,000 25,000
Distributions to minority interests — (1,750 ) — (1,750 )
Dividends paid (32,041 ) — — (32,041 )
Transactions with affiliates, net 225,069 (297,738 ) 72,669 —

Net cash provided by (used in) financing activities 212,246 (299,133 ) 96,902 10,015

Net increase (decrease) in cash and cash equivalents 97,597 (1,314 ) (7,178 ) 89,105
Cash and cash equivalents at beginning of period 373,066 3,496 13,074 389,636

Cash and cash equivalents at end of period $ 470,663 $ 2,182 $ 5,896 $ 478,741

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~

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

Nine Months Ended September 30, 2004
Parent Guarantor Non-Guarantor
Company Subsidiaries Subsidiaries Consolidated
Cash Flows from Operating Activities

Net cash provided by (used in) operating activities $ (43,734 ) $ 134,977 $ 61,262 $ 152,505

Cash Flows from Investing Activities

Additions to property, plant, equipment and mine development — (81,666 ) (66,679 ) (148,345 )
Additions to advance mining royalties — (11,310 ) (250 ) (11,560 )
Acquisitions, net — (190,940 ) (235,325 ) (426,265 )
Proceeds from disposal of assets — 24,069 554 24,623

Net cash used in investing activities — (259,847 ) (301,700 ) (561,547 )

Cash Flows from Financing Activities

Proceeds from long-term debt 250,000 — — 250,000
Payments of long-term debt (13,850 ) (13,236 ) (1,663 ) (28,749 )
Net proceeds from equity offering 383,125 — — 383,125
Proceeds from stock options exercised 19,274 — — 19,274
Proceeds from employee stock purchases 2,343 — — 2,343
Increase of securitized interests in accounts receivable — — 100,000 100,000
Payment of debt issuance costs (8,922 ) — — (8,922 )
Distributions to minority interests — (818 ) — (818 )
Dividends paid (22,878 ) — — (22,878 )
Transactions with affiliates, net (298,710 ) 139,993 158,717 —

Net cash provided by financing activities 310,382 125,939 257,054 693,375

Net increase in cash and cash equivalents 266,648 1,069 16,616 284,333
Cash and cash equivalents at beginning of period 114,575 1,392 1,535 117,502

Cash and cash equivalents at end of period $ 381,223 $ 2,461 $ 18,151 $ 401,835

~~(14)~~(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. ~~The~~As of March 31, 2006, the Company’s maximum reimbursement obligation ~~of $42.8 million~~to the commercial bank is in turn supported by a letter of ~~credit.~~

The Company owns a 49.0% interest in a joint venture that operates an underground mine and preparation plant facility in West Virginia. The partners have severally agreed to guarantee the debt of the joint venture, which consists of a $16.4 million loan facility as of September 30, 2005. The total amount of the joint venture’s debt guaranteed by the Company was $8.0 million as of September 30, 2005.

~~NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued~~credit totaling $42.8 million.

The Company has guaranteed the performance of Asset Management Group (“AMG”) under ~~their~~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 ~~September 30, 2005,~~March 31, 2006, the maximum potential future payments under this guarantee are approximately $7$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 ~~their proven~~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 (see Note 3).~~reserves. The ~~aggregate~~total amount guaranteed by the Company was ~~$4.4~~$6.3 million, and the fair value of the guarantees recognized as a liability was $0.4 million as of ~~September 30, 2005.~~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 ~~13.~~

~~(15) Risk Management and Financial Instruments~~

The Company enters into both derivative and non-derivative contracts to manage its exposure to the price volatility of diesel fuel. Fuel costs make up between three and four percent of the Company’s total operating costs and expenses. As of September 30, 2005, the Company had designated derivative contracts as cash flow hedges with notional amounts totaling 69.0 million gallons (44.9 million gallons of heating oil and 24.1 million gallons of crude oil), with maturities extending from the fourth quarter of 2005 through the end of 2007. The condensed consolidated balance sheets as of September 30, 2005 and December 31, 2004 reflect unrealized gains on the derivatives designated as cash flow hedges of $54.2 million and $5.8 million, respectively, which is recorded net of tax provisions of $21.7 million and $2.3 million, respectively, in “Accumulated other comprehensive loss.”

The Company accounts for its fuel hedge derivative instruments as cash flow hedges, as defined in SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Under SFAS No. 133, all derivatives designated as hedges that meet certain requirements are granted hedge accounting treatment. Generally, utilizing the hedge accounting, all periodic changes in fair value of the derivatives designated as hedges that are considered to be effective, as defined, are recorded in “Accumulated other comprehensive income (loss)” until the underlying diesel fuel is consumed. However, the Company is exposed to the risk that periodic changes will not be effective, as defined, or that the derivatives will no longer qualify for hedge accounting.

To the extent that the periodic changes in the fair value of the derivatives are not effective, or if the hedge ceases to qualify for hedge accounting, those periodic non-cash changes are recorded as ineffectiveness to “Operating costs and expenses” in the income statement in the period of the change. During the quarter ended11.

2614

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

~~September 30, 2005,~~(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 ~~recognized approximately $0.1 million of lower operating costs~~have fully and ~~expenses related~~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 ~~ineffectiveness~~holders of ~~its hedges.~~

~~Ineffectiveness is inherent in hedging diesel fuel with derivative positions based on other crude oil related commodities. Due to~~ the ~~volatility in markets for crude oil, and crude oil related products,~~6.875% Senior Notes and the ~~current refining spreads that have widened~~5.875% Senior Notes. The following unaudited condensed historical financial statement information is provided for the ~~price spread between crude oil and other petroleum distillates (such as diesel fuel), the Company is unable to predict the amount~~Guarantor/Non-Guarantor Subsidiaries.

Peabody Energy Corporation

Unaudited Supplemental Condensed Consolidated Statements of ~~ineffectiveness each period, including the loss~~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 ~~hedge accounting (which could be determined on a derivative by derivative basis or~~Operations
(Dollars in ~~the aggregate), which may result~~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 ~~increased volatility~~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 ~~the Company’s results.~~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

2718

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;

	•		~~regulatory~~legislation, regulations and court decisions;

	•		~~future legislation;~~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;~~products and in our trading and brokerage businesses;

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

	•		availability and costs of key supplies ~~and~~or commodities such as diesel fuel, steel, explosives and tires;

	•		reductions of purchases by major customers;

	•		geology, equipment and ~~equipment~~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 ~~effects~~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 Part II, Item 1, “Legal Proceedings.”~~

Overview

We are the largest private sector coal company in the world, with majority interests in 3334 active coal operations located throughout all major U.S. coal producing regions and internationally in Australia. ~~We also own a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela, and a 49% interest in an Appalachia joint venture.~~ In the ~~third~~first quarter ~~and first nine months~~ of 2006, we sold 61.4 million tons of coal. In 2005, we sold ~~61.6 million and 178.4 million tons of coal, respectively, which are records for the Company. In 2004, we sold 227.2~~239.9 million tons of coal that accounted for ~~20%~~an estimated 21.5% of all U.S. coal sales, and were more than ~~85%~~69% greater than the sales of our closest domestic competitor and 49% more than our closest international competitor. ~~According to reports published by the~~Based on Energy Information Administration ~~1.1 billion tons of~~(“EIA”) estimates, demand for coal ~~were consumed~~ in the United States was more than 1.1 billion tons in ~~2004. The Energy Information Administration also published estimates indicating that domestic~~2005. Domestic consumption of coal ~~by electricity generators would~~is expected to grow at a rate of ~~1.6%~~1.7% per year through ~~2025.~~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 ~~pace~~approximate rate of electricity ~~growth.~~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 ~~U.S.~~ electricity generation was approximately ~~52%.~~51%, a share that the EIA projects will grow to 57% by 2030.

