UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)

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

For the Quarterly Period Ended September 30, 2004

OR

[   ] 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	43-0921172
(State or other jurisdiction of	(I.R.S. Employer Identification No.)
incorporation or organization)

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

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

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 [X] No [   ]

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

At November 1, 2004, there were 62,340,860 shares of registrant’s common stock outstanding.

INDEX

	PAGE
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Consolidated Balance Sheets as of September 30, 2004 and December 31, 2003		1
Condensed Consolidated Statements of Operations for the Three Months Ended September 30, 2004 and 2003 and the Nine Months Ended September 30, 2004 and 2003		2
Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2004 and 2003		3
Notes to Condensed Consolidated Financial Statements		4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3. Quantitative and Qualitative Disclosures About Market Risk		44
Item 4. Controls and Procedures		44
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		44
Item 2. Changes in Securities Use of Proceeds and Issues Purchasers of Equity Securities		44
Item 3. Defaults Upon Senior Securities		44
Item 4. Submission of Matters to a Vote of Security Holders		44
Item 5. Other Information		44
Item 6. Exhibits		44
Arch Coal, Inc. 1997 Stock Incentive Plan
$350,000,000 Revolving Credit Facility Amended and Restated Credit Agreement
First Amendment to Amended and Restated Credit Agreement
Steve Leer Employment Agreement
Form of Executive Officer Employment Agreement
Certification
Certification
Certification
Certification

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ARCH COAL, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(IN THOUSANDS)

	September 30,			December 31,
	2004			2003
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	4,798		$	254,541
Trade accounts receivable		217,408			118,376
Other receivables		35,087			29,897
Inventories		112,966			69,907
Prepaid royalties		9,447			4,586
Deferred income taxes		25,900			19,700
Investment in Natural Resource Partners LP, at market		5,577			—
Other		25,857			16,638
Total current assets		437,040			513,645
Property, plant and equipment, net		2,074,203			1,315,135
Other assets
Prepaid royalties		87,155			70,880
Coal supply agreements		7,803			6,397
Deferred income taxes		242,556			246,024
Equity investments		—			172,045
Other		89,370			63,523
Total other assets		426,884			558,869
Total assets	$	2,938,127		$	2,387,649
Liabilities and stockholders’ equity
Current liabilities
Accounts payable	$	151,497		$	89,975
Accrued expenses		202,347			180,314
Current portion of debt		4,441			6,349
Total current liabilities		358,285			276,638
Long-term debt		964,260			700,022
Accrued postretirement benefits other than pension		376,355			352,097
Asset retirement obligations		179,651			143,545
Accrued workers’ compensation		82,673			77,672
Other noncurrent liabilities		155,789			149,640
Total liabilities		2,117,013			1,699,614
Stockholders’ equity
Preferred stock		29			29
Common stock		556			536
Paid-in-capital		1,041,805			988,476
Retained deficit		(181,319	)		(255,936	)
Unearned compensation		(2,481	)		—
Treasury stock, at cost		(5,047	)		(5,047	)
Accumulated other comprehensive loss		(32,429	)		(40,023	)
Total stockholders’ equity		821,114			688,035
Total liabilities and stockholders’ equity	$	2,938,127		$	2,387,649

See notes to condensed consolidated financial statements.

1

ARCH COAL, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(IN THOUSANDS, EXCEPT PER SHARE DATA)

(UNAUDITED)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
Revenues
Coal sales	$	527,776		$	354,276		$	1,354,043		$	1,060,558
Costs and expenses
Cost of coal sales		491,672			346,142			1,273,564			1,052,105
Selling, general and administrative expenses		13,211			11,082			41,195			34,845
Amortization of coal supply agreements, net		(266	)		2,890			972			13,209
Other expenses		13,987			3,636			26,806			13,157
		518,604			363,750			1,342,537			1,113,316
Other operating income
Income from equity investments		1,143			5,657			10,828			28,958
Gain on sale of units of Natural Resource Partners, LP		—			—			81,851			—
Other operating income		16,020			10,343			53,928			33,428
		17,163			16,000			146,607			62,386
Income from operations		26,335			6,526			158,113			9,628
Interest expense, net:
Interest expense		(16,220	)		(13,187	)		(45,062	)		(36,407	)
Interest income		1,110			425			2,723			1,251
		(15,110	)		(12,762	)		(42,339	)		(35,156	)
Other non-operating income (expense):
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps		(2,066	)		(2,066	)		(6,199	)		(6,889	)
Other non-operating income		461			10,441			835			11,314
		(1,605	)		8,375			(5,364	)		4,425
Income (loss) before income taxes and cumulative effect of accounting change		9,620			2,139			110,410			(21,103	)
(Benefit from) provision for income taxes		(1,155	)		(8,910	)		18,545			(17,510	)
Income (loss) before cumulative effect of accounting change		10,775			11,049			91,865			(3,593	)
Cumulative effect of accounting change		—			—			—			(3,654	)
Net income (loss)		10,775			11,049			91,865			(7,247	)
Preferred stock dividends		(1,797	)		(1,797	)		(5,391	)		(4,792	)
Net income (loss) available to common shareholders	$	8,978		$	9,252		$	86,474		$	(12,039	)
Earnings per common share
Earnings (loss) before cumulative effect of accounting change	$	0.16		$	0.18		$	1.59		$	(0.16	)
Cumulative effect of accounting change		—			—			—			(0.07	)
Basic earnings (loss) per common share	$	0.16		$	0.18		$	1.59		$	(0.23	)
Earnings (loss) before cumulative effect of accounting change	$	0.16		$	0.18		$	1.48		$	(0.16	)
Cumulative effect of accounting change		—			—			—			(0.07	)
Diluted earnings (loss) per common share	$	0.16		$	0.18		$	1.48		$	(0.23	)
Basic weighted average shares outstanding		54,874			52,520			54,431			52,441
Diluted weighted average shares outstanding		55,838			52,824			62,262			52,441
Dividends declared per share	$	0.0800		$	0.0575		$	0.2175		$	0.1725

See notes to condensed consolidated financial statements.

2

ARCH COAL, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(IN THOUSANDS)

(UNAUDITED)

	Nine Months Ended
	September 30,
	2004			2003
Operating activities
Net income (loss)	$	91,865		$	(7,247	)
Adjustments to reconcile to cash provided by operating activities:
Depreciation, depletion and amortization		115,677			118,142
Prepaid royalties expensed		10,923			10,206
Accretion on asset retirement obligations		9,198			10,148
Net gain on disposition of assets		(748	)		(3,174	)
Gain on sale of units of Natural Resource Partners, LP		(81,851	)		—
Mark-to-market adjustment for investment in Natural Resource Partners, LP		(8,393	)		—
Income from equity investments		(10,828	)		(28,958	)
Net distributions from equity investments		17,678			32,291
Cumulative effect of accounting change		—			3,654
Other nonoperating expense (income)		5,364			(4,425	)
Changes in:
Receivables		(73,997	)		22,004
Inventories		(5,324	)		(9,446	)
Accounts payable and accrued expenses		(19,889	)		(8,146	)
Income taxes		(860	)		(18,868	)
Accrued postretirement benefits other than pension		13,950			20,381
Asset retirement obligations		(7,525	)		(12,771	)
Accrued workers’ compensation benefits		(1,030	)		(958	)
Other		(14,404	)		(8,577	)
Cash provided by operating activities		39,806			114,256
Investing activities
Payments for acquisitions, net of cash acquired		(381,905	)		—
Capital expenditures		(243,566	)		(91,652	)
Proceeds from sale of units of Natural Resource Partners, LP		105,365			—
Proceeds from dispositions of capital assets		1,279			3,325
Proceeds from coal supply agreement		—			52,548
Additions to prepaid royalties		(27,171	)		(25,768	)
Cash used in investing activities		(545,998	)		(61,547	)
Financing activities
Net borrowings (payments) on revolver and lines of credit		250,426			(72,202	)
Payments on long-term debt		(6,300	)		(675,000	)
Proceeds from issuance of senior notes		—			700,000
Deferred financing costs		(1,160	)		(18,246	)
Dividends paid		(17,249	)		(12,647	)
Proceeds from sale of preferred stock		—			139,024
Proceeds from sale of common stock		30,732			2,356
Cash provided by financing activities		256,449			63,285
(Decrease) increase in cash and cash equivalents		(249,743	)		115,994
Cash and cash equivalents, beginning of period		254,541			9,557
Cash and cash equivalents, end of period	$	4,798		$	125,551

See notes to condensed consolidated financial statements.

3

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2004

(UNAUDITED)

Note A — General

The accompanying unaudited Condensed Consolidated Financial Statements have been prepared in accordance with generally accepted accounting principles for interim financial reporting and Securities and Exchange Commission regulations, but are subject to any year-end adjustments that may be necessary. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Results of operations for the period ended September 30, 2004 are not necessarily indicative of results to be expected for the year ending December 31, 2004. These financial statements should be read in conjunction with the audited financial statements and related notes thereto as of and for the year ended December 31, 2003 included in Arch Coal, Inc.’s Annual Report on Form 10-K as filed with the Securities and Exchange Commission.

