SEC Filing | Arch Resources, Inc.

/s/ Robert G. Jones

Robert G. Jones

Attorney-in-fact

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-K/A

Amendment No. 1

ANNUAL REPORT
PURSUANT TO SECTIONS 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

(Mark One)


þ		Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2004


o		Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to .

Commission file number: 1-13105

Arch Coal, Inc.

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		43-0921172 (I.R.S. Employer Identification Number

One CityPlace Drive, Suite 300, St. Louis, Missouri (Address of principal executive offices)		63141 (Zip code)

Registrant’s telephone number, including area code: (314) 994-2700

Securities registered pursuant to Section 12(b) of the Act:


Title of Each Class		Name of Each Exchange on Which Registered

Common Stock, $.01 par value Preferred Share Purchase Rights 5% Perpetual Cumulative Convertible Preferred Stock		New York Stock Exchange New York Stock Exchange None

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No £

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No þ

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

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

At June 30, 2004, based on the closing price of the registrant’s common stock on the New York Stock Exchange on that date, the aggregate market value of the voting stock held by non-affiliates of the registrant was approximately $1,599,826,582. In determining this amount, the registrant has assumed that all of its executive officers and directors, and persons known to it to be the beneficial owners of more than five percent of its common stock, are affiliates. Such assumption shall not be deemed conclusive for any other purpose.

At December 31, 2005, there were 64,548,850 shares of the registrant’s common stock outstanding.

Documents incorporated by reference:

	1.		Portions of the registrant’s definitive proxy statement, filed with the Securities and Exchange Commission on March 11, 2005, are incorporated by reference into Part III of this Form 10-K

	2.		Portions of the registrant’s Annual Report to Stockholders for the year ended December 31, 2005 are incorporated by reference into Parts I, II and IV of this Form 10-K.

Table of Contents


			Page
Explanatory Note				1

Part II				1
	Item 8.	Financial Statements and Supplementary Data		1
	Item 9A.	Controls and Procedures		1

Part IV				1
	Item 15.	Exhibits and Financial Statement Schedules		1
Portions of Annual Report to Stockholders
Subsidiaries of the Registrant
Consent of Ernst & Young LLP
Rule 13a-14(a)/15d-14(a) Certification of Steven F. Leer
Rule 13a-14(a)/15d-14(a) Certification of Robert J. Messey
Section 1350 Certification of Steven F. Leer
Section 1350 Certification of Robert J. Messey

EXPLANATORY NOTE

This Amendment No. 1 to our Annual Report on Form 10-K amends and restates Items 8 and 9A of Part II and Item 15 of Part IV of, and Exhibit 13 to, our Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 10, 2005, primarily to amend Notes 20 and 23 to our consolidated financial statements and to include a revised report of our independent registered public accounting firm. No information included in the original report on Form 10-K has been amended by this Form 10-K/A to reflect any information, events, developments or results subsequent to the filing of the original report on Form 10-K, except as contained in Note 24 to our consolidated financial statements.

PART II

Item 8. Financial Statements and Supplementary Data.

Reference is made to Item 15 of Part IV of this Amendment No. 1 to our Annual Report on Form 10-K for the information required by Item 8.

Item 9A. Controls and Procedures.

We performed an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2004. Based on that evaluation, our management, including our chief executive officer and chief financial officer, concluded that the disclosure controls and procedures were effective as of such date. There were no changes in internal control over financial reporting that occurred during our fiscal quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Reference is made to Item 15 of Part IV of this Amendment No. 1 to our Annual Report on Form 10-K for management’s annual report on internal control over financial reporting and the report of independent registered public accounting firm.

PART IV

Item 15. Exhibits and Financial Statement Schedules

Our consolidated financial statements and related notes and report of independent registered public accounting firm follow.

Index to Consolidated Financial Statements


Reports of Independent Registered Public Accounting Firm		F-1
Management’s Report on Internal Control over Financial Reporting		F-4
Report of Management		F-5
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002		F-6
Consolidated Balance Sheets at December 31, 2004 and 2003		F-7
Consolidated Statements of Stockholders’ Equity at December 31, 2004, 2003 and 2002		F-8
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002		F-9
Notes to Consolidated Financial Statements		F-10
Schedule of Valuation and Qualifying Accounts		F-48

All other schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and, therefore, have been omitted.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To Board of Directors and Shareholders

of Arch Coal, Inc.

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that Arch Coal, Inc. maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Arch Coal Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Arch Coal, Inc. maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Arch Coal, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

F-1

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Arch Coal, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004 of Arch Coal, Inc. and our report dated February 23, 2005 expressed an unqualified opinion thereon.



	Ernst & Young LLP

St. Louis, Missouri

February 23, 2005

F-2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To Board of Directors and Shareholders

of Arch Coal, Inc.

We have audited the accompanying consolidated balance sheets of Arch Coal, Inc. and subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Arch Coal, Inc. and subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Arch Coal, Inc.’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 23, 2005, expressed an unqualified opinion thereon.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations effective January 1, 2003.



	Ernst & Young LLP

St. Louis, Missouri

February 23, 2005

F-3

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rules 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation, our management concluded that our internal control over financial reporting is effective as of December 31, 2004.

Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2004 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which is included herein.

F-4

REPORT OF MANAGEMENT

The management of Arch Coal, Inc. is responsible for the preparation of the consolidated financial statements and related financial information in this annual report. The financial statements are prepared in accordance with accounting principles generally accepted in the United States and necessarily include some amounts that are based on management’s informed estimates and judgments, with appropriate consideration given to materiality.

The Company maintains a system of internal accounting controls designed to provide reasonable assurance that financial records are reliable for purposes of preparing financial statements and that assets are properly accounted for and safeguarded. The concept of reasonable assurance is based on the recognition that the cost of a system of internal accounting controls should not exceed the value of the benefits derived. The Company has a professional staff of internal auditors who monitor compliance with and assess the effectiveness of the system of internal accounting controls.

The Audit Committee of the Board of Directors, composed of directors who are free from relationships that may impair their independence from Arch Coal, Inc., meets regularly with management, the internal auditors, and the independent auditors to discuss matters relating to financial reporting, internal accounting control, and the nature, extent and results of the audit effort. The independent auditors and internal auditors have full and free access to the Audit Committee, with and without management present.



Steven F. Leer President and Chief Executive Officer		Robert J. Messey Senior Vice President and Chief Financial Officer

F-5

CONSOLIDATED STATEMENTS OF OPERATIONS


		Year Ended December 31,

		2004			2003			2002

		(In thousands of dollars except per share
		data)
REVENUES
	Coal sales	$	1,907,168		$	1,435,488		$	1,473,558
COSTS AND EXPENSES
	Cost of coal sales		1,638,284			1,280,608			1,262,516
	Depreciation, depletion and amortization		166,322			158,464			174,752
	Selling, general and administrative expenses		52,842			43,942			37,999
	Long-term incentive compensation expense		5,495			16,217			—
	Other expenses		35,758			18,245			29,595

			1,898,701			1,517,476			1,504,862

OTHER OPERATING INCOME
	Income from equity investments		10,828			34,390			10,092
	Gain on sale of units of Natural Resource Partners, LP		91,268			42,743			—
	Other operating income		67,483			45,226			50,489

			169,579			122,359			60,581

Income from operations			178,046			40,371			29,277

Interest expense, net:
	Interest expense		(62,634	)		(50,133	)		(51,922	)
	Interest income		6,130			2,636			1,083

			(56,504	)		(47,497	)		(50,839	)

Other non-operating income (expense):
	Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps		(9,010	)		(8,955	)		—
	Other non-operating income		1,044			13,211			—

			(7,966	)		4,256			—
Income (loss) before income taxes and cumulative effect of accounting change			113,576			(2,870	)		(21,562	)
Benefit from income taxes			(130	)		(23,210	)		(19,000	)

Income (loss) before cumulative effect of accounting change			113,706			20,340			(2,562	)
Cumulative effect of accounting change, net of taxes			—			(3,654	)		—

NET INCOME (LOSS)		$	113,706		$	16,686		$	(2,562	)
Preferred stock dividends			(7,187	)		(6,589	)		—

Net income (loss) available to common shareholders		$	106,519		$	10,097		$	(2,562	)

EARNINGS PER COMMON SHARE
Basic earnings (loss) before cumulative effect of accounting change			1.91			0.26			(0.05	)
Cumulative effect of accounting change			—			(0.07	)		—

Basic earnings (loss) per common share		$	1.91		$	0.19		$	(0.05	)

Diluted earnings (loss) before cumulative effect of accounting change			1.78			0.26			(0.05	)
Cumulative effect of accounting change			—			(0.07	)		—

Diluted earnings (loss) per common share		$	1.78		$	0.19		$	(0.05	)

The accompanying notes are an integral part of the consolidated financial statements.

F-6

CONSOLIDATED BALANCE SHEETS


			December 31,

			2004			2003

			(In thousands of dollars
			except share data)
ASSETS
Current assets
	Cash and cash equivalents		$	323,167		$	254,541
	Trade accounts receivable			180,902			118,376
	Other receivables			34,407			29,897
	Inventories			119,893			69,907
	Prepaid royalties			12,995			4,586
	Deferred income taxes			33,933			19,700
	Other			25,560			16,638

		Total current assets		730,857			513,645

Property, plant and equipment
	Coal lands and mineral rights			1,725,339			1,085,517
	Plant and equipment			1,423,550			1,090,762
	Deferred mine development			408,657			285,150

				3,557,546			2,461,429
Less accumulated depreciation, depletion and amortization				(1,524,346	)		(1,146,294	)

		Property, plant and equipment, net		2,033,200			1,315,135

Other assets
	Prepaid royalties			87,285			70,880
	Goodwill			37,381			—
	Deferred income taxes			241,226			246,024
	Equity investments			—			172,045
	Other			126,586			69,920

		Total other assets		492,478			558,869

		Total assets	$	3,256,535		$	2,387,649


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Accounts payable		$	148,014		$	89,975
	Accrued expenses			217,216			180,314
	Current portion of debt			9,824			6,349

		Total current liabilities		375,054			276,638
Long-term debt				1,001,323			700,022
Accrued postretirement benefits other than pension				380,424			352,097
Asset retirement obligations				179,965			143,545
Accrued workers’ compensation				82,446			77,672
Other noncurrent liabilities				157,497			149,640

		Total liabilities		2,176,709			1,699,614

Stockholders’ equity
	Preferred stock, $.01 par value, $50 liquidation preference, authorized 10,000,000 shares, issued 2,875,000 shares			29			29
	Common stock, $.01 par value, authorized 100,000,000 shares, issued 62,500,458 and 53,561,979 shares			631			536
	Paid-in capital			1,280,513			988,476
	Retained deficit			(166,273	)		(255,936	)
	Unearned compensation			(1,830	)		—
	Less treasury stock, at cost, 357,200 shares			(5,047	)		(5,047	)
	Accumulated other comprehensive loss			(28,197	)		(40,023	)

		Total stockholders’ equity		1,079,826			688,035

		Total liabilities and stockholders’ equity	$	3,256,535		$	2,387,649

The accompanying notes are an integral part of the consolidated financial statements.

F-7

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

Three Years Ended December 31, 2004


																		Accumulated
									Retained						Treasury			Other
			Common		Preferred		Paid-In		Earnings			Unearned			Stock at			Comprehensive
			Stock		Stock		Capital		(Deficit)			Compensation			Cost			Loss			Total

			(In thousands of dollars except share and per share data)
BALANCE AT JANUARY 1, 2002			$	527	$	—	$	835,427	$	(239,336	)	$	—		$	(5,047	)	$	(20,829	)	$	570,742
	Comprehensive income
		Net loss								(2,562	)											(2,562	)
		Minimum pension liability adjustment																	(16,416	)		(16,416	)
		Unrealized losses on derivatives																	(5,192	)		(5,192	)

	Total comprehensive loss																					(24,170	)
	Dividends paid ($.23 per share)									(12,045	)											(12,045	)
	Issuance of 81,454 shares of common stock under the stock incentive plan, including income tax benefits							336														336

BALANCE AT DECEMBER 31, 2002				527		—		835,763		(253,943	)		—			(5,047	)		(42,437	)		534,863
	Comprehensive income
		Net income								16,686												16,686
		Minimum pension liability adjustment																	3,403			3,403
		Unrealized losses on derivatives																	(5,940	)		(5,940	)
		Net amount reclassified to income																	4,951			4,951

	Total comprehensive income																					19,100
	Dividends
		Common ($.23 per share)								(12,090	)											(12,090	)
		Preferred ($2.29 per share)								(6,589	)											(6,589	)
	Issuance of 2,875,000 shares of perpetual cumulative convertible preferred stock					29		138,995														139,024
	Issuance of 770,609 shares of common stock under the stock incentive plan, including income tax benefits			9				13,718														13,727

BALANCE AT DECEMBER 31, 2003				536		29		988,476		(255,936	)		—			(5,047	)		(40,023	)		688,035
	Comprehensive income
		Net income								113,706												113,706
		Minimum pension liability adjustment																	1,221			1,221
		Mark-to-market for available-for-sale securities																	2,081			2,081
		Net amount reclassified to income																	8,524			8,524

	Total comprehensive income																					125,532
	Dividends
		Common ($.2975 per share)								(16,856	)											(16,856	)
		Preferred ($2.50 per share)								(7,187	)											(7,187	)
	Issuance of 7,187,500 shares of common stock pursuant to public offering			72				230,455														230,527
	Issuance of 500,000 shares of common stock as contribution to pension plan			5				15,435														15,440
	Issuance of 149,190 shares of common stock under the stock incentive plan — restricted stock units			1				4,246					(4,247	)								—
	Expense recognized on restricted stock units												2,417									2,417
	Issuance of 1,658,179 shares of common stock under the stock incentive plan — stock options, including income tax benefits			17				41,901														41,918

BALANCE AT DECEMBER 31, 2004			$	631	$	29	$	1,280,513	$	(166,273	)	$	(1,830	)	$	(5,047	)	$	(28,197	)	$	1,079,826

The accompanying notes are an integral part of the consolidated financial statements.

F-8

CONSOLIDATED STATEMENTS OF CASH FLOWS


			Year Ended December 31,

			2004			2003			2002

			(In thousands of dollars)
OPERATING ACTIVITIES
Net income (loss)			$	113,706		$	16,686		$	(2,562	)
Adjustments to reconcile to cash provided by operating activities:
	Depreciation, depletion and amortization			166,322			158,464			174,752
	Prepaid royalties expensed			13,889			13,153			8,503
	Accretion on asset retirement obligations			12,681			12,999			—
	Gain on sale of units of Natural Resource Partners, LP			(91,268	)		(42,743	)		—
	Net gain on disposition of property, plant and equipment			(6,668	)		(3,782	)		(751	)
	Income from equity investments			(10,828	)		(34,390	)		(10,092	)
	Net distributions from equity investments			17,678			49,686			17,121
	Cumulative effect of accounting change			—			3,654			—
	Other non-operating (income) expense			7,966			(4,256	)		—
	Changes in operating assets and liabilities (see Note 21)			(67,406	)		(375	)		(4,634	)
	Other			(9,344	)		(6,735	)		(5,920	)

		Cash provided by operating activities		146,728			162,361			176,417

INVESTING ACTIVITIES
	Payments for acquisitions, net of cash acquired			(387,751	)		—			—
	Capital expenditures			(292,605	)		(132,427	)		(137,089	)
	Proceeds from sale of units of Natural Resource Partners, LP			111,447			115,000			33,603
	Proceeds from coal supply agreements			—			52,548			—
	Additions to prepaid royalties			(33,813	)		(32,571	)		(27,339	)
	Proceeds from disposition of property, plant and equipment			7,428			4,282			2,522

		Cash (used in) provided by investing activities		(595,294	)		6,832			(128,303	)

FINANCING ACTIVITIES
	Net borrowings (payments) on revolver and lines of credit			25,000			(65,971	)		(26,513	)
	Net payments on long-term debt			(302	)		(675,000	)		—
	Proceeds from issuance of senior notes			261,875			700,000			—
	Debt financing costs			(12,806	)		(18,508	)		(8,228	)
	Proceeds from sale and leaseback of equipment			—			—			9,213
	Reductions of obligations under capital lease			—			—			(8,210	)
	Dividends paid			(24,043	)		(17,481	)		(12,045	)
	Proceeds from issuance of preferred stock			—			139,024			—
	Proceeds from sale of common stock			267,468			13,727			336

		Cash provided by (used in) financing activities		517,192			75,791			(45,447	)

		Increase in cash and cash equivalents		68,626			244,984			2,667
		Cash and cash equivalents, beginning of year		254,541			9,557			6,890

		Cash and cash equivalents, end of year	$	323,167		$	254,541		$	9,557

SUPPLEMENTAL CASH FLOW INFORMATION:
	Cash paid during the year for interest		$	53,558		$	30,014		$	51,695
	Cash paid (received) during the year for income taxes		$	13,350		$	(6,407	)	$	(3,115	)

The accompanying notes are an integral part of the consolidated financial statements.

F-9

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands of Dollars Except Per Share Data)


	1. Accounting Policies


	*Principles of Consolidation*

The consolidated financial statements include the accounts of Arch Coal, Inc. and its subsidiaries (“the Company”), which operate in the coal mining industry. The Company’s primary business is the production of steam and metallurgical coal from surface and deep mines throughout the United States, for sale to utility, industrial and export markets. The Company’s mines are primarily located in the Powder River Basin, Central Appalachia and Western Bituminous regions of the United States. All subsidiaries (except as noted below) are wholly owned. Intercompany transactions and accounts have been eliminated in consolidation.

The Company’s Wyoming, Colorado and Utah coal operations are included in a joint venture named Arch Western Resources, LLC (“Arch Western”). Arch Western is 99% owned by the Company and 1% owned by BP Amoco. The Company also acts as the managing member of Arch Western.

As of and for the period ending July 31, 2004, the membership interests in the Utah coal operations, Canyon Fuel Company, LLC (“Canyon Fuel”), were owned 65% by Arch Western and 35% by a subsidiary of ITOCHU Corporation. Through July 31, 2004, the Company’s 65% ownership of Canyon Fuel was accounted for on the equity method in the Consolidated Financial Statements as a result of certain super-majority voting rights in the joint venture agreement. Income from Canyon Fuel through July 31, 2004 is reflected in the Consolidated Statements of Operations as income from equity investments (see additional discussion in Note 5, “Equity Investments”). On July 31, 2004, the Company acquired the remaining 35% of Canyon Fuel. See Note 3, “Business Combinations” for further discussion.

The Company’s 17.5% partnership interest in Dominion Terminal Associates is accounted for on the equity method in the consolidated balance sheets. Allocable costs of the partnership for coal loading and storage are included in other expenses in the consolidated statements of operations. (See additional discussion in “Commitments and Contingencies” in Note 20.)


	*Accounting Estimates*

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.


	*Accounting Change*

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“FAS 143”). FAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time the obligations are incurred. Upon initial recognition of a liability, the cost should also be capitalized as part of the carrying amount of the related long-lived asset and allocated to expense over the useful life of the asset. Previously, the Company accrued for the expected costs of these obligations over the estimated useful mining life of the property. See additional discussion in Note 11, “Asset Retirement Obligations.”

F-10

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


	*Cash and Cash Equivalents*

Cash and cash equivalents are stated at cost. Cash equivalents consist of highly liquid investments with an original maturity of three months or less when purchased.


	*Allowance for Uncollectible Receivables*

The Company maintains allowances to reflect the expected uncollectability of its trade accounts receivable and other receivables based on past collection history, the economic environment and specified risks identified in the receivables portfolio. Allowances recorded at December 31, 2004 and 2003 were $3.0 million and $1.5 million, respectively.


	*Inventories*

Inventories consist of the following:


	December 31,

	2004		2003

Coal	$	76,009	$	38,249
Supplies, net of allowance		43,884		31,658

	$	119,893	$	69,907

Coal and supplies inventories are valued at the lower of average cost or market. Coal inventory costs include labor, supplies, equipment costs and operating overhead. The Company has recorded a valuation allowance for slow-moving and obsolete supplies inventories of $23.0 million and $18.8 million at December 31, 2004 and 2003, respectively.


	*Coal Acquisition Costs and Prepaid Royalties*

The costs to obtain coal lease rights are capitalized and amortized primarily by the units-of-production method over the estimated recoverable reserves. Amortization occurs either as the Company mines on the property or as others mine on the property through subleasing transactions.

Rights to leased coal lands are often acquired through royalty payments. Where royalty payments represent prepayments recoupable against production, they are capitalized, and amounts expected to be recouped within one year are classified as a current asset. As mining occurs on these leases, the prepayment is charged to cost of coal sales.


	*Coal Supply Agreements*

Acquisition costs allocated to coal supply agreements (sales contracts) are capitalized and amortized on the basis of coal to be shipped over the term of the contract. Value is allocated to coal supply agreements based on discounted cash flows attributable to the difference between the above or below-market contract price and the then-prevailing market price. The net book value of the Company’s above-market coal supply agreements was $11.1 million and $6.4 million at December 31, 2004 and 2003, respectively. These amounts are recorded in other assets in the accompanying Consolidated Balance Sheets. The net book value of all below-market coal supply agreements was $29.2 million at December 31, 2004. This amount is recorded in other noncurrent liabilities in the accompanying Consolidated Balance Sheets. Amortization expense on all above-market coal supply agreements was $3.8 million, $16.6 million and $22.2 million in 2004, 2003 and 2002, respectively. Amortization income on all below-market coal supply agreements was $4.1 million in 2004. Based on expected shipments related to these contracts, the Company expects to record annual amortization

F-11

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

expense on the above-market coal supply agreements and annual amortization income on the below-market coal supply agreements in each of the next five years as reflected in the table below.


	Above-market		Below-market
	contracts		contracts

2005	$	6,487	$	15,183
2006		769		12,326
2007		361		1,342
2008		361		389
2009		361		—

During 2003, the Company agreed to terms with a large customer seeking to buy out of the remaining term of an above-market coal supply contract. The buy-out resulted in the receipt of $52.5 million in cash during the quarter. The Company wrote off the remaining contract value of $37.5 million and recorded a deferred gain of approximately $15 million related to this transaction. The deferred gain will be recognized ratably through 2012.


	*Exploration Costs*

Costs related to locating coal deposits and determining the economic mineability of such deposits are expensed as incurred.


	*Property, Plant and Equipment*


	Plant and Equipment

Plant and equipment are recorded at cost. Interest costs applicable to major asset additions are capitalized during the construction period. Expenditures which extend the useful lives of existing plant and equipment or increase the productivity of the asset are capitalized. Plant and equipment are depreciated principally on the straight-line method over the estimated useful lives of the assets, which range from three to 30 years except for preparation plants and loadouts. Preparation plants and loadouts are depreciated using the units-of-production method over the estimated recoverable reserves, subject to a minimum level of depreciation.

Leased plant and equipment meeting certain criteria is capitalized and the present value of the related lease payments is recorded as a liability. Amortization of capitalized leased assets is computed on the straight-line method over the term of the lease.


	Deferred Mine Development

Costs of developing new mines or significantly expanding the capacity of existing mines are capitalized and amortized using the units-of-production method over the estimated recoverable reserves that are associated with the property being benefited. Additionally, the asset retirement obligation asset has been recorded as a component of deferred mine development.


	Coal Lands and Mineral Rights

A significant portion of the Company’s coal reserves are controlled through leasing arrangements. Amounts paid to acquire such lease rights are capitalized and depleted over the life of those reserves that are proven and probable. Depletion of coal lease rights is computed using the units-of-production method and the rights are assumed to have no residual value. The leases are generally long-term in nature (original terms range from 10 to 50 years), and substantially all of the leases contain provisions that allow for automatic extension of the lease term as long as mining continues.

F-12

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

The net book value of the Company’s leased coal interests was $1,169.7 million and $693.3 million at December 31, 2004 and 2003, respectively. This increase is due to the addition of leased coal interests resulting from the North Rochelle and Canyon Fuel acquisitions and the Little Thunder leasing arrangement (See additional discussion in “Commitments and Contingencies” in Note 20).


	*Goodwill*

Goodwill represents the excess of purchase price and related costs over the value assigned to the net tangible and identifiable intangible assets of businesses acquired. In accordance with SFAS No. 142, Goodwill and Other Intangible Assets (“FAS 142”), goodwill is not amortized but is tested for impairment annually, or if certain circumstances indicate a possible impairment may exist. Impairment testing is performed at a reporting unit level. An impairment loss generally would be recognized when the carrying amount of the reporting unit exceeds the fair value of the reporting unit, with the fair value of the reporting unit determined using a discounted cash flow analysis.


	*Asset Impairment*

If facts and circumstances suggest that a long-lived asset may be impaired, the carrying value is reviewed. If this review indicates that the value of the asset will not be recoverable, as determined based on projected undiscounted cash flows related to the asset over its remaining life, then the carrying value of the asset is reduced to its estimated fair value.


	*Revenue Recognition*

Coal sales revenues include sales to customers of coal produced at Company operations and coal purchased from other companies. The Company recognizes revenue from coal sales at the time title passes to the customer. Transportation costs that are billed by the Company and reimbursed to the transportation provider (pass through costs) are included in coal sales and cost of coal sales.


	*Other Operating Income*

Other operating income reflects income from sources other than coal sales, including administration and production fees from Canyon Fuel (these fees ceased as of the July 31, 2004 acquisition by the Company of the remaining 35% interest in Canyon Fuel), royalties earned from properties leased to third parties, and gains and losses from dispositions of long-term assets. These amounts are recognized as services are performed or otherwise earned.


	*Derivative Financial Instruments*

Derivative financial instruments are accounted for in accordance with Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS 133”). FAS 133 requires all derivative financial instruments to be reported on the balance sheet at fair value. Changes in fair value are recognized either in earnings or equity, depending on the nature of the underlying exposure being hedged and how effective the derivatives are at offsetting price movements in the underlying exposure.