Our primary customers are U.S. utilities, which accounted for ~~90%~~87% of our sales in ~~2004.~~2005. We typically sell coal to utility customers under long-term contracts (those with terms longer than one year). During ~~2004,~~2005, approximately 90% of our sales were under long-term contracts. ~~Our~~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 ~~can~~could be negatively impacted by poor weather conditions, unforeseen geologic conditions or equipment problems at mining locations, ~~the performance of contractors or third party coal suppliers,~~and by the availability of transportation for coal ~~shipments and the availability and costs of key supplies and commodities such as steel, tires, diesel fuel and explosives.~~shipments. On a long-term basis, our results of operations could be impacted by ~~the availability and prices of competing electricity-generation fuels,~~ our ability to secure or acquire high-quality coal reserves, ~~our ability to~~ 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 ~~its~~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. ~~Our~~The principal business of the Eastern U.S. Mining ~~operations consist of our Appalachia and Midwest operations, and its principal business~~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, ~~our~~ Western operations mine bituminous and subbituminous coal deposits and ~~our~~ Eastern operations mine bituminous coal deposits. Our Western U.S. Mining operations are characterized by predominantly surface ~~mining~~ extraction processes, lower sulfur content and Btu of coal, and higher customer transportation costs (due to longer shipping distances). Our Eastern U.S. Mining operations are characterized by ~~a majority of~~predominantly underground ~~mining~~ extraction processes, higher sulfur content and Btu of coal, and lower customer transportation costs (due to shorter shipping distances).

     Our Australian Mining operations consist of four mines. The Burton and North Goonyella mines were acquired in April 2004. We opened the Eaglefield Mine in 2004, which is a surface operation adjacent to, and fulfilling contract tonnages in conjunction with, the North Goonyella underground mine. In addition, we have owned and operated our Wilkie Creek Mine since 2002, which is our only steam coal operation in Australia. We expect to begin production from our Baralaba mine during the fourth quarter of 2005. Baralaba will be a surface operation producing metallurgical coal. Our
     Australian Mining operations are characterized by both surface and underground extraction processes, mining primarily ~~low sulfur, metallurgical~~low-sulfur, high Btu coal sold to an international customer base.
Metallurgical coal ~~represented~~is produced primarily from two of our Australian mines and two of our U.S. mines. Metallurgical coal is approximately 5%4% of our total sales volume and approximately 3%2% of U.S. sales ~~volume~~volume.
     We own a 25.5% interest in Carbones del Guasare, which owns and operates the ~~nine months ended September 30, 2005. Our~~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 ~~are~~is described in Item 1, Business, of our ~~2004~~2005 Annual Report on Form 10-K.
29

In addition to our mining operations, which comprised ~~82%~~85% of revenues in ~~the third quarter of~~ 2005, we also ~~generated 18% of our~~generate revenues from brokering and trading ~~coal. We generate additional income~~coal (15% of revenues), and ~~cash flows~~ by ~~extracting~~realizing value from our vast natural resource position by selling non-core ~~idle or reclaimed~~ land holdings and ~~non-strategic~~ mineral ~~interests.~~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~~1,500-megawatt Prairie State Energy Campus in Washington County, Illinois; the ~~1,500 megawatt~~1,500-megawatt Thoroughbred Energy Campus in Muhlenberg County, Kentucky; and the ~~300 megawatt~~300-megawatt Mustang Energy ~~Project~~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. ~~The first of these plants would not be operational earlier than mid-2010.~~

In ~~February 2005,~~April 2006, we received a group of Midwest rural electric cooperatives and municipal joint action agencies entered into definitive agreements to acquire 47% of the Prairie State Energy Campus project. After an initial appeal was successfully resolved related todecision affirming the air permit for our Thoroughbred Energy Campus. This milestone allows us to continue advancing the development of that ~~was issued~~campus.

During 2005, we engaged in ~~January 2005,~~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 ~~Environmental Protection Agency reissued~~that would transform coal into pipeline-quality synthetic natural gas. The initial project would be designed with ConocoPhillips’ “E-Gas™” Technology. When completed, the ~~air permit on April 28, 2005. The same parties who filed~~plant would be one of the ~~earlier permit challenge filed a new appeal on June 8, 2005. The Company believes the permit was appropriately issued and expects to prevail~~largest coal-to-natural-gas plants in the ~~appeal process.~~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.

~~In the first quarter of 2005, the Board of Directors, after completing an orderly succession planning process, elected~~Effective January 1, 2006, Gregory H. Boyce ~~President and Chief Operating Officer, to the position of~~became our President and Chief Executive Officer ~~effective January 1, 2006. Chairman and~~after we completed an orderly succession planning process. Irl F. Engelhardt, our former Chief Executive Officer, ~~Irl F. Engelhardt will continue his CEO duties through 2005, and will remain~~remains employed as Chairman of the ~~Board on January 1, 2006. Effective March 1, 2005, Mr. Boyce was also elected to the Board of Directors and Chairman of the Executive Committee of the~~ Board.

Effective ~~March 30, 2005,~~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~~quarterly report on Form 10-Q reflect ~~the stock~~this split. ~~During~~In July 2005, ~~we increased our quarterly dividend 27% to $0.095 per share and~~ 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 ~~July 2005, the~~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 ~~elected John F. Turner as an independent director who will serve~~authorized a 26% increase in our dividend, to $0.06 per share, to shareholders of record on the Board’s Nominating and Corporate Governance Committee. Turner is former U.S. Assistant Secretary of State for Oceans and International Environmental and Scientific Affairs (OES) within the State Department and is the past President and Chief Executive Officer of the Conservation Fund, a national nonprofit organization dedicated to public-private partnerships to protect land and water resources. He has also served as the Director of the U.S. Fish and Wildlife Service, with responsibility for increasing wetland protection and establishing 55 National Wildlife Refuges, the most of any administration in the nation’s history.February 7, 2006.

Results of Operations

Adjusted EBITDA

The discussion of our results of operations ~~in 2005 and 2004~~ below includes references to, and analysis of our segments’ Adjusted EBITDA results. Adjusted EBITDA is defined as income from continuing operations before deducting ~~early debt extinguishment costs,~~ net interest expense, income taxes, minority interests, asset retirement obligation expense and depreciation, depletion and amortization. Adjusted EBITDA is used by management 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 118 to our unaudited condensed consolidated financial ~~statements included in this report.~~

~~Recent Acquisitions Impacting Comparability of Results of Operations~~

Results in our Western U.S. Mining Operations segment include amounts for our April 15, 2004 acquisition of the Twentymile Mine in Colorado. Results in our Australian Mining Operations segment include amounts for our April 15, 2004 acquisition of the Burton and North Goonyella Mines as well as the opening of the Eaglefield Mine adjacent to the North Goonyella Mine in the fourth quarter of 2004. Our Corporate and Other segment includes results from our December 2004 acquisition of a 25.5% interest in Carbones del Guasare, which owns and operates the Paso Diablo Mine in Venezuela.statements.

Quarter Ended ~~September 30, 2005~~March 31, 2006 Compared to Quarter Ended ~~September 30, 2004~~March 31, 2005

Summary

Our first quarter 2006 revenues of $1.31 billion increased ~~$304.5~~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 ~~33.1%, to $1,223.5 million~~$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 ~~third~~Midwest in late 2005, both of which were developed from reserves acquired in the first quarter of 2005, ~~compared to~~and one new mine in Australia, of which we own a 62.5% interest. Also impacting our 2006 results are the ~~prior year. Segment Adjusted EBITDA was $267.0 million~~termination of operations at our Black Mesa and Seneca mines, which occurred in the third quarter of 2005 compared to $205.6 million in the prior year, a 29.8% increase. Third quarter net income of $113.3 million, or $0.84 per share, was 160.9% higher than prior year net income of $43.4 million, or $0.33 per share. The improvements were primarily driven by higher sales prices in nearly every region and for all of our products, particularly metallurgical coal, and by demand-driven volume increases, particularly for our Midwest products and for our ultra-low sulfur Powder River Basin products. In addition, higher gains on property transactions contributed to higher year over year results.late 2005.