Arch Coal, Inc. (the “Company”) is engaged in the production of steam and metallurgical coal from surface and deep mines throughout the United States, for sale to electric generation, industrial and export markets. The Company’s mines are primarily located in the Powder River Basin, Central Appalachia and Western Bituminous region 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 p.l.c. 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 Condensed 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 Condensed Consolidated Statements of Operations as income from equity investments (see additional discussion in Note E — “Equity Investments”). On July 31, 2004, the Company acquired the remaining 35% of Canyon Fuel. See Note B — “Business Combinations” for further discussion.

Note B — 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 $112.0 million was funded with cash of $90.0 million and a five-year, $22.0 million non-interest bearing note. Net of cash acquired, the fair value of the transaction totaled $98.4 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 condensed 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 prior to year-end.

4

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		1,696
Property, plant, equipment and mine development		116,222
Accounts payable and accrued expenses		(10,379	)
Coal supply agreements		(22,206	)
Other noncurrent assets and liabilities, net		(5,554	)
Total purchase price, net of cash received of $9.8 million	$	98,396

Amounts preliminarily allocated to coal supply agreements noted in the table above represent the liability established for 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 Condensed 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 $376.0 million, including transaction costs and subject to 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 $72.9 million. The total purchase price, including related costs and fees, of $376.0 million was funded with cash of $254.0 million, 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. The purchase results in the integration of the North Rochelle mine with the Company’s existing Black Thunder mine in the Powder River Basin. The North Rochelle mine produced an estimated 23.9 million tons of coal in 2003 and its reserve base totaled an estimated 226.0 million tons of super-compliance coal at December 31, 2003.

The preliminary purchase accounting allocations related to the acquisition have been recorded in the accompanying condensed 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 prior to year-end.

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	$	14,450
Materials and supplies		4,332
Coal inventory		4,874
Other current assets		1,283
Property, plant, equipment and mine development		367,946
Coal supply agreements		3,975
Accounts payable and accrued expenses		(74,131	)
Other noncurrent assets and liabilities, net		(20,004	)
Total purchase price, net of cash received of $0.4 million	$	302,725

Amounts preliminarily allocated to coal supply agreements noted in the table above represent the value attributed to 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.

Included in the amounts allocated to accounts payable and accrued expenses noted in the table above are $4.8 million of liabilities incurred in connection with terminating Vulcan employees upon acquisition. Upon acquisition, the

5

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 will be paid by the end of 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 Company and the operations acquired from Canyon Fuel and Triton constituted a single entity during those periods:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2004		2003		2004		2003
	(in thousands, except per share data)
Revenues:
As reported	$	527,776	$	354,276	$	1,354,043	$	1,060,558
Pro forma		570,896		463,045		1,605,816		1,389,909
Income (loss) before accounting changes:
As reported		10,775		11,049		91,865		(3,593	)
Pro forma		4,184		3,458		78,950		(9,725	)
Net income (loss) available to common shareholders:
As reported		8,978		9,252		86,474		(12,039	)
Pro forma		2,387		1,661		73,559		(24,979	)
Basic earnings (loss) per share:
As reported		0.16		0.18		1.59		(0.23	)
Pro forma		0.04		0.03		1.35		(0.48	)
Diluted earnings (loss) per share:
As reported		0.16		0.18		1.48		(0.23	)
Pro forma		0.04		0.03		1.18		(0.48	)

Note C — Coal Reserve Lease

On September 22, 2004, the U.S. Bureau of Land Management (“BLM”) accepted the Company’s bid of $611.0 million for a 5,084-acre federal coal lease known as Little Thunder, which is adjacent to the Company’s Black Thunder mine in the Powder River Basin. According to the BLM, the lease contains approximately 719.0 million mineable tons of high Btu, low-sulfur coal. The Company paid the first of five annual payments of $122.2 million under the lease using $22.2 million of cash on hand and $100.0 million borrowed under its revolving credit facility.

Note D — Adoption of FAS 143

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, that cost should 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.

The cumulative effect of the change on prior years 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 nine months ended September 30, 2003.

6

The following table describes the changes to the Company’s asset retirement obligation for the nine months ended September 30, 2004 and 2003:

	2004			2003
	(in thousands)
Balance at January 1 (including current portion)	$	162,731		$	125,440
Impact of adoption		—			41,198
Accretion expense		9,198			10,148
Additions resulting from acquisition property additions		39,459			1,301
Liabilities settled		(7,525	)		(13,567	)
Balance at September 30		203,863			164,520
Current portion included in accrued expenses		(24,212	)		(20,408	)
Long-term liability	$	179,651		$	144,112

Note E — Stock-Based Compensation

These interim financial statements include the disclosure requirements of Statement of Financial Accounting Standards 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, Accounting for Stock Issued to Employees (“APB 25”), 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 required by FAS 123, the Company’s net income (loss) available to common shareholders and earnings (loss) per common share would have been changed to the pro forma amounts as indicated in the following table:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2004		2003		2004		2003
	(in thousands, except per share data)
As reported
Net income (loss) available to common shareholders	$	8,978	$	9,252	$	86,474	$	(12,039	)
Basic earnings (loss) per share		0.16		0.18		1.59		(0.23	)
Diluted earnings (loss) per share		0.16		0.18		1.48		(0.23	)
Pro forma
Net income (loss) available to common shareholders	$	7,644	$	6,953	$	82,342	$	(18,988	)
Basic earnings (loss) per share		0.14		0.13		1.51		(0.36	)
Diluted earnings (loss) per share		0.14		0.13		1.41		(0.36	)

7

Note F — Equity Investments

As of September 30, 2004, the Company no longer holds any 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:

	September 30,		December 31,
	2004		2003
	(in thousands)
Equity investments:
Investment in Canyon Fuel	$	—	$	146,180
Investment in NRP		—		25,865
Equity investments as reported in the Condensed Consolidated Balance Sheets	$	—	$	172,045

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2004		2003		2004		2003
	(in thousands)
Income from equity investments:
Income from investment in Canyon Fuel	$	1,143	$	1,392	$	8,410	$	17,596
Income from NRP		—		4,265		2,418		11,362
Income from equity investments as reported in the Condensed Consolidated Statements of Operations	$	1,143	$	5,657	$	10,828	$	28,958

Investment in Canyon Fuel

The following table presents unaudited summarized financial information for Canyon Fuel:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
Condensed Income Statement Information	2004		2003			2004		2003
	(in thousands)
Revenues	$	20,186	$	57,751		$	142,893	$	179,234
Total costs and expenses		18,791		57,879			133,546		161,015
Net income (loss) before cumulative effect of accounting change	$	1,395	$	(128	)	$	9,347	$	18,219
65% of Canyon Fuel net income (loss) before cumulative effect of accounting change	$	906	$	(83	)	$	6,075	$	11,842
Effect of purchase adjustments		237		1,475			2,335		5,754
Arch Coal’s income from its equity investment in Canyon Fuel	$	1,143	$	1,392		$	8,410	$	17,596

Through July 31, 2004, the Company’s income from its equity investment in Canyon Fuel represents 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.

8

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 Condensed Consolidated Statements of Operations.

Investment in NRP

During the nine months ended September 30, 2004, the Company sold the majority of its remaining limited partnership units of NRP for proceeds of approximately $105.4 million. The sales resulted in a gain of $81.9 million. Subsequent to the sales, the Company’s remaining investment in NRP totals approximately 139 thousand units, representing 0.6% of NRP’s total equity interests. At this level of ownership, the investment is no longer accounted for on the equity method, but is accounted for in accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities (“FAS 115”). FAS 115 requires the investment to be marked to its market value at each reporting period. Because it is the Company’s intention to sell its remaining units, the units have been classified as trading securities. Changes in the value of trading securities are recorded as income or expense in the period of change. During the three and nine months ended September 30, 2004, the Company recorded a mark-to-market adjustment for its investment in NRP units as a gain of $0.3 million and $8.4 million, respectively. The mark-to-market adjustments are recorded as a component of other operating income in the accompanying Condensed Consolidated Statements of Operations. At September 30, 2004, the Company has classified its remaining investment in NRP as a current asset based on management’s intention to sell the investment within the next year.

Subsequent to September 30, 2004, the Company sold its remaining interest in NRP for proceeds of $6.1 million.

Prior to the March 2004 sale of limited partnership units, the Company recorded income under the equity method of accounting for its investment in NRP on a one-month lag. Equity income for the nine months ended September 30, 2004 of $2.4 million is for the period from December 2003 through February 2004.

Note G — 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 years of service 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.

Components of Net Periodic Benefit Cost

The following table details the components of pension and other postretirement benefit costs.

							Other postretirement
	Pension benefits						benefits
Three Months Ended September 30,	2004			2003			2004		2003
	(In thousands)
Service cost	$	2,396		$	2,042		$	1,089	$	813
Interest cost		3,009			2,924			7,461		7,565
Expected return on plan assets*		(3,698	)		(3,421	)		—		—
Other amortization and deferral		1,227			304			4,159		5,636
	$	2,934		$	1,849		$	12,709	$	14,014

9

							Other postretirement
	Pension benefits						Benefits
Nine Months Ended September 30,	2004			2003			2004		2003
	(In thousands)
Service cost	$	6,311		$	6,123		$	2,989	$	2,823
Interest cost		8,616			8,768			22,185		23,561
Expected return on plan assets*		(10,672	)		(10,263	)		—		—
Other amortization and deferral		3,541			919			12,539		15,680
	$	7,796		$	5,547		$	37,713	$	42,064

* The Company does not fund its other postretirement liabilities.