The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives for undertaking various hedge transactions. The Company evaluates the effectiveness of its hedging relationships both at the hedge inception and on an ongoing basis. Any ineffectiveness is recorded in the Consolidated Statements of Operations. Ineffectiveness for the years ended December 31, 2004 and 2003 was $0.2 million and $0.4 million, respectively.

F-13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

The Company has historically utilized interest-rate swap agreements to modify the interest characteristics of outstanding Company debt. The swap agreements essentially convert variable-rate debt to fixed-rate debt. These agreements require the exchange of amounts based on variable interest rates for amounts based on fixed interest rates over the life of the agreement. The Company accrues amounts to be paid or received under interest-rate swap agreements over the lives of the agreements. Such amounts are recognized as adjustments to interest expense over the lives of agreements, thereby adjusting the effective interest rate on the Company’s debt.

At December 31, 2004, the Company’s net interest rate swap position is as follows:


	•	Swaps with a notional value of $25.0 million which are designated as hedges of future interest payments to be made under the Company’s revolving credit facility. Under these swap agreements, the Company pays a fixed rate of 5.96% (before the credit spread over LIBOR) and receives a weighted-average variable rate based upon 30-day LIBOR. At December 31, 2004, the remaining term of the swap agreements was 30 months.

	•	Swaps with a total notional value of $500.0 million consisting of offsetting positions of $250.0 million each. Because of the offsetting nature of these positions, the Company is not exposed to market interest rate risk related to these swaps. Under these swaps, the Company pays a weighted average fixed rate 5.72% on $250.0 million of notional value and receives a weighted average fixed rate of 2.71% on $250.0 million of notional value. The remaining terms of these swap agreements at December 31, 2004 ranged from 8 to 31 months.

Changes in the market value of the interest-rate swaps that no longer qualify as hedges are recorded as income or expense in the period of the change. During 2003, the Company recorded gains of $13.4 million resulting from changes in the market value of interest-rate swaps. This amount is included as other non-operating income in the accompanying Consolidated Statements of Operations.


	*Income Taxes*

Deferred income taxes are based on temporary differences between the financial statement and tax basis of assets and liabilities existing at each balance sheet date using enacted tax rates for years during which taxes are expected to be paid or recovered.


	*Stock-Based Compensation*

These financial statements include the disclosure requirements of Financial Accounting Standards Board Statement No. 123, Accounting for Stock-Based Compensation (“FAS 123”), as amended by Statement of Financial Accounting Standards No. 148, Accounting for Stock-Based Compensation — Transition and Disclosure (“FAS 148”). With respect to accounting for its stock options, as permitted under FAS 123, the Company has retained the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25 (“APB 25”), Accounting for Stock Issued to Employees, and related Interpretations. Had compensation expense for stock option grants been determined based on the fair value at the grant dates consistent with the method of FAS 123, the Company’s net income (loss) and

F-14

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

earnings (loss) per common share would have been changed to the pro forma amounts as indicated in the following table:


		Year Ended December 31

		2004		2003		2002

As reported
	Net income (loss) available to common shareholders	$	106,519	$	10,097	$	(2,562	)
	Basic earnings (loss) per share		1.91		0.19		(0.05	)
	Diluted earnings (loss) per share		1.78		0.19		(0.05	)
Pro forma (unaudited)
	Net income (loss) available to common shareholders	$	101,054	$	858	$	(11,168	)
	Basic earnings (loss) per share		1.81		0.02		(0.21	)
	Diluted earnings (loss) per share		1.70		0.02		(0.21	)

On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payment” (FAS 123R), which requires all public companies to measure compensation cost in the income statement for all share-based payments (including employee stock options) at fair value for interim or annual periods beginning after June 15, 2005. The Company intends to adopt FAS 123R on July 1, 2005 using the modified-prospective method and anticipates a pre-tax charge to income of approximately $3.5 million for the expensing of unvested stock options and price contingent stock awards for the period July 1, 2005 through December 31, 2005. FAS 123R also requires the benefits of tax deductions in excess of recognized compensation cost to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption.


	*Recent Accounting Pronouncements*

In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4” (FAS 151). This Statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). Provisions of this statement are effective for fiscal years beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on its financial statements.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153, “Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions” (FAS 153). This Statement’s amendments are based on the principle that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. Further, FAS 153 eliminates the narrow exception for nonmonetary exchanges of similar productive assets and replaces it with a broader exception for exchanges of nonmonetary assets that do not have commercial substance. Provisions of this statement are effective for fiscal periods beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on its financial statements.

F-15

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


	*Reclassifications*

Certain amounts in the prior years’ financial statements have been reclassified to conform with the classifications in the current year’s financial statements with no effect on previously reported net income or stockholders’ equity.


	2. Changes in Estimates and Other Non-Recurring Revenues and Expenses

During the year ending December 31, 2004, the Company assigned its rights and obligations on a parcel of land to a third party resulting in a gain of $5.8 million. The gain is reflected in other operating income.

During 2004, the Company filed a royalty rate reduction request with the Bureau of Land Management (“BLM”) for its West Elk mine in Colorado. The BLM notified the Company that it would receive a royalty rate reduction for a specified number of tons representing a retroactive portion for the year totaling $2.7 million. The retroactive portion was recognized as a component of cost of coal sales in the Consolidated Statement of Operations.

In connection with the settlement of tax audits for prior years, the Company recorded interest income of $2.2 million in 2004 related to federal income tax refunds. This amount is reflected as interest income.

During the year ending December 31, 2004, the Company was notified by the IRS that it would receive additional black lung excise tax refunds and interest related to black lung claims that were originally denied by the IRS in 2002. The Company recognized a gain of $2.8 million ($2.1 million refund and $0.7 million of interest) related to the claims. The $2.1 million refund was recorded as a component of cost of coal sales, while the $0.7 million of interest was recorded as interest income.

During the year ending December 31, 2004, Canyon Fuel, which was accounted for under the equity method through July 31, 2004, began the process of idling its Skyline Mine (the idling process was completed in May 2004), and incurred severance costs of $3.2 million for the year ended December 31, 2004. The Company’s share of these costs totals $2.1 million and is reflected in income from equity investments.

During the year ending December 31, 2003, the Company instituted cost reduction efforts throughout its operations. These cost reduction efforts included the termination of approximately 100 employees at the Company’s corporate headquarters and its Central Appalachia mining operations and the recognition of expenses related to severance of $2.6 million. Of this amount, $1.6 million was reported as a component of cost of coal sales, with the remainder reported in selling, general and administrative expenses. Substantially all of the amounts noted were paid during 2003.

During the year ended December 31, 2003, the Company was notified by the State of Wyoming of a favorable ruling relating to the Company’s calculation of coal severance taxes. The ruling resulted in a refund of previously paid taxes and the reversal of previously accrued taxes payable. The impact on the 2003 financial results was a gain of $2.5 million, which was reflected as a reduction of cost of coal sales.

During the year ended December 31, 2003, the Company repaid its variable-rate term loans with the proceeds from the sale of fixed-rate notes. At that time, the Company determined that certain interest rate swaps that had been designated as hedges of the variable-rate interest payments were no longer effective hedges. Historical mark-to-market losses related to these swaps totaling $27.0 million had been previously deferred and are now being amortized as additional expense over the contractual terms of the swap agreements. The swap agreements’ contractual termination dates

F-16

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

range from September 2005 through October 2007. During 2004 and 2003, the Company recognized expenses of $8.3 million and $4.3 million, respectively, related to the amortization of these previously deferred mark-to-market adjustments. The Company recognized an additional $0.7 million and $4.7 million of expense in 2004 and 2003, respectively, that represented early debt extinguishment costs. These amounts are included in expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps in the accompanying Consolidated Statements of Operations.

During the year ended December 31, 2002, the Company settled certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. The settlements resulted in a pre-tax gain of $5.6 million, which was recognized in other operating income in the Consolidated Statements of Operations.

The Company recognized a pre-tax gain of $4.6 million during the year ended December 31, 2002 as a result of a workers’ compensation premium adjustment refund from the State of West Virginia. During 1998, the Company entered into the West Virginia workers’ compensation plan at one of its subsidiary operations. The subsidiary paid standard base rates until the West Virginia Division of Workers’ Compensation could determine the actual rates based on claims experience. Upon review, the Division of Workers’ Compensation refunded $4.6 million in premiums, which was recognized as an adjustment to cost of coal sales in the Consolidated Statements of Operations.

During 2002, the Company filed a royalty rate reduction request with the BLM for its West Elk mine in Colorado. The BLM notified the Company that it would receive a royalty rate reduction for a specified number of tons representing a retroactive portion for the year totaling $3.3 million. The retroactive portion was recognized as a component of cost of coal sales in the Consolidated Statement of Operations. Additionally in 2002, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined representing a retroactive refund of $1.1 million. The retroactive amount was reflected in income from equity investments in the Consolidated Statement of Operations.


	3. Business Combinations


	*Canyon Fuel 35% Acquisition*

On July 31, 2004, the Company purchased the 35% interest in Canyon Fuel that it did not own from ITOCHU Corporation. The purchase price, including related costs and fees, of $112.2 million was funded with cash of $90.2 million and a five-year, $22.0 million non-interest bearing note. Net of cash acquired, the fair value of the transaction totaled $97.4 million. As a result of the acquisition, the Company owns substantially all of the ownership interests of Canyon Fuel and will no longer account for its investment in Canyon Fuel on the equity method but will consolidate Canyon Fuel in its financial statements. As of December 31, 2003, Canyon Fuel controlled approximately 161.0 million tons of low-sulfur coal reserves in Utah and produced approximately 13.0 million tons of coal in 2003. The results of operations of the Canyon Fuel mines are included in the Company’s Western Bituminous segment.

The preliminary purchase accounting allocation related to the acquisition has been recorded in the accompanying consolidated financial statements as of, and for the period subsequent to, July 31, 2004. The final valuation of the assets acquired and liabilities assumed is expected to be finalized once third-party appraisals are completed. The Company expects the completion of these appraisals during the first half of 2005.

F-17

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

The following table summarizes the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition (dollars in thousands):


Accounts receivable	$	7,432
Materials and supplies		3,751
Coal inventory		7,434
Other current assets		6,466
Property, plant, equipment and mine development		125,881
Accounts payable and accrued expenses		(10,379	)
Coal supply agreements		(33,378	)
Other noncurrent assets and liabilities, net		(9,823	)

Total purchase price, net of cash received of $11.0 million	$	97,384

Amounts preliminarily allocated to coal supply agreements noted in the table above represent the liability established for the net below-market coal supply agreements to be amortized over the remaining terms of the contracts. The liability is classified as an other noncurrent liability on the accompanying Consolidated Balance Sheet. The amortization period on these acquired coal supply agreements ranges from one to three years.


	*Triton Acquisition*

On August 20, 2004, the Company acquired (1) Vulcan Coal Holdings, L.L.C., which owns all of the common equity of Triton Coal Company, LLC (“Triton”), and (2) all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Prior to the acquisition, Triton was the nation’s sixth largest coal producer in 2003 and operated two mines in the Powder River Basin, North Rochelle and Buckskin. Following the consummation of the transaction, the Company completed the agreement to sell Buckskin to Kiewit Mining Acquisition Company (“Kiewit”). The net sales price for this second transaction was $73.1 million. The total purchase price, including related costs and fees, was funded with cash on hand, including the proceeds from the Buckskin sale, $22.0 million in borrowings under the Company’s existing revolving credit facility and a $100.0 million term loan at its Arch Western Resources subsidiary. Upon acquisition, the Company integrated the North Rochelle mine with its existing Black Thunder mine in the Powder River Basin.

The preliminary purchase accounting allocations related to the acquisition have been recorded in the accompanying consolidated financial statements as of, and for the periods subsequent to, August 20, 2004. The final valuation of the assets acquired and liabilities assumed is expected to be finalized once third-party appraisals are completed. The Company expects the completion of these appraisals during the first half of 2005.

F-18

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

The following table summarizes the preliminary estimated fair values of the assets acquired and the liabilities assumed at the date of acquisition (dollars in thousands):


Accounts receivable	$	14,233
Materials and supplies		4,161
Coal inventory		4,874
Other current assets		2,200
Property, plant, equipment and mine development		325,194
Coal supply agreements		8,486
Goodwill		37,381
Accounts payable and accrued expenses		(72,408	)
Other noncurrent assets and liabilities, net		(15,550	)

Total purchase price, net of cash received of $0.4 million	$	308,571

Amounts preliminarily allocated to coal supply agreements noted in the table above represent the value attributed to the net above-market coal supply agreements to be amortized over the remaining terms of the contracts. The amortization period on these acquired coal supply agreements ranges from one to seven years.

The goodwill amount above arose due to the delay in time between the execution of the acquisition agreement and the date of closing because of the Federal Trade Commission’s lawsuit to block the acquisition and is attributable to the loss of value from the tons mined during this period. Of the $37.4 million allocated to goodwill above, $27.5 million was deductible for income tax purposes.

Included in the amounts allocated to accounts payable and accrued expenses noted in the table above are $5.5 million of liabilities incurred in connection with terminating Vulcan employees upon acquisition. Upon acquisition, the Company identified 24 employees of Vulcan who were terminated as part of the integration of the North Rochelle mine into the Company’s Black Thunder mine. All amounts accrued for severance have been paid as of December 31, 2004.


	*Pro Forma Financial Information*

The following unaudited pro forma financial information presents the combined results of operations of the Company, the remaining Canyon Fuel interest acquired from ITOCHU Corporation and the North Rochelle operations acquired from Triton, on a pro forma basis, as though the purchases had occurred as of the beginning of each period presented. The pro forma financial information does not necessarily reflect the results of operations that would have occurred had the

F-19

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

Company and the operations acquired from Canyon Fuel and Triton constituted a single entity during those periods:


		Year Ended December 31,

		2004		2003

		(In thousands, except
		per share data)
Revenues:
	As reported	$	1,907,168	$	1,435,488
	Pro forma		2,156,958		1,876,205
Income before accounting changes:
	As reported		113,706		20,340
	Pro forma		103,933		13,747
Net income available to common shareholders:
	As reported		106,519		10,097
	Pro forma		96,746		1,058
Basic earnings per share:
	As reported		1.91		0.19
	Pro forma		1.73		0.02
Diluted earnings per share:
	As reported		1.78		0.19
	Pro forma		1.63		0.02


	4. Other Comprehensive Income

Other comprehensive income items under Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income, are transactions recorded in stockholders’ equity during the year, excluding net income and transactions with stockholders. Following are the items included in other comprehensive income (loss), net of a 39% tax rate:


				Minimum					Accumulated
				Pension					Other
	Financial			Liability			Available-for-sale		Comprehensive
	Derivatives			Adjustments			Securities		Loss

Balance January 1, 2002	$	(17,978	)	$	(2,851	)	$	—	$	(20,829	)
2002 activity		(5,192	)		(16,416	)		—		(21,608	)

Balance December 31, 2002		(23,170	)		(19,267	)		—		(42,437	)
2003 activity		(989	)		3,403			—		2,414

Balance December 31, 2003		(24,159	)		(15,864	)		—		(40,023	)
2004 activity		8,524			1,221			2,081		11,826

Balance December 31, 2004	$	(15,635	)	$	(14,643	)	$	2,081	$	(28,197	)

The 2004 activity for financial derivatives is comprised substantially of reclassifications to net income.

F-20

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


	5. Equity Investments

As of December 31, 2004, the Company held no equity investments. The Company purchased the remaining 35% interest in Canyon Fuel on July 31, 2004. Prior to July 31, 2004, the Company accounted for its investment in Canyon Fuel on the equity method. Additionally, prior to March 10, 2004, the Company accounted for its investment in Natural Resource Partners, LP (“NRP”) on the equity method. Amounts recorded in the Condensed Consolidated Financial Statements are as follows:


		December 31,

		2004		2003

Equity investments:
	Investment in Canyon Fuel	$	—	$	146,180
	Investment in NRP		—		25,865

Equity investments as reported in Consolidated Balance Sheets		$	—	$	172,045


		Year Ended December 31,

		2004		2003		2002

Income from equity investments:
	Income from investment in Canyon Fuel	$	8,410	$	19,707	$	7,774
	Income from investment in NRP		2,418		14,683		2,318

Income from equity investments in the Consolidated Statements of Operations		$	10,828	$	34,390	$	10,092


	*Investment in Canyon Fuel*

The following tables present unaudited, summarized financial information for Canyon Fuel, for periods in which it was accounted for on the equity method.

Condensed Income Statement Information


	Period Ended		Year Ended December 31,
	July 31,
	2004		2003		2002

Revenues	$	142,893	$	242,060	$	250,325
Total costs and expenses		133,546		223,357		249,325

Net income before cumulative effect of accounting change	$	9,347	$	18,703	$	1,000

65% of Canyon Fuel net income	$	6,075	$	12,157	$	650
Effect of purchase adjustments		2,335		7,550		7,124

Arch Coal’s income from its equity investment in Canyon Fuel	$	8,410	$	19,707	$	7,774

F-21

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

Condensed Balance Sheet Information


	December 31, 2003

			Arch
			Ownership
	Canyon		of Canyon		Arch Purchase
	Fuel Basis		Fuel Basis		Adjustments			Arch Basis

Current assets	$	51,660	$	33,579	$	(2,492	)	$	31,087
Noncurrent assets		324,777		211,105		(59,622	)		151,483
Current liabilities		25,692		16,700		—			16,700
Noncurrent liabilities		30,292		19,690		—			19,690

Members’ equity	$	320,453	$	208,294	$	(62,114	)	$	146,180

Through July 31, 2004, the Company’s income from its equity investment in Canyon Fuel represented 65% of Canyon Fuel’s net income after adjusting for the effect of purchase adjustments related to its investment in Canyon Fuel. The Company’s investment in Canyon Fuel reflects purchase adjustments primarily related to the reduction in amounts assigned to sales contracts, mineral reserves and other property, plant and equipment. The purchase adjustments are amortized consistent with the underlying assets of the joint venture.

Effective January 1, 2003, Canyon Fuel adopted FAS 143 and recorded a cumulative effect loss of $2.4 million. The Company’s 65% share of this amount was offset by purchase adjustments of $0.5 million. These amounts are included in the cumulative effect of accounting change reported in the Company’s Consolidated Statements of Operations.


	*Investment in Natural Resource Partners, L.P.*

During 2002, the Company contributed 454 million tons of coal reserves with a net book value of $84.9 million to Natural Resource Partners L.P. in exchange for 4.8 million of NRP’s common limited partnership units, 4.8 million of NRP’s subordinated limited partnership units, and 42.25% of NRP’s general partner interest. Concurrent with the contribution, the Company entered into various leases with NRP for the right to mine approximately 57 million tons of the contributed reserves. No gain was recorded at the time of the contribution of the reserves and formation of NRP. On October 17, 2002, the Company sold 1.9 million of its common limited partner units in a public offering for proceeds of $33.6 million.

On December 22, 2003, the Company sold its 4.8 million subordinated units and its general partner interest for a purchase price of $115.0 million. This sale resulted in a gain of $70.6 million, of which $42.7 million was recognized in 2003 and the remainder was deferred. After this sale, the Company’s remaining ownership in NRP consisted of 2.9 million common limited partnership units, representing approximately 12.5% of NRP’s outstanding partnership interests.

During the year ended December 31, 2004, the Company sold its remaining limited partnership units of NRP in three separate transactions occurring in March, June and October. These sales resulted in proceeds of approximately $111.4 million and gains of $91.3 million.

As of December 31, 2004, the Company had deferred gains from its sales of NRP units totaling $21.8 million, which are included as “Other noncurrent liabilities” in the accompanying Consolidated Balance Sheets. These deferred gains will be recognized over the remaining term of the Company’s leases with NRP, as follows: $7.6 million in 2005, $4.6 million in 2006, $3.9 million in 2007, and a total of $5.7 million from 2008 through 2012.

F-22

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


	6. Accrued Expenses

Accrued expenses included in current liabilities consist of the following:


	December 31,

	2004		2003

Payroll and related benefits	$	32,358	$	36,846
Taxes other than income taxes		76,246		49,140
Postretirement benefits other than pension		29,685		26,324
Workers’ compensation		12,774		13,088
Interest		35,102		26,025
Asset retirement obligations		19,632		19,186
Other accrued expenses		11,419		9,705

	$	217,216	$	180,314


	7. Income Taxes

Significant components of the provision (benefit) for income taxes are as follows:


			December 31,

			2004			2003			2002

Current:
	Federal		$	7,583		$	4,668		$	(21,646	)
	State			—			—			—

		Total current		7,583			4,668			(21,646	)

Deferred:
	Federal			(5,412	)		(24,438	)		5,788
	State			(2,301	)		(3,440	)		(3,142	)

		Total deferred		(7,713	)		(27,878	)		2,646

			$	(130	)	$	(23,210	)	$	(19,000	)

A reconciliation of the statutory federal income tax expense (benefit) on the Company’s pretax income (loss) to the actual provision (benefit) for income taxes follows:


	December 31,

	2004			2003			2002

Income tax expense (benefit) at statutory rate	$	39,760		$	(1,005	)	$	(7,547	)
Percentage depletion allowance		(22,807	)		(16,211	)		(21,366	)
State taxes, net of effect of federal taxes		1,729			(2,123	)		(4,585	)
Change in valuation allowance, affecting provision		(265	)		3,543			25,880
Reversal of reserve for capital loss		—			(5,850	)		—
Favorable tax settlement		(16,861	)		(1,464	)		(10,506	)
Other, net		(1,686	)		(100	)		(876	)

	$	(130	)	$	(23,210	)	$	(19,000	)

During 2004, the IRS completed an audit and review of tax returns and claims for tax years 1999 through 2002 resulting in a favorable tax settlement, which includes a $9.7 million reduction in prior

F-23

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

years tax reserves. Also, compensatory stock options were exercised resulting in a tax benefit of $5.0 million that was recorded to paid in capital.

During 2003, the Company reversed a $5.8 million tax reserve, which was established in prior years, for capital loss deductions which the Company deemed had no value at that time. Capital losses are only deductible to the extent that a company has capital gains. Capital gains generated during 2003 and projected to be generated in future years will fully absorb the capital loss. Also during the year, the Company reversed a $1.5 million tax reserve as a result of filing amended state income tax returns based on prior year IRS audit changes.

During 2002, the Company received notice from the IRS that it will receive tax refunds of $3.6 million as a result of proposed adjustments to tax years 1997 and 1998. In addition, carryover adjustments have been allowed which will reduce the Company’s 1999 and 2000 taxes paid by an additional $5.3 million. These favorable adjustments are primarily the result of revisions in the tax treatment of acquisitions made during the audit years. Tax refunds for 1999 and 2000 will not be realized until audits of those years have been completed.

Management believes that the Company has adequately provided for any income taxes and interest which may ultimately be paid with respect to all open tax years.

F-24

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

Significant components of the Company’s deferred tax assets and liabilities that result from carryforwards and temporary differences between the financial statement basis and tax basis of assets and liabilities are summarized as follows:


				December 31,

				2004			2003

Deferred tax assets:
	Postretirement benefits other than pension			$	152,622		$	144,993
	Alternative minimum tax credit carryforward				99,582			92,229
	Net operating loss carryforwards				74,226			77,127
	Reclamation and mine closure				42,776			41,953
	Workers’ compensation				32,453			33,239
	Plant and equipment				19,143			20,372
	Other comprehensive income				16,412			18,918
	Tax intangibles				13,880			17,999
	Advance royalties				13,303			13,023
	Coal Supply Agreements				10,233			—
	Other				32,463			41,789

		Gross deferred tax assets			507,093			501,642
	Valuation allowance				(163,005	)		(161,113	)

		Total deferred tax assets			344,088			340,529

Deferred tax liabilities:
	Investment in tax partnerships				38,251			33,230
	Coal supply agreements				—			971
	Other				30,678			40,604

		Total deferred tax liabilities			68,929			74,805

			Net deferred tax asset		275,159			265,724
		Less current asset			33,933			19,700

			Long-term deferred tax asset	$	241,226		$	246,024

The Company has federal net operating loss carryforwards for regular income tax purposes of $145.2 million which will expire in the years 2007 to 2022. The Company has an alternative minimum tax credit carryforward of $99.6 million, which may carry forward indefinitely to offset future regular tax in excess of alternative minimum tax.

The Company has recorded a valuation allowance for a portion of its deferred tax assets that management believes, more likely than not, will not be realized. These deferred tax assets include a portion of the alternative minimum tax credits and some of the deductible temporary differences that will likely not be realized at the maximum effective tax rate.

F-25

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

Such valuation allowance consisted of the following components at December 31 on the years indicated:


		2004		2003

Unrealized future deductible temporary differences		$	114,776	$	117,564
Unutilized alternative minimum tax credits			48,229		43,549

	Valuation Allowance at December 31	$	163,005	$	161,113


	8. Debt and Financing Arrangements

Debt consists of the following:


	December 31,

	2004		2003

Indebtedness to banks under lines of credit	$	—	$	—
Indebtedness to banks under revolving credit agreement,
expiring December 22, 2009 (weighted average rate at December 31, 2004 — 4.73%)		25,000		—
6.75% senior notes ($950.0 million face value) due July 1, 2013		961,613		700,000
Promissory note		17,523		—
Other		7,011		6,371

		1,011,147		706,371
Less current portion		9,824		6,349

Long-term debt	$	1,001,323	$	700,022

On December 22, 2004, the Company entered into a $700.0 million revolving credit facility that matures on December 22, 2009. The rate of interest on borrowings under the credit facility is a floating rate based on LIBOR. The Company’s credit facility is secured by substantially all of its assets as well as its ownership interests in substantially all of its subsidiaries, except its ownership interests in Arch Western and its subsidiaries. The credit facility replaced the Company’s existing $350.0 million revolving credit facility. At December 31, 2004, the Company had $69.0 million in letters of credit outstanding which, when combined with the $25.0 million of outstanding borrowings under the revolver, resulted in $606.0 million of unused borrowings under the revolver.