Tons Sold

The following table presents tons sold by operating segment for the quarters ended ~~September 30, 2005~~March 31, 2006 and ~~2004:~~2005:


	(Unaudited)
	Quarter Ended September 30,				Increase (Decrease)						Quarter Ended March 31,				Increase (Decrease)
	2005		2004		Tons			%			2006		2005		Tons			%
	(Tons in millions)												(Tons in millions)
Western U.S. Mining Operations		39.1		37.9		1.2			3.2	%		39.8		38.7		1.1			2.8	%
Eastern U.S. Mining Operations		13.4		12.3		1.1			8.9	%		13.7		13.0		0.7			5.4	%
Australian Mining Operations		1.9		2.0		(0.1	)		(5.0	)%		1.9		2.0		(0.1	)		(5.0	%)
Trading and Brokerage Operations		7.2		6.5		0.7			10.8	%
Trading & Brokerage Operations												6.0		5.4		0.6			11.1	%

Total		61.6		58.7		2.9			4.9	%		61.4		59.1		2.3			3.9	%

Sales increased ~~$296.1 million,~~21.3% to $1.29 billion in 2006, reflecting increases in every ~~segment: Western U.S. Mining ($30.1 million), Eastern U.S. Mining ($105.3 million), Australian Mining ($54.1 million), and Trading & Brokerage ($106.6 million).~~operating segment. Western U.S. Mining sales increased ~~primarily due to~~$27.7 million, Eastern U.S. Mining sales were $89.0 million higher, sales ~~prices~~ in ~~the Powder River~~Australian Mining improved $49.7 million and ~~Colorado regions~~sales from our brokerage operations increased $60.0 million. Sales increased on improved pricing in every operating segment and through higher volumes atin our Powder River Basin operations ~~due to continued higher demand for Powder River Basin coal. Sales~~and our international brokerage business. Our average sales price ~~increases overcame~~per ton increased 15.3% in the ~~short-term volume impact~~first quarter of a longwall move during the quarter at one of our Colorado operations. Average sales prices for the Western U.S. Mining operations were 4.6% higher during the quarter versus prior year. Sales volumes for the Powder River operations were higher in 20052006 compared to the prior year ~~despite~~due to increased demand for all of our coal products, but particularly in the ~~negative impact of transportation from on-going rail maintenance. The restricted transportation capacity impacted all~~regions where we produce metallurgical coal. Prices for metallurgical coal ~~producers in the~~and our ultra-low sulfur Powder River Basin ~~and rail capacity is not expected to return to higher levels until late in 2005 as discussed in “Outlook” below. In~~coal have been the subject of increasing demand. We sell metallurgical coal from our Eastern U.S. and Australian Mining ~~operations, the recent trend of higher average selling prices continued, rising 20.4%~~operations. We sell ultra-low sulfur Powder River Basin coal from our Western U.S. Mining operations.

The increase in ~~the third quarter of 2005 compared~~Eastern U.S. Mining operations’ sales was primarily due to ~~prior year. Strong demand~~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, ~~is driving the~~which extended from late 2005 to February 2006. Sales increased in our Western U.S. Mining operations due to higher demand-driven prices and ~~supporting~~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 ~~volumes~~than in ~~both Appalachia and the Midwest.~~2005. The increase in ~~our~~ Australian ~~Mining~~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 ~~primarily reflected higher sales prices for metallurgical coal. Volumes for the quarter~~increased $60.0 million in ~~Australia were comparable~~2006 compared to prior year ~~as production from a new mine offset lower production at one of our metallurgical operations~~ due to poor roof conditions as further discussed in “Segment Adjusted EBITDA” below. Average sales prices in our Australian operations improved 68.2%, reflecting the strong demand for metallurgical coal. Improved Trading and Brokerage sales primarily reflected improved pricing for broker transactions. The $8.4 millionan increase in ~~other~~average per ton prices and higher international brokerage volumes.

increases and higher sales prices. The increase in prices offset higher per ton costs resulting from higher materials costs (including fuel and tires) and the impact of fixed costs over lower than anticipated volume. Costs were also negatively impacted by higher revenue-based production and sales taxes. Gains from our fuel hedging program offset most of the increase in fuel prices during the quarter. The Southwest operations’ results were comparable with prior year.

Eastern U.S. Mining operations’ Adjusted EBITDA increased $42.0 million compared to third quarter of prior year, primarily driven by higher sales prices for metallurgical and steam coal in our Appalachia operations. Adjusted EBITDA in our Appalachia operations increased principally as a result of quarter over quarter sales price increases of 36% (over 75% for metallurgical coal). Overall, volumes were higher than prior year, although one metallurgical mine experienced lower production during the quarter that will extend into the first quarter of 2006 as the operation engages in development of a new longwall mining area. Results in our Midwest operations were higher than prior year benefiting from higher volumes and prices which offset higher fuel and dragline repair costs. Also, gains from our fuel hedging program offset a significant portion of the increase in fuel prices during the quarter.

Australian Mining operations’ Adjusted EBITDA increased $19.0 million in the third quarter of 2005 compared to the prior year. Improved results were mainly driven by sales price increases of over 68% quarter over quarter. Current year results benefited from strong sales prices, but were negatively impacted by poor roof conditions that interrupted production on the longwall and a subsequent roof fall that curtailed operations during the month of September at our underground metallurgical coal operation. Continued high demurrage costs and timing of vessel loadings also negatively impacted results.

Trading and Brokerage operations’ Adjusted EBITDA increased $10.1 million versus the third quarter of 2004, due to improved brokerage margins, higher prices and trading volumes and the positive effect of settlement of a contractual dispute with one of our coal suppliers, as discussed in Note 3 to our unaudited condensed consolidated financial statements.

~~Income Before Income Taxes And Minority Interests~~

(Unaudited) Increase (Decrease) to
Quarter Ended September 30, Income
2005 2004 $ %
(Dollars in thousands)
Total Segment Adjusted EBITDA $ 266,990 $ 205,615 $ 61,375 29.8 %

Corporate and Other Adjusted EBITDA (31,552 ) (51,432 ) 19,880 38.7 %
Depreciation, depletion and amortization (77,159 ) (70,132 ) (7,027 ) (10.0 )%
Asset retirement obligation expense (7,394 ) (10,146 ) 2,752 27.1 %
Interest expense (25,327 ) (24,926 ) (401 ) (1.6 )%
Early debt extinguishment gains — 556 (556 ) n/a
Interest income 3,218 1,084 2,134 196.9 %

Income before income taxes and minority interests $ 128,776 $ 50,619 $ 78,157 154.4 %

Income before income taxes and minority interests increased $78.2 million versus the third quarter of 2004, primarily due to improved segment Adjusted EBITDA results. Corporate and Other Adjusted EBITDA improved by 38.7% and asset retirement obligation expense was lower, partially offset by an increase in depreciation, depletion and amortization.

Corporate and Other Adjusted EBITDA results include selling and administrative expenses, equity income from our Venezuelan joint venture, net gains on asset disposals or exchanges, costs associated with past mining obligations and revenues and expenses related to our other commercial activities such as coalbed methane, generation development and resource management. The $19.9 million improvement of Corporate and Other results included:

~~higher gain on disposal or exchange of assets of $45.8 million, primarily related to:~~

	•		~~a $37.4 million gain on settlement of a contract dispute with a third-party coal supplier; and~~

	•		a $6.2 million gain from an asset exchange where we acquired strategic Illinois Basin coal reserves for non-strategic reserves, our interest in a joint venture and monetary consideration (see Note 3); and

~~income in 2005 of $5.1 million from a 25.5% interest in Carbones del Guasare, acquired in December 2004, which owns and operates the Paso Diablo Mine in Venezuela.~~

~~These improvements were partially offset by the following items:~~

	•		a $6.9 million increase in past mining obligations expense, primarily related to higher retiree health care costs. The increase in retiree health care costs was primarily associated with actuarial assumptions such as higher trend rates, lower interest discount assumptions and higher amortization of actuarial losses in 2005; and

	•		a $23.4 million increase in selling and administrative expenses primarily related to an increase in performance-based incentives ($19.6 million), principally long-term plans that are driven by total shareholder returns. Our share price increased 62% during the quarter and 184% in the last twelve months, significantly outperforming market benchmarks and the peer group. The remaining increase is from higher outside services costs related to support services, acquisitions and regulatory compliance.

~~Depreciation, depletion and amortization increased $7.0 million in 2005 primarily due to increased production volumes in 2005.~~

~~Net Income~~

(Unaudited) Increase (Decrease) to
Quarter Ended September 30, Income
2005 2004 $ %
(Dollars in thousands)
Income before income taxes and minority interests $ 128,776 $ 50,619 $ 78,157 154.4 %

Income tax provision (14,714 ) (6,933 ) (7,781 ) (112.2 )%
Minority interests (722 ) (247 ) (475 ) (192.3 )%

Income from continuing operations 113,340 43,439 69,901 160.9 %
Loss from discontinued operations, net of taxes — (2 ) 2 n/a

Net income $ 113,340 $ 43,437 $ 69,903 160.9 %

Our net income increased $69.9 million, or 160.9%, in the third quarter of 2005 compared to prior year due to the increase in income before income taxes and minority interests discussed above, partially offset by an increase in the income tax provision. The income tax provision in 2005 is higher than prior year primarily as a result of higher pretax income.