Employer Contributions

The Company previously disclosed in its financial statements for the year ended December 31, 2003, that it expected to contribute $13 million to its pension plan in 2004. During the nine months ended September 30, 2004, the Company contributed 500,000 shares of its common stock to its pension plan (the pension plan subsequently sold the shares on the open market). The market value of the common stock on the date of contribution was $30.88 per share (resulting in a total contribution of $15.4 million). The Company presently does not anticipate contributing additional amounts to the pension plan in 2004.

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 nine months ending September 30, 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 implementation are expected to be $18.1 million less than that previously anticipated. Results for the nine months ending September 30, 2004 include $13.6 million of this total.

Note H — Other Comprehensive Income

Other comprehensive income items under FAS 130, Reporting Comprehensive Income, are transactions recorded in stockholders’ equity during the year, excluding net income and transactions with stockholders. The following table presents comprehensive income:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2004		2003		2004		2003
	(in thousands)
Net income (loss)	$	10,775	$	11,049	$	91,865	$	(7,247	)
Other comprehensive income (loss) net of income tax (net of amounts reclassified to earnings)		1,904		2,601		7,594		(3,212	)
Total comprehensive income (loss)	$	12,679	$	13,650	$	99,459	$	(10,459	)

Other comprehensive income for the three and nine months ended September 30, 2004 and three months ended September 30, 2003 consists primarily of the reclassification of previously deferred mark-to-market losses from other comprehensive income to net income. Other comprehensive loss for the nine months ended September 30, 2003 consists of mark-to-market adjustments related to the Company’s financial derivatives positions for the period when those positions were deemed to be effective hedges and the reclassification of previously deferred mark-to-market losses from other comprehensive income to net income.

10

Note I — Inventories

Inventories consist of the following:

	September 30,		December 31,
	2004		2003
	(in thousands)
Coal	$	68,271	$	38,249
Repair parts and supplies		44,695		31,658
	$	112,966	$	69,907

Note J — Debt

Debt consists of the following:

	September 30,		December 31,
	2004		2003
	(in thousands)
Indebtedness to banks under lines of credit	$	—	$	—
Indebtedness to banks under revolving credit agreement, expiring April 18, 2007 (weighted average rate September 30, 2004 - 4.07%)		149,000		—
Variable rate term loan due April 2007 (weighted average rate at September 30, 2004 - 4.59%)		100,000		—
6.75% senior notes due July 1, 2013		700,000		700,000
Promissory note		18,204		—
Other		1,497		6,371
		968,701		706,371
Less current portion		4,441		6,349
Long-term debt	$	964,260	$	700,022

The Company has a $350.0 million revolving credit facility that matures on April 18, 2007. 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 ownership interests in substantially all of its subsidiaries, except its ownership interests in Arch Western and its subsidiaries. At September 30, 2004, the Company had $68.9 million in letters of credit outstanding which, when combined with the $149.0 outstanding borrowings under the revolver, resulted in $132.1 million of unused borrowings under the revolver. Financial covenant requirements may restrict the amount of unused capacity available to the Company for borrowings and letters of credit.

On August 20, 2004, Arch Western borrowed $100.0 million under its term loan facility, which was established on September 19, 2003. Under the facility, the loan is due in quarterly installments from October 2004 through April 2007.

On July 31, 2004, the Company issued a five year, $22.0 million non-interest bearing note to help fund the Canyon Fuel acquisition. The promissory note is payable in quarterly installments beginning with a payment of $1.0 million in October 2004 and ending in July 2009. The note has been discounted to its present value of $18.2 million using a rate of 7.0%.

On June 25, 2003, Arch Western Finance, LLC, a subsidiary of Arch Western, completed the offering of $700 million of senior notes and utilized the proceeds of the offering to repay Arch Western’s existing term loans. The senior notes bear a fixed rate of interest of 6.75% and are due in full on July 1, 2013. 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 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 investments.

11

Note K — Contingencies

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 these claims, to the extent not previously provided for, will not have a material adverse effect on the consolidated financial position, results of operations or liquidity of the Company.

Note L — Transactions or Events Affecting Comparability of Reported Results

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

During the first nine months of 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 nine months ended September 30, 2004. The Company’s share of these costs totals $2.1 million, and is reflected in income from equity investments in the Condensed Consolidated Statements of Operations.

During the nine months ended September 30, 2004, the Office of Surface Mining completed an audit of certain of the Company’s federal reclamation fee filings for the period from 1998 through 2003. The audit resulted in the Company being assessed additional fees of $1.3 million and interest of $0.2 million. The additional fees have been recorded as a component of cost of coal sales in the accompanying Condensed Consolidated Statements of Operations, while the interest portion has been reflected as interest expense.

On June 25, 2003, Arch Western repaid its term loans with the proceeds from the offering of senior notes. The Company 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 three and nine months ending September 30, 2004, the Company recognized $2.1 million and $6.2 million, respectively, of expense related to the amortization of previously deferred mark-to-market adjustments. For the nine months ended September 30, 2003, the Company recognized $2.1 million of expense related to amortization of previously deferred mark-to-market adjustments and $4.8 million of expense related to early debt extinguishment costs. Additionally, subsequent to the repayment of the term loans, changes in market value of the interest rate swaps are recognized as income or expense. During the quarter and nine months ended September 30, 2003, the Company recognized income of $10.6 million and $11.6 million, respectively from changes in the market value of the swaps. These amounts are included in the line item “Other non-operating income” in the accompanying Condensed Consolidated Statements of Operations.

During the nine months ended September 30, 2003, the Company was notified by the State of Wyoming of a favorable ruling as it relates 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 three and nine months ended September 30, 2003 was a loss of $0.8 million and a gain of $2.5 million, respectively, which is reflected in cost of coal sales in the accompanying Condensed Consolidated Statements of Operations.

During the nine months ending September 30, 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 office and Central Appalachia mining operations, resulting in severance and related expenses of $2.6 million during the nine months ended September 30, 2003. Of the expenses 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.

During the three and nine months ended September 30, 2003, the Company recognized gains of $1.4 million and $2.9 million, respectively from sales of land at one of its idle properties. These amounts have been recorded as other operating income in the accompanying Condensed Consolidated Statements of Operations.

12

During the nine months ended September 30, 2003, the Company received $1.4 million from a customer that did not meet its 2002 contractual purchase requirements. This amount has been recorded as other operating income in the accompanying Condensed Consolidated Statements of Operations.

During the three and nine months ended September 30, 2003, the Company recognized income of $1.6 million resulting from the collection of receivables which had previously been estimated to be uncollectible and had been fully reserved in prior periods.

Note M — Earnings (Loss) per Share

The following tables sets forth the computation of basic and diluted earnings (loss) per common share from continuing operations.

	Three months ended September 30, 2004
	Numerator			Denominator		Per Share
	(Income)			(Shares)		Amount
Basic EPS:
Net income	$	10,775			54,874	$	0.19
Preferred stock dividends		(1,797	)				(0.03	)
Basic income available to common shareholders	$	8,978				$	0.16
Effect of dilutive securities:
Effect of common stock equivalents arising from stock options and restricted stock grants		—			964
Diluted EPS:
Diluted income available to common shareholders	$	8,978			55,838	$	0.16

	Three months ended September 30, 2003
	Numerator			Denominator		Per Share
	(Income)			(Shares)		Amount
Basic EPS:
Net income	$	11,049			52,520	$	0.21
Preferred stock dividends		(1,797	)				(0.03	)
Basic income available to common shareholders	$	9,252				$	0.18
Effect of dilutive securities: Effect of common stock equivalents arising from stock options and restricted stock grants		—			304
Diluted EPS:
Diluted income available to common shareholders	$	9,252			52,824	$	0.18

	Nine months ended September 30, 2004
	Numerator			Denominator		Per Share
	(Income)			(Shares)		Amount
Basic EPS:
Net income	$	91,865			54,431	$	1.69
Preferred stock dividends		(5,391	)				(0.10	)
Basic income available to common shareholders	$	86,474				$	1.59
Effect of dilutive securities:
Effect of common stock equivalents arising from stock options and restricted stock grants		—			935
Effect of common stock equivalents arising from convertible preferred stock		5,391			6,896
Diluted EPS:
Diluted income available to common shareholders	$	91,865			62,262	$	1.48

	Nine months ended September 30, 2003
Basic and diluted EPS:
Net loss before cumulative effect of accounting change	$	(3,593	)	52,441	$	(0.07	)
Cumulative effect of accounting change		(3,654	)			(0.07	)
Preferred stock dividends		(4,792	)			(0.09	)
Net loss available to common shareholders	$	(12,039	)		$	(0.23	)

13

For the nine month period ending September 30, 2003, employee stock options did not have a dilutive impact because the Company incurred losses in those periods. The Company’s Perpetual Cumulative Convertible Preferred Stock was not considered in the calculation of the number of diluted shares outstanding at September 30, 2003 because the assumed conversion of the preferred stock would have been antidilutive.