On October 22, 2004, the Company issued $250.0 million of 6.75% Senior Notes due 2013 at a price of 104.75% of par. Interest on the notes is payable on January 1 and July 1 of each year, beginning on January 1, 2005. The senior notes were issued under an indenture dated June 25, 2003, under which the Company previously issued $700.0 million of 6.75% Senior Notes due 2013. The senior notes are guaranteed by Arch Western and certain of Arch Western’s subsidiaries and are secured by a security interest in loans made to Arch Coal by Arch Western. The terms of the senior notes contain restrictive covenants that limit Arch Western’s ability to, among other things, incur additional debt, sell or transfer assets, and make certain investments.

On July 31, 2004, the Company issued a five year, $22.0 million non-interest bearing note to help fund the Canyon Fuel acquisition. At its issuance, the note was discounted to its present value using a rate of 7.0%. The promissory note is payable in quarterly installments of $1.0 million through July 2008 and $1.5 million from October 2008 through July 2009.

F-26

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

The Company also periodically establishes uncommitted lines of credit with banks. These agreements generally provide for short-term borrowings at market rates. At December 31, 2004, there were $20.0 million of such agreements in effect, of which none were outstanding.

Aggregate contractual maturities of debt are $10.9 million in 2005, $4.1 million in 2006, $4.0 million in 2007, $4.5 million in 2008, $29.5 million in 2009 and $950.0 million thereafter.

Terms of the Company’s credit facilities and leases contain financial and other covenants that limit the ability of the Company to, among other things, effect acquisitions or dispositions and borrow additional funds and require the Company to, among other things, maintain various financial ratios and comply with various other financial covenants. In addition, the covenants require the pledging of assets to collateralize the Company’s revolving credit facility. The assets pledged include equity interests in wholly-owned subsidiaries, certain real property interests, accounts receivable and inventory of the Company. Failure by the Company to comply with such covenants could result in an event of default, which, if not cured or waived, could have a material adverse effect on the Company. The Company was in compliance with all financial covenants at December 31, 2004.


	9. Fair Values of Financial Instruments

The following methods and assumptions were used by the Company in estimating its fair value disclosures for financial instruments:


	Cash and cash equivalents: The carrying amounts approximate fair value.

	Debt: At December 31, 2004 and 2003, the fair value of the Company’s senior notes and other long-term debt, including amounts classified as current, was $1,000.6 million and $728.5 million, respectively.

	Interest rate swaps: The fair values of interest rate swaps are based on quoted prices, which reflect the present value of the difference between estimated future amounts to be paid and received. At December 31, 2004 and 2003 the fair value of these swaps are liabilities of $12.4 million and $22.5 million, respectively. This liability is included in other noncurrent liabilities in the Consolidated Balance Sheets.


	10. Accrued Workers’ Compensation

The Company is liable under the federal Mine Safety and Health Act of 1969, as subsequently amended, to provide for pneumoconiosis (black lung) benefits to eligible employees, former employees, and dependents. The Company is also liable under various states’ statutes for black lung benefits. The Company currently provides for federal and state claims principally through a self-insurance program. Charges are being made to operations as determined by independent actuaries, at the present value of the actuarially computed present and future liabilities for such benefits over the employees’ applicable years of service.

In addition, the Company is liable for workers’ compensation benefits for traumatic injuries that are accrued as injuries are incurred. Traumatic claims are either covered through self-insured programs or through state sponsored workers’ compensation programs.

F-27

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

Workers’ compensation expense consists of the following components:


		2004			2003			2002

Self-insured black lung benefits:
	Service cost	$	1,447		$	1,491		$	916
	Interest cost		2,660			2,942			3,060
	Net amortization		(1,080	)		(247	)		(639	)

Total black lung disease			3,027			4,186			3,337
	Traumatic injury claims and assessments		18,725			14,008			9,038

Total provision		$	21,752		$	18,194		$	12,375

Payments for worker’s compensation benefits		$	21,068		$	17,072		$	9,856
Discount rate			6.00	%		6.50	%		7.00	%
Cost escalation rate			4.00	%		4.00	%		4.00	%

Net amortization represents the systematic recognition of actuarial gains or losses over a five year period.

As discussed in Note 2, the Company recognized a pre-tax gain of $4.6 million in 2002 as a result of a workers’ compensation premium adjustment refund from the State of West Virginia.

Summarized below is information about the amounts recognized in the consolidated balance sheets for workers’ compensation benefits:


	December 31,

	2004		2003

Black lung costs	$	51,793	$	47,038
Traumatic and other workers’ compensation claims		43,427		43,722

Total obligations		95,220		90,760
Less amount included in accrued expenses		12,774		13,088

Noncurrent obligations	$	82,446	$	77,672

The reconciliation of changes in the benefit obligation of the black lung liability is as follows:


		December 31,

		2004			2003

Beginning of year obligation		$	46,722		$	46,856
	Service cost		1,447			1,491
	Interest cost		2,660			2,942
	Actuarial gain		(1,122	)		(1,243	)
	Benefit and administrative payments		(2,066	)		(3,324	)

Net obligation at end of year			47,641			46,722
	Unrecognized gain		4,152			316

Accrued cost		$	51,793		$	47,038

Receivables related to benefits contractually recoverable from others of $0.4 million in both 2004 and 2003 are recorded in other long-term assets.

F-28

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


	11. Asset Retirement Obligations

The Company’s asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. The required reclamation activities to be performed are outlined in the Company’s mining permits. These activities include reclaiming the pit and support acreage at surface mines, sealing portals at deep mines, and reclaiming refuse areas and slurry ponds.

The Company records its asset retirement obligations at the time that they are incurred or acquired. Obligations are incurred at the time that development of a mine commences for deep and surface mines and at the time that construction begins for support facilities, refuse areas and slurry ponds. The liability is determined using discounted cash flow techniques and is accreted to its then present value each period. Accretion on the asset retirement obligation begins at the time the liability is incurred. Amortization of the related asset is recorded on a units-of-production basis over the mine’s estimated recoverable reserves.

The Company reviews its asset retirement obligation at least annually and makes necessary adjustments for permit changes as granted by state authorities and for revisions of estimates of costs and productivities. For ongoing operations, adjustments to the liability result in an adjustment to the corresponding asset. For idle operations, adjustments to the liability are recognized as income or expense in the period the adjustment is recorded.

As discussed in Note 1, effective January 1, 2003, the Company began accounting for its reclamation obligations in accordance with FAS 143. The cumulative effect of this change on periods prior to January 1, 2003 resulted in a charge to income of $3.7 million (net of income taxes of $2.3 million), or $0.07 per share, which is included in the Company’s results of operations for the year ended December 31, 2003. In addition, the net income of the Company, excluding the cumulative effect of accounting change, for the year ended December 31, 2004 is $0.4 million ($0.01 per share) more than it would have been if the Company had continued to account for these obligations under its old method. The net income of the Company, excluding the cumulative effect of accounting change, for the year ended December 31, 2003 is $1.2 million ($0.02 per share) less than it would have been if the Company had continued to account for these obligations under its old method. The unaudited pro forma amounts below reflect the retroactive application of FAS 143 as if the Company had adopted the standard on January 1, 2002 and the corresponding elimination of the cumulative effect of accounting change:


		Year Ended December 31,

		2004		2003		2002

As Reported
	Net income (loss) available to common shareholders	$	106,519	$	10,097	$	(2,562	)
	Basic income (loss) per share		1.91		0.19		(0.05	)
	Diluted income (loss) per share		1.78		0.19		(0.05	)
Pro Forma
	Net income (loss) available to common shareholders	$	106,519	$	13,751	$	(5,322	)
	Basic income (loss) per share		1.91		0.26		(0.10	)
	Diluted income (loss) per share		1.78		0.26		(0.10	)

F-29

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

The following table describes the changes to the Company’s asset retirement obligation for the years ended December 31, 2004 and 2003:


	2004			2003

Balance at January 1 (including current portion)	$	162,731		$	125,440
Impact of adoption		—			41,198
Accretion expense		12,681			12,999
Additions resulting from property additions		37,784			4,640
Adjustments to the liability from annual recosting		(1,571	)		(1,117	)
Liabilities settled		(12,028	)		(20,429	)

Balance at December 31		199,597			162,731
Current portion included in accrued expenses		(19,632	)		(19,186	)

Long-term liability	$	179,965		$	143,545


	12. Employee Benefit Plans


	*Defined Benefit Pension and Other Postretirement Benefit Plans*

The Company has non-contributory defined benefit pension plans covering certain of its salaried and non-union hourly employees. Benefits are generally based on the employee’s age and compensation. The Company funds the plans in an amount not less than the minimum statutory funding requirements nor more than the maximum amount that can be deducted for federal income tax purposes.

The Company also currently provides certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for retirees who were members of the United Mine Workers of America (“UMWA”) is not contributory. The Company’s current funding policy is to fund the cost of all postretirement medical/life insurance benefits as they are paid.

The Company uses a December 31 measurement date for its pension and postretirement benefit plans.

F-30

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

Obligations and Funded Status. Summaries of the changes in the benefit obligations, plan assets and funded status of the plans are as follows:


								Other Postretirement
		Pension Benefits						Benefits

		2004			2003			2004			2003

CHANGE IN BENEFIT OBLIGATIONS
	Benefit obligations at January 1	$	182,946		$	166,807		$	531,933		$	452,476
	Service cost		8,861			8,188			4,145			3,637
	Interest cost		11,781			11,293			29,695			31,126
	Plan amendments		139			—			—			—
	Acquisitions		23,380			—			10,748			—
	Benefits paid		(15,288	)		(11,791	)		(29,585	)		(26,286	)
	Transfer from Canyon Fuel Pension Plan		57			4,038			—			—
	Other-primarily actuarial (gain) loss		6,187			4,411			(11,066	)		70,980

	Benefit obligations at December 31	$	218,063		$	182,946		$	535,870		$	531,933

CHANGE IN PLAN ASSETS
	Value of plan assets at January 1	$	151,126		$	115,595		$	—		$	—
	Actual return on plan assets		17,974			24,380			—			—
	Acquisitions		15,599			—			—			—
	Employer contributions		21,641			18,904			29,585			26,286
	Benefits paid		(15,288	)		(11,791	)		(29,585	)		(26,286	)
	Transfer from Canyon Fuel Pension Plan		57			4,038			—			—

	Value of plan assets at December 31	$	191,109		$	151,126		$	—		$	—

NET AMOUNT RECOGNIZED
	Funded status of the plans	$	(26,954	)	$	(31,820	)	$	(535,870	)	$	(531,933	)
	Unrecognized actuarial loss		34,683			34,239			129,753			159,642
	Unrecognized prior service gain		(886	)		(1,157	)		(3,992	)		(6,130	)

	Prepaid (accrued) benefit cost	$	6,843		$	1,262		$	(410,109	)	$	(378,421	)

BALANCE SHEET AMOUNTS
	Accrued benefit liabilities	$	(17,628	)	$	(21,436	)	$	(410,109	)	$	(378,421	)
	Intangible asset (Other assets)		592			526			—			—
	Minimum pension liability adjustment (accumulated other comprehensive income)		23,879			22,172			—			—

	Net asset (liability) recognized		6,843			1,262			(410,109	)		(378,421	)
	Less current portion		(6,843	)		(1,262	)		29,685			26,324

	Long term liability	$	—		$	—		$	(380,424	)	$	(352,097	)

F-31

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


	Other Postretirement Benefits

The actuarial gain in 2004 resulted from impact of the Medicare Prescription Drug Act implementation discussed below. The actuarial loss in 2003 resulted from changes in certain actuarial assumptions, including an increase in the expected health care cost trend rate and a reduction in the discount rate.


	Pension Benefits

The accumulated benefit obligation for all pension plans was $208.7 million and $172.7 million at December 31, 2004 and 2003, respectively.

Transfers from the Canyon Fuel Company Pension Plan represent transfers of the benefit obligation (as actuarially determined) and related plan assets for employees who were transferred from Canyon Fuel to Arch Coal in 2004 and 2003.

Components of Net Periodic Benefit Cost. The following table details the components of pension and other postretirement benefit costs.


		Pension Benefits									Other Postretirement Benefits

Year Ended December 31,		2004			2003			2002			2004		2003		2002

		(In thousands)
Service cost		$	8,861		$	8,188		$	8,031		$	4,145	$	3,637	$	2,903
Interest cost			11,781			11,293			11,268			29,695		31,126		24,265
Expected return on plan assets*			(14,539	)		(13,687	)		(12,336	)		—		—		—
Other amortization and deferral			4,802			1,435			(284	)		16,685		21,315		(3,171	)

	Net benefit cost	$	10,905		$	7,229		$	6,679		$	50,525	$	56,078	$	23,997


*	The Company does not fund its other postretirement liabilities.

Assumptions. The following table provides the assumptions used to determine the actuarial present value of projected benefit obligations at December 31.

Other

Pension

Postretirement

Benefits

2004

2003

2004

2003

Weighted Average Assumptions:

Discount rate

6.00

6.50

6.00

6.50

Rate of compensation increase

3.50

3.75

N/A

N/A

F-32

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

The following table provides the assumptions used to determine net periodic benefit cost for years ended December 31.


											Other Postretirement
		Pension Benefits									Benefits

		2004			2003			2002			2004			2003			2002

Weighted Average Assumptions:
	Discount rate		6.50	%		7.00	%		7.50	%		6.50	%		7.00	%		7.50	%
	Rate of compensation increase		3.75	%		4.25	%		4.50	%		N/A			N/A			N/A
	Expected return on plan assets		8.50	%		9.00	%		9.00	%		N/A			N/A			N/A

The Company establishes the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The Company utilizes Modern Portfolio Theory modeling techniques in the development of its return assumptions. This technique projects rates of returns that can be generated through various asset allocations that lie within the risk tolerance set forth by members of the Company’s Pension Committee. The risk assessment provides a link between a Pension’s risk capacity, management’s willingness to accept investment risk and the asset allocation process, which ultimately leads to the return generated by the invested assets. For the determination of net periodic benefit cost in 2005, the Company will utilize an expected rate of return of 8.50%.

The following table provides information regarding the assumed health care cost trend rates at December 31.


	2004			2003

Health care cost trend rate assumed for next year		8.00	%		8.00	%
Ultimate trend rate		5.00	%		5.00	%
Year that the rate reaches the ultimate trend rate		2011			2010

The health care cost trend rate assumption has a significant effect on the amounts reported. For example, increasing the assumed health care cost trend rate by one percentage point each year would increase the accumulated postretirement obligation as of December 31, 2004 by $66.2 million, or 12.4%, and the net periodic postretirement benefit cost for 2004 by $4.0 million, or 7.9%.

Plan Assets. The Company’s pension plan weighted average asset allocations at December 31, 2004 and 2003, by asset category are as follows:


	Plan Assets at
	December 31,

	2004			2003

Equity securities		67	%		69	%
Debt securities		28	%		28	%
Cash and equivalents		5	%		3	%

Total		100	%		100	%

The Company’s Pension Committee (“the Committee”) is responsible for overseeing the investment of pension plan assets. The Committee is responsible for determining and monitoring appropriate asset allocations and for selecting or replacing investment managers, trustees and custodians. The pension plan’s current investment targets are 65% equity, 30% fixed income securities and 5% cash. The Pension Committee reviews the actual asset allocation in light of these

F-33

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

targets on a periodic basis and rebalances among investments as necessary. The Committee evaluates the performance of investment managers as compared to the performance of specified benchmarks and peers and monitors the investment managers to ensure adherence to their stated investment style and to the plan’s investment guidelines.

Cash Flows. The Company currently does not anticipate making any contributions to its pension plan in 2005.

The following represents expected future benefit payments, which reflect expected future service, as appropriate:


			Other
	Pension		Postretirement
	Benefits		Benefits

2005	$	18,429	$	29,274
2006		19,636		28,441
2007		19,793		30,794
2008		20,487		31,832
2009		20,883		33,018
Years 2010-2014		105,579		190,080

	$	204,807	$	343,439

Impact of Medicare Prescription Drug, Improvement and Modernization Act of 2003. On December 8, 2003, the President signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”). The Act introduces a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company has included the effects of the Act in its financial statements for the year ending December 31, 2004 in accordance with FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP 106-2”). Incorporation of the provisions of the Act resulted in a reduction of the Company’s postretirement benefit obligation of $68.0 million. Postretirement medical expenses for fiscal year 2004 after incorporation of the provisions of the Act resulted in an amount of $18.2 million less than that previously anticipated (substantially all of which is recorded as a component of cost of coal sales). The benefit for the year ending December 31, 2004 was partially offset by increased costs resulting from changes to other actuarial assumptions that were incorporated at the beginning of the year.


	*Multi-employer Pension and Benefit Plans*

Under the labor contract with the United Mine Workers of America (“UMWA”), the Company made no payments in 2004, 2003 and 2002 into a multi-employer defined benefit pension plan trust established for the benefit of union employees. Payments are based on hours worked and are expensed as hours are incurred. Under the Multi-employer Pension Plan Amendments Act of 1980, a contributor to a multi-employer pension plan may be liable, under certain circumstances, for its proportionate share of the plan’s unfunded vested benefits (withdrawal liability). The Company is not aware of any circumstances that would require it to reflect its share of unfunded vested pension benefits in its financial statements. At December 31, 2004, approximately 13% of the Company’s

F-34

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

workforce was represented by the UMWA under a collective bargaining agreement that is effective through December 31, 2006.

The Coal Industry Retiree Health Benefit Act of 1992 (“Benefit Act”) provides for the funding of medical and death benefits for certain retired members of the UMWA through premiums to be paid by assigned operators (former employers), transfers of monies in 1993 and 1994 from an overfunded pension trust established for the benefit of retired UMWA members, and transfers from the Abandoned Mine Lands Fund (funded by a federal tax on coal production) commencing in 1995. The Company treats its obligation under the Benefit Act as a participation in a multi-employer plan and records expense as premiums are paid. The Company recorded expense of $6.0 million in 2004, $5.1 million in 2003, and $3.2 million in 2002 for premiums pursuant to the Benefit Act.


	*Other Plans*

The Company sponsors savings plans which were established to assist eligible employees in providing for their future retirement needs. The Company’s contributions to the plans were $8.8 million in 2004, $8.3 million in 2003, and $8.4 million in 2002.


	13. Capital Stock

On November 24, 2004, the Company filed a registration statement on Form S-3 with the Securities and Exchange Commission. The registration statement allows us to offer, from time to time, an aggregate of up to $1.0 billion in debt securities, preferred stock, depositary shares, purchase contracts, purchase units, common stock and related rights and warrants.

On October 28, 2004, the Company completed a public offering of 7,187,500 common shares at $33.85 per share. The proceeds from the offering, net of the underwriters’ discount and related expenses, were $230.5 million. Net proceeds from the offering were used primarily to repay borrowings under the Company’s revolving credit facility incurred to finance the acquisition of Triton and the first annual payment under the Little Thunder lease, and the remaining net proceeds will be used for general corporate purposes, including the development of the Mountain Laurel mine complex in the Central Appalachia Basin.

On January 31, 2003, the Company completed a public offering of 2,875,000 shares of 5% Perpetual Cumulative Convertible Preferred Stock. The net proceeds realized by the Company from the offering of $139.0 million were used to reduce indebtedness under the Company’s revolving credit facility, and for working capital and general corporate purposes. Dividends on the preferred stock are cumulative and payable quarterly at the annual rate of 5% of the liquidation preference. Each share of the preferred stock is initially convertible, under certain conditions, into 2.3985 shares of the Company’s common stock. The preferred stock is redeemable, at the Company’s option, on or after January 31, 2008 if certain conditions are met. The holders of the preferred stock are not entitled to voting rights on matters submitted to the Company’s common shareholders. However, if the Company fails to pay the equivalent of six quarterly dividends, the holders of the preferred stock will be entitled to elect two directors to the Company’s board of directors.

On September 14, 2001, the Company’s Board of Directors approved a stock repurchase plan, under which the Company may repurchase up to 6.0 million of its shares of common stock from time to time. Through December 31, 2004, the Company repurchased 357,200 shares of its common stock for $5.0 million pursuant to the plan at an average price of $14.13 per share. The repurchased shares are being held in the Company’s treasury, which the Company accounts for using the average

F-35

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

cost method. Future repurchases under the plan will be made at management’s discretion and will depend on market conditions and other factors.


	14. Stockholder Rights Plan

On March 3, 2000, the Board of Directors adopted a stockholder rights plan under which preferred share purchase rights were distributed as a dividend to the Company’s stockholders of record on March 20, 2000. The rights are exercisable only if a person or group acquires 20% or more of the Company’s Common Stock (an “Acquiring Person”) or announces a tender or exchange offer the consummation of which would result in ownership by a person or group of 20% or more of the Company’s Common Stock. Each right entitles the holder to buy one one-hundredth of a share of a series of junior participating preferred stock at an exercise price of $42, or in certain circumstances allows the holder (except for the Acquiring Person) to purchase the Company’s Common Stock or voting stock of the Acquiring Person at a discount. At its option, the Board of Directors may allow some or all holders (except for the Acquiring Person) to exchange their rights for Company Common Stock. The rights will expire on March 20, 2010, subject to earlier redemption or exchange by the Company as described in the plan.


	15. Stock Incentive Plan and Other Incentive Plans

Under the Company’s 1997 Stock Incentive Plan (the “Company Incentive Plan”), 9,000,000 shares of the Company’s common stock were reserved for awards to officers and other selected key management employees of the Company. The Company Incentive Plan provides the Board of Directors with the flexibility to grant stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance stock or units, merit awards, phantom stock awards and rights to acquire stock through purchase under a stock purchase program (“Awards”). Awards the Board of Directors elects to pay out in cash do not count against the 9,000,000 shares authorized in the Company Incentive Plan.

As of December 31, 2004, stock options, performance units, restricted stock units and price contingent stock awards were the types of awards granted. Each is discussed more fully below.


	*Stock Options*

Stock options are generally subject to vesting provisions of at least one year from the date of grant and are granted at a price equal to 100% of the fair market value of the stock on the date of

F-36

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

grant. Information regarding stock options under the Company Incentive Plan is as follows for the years ended December 31, 2004, 2003 and 2002 (Options in thousands):


	2004					2003					2002

				Weighted					Weighted					Weighted
	Common			Average		Common			Average		Common			Average
	Shares			Price		Shares			Price		Shares			Price

Options outstanding at January 1		4,622		$	21.29		5,485		$	20.85		3,153		$	21.32
Granted		6			33.61		114			19.23		2,443			20.38
Exercised		(1,658	)		22.15		(771	)		17.54		(31	)		10.69
Canceled		(5	)		21.46		(206	)		22.60		(80	)		22.51

Options outstanding at December 31		2,965			20.85		4,622			21.29		5,485			20.85

Options exercisable at December 31		1,783		$	21.15		2,692		$	21.94		1,115		$	19.76
Options available for grant at December 31		2,677					2,981					2,886

The Company applies APB 25 and related Interpretations in accounting for the Company Incentive Plan. Accordingly, no compensation expense has been recognized for the fixed stock option portion of the Company Incentive Plan. The after-tax fair value of options granted in 2004, 2003 and 2002 was determined to be $0.1 million, $0.7 million and $14.9 million, respectively, which for purposes of the pro forma disclosure in Note 1 is recognized as compensation expense over the options’ vesting period. The fair value of the options was determined using the Black-Scholes option pricing model and the weighted average assumptions noted below. Substantially all stock options granted vest ratably over four years.


		2004			2003			2002

Weighted average fair value per share of options granted		$	15.38		$	8.33		$	8.41
Assumptions (weighted average)
	Risk-free interest rate		3.65	%		2.84	%		2.96	%
	Expected dividend yield		1.0	%		1.5	%		2.0	%
	Expected volatility		52.7	%		53.5	%		52.7	%
	Expected life (in years)		5.0			5.0			5.0

F-37

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

The table below shows pertinent information on options outstanding at December 31, 2004 (Options in thousands):

Options Outstanding

Options Exercisable

Weighted Average

Weighted

Remaining

Average

Range of

Number

Contractual Life

Exercise

Number

Exercise

Exercise prices

Outstanding

(Years)

Price

Exercisable

Price

$8.50-$10.69

159

4.46

10.56

159

10.56

$16.09-$21.95

1,103

7.10

18.82

484

19.55

$22.00-$22.90

1,561

4.94

22.71

1,012

22.78

$23.45-$35.30

142

3.01

27.70

128

27.69

$8.50-$35.30

2,965

5.63

20.85

1,783

21.15


	*Performance Units*

Performance stock or unit awards can be earned by the recipient if the Company meets certain pre-established performance measures. Until earned, the performance awards are nontransferable, and when earned, performance awards are payable in cash, stock, or restricted stock as determined by the Company’s Board of Directors. In January 2004, the Company granted performance unit awards that are earned if the Company meets certain financial, safety and environmental targets during the three years ending December 31, 2006. Amounts accrued during 2004 for these awards totaled $3.1 million. During the fourth quarter of 2003, the Company’s Board of Directors approved awards under a four-year performance unit plan that began in 2000 totaling $19.6 million (including $1.9 million awarded to employees of Canyon Fuel), which was paid in cash in the first quarter of 2004.


	*Restricted Stock Unit Awards*

On January 14, 2004 and January 30, 2004, the Company granted restricted stock unit awards of 38,807 and 110,383 shares, respectively. The fair value of the units on the date of grants was $30.88 and $27.62 per share, respectively. The restricted stock units require no payment from the employee. Compensation expense is based on the fair value on the grant date and is recorded ratably over the vesting period of three years. During the vesting period, the employee receives compensation equal to dividends declared on common shares. Amounts accrued during 2004 for these awards totaled $2.4 million.

On December 18, 2002, the Company granted a restricted stock unit award of 50,000 shares. The fair value of the shares on the date of grant was $21.11 per share. The units will vest in their entirety on January 31, 2008. The Company will recognize compensation expense in the amount of the total fair value of the grant ratably over the vesting period of the award.