~~Nine Months Ended September 30, 2005 Compared to Nine Months Ended September 30, 2004~~

~~Summary~~

Our revenues increased $801.7 million to $3,409.8 million for the first nine months of 2005, a 30.7% increase over the prior year. The increase in revenue was primarily due to improved pricing in all regions, increased sales volumes from strong demand at domestic and international mining operations and the benefit of mining operations acquired during 2004. Segment Adjusted EBITDA was $738.9 million for the first nine months of 2005 compared to $550.3 million in the prior year, a 34.3% increase. Net income of $260.5 million, or $1.95 per share, was 142.3% higher in the first nine months of 2005, compared to $107.5 million, or $0.86 per share, in the prior year. The improvements were primarily due to greater demand-driven volume, improved sales prices and the impact of mining operations acquired in 2004. In addition, higher gains on property transactions contributed to higher year over year results.

~~Tons Sold~~

~~The following table presents tons sold by operating segment for the nine months ended September 30, 2005 and 2004:~~

(Unaudited)
Nine Months Ended September 30, Increase (Decrease)
2005 2004 Tons %
(Tons in millions)
Western U.S. Mining Operations 114.5 105.4 9.1 8.6 %
Eastern U.S. Mining Operations 39.5 37.5 2.0 5.3 %
Australian Mining Operations 6.0 4.1 1.9 46.3 %
Trading and Brokerage Operations 18.4 20.5 (2.1 ) (10.2 )%

Total 178.4 167.5 10.9 6.5 %

~~Revenues~~

~~The following table presents revenues for the nine months ended September 30, 2005 and 2004:~~

(Unaudited) Increase (Decrease)
Nine Months Ended September 30, to Revenues
2005 2004 $ %
(Dollars in thousands)
Sales $ 3,343,620 $ 2,538,189 $ 805,431 31.7 %
Other revenues 66,156 69,864 (3,708 ) (5.3 )%

Total revenues $ 3,409,776 $ 2,608,053 $ 801,723 30.7 %

Our total revenues increased $801.7 million, or 30.7%, to $3,409.8 million compared to the first nine months of 2004, driven by increased pricing in all regions and higher overall volume. The three mines we acquired in the second quarter of 2004 contributed approximately $259.0 million to the increase in revenues. The remaining $542.7 million increase is primarily attributable to increases in average sales prices and volumes across all mining segments, particularly in the Powder River Basin, where strong demand continues to drive expansion of our operating capacity. Volume in our Trading and Brokerage segment was lower than prior year, but was more than offset by higher pricing in 2005.

Sales increased $805.4 million in the first nine months of 2005, reflecting increases in every segment: Western U.S. Mining ($167.3 million), Eastern U.S. Mining ($249.0 million), Australian Mining ($216.8 million), and Trading and Brokerage ($172.3 million). Increases in average per ton selling prices continued, rising 6.7% and 18.0% in our Western U.S. and Eastern U.S. Mining operations, respectively, in the first nine months of 2005 compared to prior year. The 16.4% increase in sales for our Western U.S. Mining operations ~~was primarily~~

~~attributable to the 2004 acquisition of the Twentymile Mine and to increases in both sales price and volume in the Powder River Basin. Production in the Powder River Basin~~ increased ~~6.7~~$7.4 million tons, or 7.8%, compared to the prior year in response to overall higher demand, overcoming train derailments, weather and track maintenance disruptions on the main shipping line out of the basin. Eastern U.S. Mining operations’ sales increased 24.0% compared with prior yearduring 2006 due to ~~improved pricing in Appalachia that resulted from strong steam~~a margin per ton increase of $0.09, or 2.9%, and ~~metallurgical coal demand, and higher~~a sales volume ~~and prices in the Midwest.~~increase of 1.1 million tons. The increase in Australian Mining operations’ sales was due to significantly higher prices for metallurgical coal in 2005 and the contribution from higher volumes due to the acquisition of two mines and the startup of our Eaglefield surface mine in 2004. Trading and Brokerage sales were up $172.3 million on higher pricing. Other revenues were comparable with the prior year.

~~Segment Adjusted EBITDA~~

~~Our total segment~~ Adjusted EBITDA was ~~$738.9 million for the first nine months of 2005, compared with $550.3 million in the prior year, detailed as follows:~~

Increase (Decrease) to
(Unaudited) Segmented Adjusted
Nine Months Ended September 30, EBITDA
2005 2004 $ %
(Dollars in thousands)
Western U.S. Mining Operations $ 330,277 $ 297,631 $ 32,646 11.0 %
Eastern U.S. Mining Operations 287,569 182,332 105,237 57.7 %
Australian Mining Operations 101,345 33,655 67,690 201.1 %
Trading and Brokerage Operations 19,703 36,728 (17,025 ) (46.4 )%

Total Segment Adjusted EBITDA $ 738,894 $ 550,346 $ 188,548 34.3 %

~~Western U.S. Mining operations’ Adjusted EBITDA increased $32.6 million, or 11.0%, in the first nine months of 2005 compared to prior year. The increase reflected improvements in~~driven by our Powder River Basin operations, which improved by $12.6 million and ~~the addition of the Twentymile Mine to our Colorado operations in April 2004 and increased productivity from its operations. The improvement at our Powder River operations was due to~~earned 10.7% higher ~~prices, leading to a 21.1% increase in~~ per ton ~~margin, and a 7.8% volume increase~~margins while increasing volumes 7.2% in response to ~~increased demand. In 2005, third quarter volumes reached record levels after sequentially decreasing in the second quarter due to constraints on the region’s rail system.~~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. ~~Improvements~~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 ~~Colorado overcame a decrease in~~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 ~~a $16.2 million allowance that was established relative to disputed receivables (discussed in Note 12 to our unaudited condensed consolidated financial statements).~~

In the ~~first quarter, we recorded approximately $9.5 million~~termination of ~~operating expenses related to pension curtailment charges~~operations at ~~our~~the Black Mesa ~~and Seneca mines, which are expected to close during~~Mine in late 2005. The impact to Western U.S. Mining operations’ segment Adjusted EBITDA was not significant as the majority of these curtailment costs are billable under current supply agreements. Through the third quarter of 2005, $8.5 million had been billed to customers.

Eastern U.S. Mining operations’ Adjusted EBITDA increased ~~$105.2~~$37.7 million, ~~in the first nine months of 2005~~or 39.8%, compared to prior year primarily ~~driven by higher sales prices for metallurgical and steam coal.~~due to an increase in margin per ton of $2.35, or 32.2%. Appalachia operations’ Adjusted EBITDA ~~in our Appalachia operations~~ increased ~~principally~~$17.4 million, or 31.1%, as a result of sales price increases, ~~of 31.9% in 2005,~~ partially offset by lower production at ~~two~~three of our mines due to a longwall move at one mine and ~~higher costs related to~~ geologic issues ~~contract mining, and roof support. The results~~at the other two. Results in our Midwest operations were improved $20.3 million, or 52.2%, compared to ~~the~~ prior year ~~results,~~ as ~~the~~ benefits of higher volumes, product mix and prices were partially offset by higher ~~operating~~ costs due to ~~the impact of heavy rainfall on surface operations in the~~higher fuel and explosives costs. The first quarter ~~and higher fuel, repair and maintenance costs.~~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 ~~$67.7~~$33.7 million in the ~~first nine months of 2005~~current year, a 239.0% increase compared to ~~the~~ prior ~~year. Volumes in Australia increased 46.3% primarily~~year due to ~~the acquisition~~an increase of ~~two~~$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 mines and the opening of a new surface operation at the end of 2004. Current year~~coal. While current margins ~~also~~ benefited from strong metallurgical coal sales prices, ~~but~~ margin growth was limited by the impact of ~~port congestion, related demurrage costs and~~ higher costs due to geological problems at ~~the~~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 ~~decreased $17.0~~increased $38.0 million ~~compared~~from the prior year. In 2005, we recognized a loss associated with the ~~prior year, primarily related to less favorable trading results in 2005 compared to 2004. The first nine months of 2005 includes a net charge of $7.5 million, primarily related to the breach~~failure of a coal supplier to ship under a coal supply ~~contract by a producer~~agreement in the first quarter of 2005 (see Note ~~3 to our unaudited condensed consolidated financial statements)~~2). In 2006, trading and brokerage results reflect improved brokerage margins and increased volumes.