Note N — Guarantees

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 September 30, 2004 (such amount is included in other noncurrent liabilities). Future payments for fixed operating costs and debt service are estimated to approximate $2.4 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 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. Depending on the time at which any such indemnification obligation were to arise, it could have a material adverse effect on the business, results of operations and financial condition of the Company.

Note O — Segment Information

The Company produces steam and metallurgical coal from surface and deep mines for sale in electric generation, 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 (which include all mining costs but exclude 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 15 underground mines and eight surface mines. The Company’s Western Bituminous operations are located in Colorado, southern Wyoming 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 three and nine months ending September 30, 2004 and 2003 are presented below. Results for the operating segments include all direct costs of mining. Corporate, Other and Eliminations includes corporate overhead, land management, other support functions, and the elimination of intercompany transactions.

14

Three months ending September 30, 2004

							Corporate,
							Other and
(Amounts in thousands, except per ton amounts)	PRB		CAPP		WBIT		Eliminations			Consolidated
Coal sales	$	160,495	$	303,133	$	64,148	$	—		$	527,776
Income from equity investments		—		—		1,143		—			1,143
Income from operations		12,149		20,038		5,889		(11,741	)		26,335
Total assets		1,129,833		2,066,842		1,373,331		(1,631,879	)		2,938,127
Depreciation, depletion and amortization		21,145		15,224		6,850		273			43,492
Capital expenditures		13,692		28,375		8,326		124,041			174,434
Operating cost per ton		6.46		35.45		15.30		—			—

Three months ending September 30, 2003

								Corporate,
								Other and
(Amounts in thousands, except per ton amounts)	PRB		CAPP			WBIT		Eliminations			Consolidated
Coal sales	$	103,401	$	223,280		$	27,595	$	—		$	354,276
Income from equity investments		—		—			1,392		4,265			5,657
Income (loss) from operations		12,391		(5,969	)		3,805		(3,701	)		6,526
Total assets		966,234		1,970,913			934,177		(1,559,982	)		2,311,342
Equity investments		—		—			156,722		70,552			227,274
Depreciation, depletion and amortization		14,245		19,171			4,973		656			39,045
Capital expenditures		8,985		6,636			3,209		5,881			24,711
Operating cost per ton		5.59		30.00			14.58		—			—

Nine months ending September 30, 2004

							Corporate,
							Other and
(Amounts in thousands, except per ton amounts)	PRB		CAPP		WBIT		Eliminations		Consolidated
Coal sales	$	397,951	$	837,901	$	118,191	$	—	$	1,354,043
Income from equity investments		—		—		8,410		2,418		10,828
Income from operations		42,910		39,818		17,346		58,039		158,113
Depreciation, depletion and amortization		52,651		47,090		14,783		1,153		115,677
Capital expenditures		41,275		62,541		11,356		128,394		243,566
Operating cost per ton		6.19		34.20		15.82		—		—

Nine months ending September 30, 2003

								Corporate,
								Other and
(Amounts in thousands, except per ton amounts)	PRB		CAPP			WBIT		Eliminations			Consolidated
Coal sales	$	297,279	$	685,283		$	77,996	$	—		$	1,060,558
Income from equity investments		—		—			17,596		11,362			28,958
Income (loss) from operations		36,695		(30,484	)		20,156		(16,739	)		9,628
Depreciation, depletion and amortization		40,769		60,650			14,661		2,062			118,142
Capital expenditures		16,528		29,271			5,867		39,986			91,652
Operating cost per ton		5.58		30.69			15.34		—			—

15

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2004			2003			2004			2003
	(in thousands)						(in thousands)
Total segment income from operations	$	26,335		$	6,526		$	158,113		$	9,628
Interest expense		(16,220	)		(13,187	)		(45,062	)		(36,407	)
Interest income		1,110			425			2,723			1,251
Other non-operating income (expense)		(1,605	)		8,375			(5,364	)		4,425
Income (loss) before income taxes and cumulative effect of accounting change	$	9,620		$	2,139		$	110,410		$	(21,103	)

Note P — Reclassifications

Certain amounts in the 2003 financial statements have been reclassified to conform with the classifications in the 2004 financial statements with no effect on previously reported net income (loss) or members’ equity.

Note Q — Subsequent Event

In October 2004, the Company completed the debt and equity offerings described below.

Debt Offering

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 proceeds from the issuance, net of the underwriters’ discount and related expenses, were $256.8 million. The debt offering was issued under an indenture dated June 25, 2003, to which the Company previously issued $700.0 million of 6.75% Senior Notes due 2013.

Equity Offering

On October 28, 2004, the Company completed a public offering of 7,187,500 common shares at $33.85 per share, including the underwriters’ over-allotment option. The proceeds from the offering, net of the underwriters’ discount and related expenses, were $230.6 million. The equity offering was made under the Company’s Universal Shelf Registration Statement on Form S-3.

Use of Proceeds

Net proceeds from the two offerings will be used primarily to repay Arch Western’s $100.0 million term loan and borrowings under the Company’s revolving credit facility. The balance of the net proceeds will be used for general corporate purposes, including the development of the Mountain Laurel mine complex in the Central Appalachia Basin.

16

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS

In this quarterly 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:

o Due to the significant amount of our debt, a downturn in economic or industry conditions could materially affect our ability to meet our future financial and liquidity obligations.

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

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

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

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

o Unanticipated mining conditions may cause profitability to fluctuate.

o 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.

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

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

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

o An unavailability of coal reserves would cause our profitability to decline.

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

o 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.

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

o All acquisitions involve a number of inherent risks, any of which could cause us not to realize the benefits anticipated to result.

o Changes in our credit ratings could adversely affect our costs and expenses.

o Some of our agreements impose significant potential indemnification obligations on us.

17

o Our expenditures for postretirement medical and pension benefits increased in 2003 and could further increase in the future.

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

o 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 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.

RESULTS OF OPERATIONS

Acquisitions

On August 20, 2004, we 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 $376.0 million, including transaction costs and subject to working capital adjustments. Immediately following the consummation of the transaction, we completed the agreement to sell the smaller of Triton’s two mines, Buckskin, to Kiewit Mining Acquisition Company (“Kiewit”), at a net sales price of $72.9 million. After completion of these transactions, we began the integration of the larger of Triton’s two mines, North Rochelle, with our existing Black Thunder mine in the Southern Powder River Basin.

On July 31, 2004, we purchased the remaining 35% interest in Canyon Fuel Company, LLC (“Canyon Fuel”) from ITOCHU Corporation for a purchase price of $112.0 million, including related costs and fees. Net of cash acquired, the fair value of the transaction totaled $98.4 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.

Items Affecting Comparability of Reported Results

The comparison of our operating results for the quarter-to-date and year-to-date periods ending September 30, 2004 and 2003 are affected by the following items:

	Three months ended					Nine months ended
	September 30,					September 30,
(Dollar amounts in millions)	2004		2003			2004			2003
Operating Income
Gain on sale of NRP units	$	—	$	—		$	81.9		$	—
Black lung excise tax refund		2.1					2.1
Mark-to-market adjustment for NRP units		0.3		—			8.4			—
Severance costs - Skyline Mine		—		—			(2.1	)		—
Reclamation fee assessment		—		—			(1.3	)		—
Severance tax recoveries		—		(0.8	)		—			2.5
Reduction in workforce		—		—			—			(2.6	)
Gain from land sale		—		1.4			—			2.9
Gain from coal sales contract shortfall		—		—			—			1.4
Reversal of accounts receivable allowance		—		1.6			—			1.6
Net impact on operating income		2.4		2.2			89.0			5.8

18

	Three months ended						Nine months ended
	September 30,						September 30,
(Dollar amounts in millions)	2004			2003			2004			2003
Other
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps		(2.1	)		(2.1	)		(6.2	)		(6.9	)
Mark-to-market adjustments on interest rate swaps that no longer qualify as hedges		0.4			10.6			0.7			11.6
Black lung excise tax refund — interest portion		0.7			—			0.7			—
Reclamation fee assessment — interest portion		—			—			(0.2	)		—
Net impact on pre-tax income	$	1.4		$	10.7		$	84.0		$	10.5

Gain on sale of NRP units

During the nine months ended September 30, 2004, we sold the majority of our remaining limited partnership units of Natural Resource Partners, LP (“NRP”) for proceeds of approximately $105.4 million. The sales resulted in a gain of $81.9 million.

Black lung excise tax refund

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

Mark-to-market adjustment for NRP units

Subsequent to the sale of NRP units described above, our remaining investment in NRP totals approximately 139 thousand units at September 30, 2004, representing 0.6% of NRP’s total equity interests. At this level of ownership, the investment is no longer accounted for on the equity method, but is accounted for in accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities (“FAS 115”). FAS 115 requires the investment to be marked to its market value at each reporting period. Because it is our intention to sell the remaining units, the units have been classified as trading securities. Changes in the value of trading securities are recorded as income or expense in the period of change. During the three and nine months ended September 30, 2004, we recorded mark-to-market adjustments for our investment in NRP units as a gain of $0.3 million and $8.4 million, respectively. The mark-to-market adjustments are recorded as a component of other operating income.