	*Price Contingent Stock Awards*

On January 14, 2004, the Company granted an award of 220,766 shares of performance-contingent phantom stock that vests only if the Company’s stock price reaches an average pre-established price over a period of 20 consecutive trading days within five years following the date of grant. The award can be paid in either Company stock or in cash, at the discretion of the Company’s Board of Directors. This grant has been accounted for in accordance with APB 25 in the accompany-

F-38

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

ing financial statements. Under APB 25, no compensation expense is recorded for this type of award until the performance contingency is met. If the performance contingency is met prior to the adoption of FAS 123R on July 1, 2005, the Company will recognize compensation expense equal to the number of shares multiplied by the stock price on the date the contingency is met.


	16. Concentration of Credit Risk and Major Customers

The Company places its cash equivalents in investment-grade short-term investments and limits the amount of credit exposure to any one commercial issuer.

The Company markets its coal principally to electric utilities in the United States. Sales to customers in foreign countries were $134.0 million for the year ended December 31, 2004. As of December 31, 2004 and 2003, accounts receivable from electric utilities located in the United States totaled $127.7 million and $92.2 million, respectively, or 71% and 78% of total trade receivables for 2004 and 2003, respectively. Generally, credit is extended based on an evaluation of the customer’s financial condition, and collateral is not generally required. Credit losses are provided for in the financial statements and historically have been minimal.

The Company is committed under long-term contracts to supply coal that meets certain quality requirements at specified prices. These prices are generally adjusted based on indices. Quantities sold under some of these contracts may vary from year to year within certain limits at the option of the customer. The Company and its operating subsidiaries sold approximately 123.1 million tons of coal in 2004. Approximately 76% of this tonnage (representing 70% of the Company’s revenue) was sold under long-term contracts (contracts having a term of greater than one year). Prices for coal sold under long-term contracts ranged from $5.15 to $86.64 per ton. Long-term contracts ranged in remaining life from one to 13 years. Some of these contracts include pricing which is above current market prices. Sales (including spot sales) to major customers were as follows (in thousands):

2004

2003

2002

Progress Energy

228,203

165,514

77,076

AEP

173,528

222,580

233,530

F-39

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


	17. Earnings (Loss) Per Share

The following table sets forth the computation of basic and diluted earnings (loss) per common share:

2004

Numerator

Denominator

Per Share

(Income)

(Shares)

Amount

Basic EPS:

Net income

113,706

55,901

2.04

Preferred stock dividends

(7,187

)

(0.13

)

Basic income available to common shareholders

106,519

1.91

Effect of dilutive securities:

Effect of common stock equivalents arising from stock options and restricted stock grants

—

937

Effect of common stock equivalents arising from convertible preferred stock

7,187

6,896

Diluted EPS:

Diluted income available to common shareholders

113,706

63,734

1.78


			2003

Basic EPS:
	Net income before cumulative effect of accounting change		$	20,340		52,511	$	0.39
	Cumulative effect of accounting change			(3,654	)			(0.07	)
	Preferred stock dividends			(6,589	)			(0.13	)

		Basic income available to common shareholders	$	10,097			$	0.19

Effect of dilutive securities:
	Effect of common stock equivalents arising from stock options			—		374

Diluted EPS:
	Net income before cumulative effect of accounting change		$	20,340		52,885	$	0.38
	Cumulative effect of accounting change			(3,654	)			(0.07	)
	Preferred stock dividends			(6,589	)			(0.12	)

		Diluted income available to common shareholders	$	10,097			$	0.19


		2002

Basic and diluted EPS:
	Net loss	$	(2,562	)	52,374	$	(0.05	)

At December 31, 2003 and 2002, 0.2 million, and 3.8 million shares, respectively, were not included in the diluted earnings per share calculation since the exercise price is greater than the average market price.

F-40

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

At December 31, 2004 and 2003, the Company had outstanding 2,875,000 shares of preferred stock that are convertible, at the option of the holder, into 6,896,000 shares of the Company’s common stock. The effect of the preferred stock was anti-dilutive, and therefore, not included in the diluted earnings per share calculation for 2003.

For the year 2002, employee stock options did not have a dilutive impact because the Company incurred a loss in that period.


	18. Sale and Leaseback

On June 27, 2002, the Company sold certain mining equipment for $9.2 million and leased back the equipment under operating leases with terms ranging from three to seven years. The leases contain renewal options at lease termination and purchase options at amounts approximating fair value at lease termination. The gain on the sale and leaseback was deferred and is being amortized over the base term of the leases as a reduction of lease expense.


	19. Related Party Transactions

The Company received administration and production fees from Canyon Fuel for managing the Canyon Fuel operations through July 31, 2004. The fee arrangement was calculated annually and approved by the Canyon Fuel Management Board. The production fee was calculated on a per-ton basis while the administration fee represented the costs incurred by the Company’s employees related to Canyon Fuel administrative matters. The fees recognized as other operating income by the Company and as expense by Canyon Fuel were $4.8 million, $8.5 million and $9.5 million for the years ended December 31, 2004, 2003 and 2002, respectively. Amounts receivable from Canyon Fuel were $6.5 million as of December 31, 2003 and are classified as other receivables in the Consolidated Balance Sheets.

From October 2002 through October 2004, the Company held an ownership interest in NRP. The Company leases certain coal reserves from NRP and pays royalties to NRP for the right to mine those reserves. Terms of the leases require the Company to prepay royalties with those payments recoupable against production. Amounts recognized as cost of coal sales for royalties paid to NRP during the years ended December 31, 2004, 2003 and 2002 were $15.4 million, $12.6 million and $2.1 million, respectively. Amounts paid to NRP and included in the accompanying balance sheet as prepaid royalties as of December 31, 2004 and 2003 were $1.3 million and $1.5 million, respectively.


	20. Commitments and Contingencies

The Company leases equipment, land and various other properties under noncancelable long-term leases, expiring at various dates. Certain leases contain options that would allow the Company to extend the lease or purchase the leased asset at the end of the base lease term. Rental expense related to these operating leases amounted to $22.7 million in 2004, $17.4 million in 2003, and $19.0 million in 2002. The Company has also entered into various non-cancelable royalty lease agreements and federal lease bonus payments under which future minimum payments are due. On September 22, 2004, the Company was the successful bidder in a federal auction of certain mining rights in the 5,084-acre Little Thunder tract in the Powder River Basin of Wyoming. The Company’s lease bonus bid amounted to $611.0 million for the tract that is to be paid in five equal installments of $122.2 million. The first $122.2 million installment was paid in September 2004 with the remaining four annual payments to be paid in fiscal years 2006 through 2009. These remaining lease bonus

F-41

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

payments are reflected below as a component of “Royalties”. The tract contains approximately 719.0 million mineable tons of high Btu, low-sulfur coal and is adjacent to the Company’s Black Thunder mine.

Minimum payments due in future years under these agreements in effect at December 31, 2004 are as follows (in thousands):


	Operating
	Leases		Royalties

2005	$	25,282	$	32,227
2006		23,310		155,466
2007		21,457		153,854
2008		19,713		149,384
2009		16,073		148,603
Thereafter		29,066		72,715

	$	134,901	$	712,249

The Company is a party to numerous claims and lawsuits with respect to various matters. The Company provides for costs related to contingencies when a loss is probable and the amount is reasonably determinable. After conferring with counsel, it is the opinion of management that the ultimate resolution of pending claims will not have a material adverse effect on the consolidated financial condition, results of operations or liquidity of the Company.

The Company holds a 17.5% general partnership interest in Dominion Terminal Associates (“DTA”), which operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia. DTA leases the facility from Peninsula Ports Authority of Virginia (“PPAV”) for amounts sufficient to meet debt-service requirements. Financing is provided through $132.8 million of tax-exempt bonds issued by PPAV (of which the Company is responsible for 17.5%, or $23.2 million) which mature July 1, 2016. Under the terms of a throughput and handling agreement with DTA, each partner is charged its share of cash operating and debt-service costs in exchange for the right to use its share of the facility’s loading capacity and is required to make periodic cash advances to DTA to fund such costs. On a cumulative basis, costs exceeded cash advances by $13.9 million at December 31, 2004 (such amount is included in other noncurrent liabilities). Future payments for fixed operating costs and debt service are estimated to approximate $2.7 million annually through 2015 and $26.0 million in 2016.

In connection with the Company’s acquisition of the coal operations of Atlantic Richfield Company (“ARCO”) and the simultaneous combination of the acquired ARCO operations and the Company’s Wyoming operations into the Arch Western joint venture, the Company agreed to indemnify another member of Arch Western against certain tax liabilities in the event that such liabilities arise prior to June 1, 2013 as a result of certain actions taken, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. If the Company were to become liable, the maximum amount of potential future tax payments was $211.5 million at December 31, 2004, of which none is recorded as a liability on the Company’s financial statements. Since the indemnification is dependent upon the initiation of activities within the Company’s control and the Company does not intend to initiate such activities, it is remote that the Company will become liable for any obligation related to this indemnification. However, if such indemnification obligation were to arise, it could potentially have a material adverse effect on the business, results of operations and financial condition of the Company.

F-42

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


	21. Cash Flow

The changes in operating assets and liabilities as shown in the consolidated statements of cash flows are comprised of the following:


		2004			2003			2002

Decrease (increase) in operating assets:
	Receivables	$	(31,570	)	$	18,805		$	14,028
	Inventories		(12,422	)		(2,857	)		(6,666	)
Increase (decrease) in operating liabilities:
	Accounts payable and accrued expenses		(6,780	)		8,844			(4,711	)
	Income taxes		(4,215	)		(13,822	)		(15,826	)
	Accrued postretirement benefits other than pension		18,019			27,558			(1,559	)
	Asset retirement obligations		(7,555	)		(20,606	)		6,336
	Accrued workers’ compensation		(1,257	)		(3,313	)		2,217
	Other noncurrent liabilities		(21,626	)		(14,984	)		1,547

Changes in operating assets and liabilities		$	(67,406	)	$	(375	)	$	(4,634	)


	22. Segment Information

The Company produces steam and metallurgical coal from surface and deep mines for sale to utility, industrial and export markets. The Company operates only in the United States, with mines in the major low-sulfur coal basins. The Company has three reportable business segments, which are based on the coal basins in which the Company operates. Coal quality, coal seam height, transportation methods and regulatory issues are generally consistent within a basin. Accordingly, market and contract pricing have developed by coal basin. The Company manages its coal sales by coal basin, not by individual mine complex. Mine operations are evaluated based on their per-ton operating costs (defined as including all mining costs but excluding pass-through transportation expenses). The Company’s reportable segments are Powder River Basin (PRB), Central Appalachia (CAPP) and Western Bituminous (WBIT). The Company’s operations in the Powder River Basin are located in Wyoming and include one operating surface mine (into which the North Rochelle mine was integrated) and one idle surface mine. The Company’s operations in Central Appalachia are located in southern West Virginia, eastern Kentucky, and Virginia and include 14 underground mines and eight surface mines. The Company’s Western Bituminous operations are located in southern Wyoming, Colorado and Utah and include four underground mines (one of which was idled in May 2004) and two surface mines (which were both put into reclamation mode in 2004).

Operating segment results for the years ended December 31, 2004, 2003, and 2002 are presented below. Results for the operating segments include all direct costs of mining. Corporate,

F-43

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)

Other and Eliminations includes corporate overhead, land management, other support functions, and the elimination of intercompany transactions.

Corporate,

Other and

December 31, 2004

PRB

CAPP

WBIT

Eliminations

Consolidated

Coal sales

582,421

1,126,258

198,489

—

1,907,168

Income from equity investments

—

8,410

2,418

10,828

Income from operations

72,441

39,196

18,145

48,264

178,046

Total assets

1,154,317

2,088,224

1,663,764

(1,649,770

)

3,256,535

Depreciation, depletion and amortization

78,074

62,761

24,113

1,374

166,322

Capital expenditures

55,035

84,450

23,276

129,844

292,605

Operating cost per ton

6.19

34.84

15.71


								Corporate,
								Other and
December 31, 2003	PRB		CAPP			WBIT		Eliminations			Consolidated

Coal sales	$	409,352	$	917,981		$	108,155	$	—		$	1,435,488
Income from equity investments		—		—			19,707		14,683			34,390
Income (loss) from operations		57,118		(43,872	)		22,951		4,174			40,371
Total assets		975,796		1,964,384			1,087,508		(1,640,039	)		2,387,649
Equity investments		—		—			146,180		25,865			172,045
Depreciation, depletion and amortization		44,202		64,980			18,851		30,431			158,464
Capital expenditures		18,351		47,527			8,971		57,578			132,427
Operating cost per ton		5.45		30.87			15.41

F-44

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


							Corporate,
							Other and
December 31, 2002	PRB		CAPP		WBIT		Eliminations			Consolidated

Coal sales	$	390,097	$	966,514	$	113,440	$	3,507		$	1,473,558
Income from equity investments		—		—		7,774		2,318			10,092
Income from operations		31,942		5,547		21,842		(30,054	)		29,277
Total assets		883,249		1,939,567		385,981		(1,025,989	)		2,182,808
Equity investments		—		—		160,787		70,764			231,551
Depreciation, depletion and amortization		47,992		71,583		21,393		33,784			174,752
Capital expenditures		37,333		49,591		14,027		36,138			137,089
Operating cost per ton		5.31		28.26		14.53

Reconciliation of segment income from operations to consolidated income (loss) before income taxes and cumulative effect of accounting change:


	2004			2003			2002

Total Segment Income from Operations	$	178,046		$	40,371		$	29,277
Interest expense		(62,634	)		(50,133	)		(51,922	)
Interest income		6,130			2,636			1,083
Other non-operating (expense) income		(7,966	)		4,256			—

Income (loss) before income taxes and cumulative effect of accounting change	$	113,576		$	(2,870	)	$	(21,562	)


	23. Quarterly Financial Information (Unaudited)

Quarterly financial data for 2004 and 2003 is summarized below:

March 31

June 30

September 30

December 31

(a)(b)(c)

(a)(b)(d)

(a)(b)(e)(f)(g)

2004:

Coal sales

403,490

422,778

527,775

553,125

Gross profit

19,689

23,449

36,370

23,054

Income from operations

106,909

24,870

26,335

19,932

Net income available to common shareholders

68,186

9,311

8,979

20,043

Basic earnings per common share(l)

1.27

0.17

0.16

0.33

Diluted earnings per common share(l)

1.14

0.17

0.16

0.32

F-45

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


		March 31			June 30			September 30		December 31

		(h)(i)			(b)(i)(j)			(b)(j)		(a)(b)(k)
2003:
	Coal sales	$	327,390		$	378,892		$	354,276	$	374,930
	Gross profit		(12,042	)		2,043			5,244		1,171
	Income (loss) from operations		(6,265	)		9,367			6,526		30,743
	Net income (loss) available to common shareholders before cumulative effect of accounting change		(14,384	)		(3,254	)		9,252		22,137
	Net income (loss) available to common shareholders		(18,038	)		(3,254	)		9,252		22,137
	Basic earnings (loss) per common share(l)		(0.34	)		(0.06	)		0.18		0.42
	Diluted earnings (loss) per common share(l)		(0.34	)		(0.06	)		0.18		0.40


(a)	During 2004 and 2003, the Company sold its investment in Natural Resource Partners in four separate transactions occurring in December 2003 and March, June and October 2004. The Company recognized a gain of $42.7 million in the fourth quarter of 2003 and gains of $89.6 million, $0.3 million, $0.3 million and $1.1 million in the four quarters of 2004, respectively.

(b)	In connection with the Company’s repayment of Arch Western’s term loans in 2003, the Company recognized expenses of $8.3 million and $4.3 million in 2004 and 2003, respectively, related to the costs resulting from the termination of hedge accounting for interest rate swaps. For 2004, this amount was recognized ratably throughout the year. For 2003, amounts recognized were $0.1 million in the second quarter and $2.1 million in both the third and fourth quarters. During 2004 and 2003, the Company also recognized expenses of $0.7 million and $4.7 million, respectively, related to early debt extinguishment costs. Amounts for 2004 were recognized in the fourth quarter, while amounts for 2003 were recognized in the second quarter. Additionally, subsequent to the termination of hedge accounting for interest rate swaps, the Company recognized income of $13.4 million in 2003 ($1.0 million in the second quarter, $10.6 million in the third quarter, and $1.8 million in the fourth quarter) related to changes in the market value of the swaps.

(c)	During the year ending December 31, 2004, Canyon Fuel, which was accounted for under the equity method through July 31, 2004, began the process of idling its Skyline Mine (the idling process was completed in May 2004), and incurred severance costs of $3.2 million for the year ended December 31, 2004. The Company’s share of these costs totals $2.1 million and is reflected in income from equity investments. The impact on the 2004 financial results was a charge of $1.2 million during the first quarter and a charge of $0.9 million in the second quarter.

(d)	During the third quarter of 2004, the Company was notified by the IRS that it would receive additional black lung excise tax refunds and interest related to black lung claims that were originally denied by the IRS in 2002. The Company recognized a gain of $2.8 million ($2.1 million refund and $0.7 million of interest) related to the claims. The $2.1 million refund was recorded as a component of cost of coal sales, while the $0.7 million of interest was recorded as interest income.

(e)	During the fourth quarter of 2004, the Company assigned its rights and obligations on a parcel of land to a third party resulting in a gain of $5.8 million. The gain is reflected in other operating income.

(f)	During 2004, the Company filed a royalty rate reduction request with the BLM for its West Elk mine in Colorado. The BLM notified the Company that it would receive a royalty rate reduction for a specified number of tons representing a retroactive portion for the year totaling $2.7 million. The retroactive portion was recognized as a component of cost of coal sales in the Consolidated Statement of Operations.

(g)	In connection with the settlement of tax audits for prior years, the Company recorded interest income of $2.2 million during the fourth quarter of 2004 related to federal income tax refunds. This amount is reflected as interest income.

F-46

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

(In Thousands of Dollars Except Per Share Data)


(h)	On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations. Implementation of this pronouncement resulted in a cumulative effect of accounting change of $3.7 million (net of tax).

(i)	During the year ending December 31, 2003, the Company instituted ongoing cost reduction efforts throughout its operations. These cost reduction efforts included the termination of approximately 100 employees at the Company’s corporate headquarters and its Central Appalachia mining operations and the recognition of expenses related to severance of $2.6 million. Of this amount, $0.6 million was recorded during the first quarter of 2003, with the remainder recorded during the second quarter.

(j)	During the year ended December 31, 2003, the Company was notified by the State of Wyoming of a favorable ruling relating to the Company’s calculation of coal severance taxes. The ruling resulted in a refund of previously paid taxes and the reversal of previously accrued taxes payable. The impact on the 2003 financial results was a gain of $3.3 million during the second quarter and expense of $0.8 million in the third quarter.

(k)	During the fourth quarter of 2003, the Company recognized expenses of $15.0 million for amounts earned under a long-term incentive compensation plan.

(l)	The sum of the quarterly earnings (loss) per common share amounts may not equal earnings (loss) per common share for the full year because per share amounts are computed independently for each quarter and for the year based on the weighted average number of common shares outstanding during each period.

24. Events (unaudited) Subsequent to Date of Independent Auditors’ Report

On December 31,2005, the Company entered into a Purchase and Sale Agreement (the “Purchase Agreement”) with Magnum Coal Company (“Magnum”). Pursuant to the Purchase Agreement, Arch sold stock in four of its active Central Appalacian mining operations, representing a total of 455 million tons of reserves, to Magnum. These mining properties together had sales of 14.0 million tons through December 31, 2004.

F-47

SCHEDULE II

ARCH COAL, INC. AND SUBSIDIARIES

VALUATION AND QUALIFYING ACCOUNTS

(in thousands)


						ADDITIONS
						CHARGED
				BALANCE AT		TO COSTS		CHARGED						BALANCE AT
				BEGINNING		AND		TO OTHER						END OF
				OF YEAR		EXPENSES		ACCOUNTS			DEDUCTIONS(1)			YEAR

Year Ended December 31, 2004
	Reserves deducted from Asset Accounts
		Other Assets — Other Notes and Accounts Receivable		$	1,469	$	570	$	962	(2)	$	—		$	3,001
			Current Assets — Supplies Inventory		18,763		1,746		3,010	(2)		543			22,976
		Deferred Income Taxes			161,113		—		2,157	(3)		265			163,005
Year Ended December 31, 2003
	Reserves deducted from Asset Accounts
		Other Assets — Other Notes and Accounts Receivable			3,894		1,315		—			3,740	(5)		1,469
			Current Assets — Supplies Inventory		17,515		1,583		—			335			18,763
		Deferred Income Taxes			145,603		3,543		11,967	(4)		—			161,113
Year Ended December 31, 2002
	Reserves deducted from Asset Accounts
		Other Assets — Other Notes and Accounts Receivable			544		3,409		—			59			3,894
			Current Assets — Supplies Inventory		16,598		1,831		—			914			17,515
		Deferred Income Taxes			119,723		25,880		—			—			145,603


(1)	Reserves utilized, unless otherwise indicated.

(2)	Balance at acquisition date of subsidiaries.

(3)	Amount represents the valuation allowance for tax benefits from the exercise of employee stock options. The benefit, net of valuation allowance, was recorded as paid-in capital.

(4)	Amount represents state net operating loss carryforwards identified in 2003 which were fully reserved.

(5)	Amount includes $1.6 million that was recognized as income upon collection of the related receivable.

F-48

Exhibits filed as part of this Annual Report on Form 10-K are as follows:


Exhibit		Description
3.1		Restated Certificate of Incorporation of Arch Coal, Inc. (incorporated by reference to Exhibit 3.1 of the registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000).

3.2		Restated and Amended Bylaws of Arch Coal, Inc. (incorporated by reference to Exhibit of the registrant’s Annual Report on Form 10-K for the year ended December 31, 2000).

4.1		Form of Rights Agreement, dated March 3, 2000 (incorporated by reference to Exhibit 1 to the registrant’s Current Report on Form 8-A filed on March 9, 2000).

4.2		Description of Indenture pursuant to Shelf Registration Statement (incorporated herein by reference to the Registration Statement on Form S-3 (Registration No. 333-58738) filed by the registrant on April 11, 2001).

4.3		Certificate of Designations Establishing the Designations, Powers, Preferences, Rights, Qualifications, Limitations and Restrictions of the registrant’s 5% Perpetual Cumulative Convertible Preferred Stock (incorporated herein by reference to Exhibit 3 to the Registration Statement on Form 8-A filed by the registrant on March 5, 2003).

4.4		Indenture, dated as of June 25, 2003, by and among Arch Western Finance, LLC, Arch Coal, Inc., Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., Thunder Basin Coal Company, L.L.C. and The Bank of New York, as trustee (incorporated herein by reference to Exhibit 4.1 to the Registration Statement on Form S-4 (Reg. No. 333-107569) filed by Arch Western Finance, LLC on August 1, 2003).

4.5		Credit Agreement, dated as of December 22, 2004, by and among Arch Coal, Inc., the Banks party thereto, PNC Bank, National Association, as administrative agent, Citicorp USA, Inc., JPMorgan Chase Bank, N.A., and Wachovia Bank, National Association, as co-syndication agents, and Fleet National Bank, as documentation agent (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by the registrant on December 28, 2004).

10.1		Amended and Restated Retention Agreement between Arch Coal, Inc. and Steven F. Leer, dated October 1, 2004 (incorporated by referenced to Exhibit 10.1 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2004).

10.2		Form of Retention Agreement between Arch Coal, Inc. and each of its Executive Officers (other than its Chief Executive Officer) (incorporated by referenced to Exhibit 10.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2004).

10.3		Deed of Lease and Agreement between Dingess-Rum Coal Company and Amherst Coal Company (predecessor to Ark Land Company), dated June 1, 1962, as supplemented January 1, 1968, June 1, 1973, July 1, 1974 and November 12, 1987; Lease Exchange Agreement dated July 2, 1979 amended as of January 1, 1984, January 7, 1993 and February 24, 1993; Partial Release dated as of May 6, 1988; Assignments dated March 15, 1990 and October 5, 1990 (incorporated herein by reference to Exhibit 10.8 of the Registration Statement on Form S-4 (Registration No. 333-28149) filed by the registrant on May 30, 1997).

10.4		Agreement of Lease by and between Shonk Land Company, Limited Partnership and Lawson Hamilton (predecessor to Ark Land Company), dated February 8, 1983, as amended October 7, 1987, March 9, 1989, April 1, 1992, October 31, 1992, December 5, 1992, February 16, 1993, August 4, 1994, October 1, 1995, July 31, 1996 and November 27, 1996 (incorporated herein by reference to Exhibit 10.9 of the Registration Statement on Form S-4 (Registration No. 333-28149) filed by the registrant on May 30, 1997).

10.5		Lease between Little Coal Land Company and Ashland Land & Development Co., a wholly-owned subsidiary of Ashland Coal, Inc. which was merged into Allegheny Land Company, a second tier subsidiary of the registrant (incorporated herein by reference to Exhibit 10.11 of a Post-Effective Amendment No.1 to a Registration Statement on Form S-1 (Registration No.33-22425), as amended, filed by Ashland Coal, Inc. on August 11, 1988).


Exhibit		Description
10.6		Agreement of Lease dated January 1, 1988, between Courtney Company and Allegheny Land Company (legal successor by merger with Allegheny Land Co. No. 2, the assignee of Primeacre Land Corporation under October 5, 1992, assignments), a second-tier subsidiary of the registrant (incorporated herein by reference to Exhibit 10.3 to Ashland Coal, Inc.’s Annual Report on Form 10-K for the year ended December 31, 1995).

10.7		Lease between Dickinson Properties, Inc., the Southern Land Company, and F. B. Nutter, Jr. and F. B. Nutter, Sr., predecessors in interest to Hobet Mining & Construction Co., Inc., an independent operating subsidiary of the registrant that subsequently changed its name to Hobet Mining, Inc. (incorporated herein by reference to Exhibit 10.14 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No. 33-22425), as amended, filed by Ashland Coal, Inc. on August 11, 1988).