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 ~~improvements~~increased costs compared to 2005 were partially offset by ~~the following items:~~

	•		an increase in past mining obligations expense of $28.8 million, primarily related to higher retiree health care costs. The increase in retiree health care costs was actuarially driven by higher trend rates, lower interest discount assumptions and higher amortization of actuarial losses in 2005; and

	•		a $41.9 million increase in selling and administrative expenses primarily related to higher performance-based incentives ($30.0 million), principally long-term plans that are driven by total shareholder returns. Our share price increased 109% during the first nine months of 2005, significantly outperforming benchmarks and the peer group. The remaining increase is from higher personnel and outside services costs, which are being driven by support services, acquisitions and regulatory compliance.

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 ~~$29.4~~$5.0 million in 2005 with approximately 54% of the increase due to acquisitions made in 2004 and the remainder of the increase due primarily to improved volume at existing mines in 2005. Asset retirement obligation expense decreased $8.1 million due to expenses in 2004 related to the acceleration of planned reclamation of certain closed mine sites. Interest expense increased $5.2 million primarily related to the issuance of $250 million of 5.875% Senior Notes in late March of 2004 and increases in the cost of floating rate debt2006 due to higher ~~interest rates.~~production and capital expenditures and lower amortization in 2006 of contract liabilities recorded as part of 2004 acquisitions.

Net Income


	(Unaudited)						Increase (Decrease) to						Quarter Ended			Quarter Ended			Increase (Decrease) to
	Nine Months Ended September 30,						Income						March 31,			March 31,			Income
	2005			2004			$			%			2006			2005			$			%
	(Dollars in thousands)															(Dollars in thousands)
Income before income taxes and minority interests	$	291,310		$	97,374		$	193,936			199.2	%	$	146,447		$	56,620		$	89,827			158.6	%

Income tax (provision) benefit		(29,300	)		13,863			(43,163	)		n/a
Income tax provision														(11,566	)		(4,424	)		(7,142	)		(161.4	)%
Minority interests		(1,526	)		(900	)		(626	)		(69.6	)%		(4,659	)		(306	)		(4,353	)		(1,422.5	)%

Income from continuing operations		260,484			110,337			150,147			136.1	%
Loss from discontinued operations, net of taxes		—			(2,839	)		2,839			n/a

Net income	$	260,484		$	107,498		$	152,986			142.3	%	$	130,222		$	51,890		$	78,332			151.0	%

Net income increased ~~$153.0~~$78.3 million ~~or 142.3%,~~ compared to the first ~~nine months~~quarter of ~~2004~~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.~~provision and minority interests. The increase in the income tax provision ~~recorded~~ in ~~2005 differs from the benefit in 2004~~2006 is primarily a result of higher pre-tax income. Minority interests increased as a result of ~~higher pretax income and~~acquiring additional interest in a ~~positive effective tax rate in 2005, which is driven by~~joint venture near the ~~magnitude~~end of the ~~percentage depletion deduction relative to pretax income.~~first quarter of 2006.

Outlook

Events Impacting Near-Term Operations

Shipments from our Powder River Basin mines were ~~lower than expected~~impacted in the second quarter and to a lesser extent in the third quarter of 2005 due to a six-month remedial maintenance program undertaken by the two railroad companies serving the Powder River Basin. The maintenance and repairs are expected to continue in late 2005 and into 2006. We expect these repairs may restrict shipments from our Powder River operations for the remainder of the current year, but continue to anticipate record shipment levels in 2005 and even higher levels in 2006.

~~Metallurgical coal production from our Appalachia operations is expected to be lower than prior year periods through~~ the first quarter of 2006 ~~as a metallurgical coal mine~~by rail service disruptions related to ongoing operating issues in ~~the U.S. continues development work on a new section. The longwall at the existing mine has depleted the final panel of available reserves in its current location~~February and ~~is relocating to a reserve extension in the first half of 2006.~~

~~Our underground metallurgical coal mine in Australia is experiencing difficult geologic conditions that~~March. Rail carriers are expected to continue ~~disrupting production~~in-depth maintenance on their track beginning in the ~~near term. In~~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 ~~we plan~~were also delayed due to install longwall replacement equipment with better roof control and cutting capabilities. In the interim, we plan to meet our shipping commitments from this mine by supplementing its output with production from our newly-opened, adjacent surface operation.two cyclones in Eastern Australia. In May 2005, ~~we were notified of~~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, ~~high~~ 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, ~~as long as~~driven by growth ~~continues~~ in the U.S., Asia and other industrialized economies that are increasing coal ~~demand for electricity generation and steelmaking.~~demand. The U.S. economy grew at an annual rate of ~~3.3%~~3.5% in ~~the second quarter of~~ 2005 as reported by the U.S. Commerce Department, and China’s economy grew ~~9.5%~~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, ~~favorable weather,~~ 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 ~~natural gas is leading some coal-fueled generating plants~~oil will lead to ~~operate at increased levels. U.S. coal inventories at quarter end remained at levels well below the five-year average. Primarily due to a 26%~~an increase in ~~cooling degree days, U.S. electricity~~demand for unconventional sources of transportation fuel, including coal-to-liquids (“CTL”), and that coal will increase its share as a fuel for generation ~~increased by 8.2% in the third quarter~~ of ~~2005 compared to the same period in the prior year and increased 3.4% for the first nine months year-over-year according to the Edison Electric Institute.~~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.~~increased substantially in the past year. We control approximately ~~3.4~~3.5 billion tons of proven and probable reserves in the Southern Powder River Basin and we sold ~~115.8~~34.0 million tons of coal from this region ~~during the year ended December 31, 2004, and 92.9 million tons through~~in the first ~~nine months~~quarter of ~~2005.~~2006, an increase of 7.2% over the same period in the prior year.

Metallurgical coal ~~is selling~~continues to sell at a significant premium to steam coal, and metallurgical markets remain strong ~~with~~as global steel production ~~growing 6% to 7%~~grew 5.4% in ~~2005.~~the first quarter of 2006. We expect to capitalize on the strong global market for metallurgical coal primarily through ~~a portion~~production and sales of metallurgical coal from our Appalachia operations and our Australian ~~operations, which produce mainly metallurgical coal.~~operations. In response to growing international markets, we are establishing a European trading desk.

We ~~continue to target 2005~~are targeting 2006 production of ~~210~~230 million to ~~220~~240 million tons and total sales volume of ~~240~~255 million to ~~250~~265 million tons, including 12 to 14 million tons of metallurgical coal. As of ~~September 30, 2005, we are essentially sold out of~~March 31, 2006, our ~~planned 2005 production.~~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 ~~adverse~~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. ~~Portions of the recent increase in materials costs have been due to weather-related supply disruptions in the Gulf of Mexico.~~ 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~~(through our securitization ~~program.~~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 ~~typically~~expect to fund all of our capital expenditure

requirements with cash generated from operations, and during ~~2004~~2005 and the first ~~nine months~~quarter of ~~2005,~~2006 have had no borrowings outstanding under our $900.0 million revolving line of credit, which we use primarily for standby letters of credit. ~~As of September 30, 2005, we had letters of credit outstanding under the facility of $409.9 million, leaving $490.1 million available for borrowing.~~ This provides us with available borrowing capacity ~~under the line~~($490.1 million as of ~~credit~~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 September 30, 2005. On May 9, 2005, we filed a shelf registration statement on Form S-3 with the SEC, which was declared effective in June 2005. The universal shelf registration statement permits us to offer and sell from time to time up to an aggregate maximum of $3 billion of securities, including common stock, preferred stock, debt securities, warrants and units. As of September 30, 2005, no securities have been issued under the universal shelf registration statement, which remains effective.March 31, 2006.

Net cash provided by operating activities was ~~$422.2~~$49.1 million in the first ~~nine months~~quarter of ~~2005, an increase of $269.7~~2006 compared to $97.9 million ~~or 176.8%, from~~in the first ~~nine months~~quarter of ~~2004.~~2005. The ~~increase~~decrease was primarily ~~driven~~related to the timing of working capital needs partially offset by stronger operational performance in 2005, as net income increased $153.0 million from the prior year. Also contributing to the increase was lower funding of pension plans, as we voluntarily pre-funded $50.0 million in the prior year. The remainder of the increase was primarily due to higher working capital cash flows of $25.4 million.2006.