Severance costs — Skyline Mine

During the first nine months of 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 nine months ended September 30, 2004. Our share of these costs totals $2.1 million and is reflected in income from equity investments.

Reclamation fee assessment

During the nine months ended September 30, 2004, the Office of Surface Mining completed an audit of certain of our federal reclamation fee filings for the period from 1998 through 2003. The audit resulted in an assessment of additional fees of $1.3 million and interest of $0.2 million. The additional fees have been recorded as a component of cost of coal sales in the accompanying Condensed Consolidated Statements of Operations, while the interest portion has been reflected as interest expense.

19

Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps

On June 25, 2003, we repaid the term loan of our subsidiary, Arch Western, with the proceeds from the offering of senior notes. Prior to the repayment, 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 three and nine months ending September 30, 2004, the Company recognized $2.1 million and $6.2 million, respectively, of expense related to the amortization of previously deferred mark-to-market adjustments. For the nine months ending September 30, 2003, the Company recognized $2.1 million of expense related to the amortization of previously deferred mark-to-market adjustments and $4.8 million of expense related to early debt extinguishment costs.

Severance Tax Recoveries

During the nine months ended September 30, 2003, the Company was notified by the State of Wyoming of a favorable ruling as it relates 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.

Reduction in Workforce

During the nine months ending September 30, 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 office and Central Appalachia mining operations, resulting in severance and related expenses of $2.6 million during the nine months ended September 30, 2003. Of the expenses 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.

Gain from Land Sale

During the three and nine months ended September 30, 2003, the Company recognized gains of $1.4 million and $2.9 million, respectively from sales of land at one of its idle properties. These amounts have been recorded as other operating income in the accompanying Condensed Consolidated Statements of Operations.

Gain from Contract Shortfall

During the first nine months of 2003, the Company received $1.4 million from a customer that did not meet its 2002 contractual purchase requirements. This amount has been reflected as a component of other operating income.

Reversal of Accounts Receivable Allowance

During the three and nine months ended September 30, 2003, the Company recognized income resulting from the collection of receivables which had previously been estimated to be uncollectible and had been fully reserved in prior periods.

Mark-To-Market Adjustments

The Company is 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 FASB Statement No. 133. As such, changes in the market value of the swap agreements are recorded as a component of income. For the three and nine months ending September 30, 2004, the Company recognized $0.4 million and $0.7 million, respectively, of income related to the mark-to-market adjustments on these swap agreements. For the nine months ending September 30, 2003 the Company recognized $11.6 million of income related to the mark-to-market adjustments on these swap agreements.

20

Three Months Ended September 30, 2004, Compared to Three Months Ended September 30, 2003

Revenues

	Three Months Ended
	September 30,				Increase
(Amounts in thousands, except per ton amounts)	2004		2003		$		%
Coal sales	$	527,776	$	354,276	$	173,500		49.0	%
Tons sold		33,807		25,252		8,555		33.9	%
Coal sales realization per ton	$	15.61	$	14.03	$	1.58		11.3	%

Coal sales. The increase in coal sales resulted from the combination of higher pricing, increased volumes and the acquisitions discussed above.

Sales volumes increased in all three of our operating regions, as volumes in the Powder River Basin and Western Bituminous region benefited from the acquisitions that were completed during the quarter. Powder River Basin volumes increased 39.9% and Western Bituminous volumes increased 95.8%.

Per ton realizations also increased in all three regions due primarily to higher contract prices. In the Powder River Basin, per ton realization increased 11.0%, including above-market pricing on certain contracts acquired in the Triton acquisition. The Central Appalachia Basin experienced the largest per ton realization increase (29.2% increase), as the region benefited not only from the higher contract prices, but also from a strong spot market and a higher percentage of metallurgical coal sales. The Western Bituminous region’s per ton realization increased 18.8%. In addition to higher contract pricing, per ton realizations in the Western Bituminous Basin 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 13.5% over the prior year’s comparable quarter.

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. Volumes from the Powder River Basin (which have the lowest average realization) increased to approximately 67% of all tons sold in the quarter ended September 30, 2004 from 64% of tons sold in the quarter ended September 30, 2003.

Costs and Expenses

	Three Months Ended
	September 30,					Increase (Decrease)
(Amounts in thousands, except per ton amounts)	2004			2003		$			%
Cost of coal sales	$	491,672		$	346,142	$	145,530			42.0	%
Selling, general and administrative expenses		13,211			11,082		2,129			19.2	%
Amortization of coal supply agreements		(266	)		2,890		(3,156	)		(109.2	%)
Other expenses		13,987			3,636		10,351			284.7	%
	$	518,604		$	363,750	$	154,854			42.6	%
Cost of coal sales per ton sold	$	14.54		$	13.71	$	0.83			6.1	%

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 $18.8 million.

• Poor rail performance continued during the third quarter of 2004, resulting in missed shipments and disruptions in production.

• Our Central Appalachia operations incurred higher costs related to additional preparation necessary for coal sold in metallurgical markets.

21

• The cost of purchased coal increased $43.2 million, reflecting a combination of increased purchase volumes and higher spot market prices that were prevalent during the third quarter of 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 $1.9 million and $6.5 million, respectively.

• Repairs and maintenance costs and depreciation, depletion and amortization charges increased $13.8 million and $7.9 million, respectively, due partially to the property additions resulting from the acquisitions made during the third quarter of 2004.

On a per-ton basis, operating costs (defined as including all mining costs but excluding pass-through transportation costs) at our Powder River Basin operations increased to $6.46 in the third quarter of 2004 from $5.59 in the third quarter of 2003. The increase in per ton costs in the Powder River Basin is due primarily to increased cost of purchased coal ($12.6 million, or $0.53 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.

At our Central Appalachia operations, operating cost per ton increased from $30.00 per ton in the third quarter of 2003 to $35.45 per ton in the third quarter of 2004. The increase in per ton costs was due to increased costs for coal purchases ($30.6 million, or $3.80 per ton), increased diesel fuel ($3.8 million, or $0.46 per ton) and production taxes and coal royalties ($2.7 million, or $0.23 per ton) as well as the increased preparation costs for metallurgical coal discussed above. Additionally, rail disruptions in the third quarter of 2004 were primarily at our Central Appalachia operations as rail performance was negatively impacted by hurricanes and related damage.

Operating cost per ton at our Western Bituminous operations increased to $15.30 in the third quarter of 2004 from $14.58 in the third quarter of 2003. The increase in per ton costs in the Western Bituminous Basin is due primarily to increased production taxes and coal royalties and increased repairs and maintenance costs ($5.3 million, or $0.75 per ton).

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 reduction of our postretirement medical benefit obligation of $68.0 million. Postretirement medical expenses for fiscal year 2004 after incorporation of the provisions of the Act are expected to be $18.1 million less than that previously anticipated. Results for the quarter ending September 30, 2004 include $4.5 million of this total (substantially all of which is recorded as a component of cost of coal sales).

Selling, general and administrative expenses. Selling, general and administrative expenses increased during the quarter due primarily to higher expenses resulting from consulting fees, salaries and amounts expected to be earned under our long-term incentive plans. During the quarter ended September 30, 2004, expenses related to the long-term incentive plans totaled $1.3 million, as compared to expenses of $0.7 million in 2003.

Amortization of coal supply agreements. The decrease in amortization of coal supply agreements is due primarily to the expiration of five contracts during the past year. During the third quarter of 2003, amortization of $2.5 million was recorded for these contracts, compared to no amortization in 2004.

Amortization in the third quarter of 2004 is also impacted by acquisition costs allocated to coal supply agreements for the two acquisitions completed in the quarter. Regarding the Canyon Fuel acquisition, our preliminary purchase price allocation included a liability for value attributed to below-market coal supply agreements. This amount will be recognized over the remaining life of the respective contracts. For the Triton acquisition, the preliminary purchase price includes an intangible asset for above-market coal supply agreements. This asset will be amortized to expense over the remaining terms of the acquired contracts. The net effect from the two transactions is a decrease in amortization of $0.5 million.

22

Other Operating Income

	Three Months Ended
	September 30,				Increase (Decrease)
(Amounts in thousands)	2004		2003		$			%
Income from equity investments	$	1,143	$	5,657		($4,514	)		(79.8	%)
Other operating income		16,020		10,343		5,677			54.9	%
	$	17,163	$	16,000	$	1,163			7.3	%

Income from equity investments. Income from equity investments for the quarter ending September 30, 2004 consists entirely of income from our investment in Canyon Fuel through July 31, 2004. Subsequent to that date, Canyon Fuel’s operating results are consolidated in our financial statements. For the quarter ended September 30, 2003, income from equity investments consisted of $1.4 million from our investment in Canyon Fuel and $4.3 million from our investment in NRP. The decline in income from our investment in Canyon Fuel results from the consolidation of Canyon Fuel in our financial statements subsequent to the July 31, 2004 purchase date discussed above.

Other operating income. The increase in other operating income is due primarily to the recognition of $3.3 million of additional deferred gains resulting from the December 2003 and March 2004 sales of NRP units. These deferred gains are being recognized over the terms of our leases with NRP.