10.8		Lease Agreement between Fielden B. Nutter, Dorothy Nutter and Hobet Mining & Construction Co., Inc., an independent operating subsidiary of the registrant that subsequently changed its name to Hobet Mining, Inc. (incorporated herein by reference to Exhibit 10.22 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No. 33-22425), as amended, filed by Ashland Coal, Inc. on August 11, 1988).

10.9		Lease and Modification Agreement between Horse Creek Coal Land Company, Ashland and Hobet Mining & Construction Co., Inc., an independent operating subsidiary of the registrant that subsequently changed its name to Hobet Mining, Inc. (incorporated herein by reference to Exhibit 10.24 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No. 33-22425), as amended, filed by Ashland Coal, Inc. on August 11, 1988).

10.10		Lease Agreement between C. C. Lewis Heirs Limited Partnership and Allegheny Land Company, a second-tier subsidiary of the registrant (incorporated herein by reference to Exhibit 10.25 of a Post-Effective Amendment No 1 to a Registration Statement on Form S-1 (Registration No.33-22425), as amended, filed by Ashland Coal, Inc. on August 11, 1988).

10.11		Sublease between F. B. Nutter, Sr., et al., and Hobet Mining & Construction Co., Inc., an independent operating subsidiary of the registrant that subsequently changed its name to Hobet Mining, Inc. (incorporated herein by reference to Exhibit 10.27 of a Post-Effective Amendment No. 1 to a Registration Statement on Form S-1 (Registration No. 33-22425), as amended, filed by Ashland Coal, Inc. on August 11, 1988).

10.12		Coal Lease Agreement dated as of March 31, 1992, among Hobet Mining, Inc. (successor by merger with Dal-Tex Coal Corporation) as lessee and UAC and Phoenix Coal Corporation, as lessors, and related guarantee (incorporated herein by reference to the Current Report on Form 8-K filed by Ashland Coal, Inc. on [April 6, 1992 filed by Ashland Coal, Inc.]).

10.13		Lease dated as of October 1, 1987, between Pocahontas Land Corporation and Mingo Logan Collieries Company whose name is now Mingo Logan Coal Company (incorporated herein by reference to Exhibit 10.3 to Amendment No. 1 to the Current Report on Form 8-K filed by Ashland Coal, Inc. on February 14, 1990).

10.14		Consent, Assignment of Lease and Guaranty dated January 24, 1990, among Pocahontas Land Corporation, Mingo Logan Coal Company, Mountain Gem Land, Inc. and Ashland Coal, Inc. (incorporated herein by reference to Exhibit 10.4 to Amendment No. 1 to the Current Report on Form 8-K filed by Ashland Coal, Inc. on February 14, 1990).

10.15		Federal Coal Lease dated as of June 24, 1993 between the United States Department of the Interior and Southern Utah Fuel Company (incorporated herein by reference to Exhibit 10.17 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).

10.16		Federal Coal Lease between the United States Department of the Interior and Utah Fuel Company (incorporated herein by reference to Exhibit 10.18 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).

10.17		Federal Coal Lease dated as of July 19, 1997 between the United States Department of the Interior and Canyon Fuel Company, LLC (incorporated herein by reference to Exhibit 10.19 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).


Exhibit		Description
10.18		Federal Coal Lease dated as of January 24, 1996 between the United States Department of the Interior and the Thunder Basin Coal Company (incorporated herein by reference to Exhibit 10.20 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).

10.19		Federal Coal Lease Readjustment dated as of November 1, 1967 between the United States Department of the Interior and the Thunder Basin Coal Company (incorporated herein by reference to Exhibit 10.21 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).

10.20		Federal Coal Lease effective as of May 1, 1995 between the United States Department of the Interior and Mountain Coal Company (incorporated herein by reference to Exhibit 10.22 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).

10.21		Federal Coal Lease dated as of January 1, 1999 between the Department of the Interior and Ark Land Company (incorporated herein by reference to Exhibit 10.23 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).

10.22		Federal Coal Lease dated as of October 1, 1999 between the United States Department of the Interior and Canyon Fuel Company, LLC (incorporated herein by reference to Exhibit 10 of the registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1999).

10.23		Federal Coal Lease effective as of March 1, 2005 by and between the United States of America and Ark Land LT, Inc. covering the tract of land known as “Little Thunder” in Campbell County, Wyoming (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed by the registrant on February 10, 2005).

10.24		Modified Coal Lease (WYW71692) executed January 1, 2003 by and between the United States of America, through the Bureau of Land Management, as lessor, and Triton Coal Company, LLC, as lessee, covering a tract of land known as “North Rochelle” in Campbell County, Wyoming (incorporated by reference to Exhibit 10.24 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2004).

10.25		Coal Lease (WYW71692) executed January 1, 1998 by and between the United States of America, through the Bureau of Land Management, as lessor, and Triton Coal Company, LLC, as lessee, covering a tract of land known as “North Roundup” in Campbell County, Wyoming (incorporated by reference to Exhibit 10.24 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2004).

10.26		Form of Indemnity Agreement between Arch Coal, Inc. and Indemnitee (as defined therein) (incorporated herein by reference to Exhibit 10.15 of the Registration Statement on Form S-4 (Registration No. 333-28149) filed by the registrant on May 30, 1997).

10.27		Arch Coal, Inc. Incentive Compensation Plan For Executive Officers (incorporated herein by reference to Exhibit 99.1 of the Current Report on Form 8-K filed by the registrant on February 28, 2005).

10.28		Arch Coal, Inc. (formerly Arch Mineral Corporation) Deferred Compensation Plan (incorporated herein by reference to Exhibit 4.1 of the Registration Statement on Form S-8 (Registration No. 333-68131) filed by the registrant on December 1, 1998).

10.29		Arch Coal, Inc. 1997 Stock Incentive Plan (as Amended and Restated on February 28, 2002) (incorporated herein by reference to Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002).

10.30		Arch Mineral Corporation 1996 ERISA Forfeiture Plan (incorporated herein by reference to Exhibit 10.20 to the Registration Statement on Form S-4 (Registration No. 333-28149) filed by the registrant on May 30, 1997).

10.31		Arch Coal, Inc. Outside Directors’ Deferred Compensation Plan effective January 1, 1999 (incorporated herein by reference to Exhibit 10.30 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 1998).

10.32		Second Amendment to the Arch Mineral Corporation Supplemental Retirement Plan effective January 1, 1998 (incorporated herein by reference to Exhibit 10.31 of the registrant’s Annual


Exhibit		Description
		Report on Form 10-K for the year ended December 31, 1998).

10.33		Purchase and Sale Agreement, dated as of December 31, 2005, by and between Arch Coal, Inc. and Magnum Coal Company (incorporated herein by reference to Exhibit 10.1 of the registrant’s Current Report on Form 8-K filed on January 6, 2006).

13.1		Portions of the registrant’s Annual Report to Stockholders for the year ended December 31, 2004.

21.1		Subsidiaries of the registrant.

23.1		Consent of Ernst & Young LLP.

24.1		Power of Attorney (incorporated herein by reference to Exhibit 21.1 of the registrant’s Annual Report on Form 10-K for the year ended December 31, 2004).

31.1		Rule 13a-14(a)/15d-14(a) Certification of Steven F. Leer.

31.2		Rule 13a-14(a)/15d-14(a) Certification of Robert J. Messey.

32.1		Section 1350 Certification of Steven F. Leer.

32.2		Section 1350 Certification of Robert J. Messey.


*		Exhibits 10.27, 10.28, 10.29, 10.30 and 10.32 are executive compensation plans.

Signatures

Pursuant to the requirements of Section 13 and 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


		Arch Coal, Inc.

		By:		/s/ Steven M. Leer

				Steven M. Leer
				President and Chief Executive Officer

		January 6, 2006


Signatures		Capacity
/s/ Steven F. Leer Steven F. Leer		President and Chief Executive Officer and Director (Principal Executive Officer)

/s/ Robert J. Messey Robert J. Messey		Senior Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ John W. Lorson John W. Lorson		Controller (Principal Accounting Officer)

* James R. Boyd		Director

* Frank M. Burke		Director

* Patricia Fry Godley		Director

* Douglas H. Hunt		Director

* Thomas A. Lockhart		Director

* A. Michael Perry		Director

* Robert G. Potter		Director

* Theodore D. Sands		Director

* Wesley M. Taylor		Director

exv13w1

Exhibit 13.1

PART II — ANNUAL REPORT

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS


	Forward-Looking Statements

In this annual report, statements that are not reported financial results or other historical information are “forward-looking statements.” Forward-looking statements give current expectations or forecasts of future events and are not guarantees of future performance. They are based on our management’s expectations that involve a number of business risks and uncertainties, any of which could cause actual results to differ materially from those expressed in or implied by the forward-looking statements.

Forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts. They use words such as “anticipate,” “estimate,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. In particular, these include statements relating to:


	•	our expectation of continued growth in the demand for our coal by the domestic electric generation industry;

	•	our belief that legislation and regulations relating to the Clean Air Act and other proposed environmental initiatives and the relatively higher costs of competing fuels will increase demand for our compliance and low sulfur coal;

	•	our expectations regarding incentives to generators of electricity to minimize their fuel costs as a result of electric utility deregulation;

	•	our expectation that we will continue to have adequate liquidity from cash flow from operations;

	•	a variety of market, operational, geologic, permitting, labor and weather related factors;

	•	our expectations regarding any synergies to be derived from the Triton acquisition; and

	•	the other risks and uncertainties which are described below under “Contingencies” and “Certain Trends and Uncertainties,” including, but not limited to, the following:


	•	A reduction in consumption by the domestic electric generation industry may cause our profitability to decline.

	•	Extensive environmental laws and regulations could cause the volume of our sales to decline.

	•	The coal industry is highly regulated, which restricts our ability to conduct mining operations and may cause our profitability to decline.

	•	We may not be able to obtain or renew our surety bonds on acceptable terms.

	•	Unanticipated mining conditions may cause profitability to fluctuate.

	•	Intense competition and excess industry capacity in the coal producing regions has adversely affected our revenues and may continue to do so in the future.

	•	Deregulation of the electric utility industry may cause customers to be more price-sensitive, resulting in a potential decline in our profitability.

	•	Our profitability may be adversely affected by the status of our long-term coal supply contracts.

	•	Decreases in purchases of coal by our largest customers could adversely affect our revenues.

	•	Unavailability of coal reserves would cause our profitability to decline.

II-1


	•	Disruption in, or increased costs of, transportation services could adversely affect our profitability.

	•	Numerous uncertainties exist in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower revenues, higher costs or decreased profitability.

	•	Title defects or loss of leasehold interests in our properties could result in unanticipated costs or an inability to mine these properties.

	•	Acquisitions that we have undertaken or may undertake involve a number of inherent risks, any of which could cause us not to realize the benefits anticipated to result.

	•	Some of our agreements limit our ability to manage our western operations exclusively.

	•	Our expenditures for postretirement medical and pension benefits have increased since 2002 and could further increase in the future.

	•	Our inability to comply with restrictions imposed by our credit facilities and other debt arrangements could result in a default under these agreements.

	•	Our estimated financial results may prove to be inaccurate.

We cannot guarantee that any forward-looking statements will be realized, although we believe that we have been prudent in our plans and assumptions. Achievement of future results is subject to risks, uncertainties and assumptions that may prove to be inaccurate. Should known or unknown risks or uncertainties materialize, or should underlying assumptions prove to be inaccurate, actual results could vary materially from those anticipated, estimated or projected.

We undertake no obligation to publicly update forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. You are advised, however, to consider any additional disclosures that we or Arch Coal may make on related subjects in future filings with the SEC. You should understand that it is not possible to predict or identify all factors that could cause our actual results to differ. Consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties.


	Recent Development

On March 3, 2005, shares of performance-contingent phantom stock granted in January 2004 to our executive officers vested and were paid out in a combination of cash and shares of our stock. The phantom stock grant vested when our average closing stock price exceeded $40 per share over 20 consecutive trading days. As a result of the payout, we will incur a charge of $9.9 million, or approximately $0.16 per share, during our quarter ending March 31, 2005.


	Overview

We are a producer and marketer of compliance and low-sulfur coal exclusively, which we supply to domestic electric utilities and independent power producers, as well as to steel producers and industrial facilities. We operate large, modern mines in each of the three major low-sulfur coal-producing basins in the United States. These mines are among the most productive in the regions in which they operate and are supported by an extensive, low-cost reserve base totaling 3.7 billion tons.

We derive approximately 70% of our revenues from long-term supply contracts (defined as having terms of one year or greater). These supply agreements typically have terms of one to three years, although certain contracts have much longer durations. The remainder of our coal sales result from sales on the spot market.

II-2

The locations of our mining operations are as follows:

Powder River Basin (“PRB”) — We operate one surface mine, Black Thunder (into which the operations of the North Rochelle mine were integrated during 2004), and we own one idle surface mine, Coal Creek, in the Powder River Basin of Wyoming. The PRB is the nation’s largest and fastest growing coal supply basin.

Central Appalachia (“CAPP”) — We operate or control 22 mines in this coal basin (defined as southern West Virginia, eastern Kentucky and Virginia). Included in this total are 14 deep mines and 8 surface mines. We are in the process of developing a large longwall mine, Mountain Laurel, that is expected to ramp up to full production in 2007. CAPP is the principal source of low-sulfur coal in the eastern United States.

Western Bituminous Region (“WBIT”) — We operate three mines in this region (defined as Colorado, Utah and southern Wyoming), including a longwall mine in Colorado and two longwall mines in Utah. In addition, we have announced plans to begin development work on another longwall mine at the currently idle Skyline mine complex in Utah. Coal from WBIT can be used as a substitute for high-Btu eastern coal, which is in short supply.

Coal is the dominant fuel source for electric generation in the United States. Coal was the fuel source for 51% of the electricity generated in the United States in 2004. Furthermore, coal has significant advantages that should enable it to maintain or even increase market share over the course of the next two decades. First, coal is a low-cost fuel for electric generation, averaging less than one-third of the cost of natural gas or crude oil per megawatt hour of generation. In addition, there is significant excess capacity at existing coal-fired power plants, and this excess capacity represents a very low-cost source of electricity to the grid. At present, coal-fired power plants are operating at an average utilization rate of 71%. We believe that there is significant potential to increase those utilization rates and thus drive increased coal demand. In addition, power generators have announced plans to construct 65 gigawatts of new coal-fired generating capacity in future years, which would increase the installed base by roughly 20%.

The principal driver for U.S. coal demand is growth in domestic power generation. Domestic power needs are expected to grow over the next several years as the economy grows and the U.S. economy becomes increasingly electrified. The U.S. Energy Information Administration projects that power demand will grow at a rate of 1.9% annually over the course of the next two decades.

As energy demand grows, we believe that coal is well positioned to supply much of this demand. Competing fuels that have played a prominent role in meeting the nation’s power needs in recent years are starting to be confronted with obstacles that could impede their future growth.

America’s fleet of nuclear power plants, which is the second leading source of electric generation in the U.S. with a roughly 20% share, is operating near its effective capacity. Nuclear output has remained relatively flat since 2001. It appears unlikely that any new nuclear capacity will be constructed in the next five to 10 years.

Natural gas, the source of roughly 17% of U.S. electricity supply, is facing growing concerns about the ability to increase North American production sufficiently to keep pace with demand. While imports of liquefied natural gas (LNG) are expected to alleviate some of this supply pressure in the future; it will likely be several years before LNG will play a meaningful role in U.S. electric generation.

That means that coal will continue to act as the dominant fuel source for electric generation in the years ahead. In addition, we believe that low-sulfur coal will benefit disproportionately from future coal demand growth. Utilities have sought to comply with the sulfur dioxide standards contained in Phase II of the Clean Air Act by shifting increasingly to low sulfur coals rather than building expensive scrubbing capacity. At present, less than 30% of eastern coal-based power

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generation is equipped with scrubbers. Until a significant amount of new scrubbing capacity is added, we believe that low-sulfur coal will have a very pronounced advantage in the marketplace.

Our management has positioned the company to benefit from these trends by focusing on cost containment and growth in our core operating regions.

In recent quarters, operating costs have risen due in part to higher costs associated with medical benefits, workers’ compensation, insurance, explosives, diesel fuel, steel, permitting and surety bonding. We are focused on offsetting future cost increases with cost savings and productivity improvements elsewhere. During 2005, we plan to capture operating synergies created by recent acquisitions; continue our efforts to extend best practices across all mines; implement process improvements; apply cutting-edge maintenance programs; and invest in advanced technologies where appropriate and prudent.

During 2004, we committed — or made plans to commit — more than $1.2 billion in growth capital. Much of this capital will be invested in future periods as we make additional payments on reserve additions or continue mine development projects. We expect to fund most of our currently anticipated capital requirements through existing cash on the balance sheet and internally generated cash flow.

We currently anticipate that much of our future growth will be organic in nature. As demand for coal grows, we will evaluate the expansion of our existing operations and the development of new mines on our existing reserve base.


	Results of Operations


	*Acquisitions*

On August 20, 2004, we acquired (1) Vulcan Coal Holdings, L.L.C., which owned all of the common equity of Triton Coal Company, LLC (“Triton”), and (2) all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Immediately following the consummation of the transaction, we sold the smaller of Triton’s two mines, Buckskin, to Kiewit Mining Acquisition Company, at a net sales price of $73.1 million. After completion of these transactions, we integrated the operations of the larger of Triton’s two mines, North Rochelle, with our existing Black Thunder mine in the Powder River Basin.

On July 31, 2004, we purchased the remaining 35% interest in Canyon Fuel Company, LLC (“Canyon Fuel”) not owned by us from ITOCHU Corporation for a purchase price of $112.2 million, including related costs and fees. Net of cash acquired, the fair value of the transaction totaled $97.4 million. As a result of the acquisition, we own substantially all of the ownership interests of Canyon Fuel and no longer account for our investment in Canyon Fuel on the equity method but consolidate Canyon Fuel in our financial statements subsequent to the July 31, 2004 purchase date.

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	*Items Affecting Comparability of Reported Results*

The comparison of our operating results for the years ending December 31, 2004, 2003 and 2002 are affected by the following significant items:


	Year Ended December 31,

	2004			2003			2002

	(Amount in millions)
Operating Income
Gain on sale of NRP units	$	91.3		$	42.7		$	—
Retroactive royalty rate reductions		2.7			—			4.4
Black lung excise tax refund		2.1			—			—
Severance costs — Skyline mine		(2.1	)		—			—
Gain from land sales		6.7			3.8			0.8
Long-term incentive compensation accrual		(5.5	)		(16.2	)		—
Severance tax recoveries		—			2.5			—
Reduction in workforce		—			(2.6	)		—
Gain on contract buyout		—			—			5.6
Workers’ compensation premium adjustment		—			—			4.6

Net increase in operating income	$	95.2		$	30.2		$	15.4
Other
Expenses resulting from termination of hedge accounting for interest rate swaps		(8.3	)		(4.3	)		—
Expenses resulting from early debt extinguishment		(0.7	)		(4.7	)		—
Interest on federal income tax refund		2.2			—			—
Interest on black lung excise tax refund		0.7			—			—
Gain from mark-to-market adjustments on interest rate swaps that no longer qualify as hedges		—			13.4			—

Net increase in pre-tax income	$	89.1		$	34.6		$	15.4

Gain on Sale of NRP Units. During 2004, we sold our remaining limited partnership units of NRP resulting in proceeds of approximately $111.4 million and gains of $91.3 million. During 2003, we sold our general partner interest and subordinated units resulting in proceeds of $115.0 million and a gain of $42.7 million.

Retroactive Royalty Rate Adjustments. During 2004 and 2002, we filed a royalty rate reduction request with the Bureau of Land Management (“BLM”) for our West Elk mine in Colorado. The BLM notified us that we would receive a royalty rate reduction for a specified number of tons representing retroactive portions for the respective years totaling $2.7 million and $3.3 million. The retroactive portion was recognized as a component of cost of coal sales in both years. Additionally in 2002, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined representing a retroactive refund of $1.1 million. The retroactive amount was reflected in income from equity investments.

Black Lung Excise Tax Refunds. During 2004, we were notified by the IRS that we would receive additional black lung excise tax refunds and interest related to black lung claims that were originally denied by the IRS in 2002. We recognized a gain of $2.8 million ($2.1 million refund and $0.7 million of interest) related to the claims. The $2.1 million refund was recorded as a component of cost of coal sales, while the $0.7 million of interest was recorded as interest income.

Severance Costs — Skyline Mine. During 2004, Canyon Fuel, which was accounted for under the equity method through July 31, 2004, began the process of idling its Skyline Mine (the idling

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process was completed in May 2004), and incurred severance costs of $3.2 million for the year ended December 31, 2004. Our share of these costs totals $2.1 million and is reflected in income from equity investments.

Gain from Land Sales. During the years ended December 31, 2004, 2003 and 2002, we recognized gains from land sales at our idle properties. These gains are reported as other operating income.

Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps. On June 25, 2003, we repaid the term loans of our subsidiary, Arch Western, with the proceeds from the offering of senior notes. In connection with the repayment of the term loans, we recognized expenses related to the write-off of loan fees and other debt extinguishment costs. Additionally, we had designated certain interest rate swaps as hedges of the variable rate interest payments due under the Arch Western term loans. Pursuant to the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS 133”), historical mark-to-market adjustments related to these swaps through June 25, 2003 were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the contractual terms of the swap agreements. For the years ending December 31, 2004 and 2003, we recognized expenses of $8.3 million and $4.3 million, respectively, related to the amortization of previously deferred mark-to-market adjustments and expenses of $0.7 million and $4.7 million, respectively, related to early debt extinguishment costs.

Interest on federal income tax refunds. In connection with the settlement of tax audits for prior years, we recorded interest income in 2004 related to federal income tax refunds. This amount is reflected as interest income.

Long-term Incentive Compensation Plan Expense. During 2004, we accrued $5.5 million under long-term incentive compensation plans. Awards under these plans included restricted stock unit grants that vest over three years and performance unit awards that are earned if the Company meets certain financial, safety and environmental targets during the three years ending December 31, 2006. During the fourth quarter of 2003, our Board of Directors approved awards under a four-year performance unit plan that began in 2000. Amounts accrued for the plan totaled $16.2 million in 2003.

Severance Tax Recoveries. During 2003, we were notified by the State of Wyoming of a favorable ruling relating to our calculation of coal severance taxes. The ruling resulted in a refund of previously paid taxes and the reversal of previously accrued taxes payable. This amount was recorded as a component of cost of coal sales in the Consolidated Statement of Operations.

Reduction in Workforce. During the year ending December 31, 2003, we instituted cost reduction efforts throughout our operations. These cost reduction efforts included the termination of approximately 100 employees at our corporate office and CAPP mining operations. Of the expense recognized, $1.6 million was recognized as a component of cost of coal sales, with the remainder recognized as a component of selling, general and administrative expenses.

Mark-to-market adjustments on interest rate swaps that no longer qualify as hedges. We are a party to several interest rate swap agreements that were entered into in order to hedge the variable rate interest payments due under Arch Western’s term loans. Subsequent to the repayment of those term loans, the swaps no longer qualify for hedge accounting under FAS 133. As such, favorable changes in the market value of the swap agreements were recorded as a component of income and are included in other non-operating income in the Consolidated Statements of Operations. During the year ended December 31, 2003, we recognized income of $13.4 million related to the mark-to-market adjustments on these swap agreements.

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Gain on Contract Buyout. During 2002, we settled certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. The settlements resulted in a pre-tax gain, which was recognized in other operating income in the Consolidated Statements of Operations.

Workers’ Compensation Premium Adjustment. During 2002, we received a workers’ compensation premium adjustment refund from the State of West Virginia. During 1998, we entered into the West Virginia workers’ compensation plan at one of our subsidiary operations. The subsidiary paid standard base rates until the West Virginia Division of Workers’ Compensation could determine the actual rates based on claims experience. Upon review, the Division of Workers’ Compensation refunded $4.6 million in premiums. The refund is reflected as a reduction in cost of coal sales.


	*Year Ended December 31, 2004, Compared to Year Ended December 31, 2003*

Summarized operating results for 2004 versus 2003 and additional discussion of the 2004 results are provided below.


	Revenues


	Year Ended December 31,				Increase (Decrease)

	2004		2003		$		%

	(Amounts in thousands, except per ton data)
Coal sales	$	1,907,168	$	1,435,488	$	471,680		32.9	%
Tons sold		123,060		100,634		22,426		22.3	%
Coal sales realization per ton sold	$	15.50	$	14.26	$	1.24		8.7	%


	Tons sold by operating segment


	Tons Sold				% of Total

	2004		2003		2004			2003

	(Amounts in thousands)
Powder River Basin		81,857		64,050		66.5	%		63.6	%
Central Appalachia		30,008		29,667		24.4	%		29.5	%
Western Bituminous Region		11,195		6,917		9.1	%		6.9	%

Total operating regions		123,060		100,634		100.0	%		100.0	%

Coal sales. The increase in coal sales resulted from the combination of higher pricing, increased volumes and the acquisitions of Triton and the remaining 35% interest in Canyon Fuel during the third quarter of 2004.

Volumes increased slightly in Central Appalachia (an increase of 1.2%), but increased more dramatically in the Powder River Basin (an increase of 27.8%) and at our Western Bituminous operations (an increase of 61.9%). Volumes in both the Powder River Basin and the Western Bituminous region benefited from the acquisitions that were completed in the third quarter of 2004.

Per ton realizations increased due primarily to higher contract prices in all three regions. In the Powder River Basin, per ton realization increased 11.3%, including above-market pricing on certain contracts acquired in the Triton acquisition. The Central Appalachia region experienced the largest per ton realization increase (an increase of 21.3%), as both contract and spot market prices were higher than in 2003. Additionally, a higher percentage of our sales were metallurgical coal sales in 2004 as compared to 2003. The Western Bituminous region’s per ton realization increased 13.4%. In addition to higher contract pricing, per ton realizations in the Western Bituminous region were also affected by the acquisition of the remaining 35% interest in Canyon Fuel. Excluding the effects of the Canyon Fuel acquisition, per ton realizations for Western Bituminous would have increased 10.4% over the prior year.