Net cash used in investing activities was ~~$343.1~~$182.6 million during the first ~~nine months~~quarter of ~~2005~~2006 compared to ~~$561.5~~$122.4 million used in ~~2004. Capital expenditures were $346.7 million in the first nine months of 2005, an~~2005. The increase ~~of $198.4 million over prior year. Included in the 2005~~reflects higher capital expenditures, ~~was~~the acquisition of an additional interest in a ~~$63.5 million payment for~~joint venture, and lower proceeds from the ~~327 million ton West Roundup federal coal reserve lease~~disposal of assets in ~~the Powder River Basin, which was awarded to us in February 2005.~~2006. The ~~2005~~additional capital expenditures ~~also~~ included ~~expenditures for Twentymile mine~~ longwall equipment ~~expenditures for longwall components~~ and ~~other projects~~mine development at our Australian mines, ~~the acquisition of new coal reserves, and~~longwall replacement at our Twentymile mine, the opening of new mines and upgrading of existing mines in the ~~Midwest. Investing activities~~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, ~~also reflected $56.5 million in capital expenditures for~~we acquired mining assets, ~~acquired from Lexington Coal Company,~~ 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 ~~increased $46.6 million primarily due to higher proceeds~~ in 2005 ~~from~~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 non-strategic property, reserves and equipment. In 2004, we acquired the Twentymile mine in Colorado and two mines in Australia for $421.3 million and made a $5.0 million earn-out payment related to our April 2003 acquisition of the remaining minority interest in Black Beauty Coal Company.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 ~~was $10.0 million during the first nine months~~ of ~~2005 compared to $693.4~~$16.1 million in the prior ~~year, with~~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 ~~decrease primarily~~exercise of stock options of $6.3 million, and a $13.1 million tax benefit related to ~~the 2004 issuance of 17.6 million shares of common~~ stock at $22.50 per share, netting proceeds of $383.1 million; issuance of $250 million of 5.875% Senior Notes due in 2016; and the payment of debt issuance costs of $8.9 million in connection with the acquisition of the three mines discussed above. During the first nine months of 2005 and 2004, we made scheduled payments on our long-term debt of $15.6 and $28.7 million, respectively. Securitized interest in accounts receivable increased by $25.0 million in the first nine months of 2005 compared to an increase of $100.0 million in 2004. We paid dividends of $32.0 million and $22.9 million in the first nine months of 2005 and 2004, respectively. In September 2005, we issued $11.5 million in notes payable as part of an asset exchange in which we acquired additional Illinois Basin coal reserves.option exercises

4029

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

The following table updates, as of September 30, 2005, our contractual coal reserve lease and royalty obligations presented in our 2004 Annual Report on Form 10-K. These obligations have changed due to the Federal Coal Lease bid that we won in February 2005. The first payment of $63.5 million on this lease was made during the first quarter of 2005, and future payments of the same amount will be due annually through 2009.

Payments Due by Year
Within 2-3 4-5 After
(Dollars in thousands) 1 Year Years Years 5 Years

Coal reserve lease and royalty obligations $ 142,575 $ 401,642 $ 334,736 $ 52,996

At ~~September 30, 2005,~~March 31, 2006, we had ~~$332.0~~$140.9 million of purchase obligations for capital expenditures and $598.1 million of obligations related to ~~capital expenditures, of which $312.7 million is for 2005 and 2006. Commitments for~~federal coal ~~reserve-related expenditures, including Federal Coal Leases, are included in the table above. Total projected~~reserve lease payments. At March 31, 2006, total capital expenditures for ~~calendar year 2005~~2006 are ~~approximately~~expected to range from $450 million to ~~$500 million.~~$525 million, excluding federal coal reserve lease payments. Approximately ~~50%~~60% of projected ~~2005~~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 ~~Federal Coal Leases and longwall equipment at~~expenditures relate to growth initiatives such as increasing capacity in the Twentymile Mine and longwall replacement components in Australia, and the remainder is expected to be used to purchase or develop reserves, replace or add equipment, fund cost reduction initiatives and upgrade equipment and facilities at recently acquired operations.Powder River Basin. We ~~have and expect to continue~~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. In the third quarter of 2005, we renegotiated certain terms of the program, including lowering the program pricing, removing a minimum balance requirement and adding the ability to issue letters of credit under the program. We expect the new program terms to result in annual savings of approximately $2 million. The amount of undivided interests in accounts receivable sold to the Conduit was $225.0 million ~~and $200.0 million~~ as of ~~September 30, 2005~~March 31, 2006 and December 31, ~~2004, respectively.~~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 ~~nine months~~quarter ended September 30, 2005. Material off-balance sheet arrangements are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended DecemberMarch 31, ~~2004.~~2006. See Note 1410 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.

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~~Other~~Newly Adopted Accounting Pronouncements

~~Labor Agreements~~ 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 ~~miners at~~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 ~~Burton mine in Australia have agreed~~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 ~~a new labor agreement that expires on June 9, 2008. The Western Surface Agreement of 2000, which applies~~December 31, 2005, as the exercise price was equal to ~~hourly workers at two mines in Arizona and one~~the market price of our ~~Colorado mines, was extended~~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 ~~third~~ quarter ended March 31, 2006, we would have recognized $6.0 million (or $0.02 per diluted share) of ~~2005 for an additional two years~~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 ~~expires on September 1, 2007.~~

~~Risks Related to Contract Miners~~employee stock purchase plan share-based payments made before and ~~Brokerage Sources~~

~~In conducting our trading, brokerage and mining operations, we utilize third party sources~~after the adoption of ~~coal production, including contract miners and brokerage sources, to fulfill deliveries under our coal supply agreements. Recently, certain~~SFAS No. 123(R). We began utilizing restricted stock as part of our ~~brokerage sources and contract miners have experienced adverse geologic mining and/or financial difficulties that have made their delivery~~equity-based compensation strategy in January 2005. Accounting for restricted stock awards was not changed by the adoption of coal to us at the contractual price difficult or uncertain. Our profitability or exposure to loss on transactions or relationships such as these is dependent upon the reliability (including financial viability) and price of the third-party supply, our obligation to supply coal to customers in the event that adverse geologic mining conditions restrict deliveries from our suppliers, our willingness to participate in temporary cost increases experienced by our third-party coal suppliers, our ability to pass on temporary cost increases to our customers, the ability to substitute, when economical, third-party coal sources with internal production or coal purchased in the market, and other factors.

~~Mohave Generating Station~~

SFAS 123(R). See Note 125 to our unaudited condensed consolidated financial statements ~~included in this report relating to the suspension of the operations~~for further discussion of our ~~Black Mesa Mine and the Mohave Generating Station on December~~ share-based compensation plans.

31 ~~2005.~~

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 ~~and swaps~~ at ~~September 30, 2005~~March 31, 2006 and December 31, ~~2004.~~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 ~~nine~~three months ended ~~September 30, 2005,~~March 31, 2006, the actual low, high and average values at risk for our coal trading portfolio were ~~$1.3~~$0.7 million, ~~$3.9~~$2.1 million and ~~$2.5~~$1.4 million, respectively. As of ~~September 30, 2005,~~March 31, 2006, the timing of the estimated future realization of the value of ~~the Company’s~~our trading portfolio was as follows:


Year of	Percentage			Percentage
Expiration	of Portfolio			of Portfolio
2005		48	%
2006		42	%		70	%
2007		10	%		18	%
2008					12	%
					100	%
		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, steel producers, and financial institutions.~~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 ~~generally seek to~~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 ~~and fuel hedging derivatives~~ is not considered to be significant based upon the creditworthiness of the participating financial institutions.