Interest Expense, Net

	Three Months Ended
	September 30,						Increase (Decrease)
(Amounts in thousands)	2004			2003			$			%
Interest expense	$	16,220		$	13,187		$	3,033			23.0	%
Interest income		(1,110	)		(425	)		(685	)		(161.2	%)
	$	15,110		$	12,762		$	2,348			18.4	%

Interest expense. The increase in interest expense is partly due to a 17% increase in the amount of average borrowings in the third quarter of 2004 as compared to the third quarter of 2003 as a result of additional debt issued during the current quarter to finance the acquisitions discussed above and to finance the initial payment due under the Little Thunder lease. The increase in interest expense is also due to a higher average interest rate in the third quarter of 2004 as compared to the third quarter of 2003.

Other non-operating expense

	Three Months Ended
	September 30,						Increase (Decrease)
(Amounts in thousands)	2004			2003			$		%
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps	$	2,066		$	2,066		$	—		N/A
Other non-operating income		(461	)		(10,441	)		9,980		95.6	%
	$	1,605			($8,375	)	$	9,980		119.2	%

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 quarter ended September 30, 2004 and 2003 include expenses of $2.1 million for both periods related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred.

Additionally, other non-operating income decreased due primarily to a decrease in the amount of income that was recognized for mark-to-market adjustments on interest rate swap agreements that no longer qualified for hedge accounting. For the quarter ended September 30, 2003 we were a party to swaps with a notional value of $200.0

23

million that were not designated as hedges and for which we had not entered into offsetting positions. Mark-to-market adjustments for these swaps resulted in gains of $10.6 million during the quarter ended September 30, 2003. Subsequent to September 30, 2003, we terminated or entered into offsetting positions for all swap agreements that were not considered effective hedges.

Income taxes

	Three Months Ended
	September 30,				Increase (Decrease)
(Amounts in thousands)	2004		2003		$			%
Benefit from income taxes	$	1,155	$	8,910		($7,755	)		(87.0	%)

The Company’s effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The income tax benefit recorded in the third quarter of 2004 is primarily the result of the tax benefit from percentage depletion.

Net income (loss)

	Three Months Ended
	September 30,				Increase (Decrease)
(Amounts in thousands)	2004		2003		$			%
Net income	$	10,775	$	11,049		($274	)		(2.5	%)

The decrease in net income is due primarily to the decreased tax benefits and lower non-operating income, offset partially by improved operating margins realized for the third quarter of 2004 as compared to the same period of 2003.

Nine Months Ended September 30, 2004, Compared to Nine Months Ended September 30, 2003

Revenues

	Nine Months Ended
	September 30,				Increase (Decrease)
(Amounts in thousands, except per ton amounts)	2004		2003		$		%
Coal sales	$	1,354,043	$	1,060,558	$	293,485		27.7	%
Tons sold		86,077		73,594		12,483		17.0	%
Coal sales realization per ton	$	15.73	$	14.41	$	1.32		9.2	%

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 (1.3%), but increased more dramatically in the Powder River Basin (increase of 22.7%) and at our Western Bituminous operations (an increase of 32.5%). 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 9.1%, including above-market pricing on certain contracts acquired in the Triton acquisition. The Central Appalachia Basin experienced the largest per ton realization increase (20.7% increase), as both contract and spot market prices were higher than the same period in 2003. Additionally, a higher percentage of our sales were metallurgical sales in the first nine months of 2004 as compared to the same period in 2003. The Western Bituminous region’s per ton realization increased 14.4%. In addition to higher contract pricing, per ton realizations in the Western Bituminous Basin were also affected by the acquisition of the remaining 35% interest in

24

Canyon Fuel. Excluding the effects of the Canyon Fuel acquisition, per ton realizations for Western Bituminous would have increased 11.2% over the prior year’s comparable quarter.

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. Volumes from the Powder River Basin (which have the lowest average realization) increased to approximately 66% of all tons sold in the nine months ended September 30, 2004 from 63% of tons sold in the nine months ended September 30, 2003.

Costs and Expenses

	Nine Months Ended
	September 30,				Increase (Decrease)
(Amounts in thousands, except per ton amounts)	2004		2003		$			%
Cost of coal sales	$	1,273,564	$	1,052,105	$	221,459			21.0	%
Selling, general and administrative expenses		41,195		34,845		6,350			18.2	%
Amortization of coal supply agreements		972		13,209		(12,237	)		(92.6	%)
Other expenses		26,806		13,157		13,649			103.7	%
	$	1,342,537	$	1,113,316	$	229,221			20.6	%
Cost of coal sales per ton sold	$	14.80	$	14.30	$	0.50			3.5	%

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 $44.6 million.

• Poor rail performance during the second and third quarters of 2004 resulted in missed shipments and disruptions in production.

• Our Central Appalachia operations incurred higher costs related to additional preparation necessary for coal sold in metallurgical markets.

• The cost of purchased coal increased $63.5 million, reflecting a combination of increased purchase volumes and higher spot market prices that were prevalent during the first nine months of 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 $6.7 million and $11.7 million, respectively.

• Repairs and maintenance costs and depreciation, depletion and amortization charges both increased $10.4 million due partially to the property additions resulting from the acquisitions made during the third quarter of 2004.

On a per-ton basis, operating costs (defined as including all mining costs but excluding pass-through transportation expenses) at our Powder River Basin operations increased to $6.19 for the first nine months of 2004 from $5.58 for the first nine months of 2003. The increase in per ton costs in the Powder River Basin is due primarily to increased cost of purchased coal ($18.0 million, or $0.30 per ton), increased production taxes and coal royalties ($26.2 million, or $0.11 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.

At our Central Appalachia operations, operating cost per ton increased from $30.69 for the first nine months of 2003 to $34.20 for the first nine months of 2004. The increase in per ton costs was due to increased costs for purchased coal ($45.5 million, or $1.96 per ton), increased production taxes and coal royalties ($12.1 million, or $0.50 per ton), higher costs for diesel fuel and explosives as well as the increased preparation costs for metallurgical coal discussed above.

Operating costs at our Western Bituminous operations increased to $15.82 per ton for the first nine months of 2004 from $15.34 per ton for the first nine months of 2003. The increase in per ton costs in the Western Bituminous Basin is due primarily to increased production taxes and coal royalties and increased repairs and maintenance costs ($4.9 million, or $0.29 per ton).

25

Our results for the nine months ending September 30, 2004 reflect 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 reduction of our postretirement medical benefit obligation of $68.0 million. Postretirement medical expenses for fiscal year 2004 after incorporation of the provisions of the Act are expected to be $18.1 million less than that previously anticipated. Results for the nine months ending September 30, 2004 include $13.6 million of this total (substantially all of which is recorded as a component of cost of coal sales). The benefit for the nine months ending September 30, 2004 was offset by increased costs resulting from changes to other actuarial assumptions that were incorporated at the beginning of the year.

Selling, general and administrative expenses. Selling, general and administrative expenses increased during the first nine months due primarily to higher expenses resulting from amounts expected to be earned under our annual and long-term incentive plans. During the nine months ended September 30, 2004, expenses related to annual bonus and long-term incentive plans totaled $7.6 million, as compared to expenses of $1.3 million in 2003.

Amortization of coal supply agreements. The decrease in amortization of coal supply agreements is due primarily to the expiration of five contracts during the past year. During the first nine months of 2003, amortization of $11.5 million was recorded for these contracts, compared to no amortization in 2004.

Other Operating Income

	Nine Months Ended
	September 30,				Increase (Decrease)
(Amounts in thousands)	2004		2003		$			%
Income from equity investments	$	10,828	$	28,958		($18,130	)		(62.6	%)
Gain on sale of units of NRP		81,851		—		81,851			N/A
Other operating income		53,928		33,428		20,500			61.3	%
	$	146,607	$	62,386	$	84,221			135.0	%

Income from equity investments. Income from equity investments for the nine months ending September 30, 2004 consists of $8.4 million from our investment in Canyon Fuel (prior to the July 31, 2004 acquisition of the remaining 35% interest) and $2.4 million from our investment in NRP (prior to the sale of NRP units in March). For the nine months ended September 30, 2003, income from equity investments consisted of $17.6 million of income from our investment in Canyon Fuel and $11.4 million from our investment in NRP. The decline in income from our investment in Canyon Fuel results from the consolidation of Canyon Fuel in our financial statements subsequent to the July 31, 2004 purchase date, lower production and sales levels at Canyon Fuel prior to the remaining 35% acquisition and the costs related to idling the Skyline Mine, including the severance costs noted above.

Other operating income. The increase in other operating income is partially due to the $8.4 million mark-to-market gain on the remaining investment in NRP, as described above. The remaining increase in other operating income is primarily due to the recognition in the first nine months of 2004 of $9.2 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.

Interest Expense, Net

	Nine Months Ended
	September 30,						Increase (Decrease)
(Amounts in thousands)	2004			2003			$			%
Interest expense	$	45,062		$	36,407		$	8,655			23.8	%
Interest income		(2,723	)		(1,251	)		(1,472	)		(117.7	%)
	$	42,339		$	35,156		$	7,183			20.4	%

Interest expense. The increase in interest expense results primarily from a higher average interest rate in the first nine months of 2004 as compared to the same period in 2003. In 2004, the Company’s outstanding borrowings consist primarily of fixed rate borrowings, while borrowings in the first half of 2003 were primarily variable rate

26

borrowings. Short-term interest rates in 2003 were lower than the fixed rate of borrowing that makes up the majority of average debt balances in 2004. The increase in interest expense also results partly from a higher amount of average borrowings in the first nine months of 2004 as compared to the same period in 2003 as a result of additional debt issued late in the 2004 year-to-date period to finance the acquisitions discussed above and the first payment under the Little Thunder lease.