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On a consolidated basis, the increase in per ton realizations was partially offset by the change in mix of sales volumes among our operating regions. As reflected in the table above, Central Appalachia volumes (which have the highest average realization) decreased while volumes in the Powder River Basin and Western Bituminous Region increased from the prior year.


	Costs and Expenses


	Year Ended December 31,				Increase (Decrease)

	2004		2003		$			%

	(Amounts in thousands, except per ton data)
Cost of coal sales	$	1,638,284	$	1,280,608	$	357,676			27.9	%
Depreciation, depletion and amortization		166,322		158,464		7,858			5.0	%
Selling, general and administrative expenses		52,842		43,942		8,900			20.3	%
Long-term incentive compensation expense		5,495		16,217		(10,722	)		(66.1	)%
Other expenses		35,758		18,245		17,513			96.0	%

	$	1,898,701	$	1,517,476	$	381,225			25.1	%

Cost of coal sales. The increase in cost of coal sales is primarily due to the increase in coal sales revenues discussed above. Specific factors contributing to the increase are as follows:


	•	Production taxes and coal royalties (which are incurred as a percentage of coal sales realization) increased $71.8 million.

	•	Poor rail performance during 2004 resulted in missed shipments and disruptions in production.

	•	Our Central Appalachia operations incurred higher costs related to additional processing necessary to sell coal in metallurgical markets.

	•	The cost of purchased coal increased $105.9 million, reflecting a combination of increased purchase volumes and higher spot market prices that were prevalent during 2004. During 2004, we utilized purchased coal to fulfill steam coal sales commitments in order to direct more of our produced coal into the metallurgical markets.

	•	Costs for explosives and diesel fuel increased $9.5 million and $22.4 million, respectively.

	•	Costs for operating supplies increased $16.9 million due primarily to increased commodity and steel prices during the year.

	•	Repairs and maintenance costs increased $21.3 million due partially to the acquisitions made during the third quarter of 2004.

During the first quarter of 2004, we reflected the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”), in accordance with the provisions of FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. Incorporation of the provisions of the Act resulted in a $68.0 million reduction of our postretirement medical benefit obligation. Postretirement medical expenses for fiscal year 2004 after incorporation of the provisions of the Act resulted in $18.2 million less expense than that previously anticipated (substantially all of which is recorded as a component of cost of coal sales). The benefit for the year ending December 31, 2004 was partially offset by increased costs resulting from changes to other actuarial assumptions that were incorporated at the beginning of the year.

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Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property additions resulting from the acquisitions made during the third quarter of 2004.

Regional Analysis:


	Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations.


	Year Ended				Increase
	December 31,				(Decrease)

	2004		2003		$		%

Powder River Basin	$	6.19	$	5.45	$	0.74		13.6	%
Central Appalachia	$	34.84	$	30.87	$	3.97		12.9	%
Western Bituminous Region	$	15.71	$	15.41	$	0.30		1.9	%


	Powder River Basin — On a per-ton basis, operating costs increased in the Powder River Basin primarily due to increased cost of purchased coal ($0.31 per ton), increased production taxes and coal royalties ($0.17 per ton) and to the higher explosives and diesel fuel costs discussed above. Additionally, average costs were higher due to the integration of the acquired North Rochelle mine into our Black Thunder mine.

	Central Appalachia — Operating cost per ton increased due to increased costs for coal purchases ($2.52 per ton), increased diesel fuel ($0.38 per ton) and production taxes and coal royalties ($0.49 per ton) as well as the increased preparation costs for metallurgical coal discussed above. Additionally, poor rail performance at our Central Appalachia operations resulted in disruptions in production. As many of our costs are fixed in nature, the reduced volume did not result in reduced overall costs.

	Western Bituminous Region — Operating cost per ton increased primarily due to increased production taxes and coal royalties ($0.27 per ton).

Selling, general and administrative expenses. Selling, general and administrative expenses increased due primarily to legal and professional fees, franchise taxes and higher expenses resulting from amounts expected to be earned under our annual incentive plans.

Other expenses. The increase in other expenses is primarily a result of higher costs to terminate certain contractual obligations for the purchase of coal as compared to the prior year.


	Other Operating Income


	Year Ended				Increase
	December 31,				(Decrease)

	2004		2003		$			%

	(Amounts in thousands)
Income from equity investments	$	10,828	$	34,390	$	(23,562	)		(68.5	)%
Gain on sale of units of NRP		91,268		42,743		48,525			113.5	%
Other operating income		67,483		45,226		22,257			49.2	%

	$	169,579	$	122,359	$	47,220			38.6	%

Income from equity investments. Income from equity investments for 2004 consists of $8.4 million from our investment in Canyon Fuel (prior to our July 31, 2004 acquisition of the 35% interest we did not own) and $2.4 million from our investment in NRP (prior to the sale of NRP units in March 2004). For 2003, income from equity investments consisted of $19.7 million of income from our

II-9

investment in Canyon Fuel and $14.7 million from our investment in NRP. The decline in income from our investment in Canyon Fuel results from the consolidation of Canyon Fuel into our financial statements subsequent to the July 31, 2004 purchase date, lower production and sales levels at Canyon Fuel prior to the acquisition and additional costs related to idling the Skyline Mine, including the severance costs noted above.

Other operating income. The increase in other operating income is primarily due to the recognition in 2004 of $13.9 million of previously deferred gains from the 2003 and 2004 NRP unit sales. These deferred gains are being recognized over the terms of our leases with NRP. The increase is also due to gains recognized on land sales of $6.7 million in 2004 compared to $3.8 million in 2003.


	Interest Expense, Net


	Year Ended						Increase
	December 31,						(Decrease)

	2004			2003			$			%

	(Amounts in thousands)
Interest expense	$	62,634		$	50,133		$	12,501			24.9	%
Interest income		(6,130	)		(2,636	)		(3,494	)		(132.5	)%

	$	56,504		$	47,497		$	9,007			19.0	%

Interest expense. The increase in interest expense results from a higher average interest rate in the first six months of 2004 as compared to the same period in 2003 as well as a higher amount of average borrowings from August through December 2004 as compared to the prior year. In 2004, the Company’s outstanding borrowings consisted primarily of fixed rate borrowings, while borrowings in the first half of 2003 were primarily variable rate borrowings. Short-term interest rates in 2003 were lower than the fixed rate borrowing that made up the majority of average debt balances in 2004.

Interest Income. The increase in interest income is partly due to interest on the federal income tax refunds discussed above. The remaining increase results primarily from interest on short-term investments.


	Other non-operating income and expense


	Year Ended						Increase
	December 31,						(Decrease)

	2004			2003			$		%

	(Amounts in thousands)
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps	$	9,010		$	8,955		$	55		0.6	%
Other non-operating income		(1,044	)		(13,211	)		12,167		92.1	%

	$	7,966		$	(4,256	)	$	12,222		287.2	%

Amounts reported as non-operating consist of income or expense resulting from the Company’s financing activities other than interest. As described above, the Company’s results of operations for the years ended December 31, 2004 and 2003 include expenses of $8.3 million and $4.3 million, respectively, related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Additionally, we incurred expenses of $0.7 million and $4.7 million related to early debt extinguishment costs in 2004 and 2003, respectively.

Other non-operating income in 2003 was primarily from mark-to-market adjustments on swaps as described above. During 2003, we terminated these positions or entered into offsetting positions.

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	Income taxes


	Year Ended				Increase
	December 31,				(Decrease)

	2004		2003		$			%

	(Amounts in thousands)
Income tax benefit	$	130	$	23,210	$	(23,080	)		(99.4	)%

Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The income tax benefit recorded in 2004 is due primarily to a $7.1 million benefit due to favorable tax settlements and a $9.7 million reduction in income tax reserves associated with the completion of the 1999 through 2002 federal income tax audits. The change is also the result of the tax benefit from percentage depletion offset by the tax impact from the sales of the NRP units throughout 2004.

Deferred tax assets and liabilities are recorded at the maximum effective tax rate. Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. We have historically been subject to alternative minimum tax (AMT), and it is more likely than not that we will remain an AMT taxpayer in the foreseeable future. Valuation allowances are established against deferred tax assets so as to value the asset to an amount that is realizable, as further described in “Management’s Discussion and Analysis of Financial Condition — Critical Accounting Policies.”


	Net income before cumulative effect of accounting change


	Year Ended				Increase
	December 31,				(Decrease)

	2004		2003		$		%

	(Amounts in thousands)
Net income before cumulative effect of accounting change	$	113,706	$	20,340	$	93,366		459.0	%

The increase in net income before cumulative effect of accounting change is primarily due to higher coal sales revenues and the gain recognized from the sales of NRP units during 2004 (net of related tax provision).


	*Year Ended December 31, 2003, Compared to Year Ended December 31, 2002*

Summarized operating results for 2003 versus 2002 and additional discussion of the 2003 results are provided below.


	Revenues


	Year Ended				Increase
	December 31,				(Decrease)

	2003		2002		$			%

	(Amounts in thousands, except per ton data)
Coal sales	$	1,435,488	$	1,473,558	$	(38,070	)		(2.6	)%
Tons sold		100,634		106,691		(6,057	)		(5.7	)%
Coal sales realization per ton sold	$	14.26	$	13.81	$	0.45			3.3	%

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	Percentage of tons sold by operating segment


	Tons Sold				% of Total

	2003		2002		2003			2002

	(Amounts in thousands)
Powder River Basin		64,050		67,249		63.6	%		63.0	%
Central Appalachia		29,667		32,054		29.5	%		30.1	%
Western Bituminous Region		6,917		7,388		6.9	%		6.9	%

Total operating regions		100,634		106,691		100.0	%		100.0	%

Coal sales. Coal sales revenues decreased in 2003 as compared to 2002 primarily as a result of a decline in sales volume in 2003. Volumes were depressed in large part because our utility customers reduced coal stockpile inventory levels throughout the year. Offsetting the volume decline was an increase in average realization, due primarily to higher pricing on contract shipments made in 2003 as compared to 2002. We experienced higher pricing in all of our operating basins, as average realizations increased 10.4% in the Powder River Basin, 2.6% in Central Appalachia and 2.8% in the Western Bituminous region.

Our consolidated coal sales revenues are impacted by the mix of sales among our operating regions, as Central Appalachia coal has higher pricing on a per-ton basis than either of our other operating regions. The comparison of revenues for 2003 and 2002 is relatively unaffected by the mix of sales between our operating regions.


	Costs and Expenses


	Year Ended				Increase
	December 31,				(Decrease)

	2003		2002		$			%

	(Amounts in thousands, except per ton data)
Cost of coal sales	$	1,280,608	$	1,262,516	$	18,092			1.4	%
Depreciation, depletion and amortization		158,464		174,752		(16,288	)		(9.3	)%
Selling, general and administrative expenses		43,942		37,999		5,943			15.6	%
Long-term incentive compensation expense		16,217		—		16,217			N/A
Other expenses		18,245		29,595		(11,350	)		(38.4	)%

	$	1,517,476	$	1,504,862	$	12,614			0.8	%

Cost of coal sales. Cost of coal sales increased despite a decrease in coal sales revenues and tonnage due primarily to increased costs related to our pension and postretirement medical plans of $34.0 million. This increase was a result of changes in the actuarial assumptions used to determine the liabilities and expenses related to the plans. Of the $34.0 million increase, $33.5 million related to our Central Appalachian operations. Additionally, cost of coal sales in 2003 was negatively impacted by the charges related to the reduction in force mentioned above and due to disruptions in production resulting from severe weather in the first quarter of 2003 at certain operations.

Depreciation, depletion and amortization. The decrease is due partially to a decline in depletion in 2003 as compared to 2002 that relates to a decrease in overall sales volumes of 5.7%. The decrease also relates to a decline in the amortization of coal supply agreements in 2003 as compared to 2002. This was primarily a result of the renegotiation of a significant contract in 2003. In April 2003, we agreed to terms with a customer seeking to buy out of the remaining term of an above-market supply contract. The buyout resulted in the receipt of $52.5 million in cash and the write off of the contract value of approximately $37.5 million. Amortization related to this contract was

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$0.9 million in 2003 compared to $2.8 million in 2002. Additionally, two other contracts were fully amortized in 2003. Amortization on these contracts totaled $2.5 million in 2003 versus $5.4 million in 2002.

Regional Analysis:


	Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations.


	Year Ended				Increase
	December 31,				(Decrease)

	2003		2002		$		%

Powder River Basin	$	5.45	$	5.31	$	0.14		2.6	%
Central Appalachia	$	30.87	$	28.26	$	2.61		9.2	%
Western Bituminous Region	$	15.41	$	14.53	$	0.88		6.1	%


	Powder River Basin — On a per-ton basis, operating costs increased slightly primarily a result of higher costs for certain operating supplies, including explosives and diesel fuel.

	Central Appalachia — On a per-ton basis, operating costs increased 9.2% in 2003. As discussed above, Central Appalachia costs were negatively affected by the increased expense resulting from changes in actuarial assumptions on our pension and postretirement medical plans.

	Western Bituminous Region — On a per-ton basis, operating costs increased 6.1% in 2003. Volumes declined as a result of our utility customers reducing inventory stockpiles throughout the year. As many of our costs are fixed in nature, the reduced volume did not result in reduced overall costs.

Selling, general and administrative expenses. The increase in selling, general and administrative expenses is primarily due to an increase in compensation-related expenses and costs related to the reduction in force mentioned above. Our 2003 administrative expenses include approximately $2.7 million earned under our annual incentive plan. No amounts were earned under the annual incentive plan in 2002.

Other expenses. The decrease in other expenses is primarily a result of lower costs to terminate certain contractual obligations for the purchase of coal as compared to the prior year.


	Other Operating Income


	Year Ended				Increase
	December 31,				(Decrease)

	2003		2002		$			%

	(Amounts in thousands)
Income from equity investments	$	34,390	$	10,092	$	24,298			240.8	%
Gain on sale of units of NRP		42,743		—		42,743			N/A
Other operating income		45,226		50,489		(5,263	)		(10.4	)%

	$	122,359	$	60,581	$	61,778			102.0	%

Income from equity investments. Income from equity investments for 2003 is comprised of $19.7 million from our investment in Canyon Fuel and $14.7 million from our investment in NRP. For 2002, income from Canyon Fuel was $7.8 million and income from NRP was $2.3 million. The improved results from Canyon Fuel are due primarily to improved operating margins, as reduced operating costs more than offset slightly lower realizations. The increase in income from NRP is due to

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the fact that 2003 includes a full year of income from NRP, while 2002 includes only that period from the formation of NRP in October 2002.

Other operating income. The decline in other operating income is due primarily to lower outlease royalty income resulting from the contribution of reserves and the related leases to NRP. The royalty income we recorded in 2003 was $7.1 million lower than that reported in 2002. This decline was partially offset by the gains on the sale of land described above.


	Interest Expense, Net


	Year Ended						Increase
	December 31,						(Decrease)

	2004			2003			$			%

	(Amounts in thousands)
Interest expense	$	50,133		$	51,922		$	(1,789	)		(3.4	)%
Interest income		(2,636	)		(1,083	)		(1,553	)		(143.4	)%

	$	47,497		$	50,839		$	(3,342	)		(6.6	)%

Interest expense. The decline in interest expense is the result of lower average outstanding borrowings, as average debt levels declined more than 10% in 2003 as compared to 2002. During 2003, we reduced our overall debt levels through a public offering of preferred stock. This decline in debt levels was partially offset by higher interest rates. In June of 2003, we replaced Arch Western’s variable-rate term loans with fixed rate senior notes. The fixed-rate on the senior notes is higher than the variable rates that we paid in 2002.


	Other non-operating income and expense

Amounts reported as non-operating consist of income or expense resulting from our financing activities other than interest. As described above, our results of operations for 2003 include expenses of $4.7 million related to debt extinguishment costs and $4.3 million related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred.

Additionally, we recognized income of $13.4 million from mark-to-market adjustments for interest rate swap agreements which no longer qualify for hedge accounting.


	Benefit from income taxes


	Year Ended				Increase
	December 31,				(Decrease)

	2003		2002		$		%

	(Amounts in thousands)
Benefit from income taxes	$	23,210	$	19,000	$	4,210		22.2	%

Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The increase in the income tax benefit for 2003 is primarily due to the utilization of a capital loss which had previously been reserved. We were able to utilize the capital loss to offset a portion of the gain from the sale of units of NRP.

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	Net income (loss) before cumulative effect of accounting change


	Year Ended					Increase
	December 31,					(Decrease)

	2003		2002			$		%

	(Amounts in thousands)
Net income (loss) before cumulative effect of accounting change	$	20,340	$	(2,562	)	$	22,902		N/A

The increase in net income before cumulative effect of accounting change is primarily due to the gain on the sale of units of NRP, offset by the long-term compensation plan expense, each of which is described above.


	Cumulative effect of accounting change

Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“FAS 143”). FAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Application of FAS 143 resulted in a cumulative effect loss as of January 1, 2003 of $3.7 million, net of tax.


	Outlook

Railroad Transportation Disruptions. During 2004, rail service disruptions resulted in missed shipments in all of our operating regions, including some of our highest margin coal in Central Appalachia. In addition, we were periodically forced to curtail production at the West Elk mine in Colorado and the Black Thunder mine in Wyoming due to high inventory levels stemming from insufficient rail service. Inventory levels increased approximately 89% from the prior year to 16.1 million tons as of December 31, 2004.

The railroad disruptions, which initially resulted from inadequate staffing at the railroads, equipment shortages and an unexpected increase in overall rail shipments, improved somewhat during the third and fourth quarters, but suffered a setback following hurricane-related disruptions in the Southeast regions of the United States late in the third quarter. We anticipate continued challenges, with gradual improvement in rail service in the first half of 2005. We are working with our customers and the railroads in an effort to address these issues in a timely manner.

Expenses Related to Interest Rate Swaps. We had designated certain interest rate swaps as hedges of the variable rate interest payments due under Arch Western’s term loans. Pursuant to the requirements of FAS 133, historical mark-to-market adjustments related to these swaps through June 25, 2003 of $27.0 million were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the original contractual terms of the swap agreements. As of December 31, 2004, the remaining deferred amounts will be recognized as expense in the following periods: $7.7 million in 2005; $4.8 million in 2006; and $1.9 million in 2007.

Chief Objectives. We are focused on taking steps to increase shareholder returns by improving earnings, strengthening cash generation, and improving productivity at our large-scale mines, while building on our strategic position in each of the nation’s three principal low-sulfur coal basins. We believe that success in the coal industry is largely dependent on leadership in three crucial areas of performance — safety, environmental stewardship and return on investment — and we are pursuing such leadership aggressively. At the same time, we are sustaining our longstanding focus on being a low-cost producer in the regions where we operate. We are also seeking to enhance our position as a preferred supplier to U.S. power producers by acting as a reliable and highly ethical partner. We plan to focus on organic growth by continuing to develop our existing reserve base, which is large and

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highly strategic. We also plan to evaluate acquisitions that represent a good fit with our existing operations.


	Disclosure and Internal Controls

An evaluation was performed under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2004. Based on that evaluation, our management, including the CEO and CFO, concluded that the disclosure controls and procedures were effective as of such date. There were no changes in internal control over financial reporting that occurred during our fiscal quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


	Liquidity and Capital Resources

The following is a summary of cash provided by or used in each of the indicated types of activities during the past three years:


		Year Ended December 31,

		2004			2003		2002

		(In thousands)
Cash provided by (used in):
	Operating activities	$	146,728		$	162,361	$	176,417
	Investing activities		(595,294	)		6,832		(128,303	)
	Financing activities		517,192			75,791		(45,447	)

Cash provided by operating activities declined in 2004 as compared to 2003 primarily as a result of increased investment in working capital. Trade accounts receivable represented the largest use of funds, increasing by more than $32.5 million (net of amounts acquired in business combinations) in 2004. This increase is due to higher sales levels during the period, as revenues have increased approximately 33% in 2004 as compared to 2003. Additionally, inventory increased by more than $12.0 million (net of amounts acquired in business combinations) in 2004. This increase is due primarily to the continued rail difficulties that resulted in missed shipments during the year. Cash provided by operating activities in 2003 declined as compared to 2002 due primarily to lower income levels (after adjusting for gains from the NRP unit sale in December 2003 and other asset sales).

Cash used in investing activities in 2004 is represented largely by payments for acquisitions of $387.8 million, net of cash acquired, during the third quarter of 2004. We acquired the 35% of the Canyon Fuel investment not owned by us and the North Rochelle operations from Triton in July and August 2004, respectively. The Canyon Fuel acquisition was funded with a $22.0 million five-year note and approximately $90 million of cash on hand. The Triton acquisition was funded with borrowings under our existing revolving credit facility of $22.0 million, a term loan in the amount of $100.0 million, and with cash on hand. Capital expenditures and advance royalty payments were $292.6 million and $33.8 million, respectively. Capital expenditures include $122.2 million related to the first of five annual payments under the lease of coal mineral reserves at Little Thunder discussed below. The remaining capital expenditures related to other various plant and equipment purchases, primarily at our Powder River Basin and Central Appalachia mines. These cash outlays were offset partially by proceeds of $111.4 million from the sale of the NRP units. Cash provided by investing activities in 2003 reflects the receipt of $115.0 million from the sale of the subordinated units and general partner interest of NRP and the receipt of $52.5 million from the buyout of a coal supply contract with above-market pricing. These non-recurring cash inflows offset our capital expenditures and advance royalty payments, which totaled $165.0 million. Cash used in investing activities in 2002 is due primarily to capital expenditures and advance royalty payments, which totaled $164.4 million,

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offset partially by the impact of the sale of limited partnership units of NRP in 2002, which generated proceeds of $33.6 million.

On September 22, 2004, the U.S. Bureau of Land Management (“BLM”) accepted our bid of $611.0 million for a 5,084-acre federal coal lease known as Little Thunder, which is adjacent to our Black Thunder mine in the Powder River Basin. According to the BLM, the lease contains approximately 719.0 million mineable tons of compliance coal. We paid the first of five annual payments at the time of the bid. The remaining four annual lease payments will be made in fiscal years 2006 through 2009.

Cash provided by financing activities in 2004 consists primarily of proceeds from the issuance of senior notes of $261.9 million and proceeds from the issuance of common stock through a public offering of $230.5 million (as described more fully below). Additionally, financing activities in 2004 also include net borrowings under our revolving credit facility of $25.0 million, proceeds of $37.0 million from the issuance of common stock under our employee stock incentive plan and dividend payments of $24.0 million. Cash provided by financing activities in 2003 reflects the proceeds from the issuance of the Arch Western Finance senior notes (which were used to retire Arch Western’s existing debt) and the proceeds from the sale of preferred stock (see additional discussion below). Cash used in financing activities during 2002 primarily represents net payments under our revolver and lines of credit, payments of dividends, and reductions of capital lease obligations. In addition, during 2002, we entered into a sale and leaseback of equipment that resulted in proceeds of $9.2 million.

On November 24, 2004, we filed a Universal Shelf Registration Statement on Form S-3 with the Securities and Exchange Commission. The Universal Shelf allows us to offer, from time to time, an aggregate of up to $1.0 billion in debt securities, preferred stock, depositary shares, purchase contracts, purchase units, common stock and related rights and warrants.

On October 28, 2004, we completed a public offering of 7,187,500 shares of our common stock, including the underwriters’ full over-allotment option, at a price of $33.85 per share. We used the net proceeds of the offering, totaling $230.5 million after the underwriters’ discount and expenses, to repay borrowings under our revolving credit facility incurred to finance our acquisition of Triton Coal Company and the first annual payment for the Little Thunder federal coal lease. We intend to use the remaining proceeds for general corporate purposes, including the development of the Mountain Laurel longwall mine in Central Appalachia.

On October 22, 2004, two subsidiaries of Arch Western, as co-obligors, issued $250 million of 6³/4% senior notes due 2013 at a price of 104.75% of par, pursuant to Rule 144A under the Securities Act of 1933, as amended. The notes form a single series with Arch Western Finance’s existing 6³/4% senior notes due 2013, except that the new notes are subject to certain transfer restrictions and are not fully fungible with the existing notes. We have an exchange offer underway for the notes; after completion of the exchange offer, the notes will be fully fungible with the previously issued notes. The net proceeds of the offering were used to repay and retire the outstanding indebtedness under Arch Western’s $100.0 million term loan maturing in 2007, to repay indebtedness under our revolving credit facility and for general corporate purposes.

On June 25, 2003, Arch Western Finance, LLC, a subsidiary of Arch Western, completed the offering of $700 million of 6³/4% senior notes due 2013. The proceeds of the offering were primarily used to repay Arch Western’s existing term loans. Interest on the senior notes is payable on January 1 and July 1 each year commencing January 1, 2004. The senior notes are guaranteed by Arch Western and certain of Arch Western’s subsidiaries and are secured by a security interest in promissory notes we issued to Arch Western evidencing cash loaned to us by Arch Western. The terms of the senior notes contain restrictive covenants that limit Arch Western’s ability to, among other things, incur additional debt, sell or transfer assets, and make investments.

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On January 31, 2003, we completed a public offering of 2,875,000 shares of 5% Perpetual Cumulative Convertible Preferred Stock. The net proceeds from the offering of approximately $139.0 million were used to reduce indebtedness under our revolving credit facility and for working capital and general corporate purposes, including potential acquisitions.

Excluding any significant mineral reserve acquisitions, we generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations. We believe that cash generated from operations and our borrowing capacity will be sufficient to meet working capital requirements, anticipated capital expenditures and scheduled debt payments for at least the next several years. Our ability to satisfy debt service obligations, to fund planned capital expenditures, to make acquisitions and to pay dividends will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.