Foreign Currency Risk

We utilize currency forwards ~~and options~~ to hedge currency risk associated with anticipated Australian dollar expenditures. Our currency hedging program for ~~the remainder of 2005~~2006 involves hedging approximately 75% of our anticipated, non-capital Australian dollar-denominated ~~expenditures and portions of our near-term capital~~ expenditures. As of ~~September 30, 2005,~~March 31, 2006, we had in place forward contracts designated as cash ~~flows~~flow hedges with ~~Australian dollar-denominated~~ notional amounts outstanding totaling ~~$735~~A$968.9 million of which ~~$96~~A$354.9 million, ~~$371~~A$348.0 million, ~~$184~~A$221.0 million and ~~$84~~A$45.0 million will expire in ~~2005,~~ 2006, 2007, 2008, and ~~2008,~~2009 respectively. Our current expectation for the ~~fourth quarter~~

~~2005~~remainder of 2006 non-capital, Australian dollar-denominated cash expenditures is approximately ~~$120~~$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~~“Operating costs and expenses” of ~~$4.8~~$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 ~~September 30, 2005,~~March 31, 2006, after taking into consideration the effects of interest rate swaps, we had ~~$859.8~~$835.4 million of fixed-rate borrowings and ~~$547.5~~$542.8 million of variable-rate borrowings outstanding. A ~~one-percentage~~one percentage point increase in interest rates would result in an annualized increase to interest expense of ~~$5.5~~$5.4 million on our variable-rate borrowings. With respect to our fixed-rate borrowings, a ~~one-percentage~~one percentage point increase in interest rates would result in a ~~$53.8~~$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 ~~2004~~2005 and ~~2003.~~2004. As of ~~September 30, 2005, we are essentially sold out of our planned 2005 production. Also as of September 30, 2005,~~March 31, 2006, we had 205 to 3010 million tons, 9570 to ~~105~~80 million tons and ~~165~~135 to ~~175~~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 for 2006, 2007 and 2008, respectively.~~prices. We have an annual metallurgical coal production capacity of 12 to 14 million ~~tons, all of which is priced for 2005 and approximately 50% of which is priced for 2006.~~tons.

Some of the products used in our mining activities, such as diesel fuel and explosives, are subject to commodity price risk. To manage ~~some of~~ 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 ~~some of~~ our commodity price exposure. As of ~~September 30, 2005,~~March 31, 2006, we had derivative contracts outstanding that are designated as cash flow hedges of anticipated purchases of ~~fuel.~~fuel and explosives.

Notional amounts outstanding under ~~these~~fuel-related contracts, scheduled to expire through 2007, were ~~44.9~~36.0 million gallons of heating oil and ~~24.1~~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 ~~90%~~57% of our anticipated diesel fuel requirements in ~~2005.~~

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 ~~September 30, 2005~~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.

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~~(Incorporated by reference to Exhibit 3.2 toof the ~~Company’s~~Registrant’s Annual Report on Form 10-K for the year ended December 31, 2004, filed on March 16, 2005).

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

4.1*4.1		6 ~~7/8%~~⁷/₈% Senior Notes ~~Indenture~~ Due 2013 ~~Seventh~~Eighth Supplemental Indenture, dated as of ~~September 30, 2005,~~January 20, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and US Bank National Association, as ~~trustee.~~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*4.2		5 ~~7/8%~~⁷/₈% Senior Notes Due 2016 ~~Fifth~~Sixth Supplemental Indenture, dated as of ~~September 30, 2005,~~January 20, 2006, among the Registrant, the Guaranteeing Subsidiaries (as defined therein), and ~~U.S.~~US Bank National Association, as ~~trustee.~~

~~10.1~~		~~Indemnification Agreement dated July 21, 2005 by and between Peabody Energy Corporation and John F. Turner (incorporated~~trustee (Incorporated by reference to Exhibit ~~10.1~~4.21 of the ~~Company’s Current~~Registrant’s Annual Report on Form ~~8-K~~10-K for the year ended December 31, 2005, filed on ~~August 5, 2005)~~March 6, 2006).

10.2*		Amended and Restated Receivables Purchase Agreement, dated as of September 30, 2005, by and among Seller, Registrant, the Sub-Servicers named therein, Market Street Funding Corporation, as Issuer, PNC Bank, National Association, as Administrator and as LC Bank, and financial institutions from time to time parties thereto, as LC Participants.

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.

4737


			Page
PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Unaudited Condensed Consolidated Income Statements ~~of Operations~~ for the Quarters Ended March 31, 2006 and ~~Nine Months Ended September 30,~~ 2005 ~~and 2004~~			2

Condensed Consolidated Balance Sheets as of ~~September 30, 2005~~March 31, 2006 (unaudited) and December 31, ~~2004~~2005			3

Unaudited Condensed Consolidated Statements of Cash Flows for the ~~Nine Months~~Quarters Ended ~~September 30,~~March 31, 2006 and 2005 ~~and 2004~~			4

Notes to Unaudited Condensed Consolidated Financial Statements			5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			2821

Item 3. Quantitative and Qualitative Disclosures About Market Risk			4232

Item 4. Controls and Procedures			4434

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			4534

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			35

Item 6. Exhibits			4535
~~Seventh Supplemental Indenture~~
~~Fifth Supplemental Indenture~~
~~Amended and Restated Receivables Purchase Agreement~~
Certification of CEO Pursuant to Rule ~~13A-14(A)~~13a-14(a)
Certification of EVP/CFO Pursuant to Rule ~~13A-14(A)~~13a-14(a)
Certification of CEO Pursuant to 18 U.S.C. Section 1350
Certification of EVP/CFO Pursuant to 18 U.S.C. 18 Section 1350


	Quarter Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004			Quarter Ended March 31,
	2006			2005
Service cost for benefits earned	$	2,964		$	3,147		$	8,890		$	9,122		$	3,059		$	2,963
Interest cost on projected benefit obligation		11,373			11,027			34,119			32,594			11,509			11,373
Expected return on plan assets		(13,203	)		(12,573	)		(39,609	)		(37,238	)		(13,647	)		(13,203	)
Amortization of prior service cost		(4	)		64			(12	)		191			(8	)		(4	)
Amortization of net loss		6,147			5,477			18,441			16,573			5,671			6,346

Net periodic pension costs		7,277			7,142			21,829			21,242			6,584			7,475
Curtailment charges		—			—			9,527			—			—			9,527

Total pension costs	$	7,277		$	7,142		$	31,356		$	21,242		$	6,584		$	17,002


	Quarter Ended						Nine Months Ended
	September 30,						September 30,
	2005			2004			2005			2004			Quarter Ended March 31,
	2006			2005
Service cost for benefits earned	$	1,355		$	908		$	4,004		$	3,308		$	1,879		$	1,325
Interest cost on accumulated postretirement benefit obligation		18,154			16,089			54,505			47,680			18,464			18,175
Amortization of prior service cost		(1,355	)		(3,308	)		(4,004	)		(9,923	)		(1,334	)		(1,325	)
Amortization of actuarial losses		6,579			918			19,729			2,755			8,012			6,575

Net periodic postretirement benefit costs	$	24,733		$	14,607		$	74,234		$	43,820		$	27,021		$	24,750


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

(Address of principal executive offices)		(Zip Code)


Accounts receivable	$	46,639
Materials and supplies		5,669
Coal inventory		11,543
Other current assets		6,234
Property, plant, equipment and mine development, net		463,567
Accounts payable and accrued expenses		(48,688	)
Other noncurrent assets and liabilities, net		(63,699	)

Total purchase price, net of cash received of $20,914	$	421,265


	Nine Months Ended
	September 30, 2004 *
Revenues:
As reported	$	2,608,053
Pro forma		2,733,415

Income from continuing operations:
As reported	$	110,337
Pro forma		107,696

Net income:
As reported	$	107,498
Pro forma		104,857

Basic earnings per share — net income:
As reported	$	0.88
Pro forma		0.82

Diluted earnings per share — net income:
As reported	$	0.86
Pro forma		0.80


	September 30, 2005				December 31, 2004
	Assets		Liabilities		Assets		Liabilities		March 31, 2006				December 31, 2005
	Assets		Liabilities		Assets		Liabilities
Forward contracts	$	85,554	$	67,330	$	89,042	$	60,914	$	77,638	$	61,917	$	146,596	$	131,988
Other		—		68		123		2,651		—		1,738		—		385

Total	$	85,554	$	67,398	$	89,165	$	63,565	$	77,638	$	63,655	$	146,596	$	132,373


Year of	Percentage			Percentage
Expiration	of Portfolio			of Portfolio
2005		48	%
2006		42	%		70	%
2007		10	%		18	%
2008					12	%

		100	%		100	%


⁽¹⁾		~~For the nine months ended September 30, 2005, Western U.S. Mining results include a charge related to the reserves established for disputed legal fees billed to customers~~Adjusted EBITDA is defined as ~~discussed in Note 12.~~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 ~~include a benefit for the quarter and~~included a charge for contract losses in the ~~nine months ended September 30,~~first quarter of 2005 primarily related to the breach of a coal supply contract ~~losses and~~by a ~~settlement agreement as discussed in~~producer (see Note 3.2).