Other non-operating expense

	Nine Months Ended
	September 30,						Increase (Decrease)
(Amounts in thousands)	2004			2003			$			%
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps	$	6,199		$	6,889		$	(690	)		(10.0	%)
Other non-operating income		(835	)		(11,314	)		10,479			92.6	%
	$	5,364		$	(4,425	)	$	9,789			221.2	%

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 nine months ended September 30, 2004 include expenses of $6.2 million related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. The amounts recorded for the nine months ended September 30, 2003 include expenses of $4.8 million related to early debt extinguishment costs and $2.1 million related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred.

Additionally, other non-operating income decreased due to a $10.9 million decrease in the amount of income that was recognized for the mark-to-market adjustments on the interest rate swap agreements which no longer qualified for hedge accounting. For the nine months ended September 30, 2003 we possessed swaps with a notional value of $200.0 million which were not designated as hedges and for which we had not entered offsetting positions, thus recognizing gains of $11.6 million on the mark-to-market adjustments of those open positions. In the nine months ended September 30, 2004, we were fully offset on all our swap agreement positions and thus only recognized mark-to-market gains of $0.7 million.

Income taxes

	Nine Months Ended
	September 30,					Increase (Decrease)
(Amounts in thousands)	2004			2003		$			%
Income tax (provision) benefit		($18,545	)	$	17,510		($36,055	)		(205.9	%)

The Company’s effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The income tax provision recorded in the first nine months of 2004 is primarily the result of the tax impact from the sale of the NRP units in the first quarter of 2004.

Net income (loss) before cumulative effect of accounting change

	Nine Months Ended
	September 30,					Increase (Decrease)
(Amounts in thousands)	2004		2003			$		%
Net income (loss) before cumulative effect of accounting change	$	91,865	$	(3,593	)	$	95,458		2,656.8	%

The increase in net income (loss) before cumulative effect of accounting change is primarily due to higher coal sales revenues, the gain from the sale of NRP units during the first and second quarters of 2004 (net of related tax provision) and the favorable mark-to-market adjustment for the remaining NRP investment (net of related tax provision).

27

Cumulative effect of accounting change

Effective 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 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.

DISCLOSURE 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 September 30, 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 have been no significant changes in our internal controls or in other factors that could significantly affect internal controls subsequent to September 30, 2004.

RECENT DEVELOPMENTS

Arch Western Debt Offering. On October 22, 2004, two subsidiaries of Arch Western, as co-obligors, issued $250 million of 6-3/4% 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 6-3/4% senior notes due in 2013, except that the new notes are subject to certain transfer restrictions and are not fully fungible with the existing notes. The net proceeds of the offering of $256.8 million 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.

Equity Offering. On October 28, 2004, we completed a public offering of 7,187,500 shares of our common stock, including the full over-allotment option, at a price of $33.85 per share. We used the net proceeds of the offering, totaling $230.6 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.

OUTLOOK

Railroad Transportation Disruptions. During the second and third quarters of 2004, rail service disruptions resulted in missed shipments in all of our operating regions, including some of our highest margin Central Appalachia business. In addition, we were 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 more than 21% to 10.2 million tons year-to-date.

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 quarter, but suffered a setback following hurricane-related disruptions in the southeast regions of the United States late in the quarter. We anticipate continued challenges with rail service in the fourth quarter. 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 September 30, 2004, the remaining deferred amounts will be recognized as expense in the following periods: $2.1 million for the remainder of 2004; $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

28

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

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 nine months ended September 30, 2004 and 2003:

	2004			2003
	(in thousands)
Cash provided by (used in):
Operating activities	$	39,806		$	114,256
Investing activities		(545,998	)		(61,547	)
Financing activities		256,449			63,285

Cash provided by operating activities declined in the nine months ended September 30, 2004 as compared to the same period in 2003 primarily as a result of increased investment in working capital. Trade accounts receivable represented the largest use of funds, increasing by more than $69 million (net of amounts acquired in business combinations) in the first nine months of 2004. This increase is due to higher sales levels during the period, as revenues have increased approximately 28% in the first nine months of 2004 as compared to the same period in 2003. Additionally, inventory increased by more than $5 million (net of amounts acquired in business combinations) in the first nine months of 2004. This increase is due primarily to the continued rail difficulties that resulted in missed shipments during the first nine months of the year.

Cash used in investing activities in the first nine months of 2004 is represented largely by payments for acquisitions, net of cash acquired, during the third quarter of 2004. We acquired the remaining 35% of our Canyon Fuel investment and the North Rochelle operations from Triton in July and August 2004, respectively. Capital expenditures and advance royalty payments were $243.6 million and $27.2 million, respectively. Capital expenditures included $122.2 million related to a 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 outlays, primarily at our Powder River Basin and Central Appalachia mines. These cash outlays were offset partially by proceeds of $105.4 million from the sale of the NRP units. Cash used in investing activities during the nine months ended September 30, 2003 reflects capital expenditures of $91.7 million and advance royalty payments of $25.8 million. Proceeds from coal supply agreements in the first nine months of 2003 were $52.5 million, which represents the buyout of a coal supply contract with above-market pricing. During the first nine months of 2003, we made the fifth and final annual payment of $31.6 million under the Thundercloud federal lease, which is part of the Black Thunder mine in Wyoming.

Cash provided by financing activities during the nine months ended September 30, 2004 consists of borrowings under our revolving credit facility and term loan facility and proceeds from the issuance of common stock under our employee stock incentive plan, offset by payments on long-term debt and dividend payments. Borrowing under our revolving credit facility consisted of $149.0 million, representing borrowings to primarily fund the first of five annual payments on the Little Thunder mineral reserve lease discussed below and the Triton acquisition. Borrowings under our Arch Western term loan facility were used to fund the Triton acquisition as well. Cash provided by financing activities during the first nine months of 2003 reflects the proceeds from the issuance of Arch Western senior notes (which were used to retire existing debt) and the proceeds from the sale of preferred stock, offset additionally by the pay-down of amounts outstanding under our revolving credit facility. On January 31, 2003, we utilized our Universal Shelf and completed the sale 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. On June 25, 2003, Arch Western Finance, LLC, a subsidiary of Arch Western, completed the offering of $700 million of 6.75% senior notes. The proceeds of the offering were primarily used to repay Arch Western’s existing term loans.

29

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 $243.6 million and $91.7 million for the nine months ended September 30, 2004 and 2003, 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 estimate that our capital expenditures will be approximately $328.1 million in total for 2004. This estimate assumes a small amount of capital related to initial development work at the Mountain Laurel complex during the last quarter of the year. 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 proceeds from the debt and equity offerings discussed above.

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 high Btu, low-sulfur coal. We paid the first of five annual payments of $122.2 million under the lease using $22.2 million of cash on hand and $100.0 million borrowed under our revolving credit facility.

At September 30, 2004, we had $68.9 million in letters of credit outstanding which, when combined with the $149.0 million of outstanding borrowings under the revolver, resulted in $132.1 million of unused borrowings under our revolving credit facility. Sufficient unused capacity is currently available to fund our current operating needs. At September 30, 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 minimum fixed charge coverage ratio and a minimum net worth test. The leverage ratio requires that we not permit the ratio of total indebtedness at the end of any calendar quarter to adjusted EBITDA for the four quarters then ended exceed a specified amount. The fixed charge coverage ratio requires that we not permit the ratio of adjusted EBITDA plus lease expense to interest expense plus lease expense for the four quarters then ended to be less than a specified amount. The net worth test requires that we not permit our net worth to be less than a specified amount plus 50% of cumulative net income. At September 30, 2004, we were in compliance with all financial covenants and the financial covenant requirements did not limit our borrowing capacity under our revolving credit facility.

On August 20, 2004, Arch Western borrowed $100.0 million under its term loan facility, which was established on September 19, 2003. The $100.0 million was used to help fund the Triton acquisition that occurred on August 20, 2004.

On June 25, 2003, Arch Western Finance, LLC, a subsidiary of Arch Western, completed the offering of $700 million of senior notes. The proceeds of the offering were primarily used to repay Arch Western’s existing term loans. The senior notes bear a fixed rate of interest of 6.75% and are due in full on July 1, 2013. 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.

We periodically establish uncommitted lines of credit with banks. These agreements generally provide for short-term borrowings at market rates. At September 30, 2004, there were $20.0 million of such agreements in effect, of which none were outstanding.

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At September 30, 2004, our outstanding debt was comprised of debt that bore interest at both fixed and variable rates.

30

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 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. As of September 30, 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 September 30, 2004 was 32 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 September 30, 2004 ranged from 11 to 34 months.

As of September 30, 2004, the fair value of our net interest rate swap position was a liability of $15.2 million.

We are also exposed to commodity price risk related to our purchase of diesel fuel. We enter into forward purchase contracts to reduce volatility in the price of diesel fuel for our operations.