Capital expenditures were $292.6 million, $132.4 million and $137.1 million for 2004, 2003 and 2002, respectively. Capital expenditures are made to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We anticipate that capital expenditures during 2005 will range from $340 to $360 million. This estimate includes capital expenditures related to development work at certain of our mining operations, including the Mountain Laurel complex in West Virginia and the North Lease mine in Utah formerly known as Skyline. Also, this estimate assumes no other acquisitions, significant expansions of our existing mining operations or additions to our reserve base. We anticipate that we will fund these capital expenditures with available cash, existing credit facilities and cash generated from operations.

On December 22, 2004, we entered into a $700.0 million revolving credit facility that matures on December 22, 2009. The rate of interest on borrowings under the credit facility is a floating rate based on LIBOR. The credit facility is secured by substantially all of our assets as well as our ownership interests in substantially all of our subsidiaries, except our ownership interests in Arch Western and its subsidiaries. The credit facility replaced our existing $350.0 million revolving credit facility. At December 31, 2004, we had $69.0 million in letters of credit outstanding which, when combined with the $25.0 million of outstanding borrowings under the revolver, resulted in $606.0 million of unused borrowings under the revolver. At December 31, 2004, financial covenant requirements do not restrict the amount of unused capacity available to us for borrowing and letters of credit.

Financial covenants contained in our revolving credit facility consist of a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. The leverage ratio requires that we not permit the ratio of total net debt (as defined in the facility) at the end of any calendar quarter to EBITDA (as defined in the facility) for the four quarters then ended to exceed a specified amount. The interest coverage ratio requires that we not permit the ratio of EBITDA (as defined) at the end of any calendar quarter to interest expense for the four quarters then ended to be less than a specified amount. The senior secured leverage ratio requires that we not permit the ratio of total net senior secured debt (as defined) at the end of any calendar quarter to EBITDA (as defined) for the four quarters then ended to exceed a specified amount. We were in compliance with all financial covenants at December 31, 2004.

At December 31, 2004, debt amounted to $1,011.1 million, or 48% of capital employed, compared to $706.4 million, or 51% of capital employed, at December 31, 2003. Based on the level of consolidated indebtedness and prevailing interest rates at December 31, 2004, debt service obligations, which include the current maturities of debt and interest expense for 2005, are estimated to be $76.0 million.

We periodically establish uncommitted lines of credit with banks. These agreements generally provide for short-term borrowings at market rates. At December 31, 2004, there were $20.0 million of such agreements in effect, of which none were outstanding.

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We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2004, substantially all of our outstanding debt bore interest at fixed rates.

Additionally, we are exposed to market risk associated with interest rates resulting from our interest rate swap positions. Prior to the June 25, 2003 Arch Western Finance senior notes offering and subsequent repayment of Arch Western’s term loans, we utilized interest rate swap agreements to convert the variable-rate interest payments due under the term loans and our revolving credit facility to fixed-rate payments.

At December 31, 2004, our net interest rate swap position is as follows:


	•	Swaps with a notional value of $25.0 million which are designated as hedges of future interest payments to be made under our revolving credit facility. Under these swaps, we pay a fixed rate of 5.96% (before the credit spread over LIBOR) and receive a variable rate based upon 30-day LIBOR. The remaining term of the swap agreements at December 31, 2004 was 30 months.

	•	Swaps with a total notional value of $500.0 million consisting of offsetting positions of $250.0 million each. Because of the offsetting nature of these positions, we are not exposed to significant market interest rate risk related to these swaps. Under these swaps, we pay a weighted average fixed rate 5.72% on $250.0 million of notional value and receive a weighted average fixed rate of 2.71% on $250.0 million of notional value. The remaining terms of these swap agreements at December 31, 2004 ranged from 8 to 31 months.

As of December 31, 2004, the fair value of our net interest rate swap position was a liability of $12.4 million. This liability is included in other noncurrent liabilities in the accompanying Consolidated Balance Sheets.

We are also exposed to commodity price risk related to our purchase of diesel fuel. We enter into forward purchase contracts and heating oil swaps to reduce volatility in the price of diesel fuel for our operations. The swap agreements essentially fix the price paid for diesel fuel by requiring us to pay a fixed heating oil price and receive a floating heating oil price. The changes in the floating heating oil price highly correlate to changes in diesel fuel prices.

The discussion below presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices. The range of changes reflects our view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen. The major accounting policies for these instruments are described in Note 1 to the consolidated financial statements.

At December 31, 2004, our debt portfolio consisted of substantially fixed rates. A change in interest rates on the fixed rate debt impacts the net financial instrument position but has no impact on interest incurred or cash flows. The sensitivity analysis related to our fixed rate debt assumes an instantaneous 100-basis point move in interest rates from their levels at December 31, 2004, with all other variables held constant. A 100-basis point increase in market interest rates would result in a $58.4 million decrease in the fair value of the Company’s fixed rate debt at December 31, 2004. At December 31, 2004, a $.05 per gallon increase in the price of heating oil would result in a $0.1 million increase in the fair value of the financial position of the heating oil swap agreements.

As it relates to our interest rate swap positions, a change in interest rates impacts the net financial instrument position. A 100-basis point increase in market interest rates would result in a $0.6 million decrease in the fair value of our liability under the interest rate swap positions at December 31, 2004.

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	Contractual Obligations

The following is a summary of our significant contractual obligations as of December 31, 2004 (in thousands):


	Payments Due by Period

	2005		2006-2007		2008-2009		After 2009

Long-term debt, including related interest	$	75,069	$	136,317	$	162,250	$	1,174,438
Operating leases		25,282		44,767		35,786		29,066
Royalty leases		32,227		309,320		297,987		72,715
Unconditional purchase obligations		539,107		163,975		100,113		—
Other long-term obligations		—		—		—		23,200

Total contractual cash obligations	$	671,685	$	654,379	$	596,136	$	1,299,419

Royalty leases represent non-cancelable royalty lease agreements as well as federal lease bonus payments due under the Little Thunder lease. Payments due under the Little Thunder lease total $611.0 million, to be paid in five equal annual installments of $122.2 million. The first installment was paid in September 2004 with the remaining four annual payments due in fiscal years 2006 through 2009. Unconditional purchase obligations represent amounts committed for purchases of materials and supplies, payments for services, purchased coal, and capital expenditures. Other long-term obligations represent our contractual amounts owed in conjunction with our ownership interest in Dominion Terminal Associates as described in Note 20 to the Consolidated Financial Statements.

We currently do not anticipate making any contributions to our pension plan in 2005. We believe that our on-hand cash balance, cash generated from operations, and borrowing capacity under our revolving credit facility and other debt facilities will be sufficient to meet these obligations and our requirements for working capital and capital expenditures.


	Contingencies


	*Reclamation*

The federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. We accrue for the costs of reclamation in accordance with the provisions of FAS 143, which was adopted as of January 1, 2003. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at deep mines. Other costs of reclamation common to surface and underground mining are related to reclaiming refuse and slurry ponds, eliminating sedimentation and drainage control structures, and dismantling or demolishing equipment or buildings used in mining operations. The establishment of the asset retirement obligation liability is based upon permit requirements and requires various estimates and assumptions, principally associated with costs and productivities.

We review our entire environmental liability periodically and make necessary adjustments, including permit changes and revisions to costs and productivities to reflect current experience. Our management believes it is making adequate provisions for all expected reclamation and other associated costs.


	*Legal Contingencies*

Permit Litigation Matters. A group of local and national environmental organizations filed suit against the U.S. Army Corps of Engineers in the U.S. District Court in Huntington, West Virginia on October 23, 2003. In its complaint, Ohio River Valley Environmental Coalition, et al v. Bulen, et al, the plaintiffs allege that the Corps has violated its statutory duties arising under the Clean Water Act, the

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Administrative Procedure Act and the National Environmental Policy Act in issuing the Nationwide 21 (“NWP 21”) general permit. The plaintiffs allege that the procedural requirements of the three federal statutes identified in their complaint have been violated, and that the Corps may not utilize the mechanism of a nationwide permit to authorize valley fills. Among specific fills identified in the complaint as not meeting the requirements of the NWP 21 are valley fills associated with several of our operating subsidiaries, although none are party to this litigation. If the plaintiffs prevail in this litigation, it may delay our receipt of these permits.

On July 8, 2004, the District court entered a final order enjoining the Corps from authorizing new valley fills using the mechanism of its nationwide permit. The Court also ordered the Corps to suspend current authorizations issued for fills that had not yet commenced construction on the date of the order. The district court modified its earlier decision on August 13 when it directed the Corps to suspend all permits for fills that had not commenced construction as of July 8, 2004.

A total of three permits at two of our operating subsidiaries will be affected by the Court’s July 8 order. Because the Court found that it is the Corps’ procedure in issuing the permits, and not defects in the fills themselves, our affected subsidiaries will be able to re-apply for individual permits under section 404 of the Clean Water act to construct each fill. We currently do not believe that the individual permit process will have an impact on our mining operations.

The Corps and several intervening trade associations, of which we are a member of three, filed an appeal with the U.S. Court of Appeals for the Fourth circuit in this matter on September 16, 2004.

West Virginia Flooding Litigation. We and three of our subsidiaries have been named, among others, in 17 separate complaints filed in Wyoming, McDowell, Fayette, Upshur, Kanawha, Raleigh, Boone and Mercer Counties, West Virginia. These cases collectively include approximately 1,780 plaintiffs who are seeking damages for property damage and personal injuries arising out of flooding that occurred in southern West Virginia in July of 2001. The plaintiffs have sued coal, timber, railroad and land companies under the theory that mining, construction of haul roads and removal of timber caused natural surface waters to be diverted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that these cases, along with several additional flood damages cases not involving our subsidiaries, be handled pursuant to the Court’s Mass Litigation rules. As a result of this ruling, the cases have been transferred to the Circuit Court of Raleigh County in West Virginia to be handled by a panel consisting of three circuit court judges, which certified certain legal issues back to the West Virginia Supreme Court. The West Virginia Supreme Court has resolved these issues, and the panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts.

While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition or results of operations.

Ark Land Company v. Crown Industries. In response to a declaratory judgment action filed by Ark Land Company, a subsidiary of ours, in Mingo County, West Virginia against Crown Industries involving the interpretation of a severance deed under which Ark Land controls the coal and mining rights on property in Mingo County, West Virginia, Crown Industries filed a counterclaim against Ark Land and a third party complaint against us and two of our other subsidiaries seeking damages for trespass, nuisance and property damage arising out of the exercise of rights under the severance deed on the property by our subsidiaries. The defendant has alleged that our subsidiaries have insufficient rights to haul certain foreign coals across the property without payment of certain wheelage or other fees to the defendant. In addition, the defendant has alleged that we and our subsidiaries have violated West Virginia’s Standards for Management of Waste Oil and the West Virginia Surface Coal Mining and Reclamation Act by spilling and disposing of hydrocarbon and other wastes on and in the property and

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by failing to return the property to its approximate original contour. It also alleges that we or our contractor have improperly disposed of explosive components. This case is set for trial in May 2005.

While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on it, we believe this matter will be resolved without a material adverse effect on our financial condition or results of operations.

We are a party to numerous other claims and lawsuits with respect to various matters. We provide for costs related to contingencies, including environmental matters, when a loss is probable and the amount is reasonably determinable. After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.


	Certain Trends and Uncertainties


	*Substantial Leverage — Covenants*

As of December 31, 2004, we had outstanding consolidated indebtedness of $1,011.1 million, representing approximately 48% of our capital employed. Despite making substantial progress in reducing debt, we continue to have significant debt service obligations, and the terms of our credit agreements limit our flexibility and result in a number of limitations on us. We also have significant lease and royalty obligations. Our ability to satisfy debt service, lease and royalty obligations and to effect any refinancing of our indebtedness will depend upon future operating performance, which will be affected by prevailing economic conditions in the markets that we serve as well as financial, business and other factors, many of which are beyond our control. We may be unable to generate sufficient cash flow from operations and future borrowings, or other financings may be unavailable in an amount sufficient to enable us to fund our debt service, lease and royalty payment obligations or our other liquidity needs.

Our relative amount of debt and the terms of our credit agreements could have material consequences to our business, including, but not limited to: (i) making it more difficult to satisfy debt covenants and debt service, lease payment and other obligations; (ii) making it more difficult to pay quarterly dividends as we have in the past; (iii) increasing our vulnerability to general adverse economic and industry conditions; (iv) limiting our ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general corporate requirements; (v) reducing the availability of cash flows from operations to fund acquisitions, working capital, capital expenditures or other general corporate purposes; (vi) limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; or (vii) placing us at a competitive disadvantage when compared to competitors with less relative amounts of debt.

The agreements governing our outstanding debt impose a number of restrictions on us. For example, the terms of our credit facilities and leases contain financial and other covenants that create limitations on our ability to, among other things, borrow the full amount under our credit facilities, effect acquisitions or dispositions and incur additional debt, and require us to, among other things, maintain various financial ratios and comply with various other financial covenants. Our ability to comply with these restrictions may be affected by events beyond our control and, as a result, we may be unable to comply with these restrictions. A failure to comply with these restrictions could adversely affect our ability to borrow under our credit facilities or result in an event of default under these agreements. In the event of a default, our lenders could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts, or we might be forced to seek an amendment to our debt agreements which could make the terms of these agreements more onerous for us.

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Any downgrade in our credit ratings could adversely affect our ability to borrow and result in more restrictive borrowing terms, including increased borrowing costs, more restrictive covenants and the extension of less open credit. This in turn could affect our internal cost of capital estimates and therefore operational decisions.


	*Profitability*

Our mining operations are inherently subject to changing conditions that can affect levels of production and production costs at particular mines for varying lengths of time and can result in decreases in our profitability. We are exposed to commodity price risk related to our purchase of diesel fuel, explosives and steel. In addition, weather conditions, equipment replacement or repair, fires, variations in thickness of the layer, or seam, of coal, amounts of overburden, rock and other natural materials and other geological conditions have had, and can be expected in the future to have, a significant impact on our operating results. Prolonged disruption of production at any of our principal mines, particularly our Black Thunder mine, would result in a decrease in our revenues and profitability, which could be material. Other factors affecting the production and sale of our coal that could result in decreases in our profitability include:


	•	continued high pricing environment for our raw materials, including, among other things, diesel fuel, explosives and steel;

	•	expiration or termination of, or sales price redeterminations or suspension of deliveries under, coal supply agreements;

	•	disruption or increases in the cost of transportation services;

	•	changes in laws or regulations, including permitting requirements;

	•	litigation;

	•	work stoppages or other labor difficulties;

	•	labor shortages

	•	mine worker vacation schedules and related maintenance activities; and

	•	changes in coal market and general economic conditions.


	*Environmental and Regulatory Factors*

The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:


	•	the discharge of materials into the environment;

	•	employee health and safety;

	•	mine permits and other licensing requirements;

	•	reclamation and restoration of mining properties after mining is completed;

	•	management of materials generated by mining operations;

	•	surface subsidence from underground mining;

	•	water pollution;

	•	legislatively mandated benefits for current and retired coal miners;

	•	air quality standards;

	•	protection of wetlands;

	•	endangered plant and wildlife protection;

	•	limitations on land use;

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	•	storage of petroleum products and substances that are regarded as hazardous under applicable laws; and

	•	management of electrical equipment containing polychlorinated biphenyls, or PCBs.

In addition, the electric generating industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, either of which may have a significant impact on our mining operations or our customers’ ability to use coal and may require us or our customers to significantly change operations or to incur substantial costs.

While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of our coal. These regulations can take a variety of forms, as explained below.

The Clean Air Act imposes obligations on the Environmental Protection Agency, or EPA, and the states to implement regulatory programs that will lead to the attainment and maintenance of EPA-promulgated ambient air quality standards, including standards for sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standard for ozone. In particular, coal-fired power plants will be affected by state regulations designed to achieve attainment of the ambient air quality standard for ozone. Ozone is produced by the combination of two precursor pollutants: volatile organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead.

In July 1997, the EPA adopted more stringent ambient air quality standards for particulate matter and ozone. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. In April 2004, the EPA issued final nonattainment designations for the eight-hour ozone standard, and, in December 2004, issued the final nonattainment standard for PM25. States will have to reuse their State Implementation Plans to require electric power generators to further reduce nitrogen oxide and particulate matter emissions, particularly in designated nonattainment areas. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and our development of new mines. This in turn may result in decreased production and a corresponding decrease in our revenues. Although the future scope of these ozone and particulate

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matter regulations cannot be predicted, future regulations regarding these and other ambient air standards could restrict the market for coal and the development of new mines.

The EPA has also initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. By imposing limitations upon the placement and construction of new coal-fired power plants, the EPA’s regional haze program could affect the future market for coal.

Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities for alleged violations of the Clean Air Act. The EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. We supply coal to some of the currently affected utilities, and it is possible that other of our customers will be sued. These lawsuits could require the utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely impact their demand for coal.

New regulations concerning the routine maintenance provisions of the New Source Review program were published in October 2003. Fourteen states, the District of Columbia and a number of municipalities filed lawsuits challenging these regulations, and in December 2003 the Court stayed the effectiveness of these rules. Oral agreement was heard on this matter in January 2005. In January 2004, the EPA Administrator announced that EPA would be taking new enforcement actions against utilities for violations of the existing New Source Review requirements, and shortly thereafter, EPA issued enforcement notices to several electric utility companies.

In January 2004, the EPA proposed two new rules pursuant to the Clean Air Act that, once final, may require additional controls and impose more stringent requirements at coal-fired power generation facilities. First, EPA is seeking to lower nickel and mercury emissions at new and existing sources by requiring the use of Maximum Achievable Control Technology (“MACT”) or by implementing a nationwide “cap and trade” program. Second, EPA has proposed to require the submission of State Implementation Plans by 29 states and the District of Columbia to include control measures to reduce the emissions of sulfur dioxide and/or nitrogen oxides, pursuant to the eight-hour ozone and PM25 standards established pursuant to the Clean Air Act. The EPA has stated that it will issue new rules in 2005. Should either or both of these proposed rules become final, additional costs may be associated with operating coal-fired power generation facilities that may render coal a less attractive fuel source.

Other Clean Air Act programs are also applicable to power plants that use our coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur dioxide reductions can affect coal mining operations. Title IV imposes a two phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants

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of greater than 25 megawatt capacity. Affected electric utilities can comply with these requirements by:


	•	burning lower sulfur coal, either exclusively or mixed with higher sulfur coal;

	•	installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal;

	•	reducing electricity generating levels; or

	•	purchasing or trading emissions credits.

Specific emissions sources receive these credits, which electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each credit allows its holder to emit one ton of sulfur dioxide.

In addition to emissions control requirements designed to control acid rain and to attain the national ambient air quality standards, the Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA recently announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009. These controls are likely to require significant new improvements in controls by power plant owners. The most prominently targeted pollutant is mercury, which is already the subject of a proposed rule, although other by-products of coal combustion may be covered by future hazardous air pollutant standards for coal combustion sources.

Other proposed initiatives may have an effect upon coal operations. One such proposal is the Bush Administration’s recently announced Clear Skies Initiative. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides, and mercury from power plants. Other so-called multi-pollutant bills, which could regulate additional air pollutants, have been proposed by various members of Congress. While the details of all of these proposed initiatives vary, there appears to be a movement towards increased regulation of a number of air pollutants. Were such initiatives enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements.

Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Safety and Health Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Safety and Health Acts of 1969 and 1977, the Black Lung Act requires payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dies from this disease.

Surface Mining Control and Reclamation Act. SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we are contractually obligated under the terms of our leases to comply with all laws, including SMCRA and equivalent state and local laws. These obligations include reclaiming and restoring the mined areas by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.

SMCRA also requires us to submit a bond or otherwise financially secure the performance of our reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the property or compensating the property owners for damage occurring

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on the surface of the property as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from underground mines.

We also lease some of our coal reserves to third party operators. Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees and other third parties could potentially be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the mine operator. Sanctions against the “owner” or “controller” are quite severe and can include civil penalties, reclamation fees and reclamation costs. We are not aware of any currently pending or asserted claims against us asserting that we “own” or “control” any of our lessees’ operations.

Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act. Efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel.

West Virginia Antidegradation Policy. In January 2002, a number of environmental groups and individuals filed suit in the U.S. District Court for the Southern District of West Virginia to challenge the EPA’s approval of West Virginia’s antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. In August 2003, the Southern District of West Virginia vacated the EPA’s approval of West Virginia’s anti-degradation procedures, and remanded the matter to the EPA. On March 29, 2004, EPA Regions III sent a letter to the WVDEP that approved portions of the state’s anti-degradation program, denied approval of portions pending further study, and recommended removal of certain language on the state’s regulations. Depending upon the outcome of the DEP review, the issuance or re-issuance of Clean Water Act permits to us may be delayed or denied, and may increase the costs, time and difficulty associated with obtaining and complying Clean Water Act permits for surface mining operations.

Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Thus, coal mines that we currently own or have previously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and

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similar state laws. In particular, we may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where we own surface rights.

Mining Permits and Approvals. Mining companies must obtain numerous permits that strictly regulate environmental and health and safety matters in connection with coal mining, some of which have significant bonding requirements. In connection with obtaining these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

Regulatory authorities exercise considerable discretion in the timing of permit issuance. Also, private individuals and the public at large possess rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need for our mining operations may not be issued, or, if issued, may not be issued in a timely fashion, or may involve requirements that may be changed or interpreted in a manner which restricts our ability to conduct our mining operations or to do so profitably.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically we submit the necessary permit applications several months before we plan to begin mining a new area. In our experience, permits generally are approved several months after a completed application is submitted. In the past, we have generally obtained our mining permits without significant delay. However, we cannot be sure that we will not experience difficulty in obtaining mining permits in the future.

Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the activities of mine operators, including us, may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws, may also require substantial increases in equipment expenditures and operating costs, as well as delays, interruptions or the termination of operations. We cannot predict the possible effect of such regulatory changes.

Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

Surety Bonds. Federal and state laws require us to obtain surety bonds to guarantee performance or payment of certain long-term obligations including mine closure and reclamation costs, federal and state workers’ compensation benefits, coal leases and other miscellaneous obligations. It has become increasingly difficult for us to secure new surety bonds or retain existing bonds without the posting of collateral. In addition, surety bond costs have increased and the market terms of such bonds have generally become more unfavorable. We may be unable to maintain our surety bonds or acquire new bonds in the future due to lack of availability, higher expense, unfavorable market terms, or an inability to post sufficient collateral. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material adverse impact on us.

Endangered Species. The federal Endangered Species Act and counterpart state legislation protects species threatened with possible extinction. Protection of endangered species may have the

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effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

Other Environmental Laws Affecting Us. We are required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include, for example, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. We believe that we are in substantial compliance with all applicable environmental laws.


	*Competition*

The coal industry is intensely competitive, primarily as a result of the existence of numerous producers in the coal-producing regions in which we operate, and some of our competitors may have greater financial resources. We compete with several major coal producers in the Central Appalachian and Powder River Basin areas. We also compete with a number of smaller producers in those and other market regions. Additionally, we are subject to the continuing risk of reduced profitability as a result of excess industry capacity.


	*Electric Industry Factors; Customer Creditworthiness*

Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which has accounted for approximately 90% of domestic coal consumption in recent years. These coal consumption patterns are influenced by factors beyond our control, including the demand for electricity (which is dependent to a significant extent on summer and winter temperatures and the strength of the economy); government regulation; technological developments and the location, availability, quality and price of competing sources of coal; other fuels such as natural gas, oil and nuclear; and alternative energy sources such as hydroelectric power. Demand for our low-sulfur coal and the prices that we will be able to obtain for it will also be affected by the price and availability of high-sulfur coal, which can be marketed in tandem with emissions allowances in order to meet federal Clean Air Act requirements. Any reduction in the demand for our coal by the domestic electric generation industry may cause a decline in profitability.

Electric utility deregulation is expected to provide incentives to generators of electricity to minimize their fuel costs and is believed to have caused electric generators to be more aggressive in negotiating prices with coal suppliers. Deregulation may have an adverse effect on our profitability to the extent it causes our customers to be more cost-sensitive.

In addition, our ability to receive payment for coal sold and delivered depends on the creditworthiness of our customers. In general, the creditworthiness of our customers has deteriorated. If such trends continue, our acceptable customer base may be limited.


	*Terms of Long-Term Coal Supply Contracts*

During 2004, sales of coal under long-term contracts, which are contracts with a term greater than 12 months, accounted for 70% of our total revenues. The prices for coal shipped under these contracts may be below the current market price for similar type coal at any given time. For the year ended December 31, 2004, the weighted average price of coal sold under our long-term contracts was $15.15 per ton. As a consequence of the substantial volume of our sales which are subject to these long-term agreements, we have less coal available with which to capitalize on stronger coal

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prices if and when they arise. In addition, because long-term contracts may allow the customer to elect volume flexibility, our ability to realize the higher prices that may be available on the spot market may be restricted when customers elect to purchase higher volumes under such contracts. Our exposure to market-based pricing may also be increased should customers elect to purchase fewer tons. In addition, the increasingly short terms of sales contracts and the consequent absence of price adjustment provisions in such contracts make it more likely that we will not be able to recover inflation related increases in mining costs during the contract term.


	*Reserve Degradation and Depletion*

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We have in the past acquired and will in the future acquire coal reserves for our mine portfolio from third parties. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines can also have an adverse effect on operating results that is disproportionate to the percentage of overall production represented by such mines. Mingo Logan’s Mountaineer Mine is estimated to exhaust its longwall mineable reserves in the first quarter of 2007, although we expect to make up the lost production with our planned opening of our Mountain Laurel complex in Logan County, West Virginia which should ramp up to full production in mid-2007. The Mountaineer Mine generated $30.5 million and $26.1 million of our total operating income in the years ended 2004 and 2003, respectively.