⁽³⁾		First quarter 2005 Corporate and Other results ~~include the gains~~included a $31.1 million gain on the ~~disposal or exchange~~sale of ~~assets discussed in~~Penn Virginia Resource Partners, L.P. units (see Note 3.2).


	Quarter Ended September 30, 2005
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	959,278		$	287,688		$	(23,456	)	$	1,223,510
Costs and expenses:
Operating costs and expenses		(12,025	)		779,477			243,507			(23,456	)		987,503
Depreciation, depletion and amortization		—			68,853			8,306			—			77,159
Asset retirement obligation expense		—			8,049			(655	)		—			7,394
Selling and administrative expenses		1,288			53,753			1,968			—			57,009
Other operating income:
Net gain on disposal or exchange of assets		—			(47,516	)		(61	)		—			(47,577	)
Income from equity affiliates		—			(3,803	)		(5,060	)		—			(8,863	)
Interest expense		39,163			13,607			5,463			(32,906	)		25,327
Interest income		(6,255	)		(22,942	)		(6,927	)		32,906			(3,218	)

Income (loss) before income taxes and minority interests		(22,171	)		109,800			41,147			—			128,776
Income tax provision (benefit)		(18,545	)		24,474			8,785			—			14,714
Minority interests		—			722			—			—			722

Net income (loss)	$	(3,626	)	$	84,604		$	32,362		$	—		$	113,340


	Quarter Ended September 30, 2004
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	784,385		$	150,642		$	(16,038	)	$	918,989
Costs and expenses:
Operating costs and expenses		(1,874	)		633,143			120,387			(16,038	)		735,618
Depreciation, depletion and amortization		—			63,221			6,911			—			70,132
Asset retirement obligation expense		—			9,615			531			—			10,146
Selling and administrative expenses		354			32,279			990			—			33,623
Other operating income:
Net (gain) loss on disposal or exchange of assets		—			(1,795	)		5			—			(1,790	)
Income from equity affiliates		—			(2,645	)		—			—			(2,645	)
Interest expense		37,201			13,470			1,184			(26,929	)		24,926
Early debt extinguishment gains		(556	)		—			—			—			(556	)
Interest income		(4,594	)		(17,965	)		(5,454	)		26,929			(1,084	)

Income (loss) before income taxes and minority interests		(30,531	)		55,062			26,088			—			50,619
Income tax provision (benefit)		(11,875	)		9,870			8,938			—			6,933
Minority interests		—			247			—			—			247

Income (loss) from continuing operations		(18,656	)		44,945			17,150			—			43,439
Loss from discontinued operations, net of taxes		—			(2	)		—			—			(2	)

Net income (loss)	$	(18,656	)	$	44,943		$	17,150		$	—		$	43,437


	Nine Months Ended September 30, 2005
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	2,723,601		$	750,258		$	(64,083	)	$	3,409,776
Costs and expenses:
Operating costs and expenses		(19,416	)		2,228,185			637,173			(64,083	)		2,781,859
Depreciation, depletion and amortization		—			208,239			24,182			—			232,421
Asset retirement obligation expense		—			23,251			500			—			23,751
Selling and administrative expenses		2,836			128,109			4,495			—			135,440
Other operating income:
Net gain on disposal or exchange of assets		—			(94,994	)		(157	)		—			(95,151	)
Income from equity affiliates		—			(13,445	)		(16,096	)		—			(29,541	)
Interest expense		114,939			41,337			16,824			(97,012	)		76,088
Interest income		(16,349	)		(67,657	)		(19,407	)		97,012			(6,401	)

Income (loss) before income taxes and minority interests		(82,010	)		270,576			102,744			—			291,310
Income tax provision (benefit)		(47,764	)		57,013			20,051			—			29,300
Minority interests		—			1,526			—			—			1,526

Net income (loss)	$	(34,246	)	$	212,037		$	82,693		$	—		$	260,484


	Nine Months Ended September 30, 2004
	Parent			Guarantor			Non-Guarantor
	Company			Subsidiaries			Subsidiaries			Eliminations			Consolidated
Total revenues	$	—		$	2,290,416		$	367,048		$	(49,411	)	$	2,608,053
Costs and expenses:
Operating costs and expenses		(1,883	)		1,875,566			318,808			(49,411	)		2,143,080
Depreciation, depletion and amortization		—			189,746			13,246			—			202,992
Asset retirement obligation expense		—			30,768			1,042			—			31,810
Selling and administrative expenses		910			90,210			2,439			—			93,559
Other operating income:
Net gain on disposal or exchange of assets		—			(13,791	)		(354	)		—			(14,145	)
Income from equity affiliates		—			(13,698	)		—			—			(13,698	)
Interest expense		107,367			73,497			2,515			(112,530	)		70,849
Early debt extinguishment gains		(556	)		—			—			—			(556	)
Interest income		(47,584	)		(53,746	)		(14,412	)		112,530			(3,212	)

Income (loss) before income taxes and minority interests		(58,254	)		111,864			43,764			—			97,374
Income tax provision (benefit)		(34,056	)		9,594			10,599			—			(13,863	)
Minority interests		—			900			—			—			900

Income (loss) from continuing operations		(24,198	)		101,370			33,165			—			110,337
Loss from discontinued operations, net of taxes		—			(2,839	)		—			—			(2,839	)

Net income (loss)	$	(24,198	)	$	98,531		$	33,165		$	—		$	107,498


	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


	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


	(Unaudited)				Increase					Quarter Ended		Quarter Ended		Increase
	Quarter Ended September 30,				to Revenues					March 31,		March 31,		to Revenues
	2005		2004		$		%			2006		2005		$		%
	(Dollars in thousands)									(Dollars in thousands)
Sales	$	1,191,282	$	895,156	$	296,126		33.1	%	$	1,288,906	$	1,062,521	$	226,385		21.3	%
Other revenues		32,228		23,833		8,395		35.2	%		22,904		14,959		7,945		53.1	%

Total revenues	$	1,223,510	$	918,989	$	304,521		33.1	%	$	1,311,810	$	1,077,480	$	234,330		21.7	%


					Increase (Decrease) to											Increase to
	(Unaudited)				Segmented Adjusted						Quarter Ended		Quarter Ended			Segmented Adjusted
	Quarter Ended September 30,				EBITDA						March 31,		March 31,			EBITDA
	2005		2004		$			%			2006		2005			$		%
	(Dollars in thousands)										(Dollars in thousands)
Western U.S. Mining Operations	$	104,213	$	113,874	$	(9,661	)		(8.5	)%	$	127,793	$	120,425		$	7,368		6.1	%
Eastern U.S. Mining Operations		96,865		54,911		41,954			76.4	%		132,544		94,806			37,738		39.8	%
Australian Mining Operations		39,780		20,777		19,003			91.5	%		47,756		14,086			33,670		239.0	%
Trading and Brokerage Operations		26,132		16,053		10,079			62.8	%		16,179		(21,868	)		38,047		n/a

Total Segment Adjusted EBITDA	$	266,990	$	205,615	$	61,375			29.8	%	$	324,272	$	207,449		$	116,823		56.3	%

	•		higher gains on disposal or exchange of assets of $81.0 million primarily related to settlement of a contract dispute with a third-party coal supplier (see Note 3), Penn Virginia (“PVR”) unit sales, three resource sales involving non-strategic coal assets and properties ($12.5 million), and an asset exchange in which we acquired Illinois Basin coal reserves in exchange for a) coal reserves, b) our interest in a joint venture and c) monetary consideration. In 2005, we also realized a $31.1 million gain from the sale of all of our remaining 0.838 million PVR units compared to a gain of $9.9 million on the sale of 0.575 million PVR units in 2004;

	•		~~income in 2005 of $16.1 million from our 25.5% interest in Carbones del Guasare (acquired in December 2004), which owns and operates the Paso Diablo Mine in Venezuela; and~~

	•		~~lower net expenses related to generation development of $4.8 million, primarily due to reimbursements from the Prairie State Energy Campus partnership group.~~


	Payments Due by Year
	Within		2-3		4-5		After
(Dollars in thousands)	1 Year		Years		Years		5 Years

Coal reserve lease and royalty obligations	$	142,575	$	401,642	$	334,736	$	52,996


					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: November 8, 2005~~	~~By:~~	~~/s/ RICHARD A. NAVARRE~~
		~~Richard A. Navarre~~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)