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 our consolidated financial statements as of and for the year ended December 31, 2003 as filed on our Annual Report on Form 10-K with the Securities and Exchange Commission.

At September 30, 2004, our debt portfolio consisted of a fixed rate and variable rate debt mixture. Changes in interest rates have different impacts on the fixed-rate and variable-rate portions of the Company’s debt portfolio. 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. A change in interest rates on the variable portion of the debt portfolio impacts the interest incurred and cash flows but does not impact the net financial instrument position. The sensitivity analysis related to our fixed rate debt assumes an instantaneous 100-basis point move in interest rates from their levels at September 30, 2004, with all other variables held constant. A 100-basis point increase in market interest rates would result in a $43.9 million decrease in the fair value of the Company’s fixed rate debt at September 30, 2004. Based on the variable-rate debt included in the Company’s debt portfolio as of September 30, 2004, a 100-basis point increase in interest rates would result in an annualized additional $2.5 million of interest expense incurred.

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 September 30, 2004.

CONTRACTUAL OBLIGATIONS

In our Annual Report on Form 10-K for the year ended December 31, 2003, we disclosed our significant contractual obligations. The following updates those disclosures.

• On July 31, 2004, we purchased the remaining 35% interest in Canyon Fuel. A portion of the $112.0 million purchase price was financed with a $22.0 million promissory note payable to the seller. The note requires quarterly installments of $1.0 million beginning in October 2004 and ending in July 2008 and quarterly installments of $1.5 million beginning in October 2008 and ending in July 2009.

• Regarding our accepted bid by the BLM of the Little Thunder coal reserve lease discussed above, we made the first of five annual lease payments in September 2004 in the amount of $122.2 million. The next four lease payments will be made in equal annual installments of $122.2 million in fiscal years 2006 through 2009, respectively.

31

• During 2004, we have entered into several operating lease arrangements for mining equipment. Monthly payments due under these leases total approximately $0.5 million and the terms of these leases range from 66 months to 84 months.

• Subsequent to September 30, 2004, we issued $250.0 million 6.75% Senior Notes due 2013. These Senior Notes mature on July 1, 2013 and require bi-annual interest payments on January 1 and July 1 of each year, commencing on January 1, 2005.

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

A separate matter involves a surface mining permit issued by the West Virginia Department of Environmental Protection (DEP) to our Coal-Mac subsidiary on September 29, 2003. This permit has been challenged in an administrative proceeding brought by the West Virginia Highlands Conservancy. The appeal alleges that the permit is incomplete and inaccurate, and thereby not in compliance with the DEP’s regulations. Specifically, the petition alleges that the proposal to construct a valley fill is inconsistent with a provision of the state regulations known as the “buffer zone rule”, that the operation has failed to provide for suitable topsoil material for use in its reclamation, and that the state agency failed to evaluate the consequences to the water quality from the alleged discharge of one substance from the mine site. The DEP is required by state law to defend the issuance of the permit. We have intervened in this matter to support the DEP’s decision to issue the permit. In a decision entered on September 13, 2004, the Surface Mine Board rejected the grounds for the appeal asserted by the Highlands Conservancy. A final order was entered by the Board on October 22, 2004. An appeal may be taken to a state circuit court within 30 days of the Board’s final order.

32

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 has certified certain legal issues back to the West Virginia Supreme Court. Upon resolution of the legal issues by the West Virginia Supreme Court, the panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts.

In a similar case, Hobert D. Adkins Jr. et al. v. AEI Resources, Inc. et al., approximately 248 plaintiffs sued us, three of our subsidiaries and over a hundred other parties in Raleigh County, WV, Circuit Court for property damages arising out of a May 2, 2002, flood. However, on September 30, 2004, the judge dismissed the case for lack of venue.

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 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 hydrocarbon wastes on and in the property and by failing to return the property to its approximate original contour.

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 September 30, 2004, we had outstanding consolidated indebtedness of $968.7 million, representing approximately 54% 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

33

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.

On October 15, 2004, Moody’s downgraded our credit ratings, including the ratings on the notes, to Ba3 with a stable outlook. 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.

We reported a net loss available to common shareholders of $2.6 million for the year ended December 31, 2002 and $12.0 million for the first nine months of 2003. The losses in 2002 and the first three quarters of 2003 were primarily

34

attributable to our decision to scale back production during the period in response to a weak market environment and increased costs at certain of our operations. The decision to scale back production came after we had prepared most of the operations to maximize production in order to capitalize on higher market prices for coal that we had previously projected. Therefore, certain costs incurred to maximize production did not result in higher revenues but did increase the cost of coal sales.

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;

• 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.

35

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. Revised State Implementation Plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. 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 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. 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, 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

36

Control Technology (“MACT”) and 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 8-hour ozone standard established pursuant to the Clean Air Act. 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 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, 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

37

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 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 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

38

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. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants into waters that have been designated by the state as high quality. This 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. If the plaintiffs are successful, the exemption from the antidegradation review policy is revoked and we discharge into waters designated as high quality by the state, the cost, time and difficulty associated with obtaining and complying with Clean Water Act permits for our affected surface mining operations would increase and may hinder our ability to conduct such operations 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 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.

39

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 and weak power demand by the industrial sector of the economy, which led us to reduce the rate of coal production from planned levels and adversely impacted our profitability.

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 a negative 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 2003, sales of coal under long-term contracts, which are contracts with a term greater than 12 months, accounted for 83% 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 nine months ended September 30, 2004, the weighted average price of coal sold under our long-term contracts was $15.01 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 prices if and when they arise. In addition, because long-term contracts typically 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

40

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 $26.1 million and $33.7 million of our total operating income in the years ended 2003 and 2002, 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.

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

41

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;

• 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.

Post Retirement 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 increased by approximately $32.6 million in 2003. 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 his or her cash balance account was credited with the present value of his or her 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

42

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 western 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 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.

The membership interests in Canyon Fuel, which operates three coal mines in Utah, were owned 65% by Arch Western and 35% by a subsidiary of ITOCHU Corporation of Japan until July 30, 2004 when we acquired ITOCHU’s 35% interest in Canyon Fuel. The agreement that governed the management and operations of Canyon Fuel prior to July 30, 2004 provided for a management board to manage its business and affairs. Some major business decisions concerning Canyon Fuel required the vote of 70% of the membership interests and therefore limited our ability to make these decisions. These decisions include admission of additional members; approval of annual business plans; the making of significant capital expenditures; sales of coal below specified prices; agreements between Canyon Fuel and any member; the institution or settlement of litigation; a material change in the nature of Canyon Fuel’s business or a material acquisition; the sale or other disposition, including by merger, of assets other than in the ordinary course of business; incurrence of indebtedness; the entering into of leases; and the selection and removal of officers. The Canyon Fuel agreement also contained various restrictions on the transfer of membership interests in Canyon Fuel.

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.

43

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information required by this Item is contained under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report and is incorporated herein by reference.

ITEM 4. CONTROLS AND PROCEDURES

The information required by this Item is contained under the caption “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report and is incorporated herein by reference.

PART II — OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The information required by this Item is contained in the “Contingencies - Legal Contingencies” section of “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report and is incorporated herein by reference.

ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

Nothing to report under this item.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

Nothing to report under this item.

ITEM 4. SUMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Nothing to report under this item.

ITEM 5. OTHER INFORMATION

Nothing to report under this item.

ITEM 6. EXHIBITS

(a)

3.1	Amended and Restated Certificate of Incorporation of Arch Coal, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2000)
3.2	Amended and Restated Bylaws of Arch Coal, Inc. (incorporated herein by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the Year Ended December 31, 2000)
3.3	Certificate of Designations Establishing the Designations, Powers, Preferences, Rights, Qualifications, Limitations and Restrictions of the Company’s 5% Perpetual Cumulative Convertible Preferred Stock (incorporated herein by reference to Exhibit 3 to current report on Form 8-A filed on March 5, 2003)
10.1	Arch Coal, Inc. 1997 Stock Incentive Plan (as amended and restated on July 22, 2004)
10.2	$350,000,000 Revolving Credit Facility Amended and Restated Credit Agreement as of August 20, 2004 by and among Arch Coal, Inc. the Lenders party thereto, PNC Bank, National Association, as Administrative Agent, JPMorgan Chase Bank, as a Syndication Agent and Citibank, N.A., Credit Lyonnais New York Branch and U.S. Bank National Association, as Documentation Agents

44

10.3	First Amendment to Amended and Restated Credit Agreement dated and effective as of October 22, 2004 by and among Arch Coal, Inc., the Lenders party thereto, JPMorgan Chase Bank, as syndication agent, Citibank, N.A., Calyon New York Branch (successor by merger to Credit Lyonnais New York Branch) and U.S. Bank National Association, as documentation agents, and PNC Bank, National Association, as administrative agent.
10.4	Steve Leer Employment Agreement
10.5	Form of Executive Officer Employment Agreement
31.1	Certification of Principal Executive Officer Pursuant to § 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer Pursuant to § 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer Pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer Pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002.

45

SIGNATURES

     Pursuant to the requirements 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.
	(Registrant)
Date: November 9, 2004	/s/ John W. Lorson
	John W. Lorson
	Controller
	(Chief Accounting Officer)

46