	*Potential Fluctuations in Operating Results — Factors Routinely Affecting Results of Operations*

Our mining operations are inherently subject to changing conditions that can affect levels of production and production costs at particular mines for varying lengths of time and can result in decreases in profitability. Weather conditions, equipment replacement or repair, fuel and supply prices, insurance costs, fires, variations in coal seam thickness, amounts of overburden rock and other natural materials, and other geological conditions have had, and can be expected in the future to have, a significant impact on operating results. A prolonged disruption of production at any of our principal mines, particularly the Mingo Logan operation in West Virginia or Black Thunder mine in Wyoming, would result in a decrease, which could be material, in our revenues and profitability.

The geological characteristics of Central Appalachia coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. In addition, as compared to mines in the Powder River Basin, permitting and licensing and other environmental and regulatory requirements are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and customers’ ability to use coal produced by, operators in Central Appalachia, including us.

Other factors affecting the production and sale of our coal that could result in decreases in profitability include: (i) expiration or termination of, or sales price redeterminations or suspension of deliveries under, coal supply agreements; (ii) disruption or increases in the cost of transportation services; (iii) changes in laws or regulations, including permitting requirements; (iv) litigation; (v) work stoppages or other labor difficulties; (vi) mine worker vacation schedules and related maintenance activities; and (vii) changes in coal market and general economic conditions.

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	*Transportation*

The coal industry depends on rail, trucking and barge transportation to deliver shipments of coal to customers, and transportation costs are a significant component of the total cost of supplying coal. Disruption or insufficient availability of these transportation services could temporarily impair our ability to supply coal to customers and thus adversely affect our business and the results of our operations. In addition, increases in transportation costs associated with our coal, or increases in our transportation costs relative to transportation costs for coal produced by our competitors or of other fuels, could adversely effect our business and results of operations.


	*Reserves — Title; Leasehold Interests*

We base our reserve information on geological data assembled and analyzed by our staff, which includes various engineers and geologists, and periodically reviewed by outside firms. The reserve estimates are annually updated to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, such as geological and mining conditions which may not be fully identified by available exploration data or may differ from experience in current operations, historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies, and assumptions concerning coal prices, operating costs, severance and excise taxes, development costs, and reclamation costs, all of which may cause estimates to vary considerably from actual results.

For these reasons, estimates of the economically recoverable quantities attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties, and revenues and expenditures with respect to our reserves, may vary from estimates, and such variances may be material. These estimates thus may not accurately reflect our actual reserves.

Most of our mining operations are conducted on properties we lease. The loss of any lease could adversely affect our ability to develop the associated reserves. Because title to most of our leased properties and mineral rights is not usually verified until we have made a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property, our right to mine certain of our reserves may be adversely affected if defects in title or boundaries exist. In order to obtain leases or mining contracts to conduct mining operations on property where these defects exist, we have had to, and may in the future have to, incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves or maintain our leasehold interests in properties on which mining operations are not commenced during the term of the lease.


	*Acquisitions*

We continually seek to expand our operations and coal reserves in the regions in which we operate through acquisitions of businesses and assets, including leases of coal reserves. Acquisition transactions involve inherent risks, such as:


	•	uncertainties in assessing the value, strengths, weaknesses, contingent and other liabilities and potential profitability of acquisition or other transaction candidates;

	•	the potential loss of key personnel of an acquired business;

	•	the ability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction;

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	•	problems that could arise from the integration of the acquired business;

	•	unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction rationale; and

	•	unexpected development costs, such as those related to the development of the Little Thunder reserves, that adversely affect our profitability.

Any one or more of these factors could cause us not to realize the benefits anticipated to result from the acquisition of businesses or assets.


	*Pension and Postretirement Benefits*

We estimate our future postretirement medical and pension benefit obligations based on various assumptions, including:


	•	actuarial estimates;

	•	assumed discount rates;

	•	estimates of mine lives;

	•	expected returns on pension plan assets; and

	•	changes in health care costs.

Based on changes in our assumptions, our annual postretirement health and pension benefit costs have increased. If our assumptions relating to these benefits change in the future, our costs could further increase, which would reduce our profitability. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse effect on our financial results.

On January 1, 1998, we replaced our existing pension plans with a new cash balance pension plan. The accrued benefits of active participants under the former plans were vested as of that date and the participant’s cash balance account was credited with the present value of the participant’s earned pension benefit, payable at normal retirement age. On February 12, 2004, the United States District Court for the Southern District of Illinois affirmed its earlier ruling that the cash balance formula used in IBM’s conversion to a cash balance plan violated the age discrimination provisions under ERISA. IBM has announced that it will appeal the decision to the Seventh Circuit Court of Appeals. The Illinois District Court’s decision conflicts with the decisions of two other district courts and with proposed regulations for cash balance plans issued by Treasury and the IRS in December 2002. In addition, on February 2, 2004, the Treasury Department proposed legislation that would clarify that cash balance plans do not violate the age discrimination rules that apply to pension plans as long as they treat older workers at least as well as younger workers. The retirement account formula used for our pension plan may not meet the standard ultimately set forth in the IBM Court’s decision. Consequently, the IBM decision may have an impact on our and other companies’ cash balance pension plans. The effect of the IBM decision on our cash balance plan or our financial position has not been determined at this time.


	*Certain Contractual Arrangements*

Our affiliate, Arch Western Resources, LLC, is the owner of our reserves and mining facilities in the Powder River Basin and Western Bituminous regions of the United States. The agreement under which Arch Western was formed provides that a subsidiary of ours, as the managing member of Arch Western, generally has exclusive power and authority to conduct, manage and control the business of Arch Western. However, consent of BP p.l.c., the other member of Arch Western, would generally be required in the event that Arch Western proposes to make a distribution, incur indebtedness, sell properties or merge or consolidate with any other entity if, at such time, Arch Western has a debt

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rating less favorable than specified ratings with Moody’s Investors Service or Standard & Poor’s or fails to meet specified indebtedness and interest ratios.

In connection with our June 1, 1998 acquisition of Atlantic Richfield Company’s (“ARCO”) coal operations, we entered into an agreement under which we agreed to indemnify ARCO against specified tax liabilities in the event that these liabilities arise as a result of certain actions taken prior to June 1, 2013, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western, or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. ARCO was acquired by BP p.l.c. in 2000. Depending on the time at which any such indemnification obligation were to arise, it could impact our profitability for the period in which it arises.

Our Amended and Restated Certificate of Incorporation requires the affirmative vote of the holders of at least two-thirds of outstanding common stock voting thereon to approve a merger or consolidation and certain other fundamental actions involving or affecting control of us. Our Bylaws require the affirmative vote of at least two-thirds of the members of our Board of Directors in order to declare dividends and to authorize certain other actions.


	*Critical Accounting Policies*

Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Additionally, these estimates and judgments are discussed with our Audit Committee on a periodic basis. Actual results may differ from the estimates used under different assumptions or conditions. Note 1 to the Consolidated Financial Statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity:


	*Asset Retirement Obligations*

Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We account for the costs of our reclamation activities in accordance with the provisions of FAS 143. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon historical internal or third-party costs, depending on how the work is expected to be performed. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of FAS 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed further below:


	•	Discount rate — FAS 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of FAS 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.

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	•	Third-party margin — FAS 143 requires the measurement of an obligation to be based upon the amount a third-party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin is added to the estimated costs of these activities. This margin is estimated based upon our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than the estimates of our cost to perform the reclamation activities with internal resources. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.

On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2004, we had recorded asset retirement obligation liabilities of $199.6 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2004, we estimate that the aggregate undiscounted cost of final mine closure is approximately $354.7 million.


	*Employee Benefit Plans*

We have non-contributory defined benefit pension plans covering certain of our salaried and non-union hourly employees. Benefits are generally based on the employee’s age and compensation. We fund the plans in an amount not less than the minimum statutory funding requirements nor more than the maximum amount that can be deducted for federal income tax purposes. For the years ended December 31, 2004 and 2003, we contributed $21.6 million and $18.9 million to the plan. We account for our defined benefit plans in accordance with FAS 87, Employer’s Accounting for Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis.

The calculation of our net periodic benefit costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pension plans requires the use of a number of assumptions that we deem to be “critical accounting estimates.” Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions.


	•	The expected long-term rate of return on plan assets is an assumption reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The pension plan’s investment targets are 65% equity, 30% fixed income securities and 5% cash. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine pension expense was 8.5% and 9.0% for the years ended December 31, 2004 and 2003, respectively, which is less than the plan’s actual life-to-date returns. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into the future. The impact of lowering the expected long-term rate of return on plan assets from 8.5% to 8.0% for 2004 would have been an increase to expense of approximately $0.9 million.

	•	The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic pension cost. In estimating that rate, Statement No. 87 requires rates of return on high quality, fixed income investments. We utilize a bond portfolio model that includes

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		bonds that are rated “AA” or higher with maturities that match the expected benefit payments under the plan. The discount rates used to determine pension expense for 2004 and 2003 were 6.5% and 7.0%, respectively. The impact of lowering the discount rate from the 6.5% utilized in 2004 to an assumed 6.0% would have resulted in an approximate $1.3 million increase in expense in 2004.

The differences generated in changes in assumed discount rates and returns on plan assets are amortized into earnings over a five-year period.

For the measurement of our year-end pension obligation for 2004 (and pension expense for 2005), we maintained our long-term rate of return assumption at 8.5% and changed our discount rate to 6.0%.

We also currently provide certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for retirees who were members of the United Mine Workers of America is not contributory. Our current funding policy is to fund the cost of all postretirement medical/life insurance benefits as they are paid. We account for our other postretirement benefits in accordance with FAS 106, Employer’s Accounting for Postretirement Benefits Other Than Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis.

Various actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. These assumptions include the discount rate and the future medical cost trend rate.


	•	The discount rate assumption reflects the rates available on high-quality fixed-income debt instruments at year-end and is calculated in the same manner as discussed above for the pension plan. The discount rate used to calculate the postretirement benefit expense for 2004 and 2003 was 6.5% and 7.0%, respectively. Had the discount rate been lowered from 6.5% to 6.0% in 2004, we would have incurred additional expense of $8.4 million.

	•	Future medical trend rate represents the rate at which medical costs are expected to increase over the life of the plan. The health care cost trend rate is determined based upon our historical changes in health care costs as well as external data regarding such costs. We have implemented many effective programs that have resulted in actual increases in medical costs to fall far below the double-digit increases experienced by most companies in recent years. The postretirement expense in 2004 was based on an assumed medical inflationary rate of 8.0%, trending down in half percent increments to 5%, which represents the ultimate inflationary rate for the remainder of the plan life. This assumption was based on our then current three-year historical average of per capita increases in health care costs. If we had utilized a medical trend rate of 9.0% in 2004, we would have incurred $4.0 million of additional expense.

For the measurement of our year-end other postretirement obligation for 2004 (and other postretirement expense for 2005), we maintained our medical inflationary rate assumption at 8.0% (trending down to 5%) and changed our discount rate to 6.0%.


	*Income Taxes*

We record deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of assets and liabilities. A valuation allowance is recorded to reflect the amount of future tax benefits that management believes are not likely to be realized. In determining the appropriate valuation allowance, we take into account the level of expected future

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taxable income and available tax planning strategies. If future taxable income was lower than expected or if expected tax planning strategies were not available as anticipated, we may record additional valuation allowance through income tax expense in the period such determination was made.

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SELECTED FINANCIAL INFORMATION


		Year Ended December 31,

		2004			2003			2002			2001		2000
		(1,2,3,5)			(1,2,4,5)			(6,7,8)			(9,10,11)		(9,10,12,13)

		(In thousands, except per share data)
Statement of Operations Data:
Coal sales revenues		$	1,907,168		$	1,435,488		$	1,473,558		$	1,403,370	$	1,342,171
Income from operations			178,046			40,371			29,277			62,456		73,984
Income (loss) before cumulative effect of accounting change			113,706			20,340			(2,562	)		7,209		(12,736	)
Cumulative effect of accounting change			—			(3,654	)		—			—		—

Net income (loss)			113,706			16,686			(2,562	)		7,209		(12,736	)
Preferred stock dividends			(7,187	)		(6,589	)		—			—		—

Net income (loss) available to common shareholders		$	106,519		$	10,097		$	(2,562	)	$	7,209	$	(12,736	)

	Basic earnings (loss) per common share before cumulative effect of accounting change	$	1.91		$	.26		$	(0.05	)	$	.15	$	(0.33	)
	Diluted earnings (loss) per common share before cumulative effect of accounting change	$	1.78		$	.26		$	(0.05	)	$	.15	$	(0.33	)
	Basic earnings (loss) per common share	$	1.91		$	.19		$	(0.05	)	$	.15	$	(0.33	)
	Diluted earnings (loss) per common share	$	1.78		$	.19		$	(0.05	)	$	.15	$	(0.33	)
Balance Sheet Data:
	Total assets	$	3,256,535		$	2,387,649		$	2,182,808		$	2,203,559	$	2,232,614
	Working capital		355,803			237,007			37,799			49,813		(37,556	)
	Long-term debt, less current maturities		1,001,323			700,022			740,242			767,355		1,090,666
	Other long-term obligations		800,332			722,954			653,789			625,819		606,628
	Stockholders’ equity	$	1,079,826		$	688,035		$	534,863		$	570,742	$	219,874
Common Stock Data:
	Dividends per share	$	.2975		$	.23		$	.23		$	.23	$	.23
	Shares outstanding at year-end		62,143			53,205			52,434			52,353		38,173
Cash Flow Data:
	Cash provided by operating activities	$	146,728		$	162,361		$	176,417		$	145,661	$	135,772
	Depreciation, depletion and amortization		166,322			158,464			174,752			177,504		201,512
	Capital expenditures		292,605			132,427			137,089			123,414		115,080
	Dividend payments		24,043			17,481			12,045			11,565		8,778
Operating Data:
	Tons sold		123,060			100,634			106,691			109,455		105,519
	Tons produced		115,861			93,966			99,641			104,471		100,060
	Tons purchased from third parties		12,572			6,602			8,060			5,569		5,084

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(1)	During 2004 and 2003, the Company sold its investment in Natural Resource Partners in four separate transactions occurring in December 2003 and March, June and October 2004. The Company recognized a gain of $42.7 million in the fourth quarter of 2003 and gains of $91.3 million during 2004.

(2)	In connection with the Company’s repayment of Arch Western’s term loans in 2003, the Company recognized expenses of $8.3 million and $4.3 million in 2004 and 2003, respectively, related to the costs resulting from the termination of hedge accounting for interest rate swaps. During 2004 and 2003, the Company also recognized expenses of $0.7 million and $4.7 million, respectively, related to early debt extinguishment costs. Additionally, subsequent to the termination of hedge accounting for interest rate swaps, the Company recognized income of $13.4 million in 2003 related to changes in the market value of the swaps.

(3)	During 2004, the Company assigned its rights and obligations on a parcel of land to a third party resulting in a gain of $5.8 million. The gain is reflected in other operating income.

(4)	On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations. Implementation of this pronouncement resulted in a cumulative effect of accounting change of $3.7 million (net of tax).

(5)	As discussed in Note 15, “Stock Incentive Plan and Other Incentive Plans,” the Company recognized expenses of $5.5 million and $16.2 million under long-term incentive compensation plans in 2004 and 2003, respectively.

(6)	During the year ended December 31, 2002, the Company settled certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. The settlements resulted in a pre-tax gain of $5.6 million which was recognized in other revenues in the Consolidated Statement of Operations.

(7)	The Company recognized a pre-tax gain of $4.6 million during the year ended December 31, 2002 as a result of a workers’ compensation premium adjustment refund from the State of West Virginia. During 1998, the Company entered into the West Virginia workers’ compensation plan at one of its subsidiary operations. The subsidiary paid standard base rates until the West Virginia Division of Workers’ Compensation could determine the actual rates based on claims experience. Upon review, the Division of Workers’ Compensation refunded $4.6 million in premiums which was recognized as an adjustment to cost of coal sales in the Consolidated Statement of Operations.

(8)	During 2002, the Company filed a royalty rate reduction request with the BLM for its West Elk mine in Colorado. The BLM notified the Company that it would receive a royalty rate reduction for a specified number of tons representing a retroactive portion for the year totaling $3.3 million. The retroactive portion was recognized as a component of cost of coal sales in the Consolidated Statement of Operations. Additionally in 2002, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined representing a retroactive refund of $1.1 million. The retroactive amount was reflected in income from equity investments in the Consolidated Statement of Operations.

(9)	At the West Elk underground mine in Gunnison County, Colorado, following the detection of combustion-related gases in a portion of the mine, the Company idled its operation on January 28, 2000. On July 12, 2000, after controlling the combustion-related gases, the Company resumed production at the West Elk mine and started to ramp up to normal levels of production. The Company recognized partial pre-tax insurance settlements of $31.0 million during 2000 and a final pre-tax insurance settlement related to the event of $9.4 million during 2001.


(10)	The IRS issued a notice outlining the procedures for obtaining tax refunds on certain excise taxes paid by the industry on export sales tonnage. The notice was the result of a 1998 federal court decision that found such taxes to be unconstitutional. The Company recorded $12.7 million of

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	pre-tax income related to these excise tax recoveries during 2000. During 2001, the Company recorded an additional $4.6 million of pre-tax income resulting from additional favorable developments associated with these tax refunds.

(11)	The Company recognized a $7.4 million pre-tax gain during 2001 from a state tax credit covering prior periods.

(12)	As a result of adjustments to employee postretirement medical benefits, the Company recognized $9.8 million of pre-tax curtailment gains in 2000 resulting from previously unrecognized postretirement benefit changes which occurred in prior years.

(13)	During 2000, the Company settled certain workers’ compensation liabilities with the state of West Virginia partially offset by adjusting other workers’ compensation liabilities resulting in a net pre-tax gain of $8.3 million.

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CORPORATE GOVERNANCE AND STOCKHOLDER INFORMATION


	Common Stock

Our common stock is listed and traded on the New York Stock Exchange and also has unlisted trading privileges on the Chicago Stock Exchange. The ticker symbol is ACI. The following table sets forth for each period indicated the dividends paid per common share, the high and low sale prices of our common stock and the closing price of our common stock on the last trading day of the period indicated.

March 31,

June 30,

September 30,

December 31,

Quarter Ended

2004

Dividends per common share

.0575

.0800

High

32.89

36.99

36.93

39.00

Low

26.20

27.73

30.10

31.86

Close

31.39

36.59

35.49

35.54


	March 31,		June 30,		September 30,		December 31,
Quarter Ended	2003		2003		2003		2003

Dividends per common share	$	.0575	$	.0575	$	.0575	$	.0575
High	$	22.50	$	24.55	$	23.60	$	32.20
Low	$	16.50	$	17.18	$	19.12	$	22.06
Close	$	19.01	$	22.98	$	22.21	$	31.17

On March 1, 2005, our common stock closed at $43.50 on the New York Stock Exchange. At that date, there were 9,902 holders of record of our common stock.


	Dividends

In 2004, we paid dividends totaling $16.9 million, or $.2975 per share, on our outstanding shares of common stock. In 2003, we paid dividends totaling $12.1 million, or $.23 per share, on our outstanding shares of common stock. There is no assurance as to the amount or payment of dividends in the future because they are dependent on our future earnings, capital requirements and financial condition.


	Code of Business Conduct

We have established a Code of Business Conduct which operates as our Code of Ethics and which applies to all of our salaried employees, including our CEO, CFO and Controller. The Code of Business Conduct is available on our website at www.archcoal.com under the “Investors” section.


	Corporate Governance Guidelines

Our Board of Directors has adopted Corporate Governance Guidelines which address various matters pertaining to Director selection and duties. The Guidelines are available on our website at www.archcoal.com under the “Investors” section.


	Committee Charters

Each of the Audit, Personnel & Compensation and Nominating & Corporate Governance Committees of our Board of Directors has adopted and maintains a written Charter. Each of these Charters is available on our website at www.archcoal.com under the “Investors” section.

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	Stock Information

Questions by stockholders regarding stockholder records, stock transfers, stock certificates, dividends or other stock inquiries (other than our Dividend Reinvestment and Direct Stock Purchase Plan) should be directed to:

American Stock Transfer & Trust Company

59 Maiden Lane

Plaza Level

New York, NY 10038

Toll-free Telephone: (800) 360-4519

Web Site: www.amstock.com

Requests for information about our Dividend Reinvestment and Direct Stock Purchase and Sale Plan should be directed to:

American Stock Transfer & Trust Company

P.O. Box 922

Wall Street Station

New York, NY 10269-0560

Toll-free Telephone: (877) 390-3073

Website: www.amstock.com


	Independent Registered Public Accounting Firm

Ernst & Young LLP

190 Carondelet Plaza, Suite 1300

St. Louis, MO 63105


	Certifications

The most recent certifications by our Chief Executive and Chief Financial Officers pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 are filed as exhibits to our Form 10-K for 2004. Our Chief Executive Officer’s most recent certification to the New York Stock Exchange was submitted on May 20, 2004.


	Document Copies

Copies of the above documents and the Company’s Securities and Exchange Commission Form 10-K are available without charge. Requests for these documents, as well as inquires from stockholders and security analysis, should be directed to:

Investor Relations

Arch Coal, Inc.

One CityPlace Drive, Suite 300

St. Louis, MO 63141

(314) 994-2717

Fax: (314) 994-2878

www.archcoal.com

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EXHIBIT 21.1 SUBSIDIARIES OF THE COMPANY The following is a complete list of the direct and indirect subsidiaries of Arch Coal, Inc., a Delaware corporation: Arch Coal, Inc. Arch Energy Resources, Inc........................................... 100% Arch Reclamation Services, Inc....................................... 100% Arch Western Acquisition Corporation................................. 100% Arch Western Resources, LLC................................... 99% Arch of Wyoming, LLC.................................... 100% Arch Western Finance LLC......................... 100% Arch Western Bituminous Group LLC....................... 100% Canyon Fuel Company, LLC......................... 65% Mountain Coal Company, LLC....................... 100% Thunder Basin Coal Company, L.L.C....................... 100% Triton Coal Company, L.L.C....................... 100% Ark Land Company..................................................... 100% Western Energy Resources, Inc................................. 100% Ark Land LT, Inc.............................................. 100% Ark Land WR, Inc.............................................. 100% Allegheny Land Company............................................... 100% Arch Coal Sales Company, Inc......................................... 100% Arch Receivable Company, LLC......................................... 100% Arch Coal Terminal, Inc.............................................. 100% Ashland Terminal, Inc................................................ 100% Canyon Fuel Company, LLC............................................. 35% Catenary Coal Holdings, Inc.......................................... 100% Cumberland River Coal Company................................. 100% Lone Mountain Processing, Inc................................. 100% Coal-Mac, Inc........................................................ 100% Energy Development Co................................................ 100% Mingo Logan Coal Company............................................. 100% Mountain Gem Land, Inc............................................... 100% Mountain Mining, Inc................................................. 100% Julian Tipple, Inc............................................ 100% Mountaineer Land Company............................................. 100% P.C. Holding, Inc.................................................... 100% Paint Creek Terminals, Inc........................................... 100% Saddleback Hills Coal Company........................................ 100%

EXHIBIT 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the following Registration Statements: (1) Registration Statement (Form S-3 No. 333-120781) of Arch Coal, Inc. and in the related Prospectus, (2) Registration Statements (Form S-8 Nos. 333-30565 and 333-112536) pertaining to the Arch Coal, Inc. 1997 Stock Incentive Plan and in the related Prospectus, (3) Registration Statement (Form S-8 No. 333-32777) pertaining to the Arch Coal, Inc. Employee Thrift Plan and in the related Prospectus, (4) Registration Statement (Form S-8 No. 333-68131) pertaining to the Arch Coal, Inc. Deferred Compensation Plan and in the related Prospectus, and (5) Registration Statements (Form S-8 Nos. 333-112537 and 333-127548) pertaining to the Arch Coal, Inc. Retirement Account Plan; of our reports dated February 23, 2005, with respect to the consolidated financial statements of Arch Coal, Inc., management's assessment of the effectiveness of internal control over financial reporting, and the effectiveness of internal control over financial reporting of Arch Coal, Inc., included in this Form 10-K/A. Our audits also included the financial statement schedule of Arch Coal, Inc. listed in item 15. This schedule is the responsibility of Arch Coal, Inc.'s management. Our responsibility is to express an opinion based on our audits. In our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. ERNST & YOUNG LLP St. Louis, Missouri January 6, 2006

EXHIBIT 31.1 CERTIFICATION I, Steven F. Leer, certify that: 1. I have reviewed this annual report on Form 10-K/A of Arch Coal, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. /s/ Steven F. Leer ------------------------------------- Steven F. Leer President and Chief Executive Officer Date: January 6, 2006

EXHIBIT 31.2 CERTIFICATION I, Robert J. Messey, certify that: 1. I have reviewed this annual report on Form 10-K/A of Arch Coal, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. /s/ Robert J. Messey ------------------------------------------------- Robert J. Messey Senior Vice President and Chief Financial Officer Date: January 6, 2006

EXHIBIT 32.1 CERTIFICATION OF PERIODIC FINANCIAL REPORTS I, Steven F. Leer, President and Chief Executive Officer of Arch Coal, Inc., certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the Annual Report on Form 10-K/A for the year ended December 31, 2004 (the "Periodic Report") which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Arch Coal, Inc. /s/ Steven F. Leer ------------------------------------- Steven F. Leer President and Chief Executive Officer Date: January 6, 2006

EXHIBIT 32.2 CERTIFICATION OF PERIODIC FINANCIAL REPORTS I, Robert J. Messey, Executive Vice President and Chief Financial Officer of Arch Coal, Inc., certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) the Annual Report on Form 10-K/A for the year ended December 31, 2004 (the "Periodic Report") which this statement accompanies fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and (2) information contained in the Periodic Report fairly presents, in all material respects, the financial condition and results of operations of Arch Coal, Inc. /s/ Robert J. Messey ------------------------------------------------- Robert J. Messey Senior Vice President and Chief Financial Officer Date: January 6, 2006