ARCH WESTERN RESOURCES LLC - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


(Mark One)

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the Quarterly Period Ended March 31, 2005


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from _______to ________

		Commission file number _____________

ARCH WESTERN RESOURCES, LLC

(Exact name of registrant as specified in its charter)


Delaware		43-1811130
(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 þ No o

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

At May 1, 2005, 99.5% of the registrant’s common equity was held by Arch Western Acquisition Corporation and the remaining .5 percent was held by BP p.l.c.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ARCH WESTERN RESOURCES, LLC

CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)


	March 31,		December 31,
	2005		2004
	(Unaudited)
Assets
Current assets
Cash and cash equivalents	$	344	$	1,351
Trade receivables		114,649		83,230
Other receivables		5,235		5,691
Inventories		77,207		78,372
Prepaid royalties		12,176		7,792
Other		12,109		11,529

Total current assets		221,720		187,965

Property, plant and equipment, net		1,095,186		1,101,674

Other assets
Receivable from Arch Coal, Inc.		679,055		677,934
Other		43,038		45,863

Total other assets		722,093		723,797

Total assets	$	2,038,999	$	2,013,436

Liabilities and members’ equity
Current liabilities
Accounts payable	$	63,663	$	56,612
Accrued expenses		116,446		129,435

Total current liabilities		180,109		186,047
Long-term debt		961,272		961,613
Accrued postretirement benefits other than pension		24,652		24,643
Asset retirement obligations		129,103		128,184
Accrued workers’ compensation		12,115		12,749
Other noncurrent liabilities		40,815		42,770

Total liabilities		1,348,066		1,356,006

Minority interest		112,128		109,401
Redeemable equity interests		5,125		4,971
Non-redeemable members’ equity		573,680		543,058

Total liabilities, redeemable equity interests and non-redeemable members’ equity	$	2,038,999	$	2,013,436

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

ARCH WESTERN RESOURCES, LLC

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
(UNAUDITED)


	Three Months Ended
	March 31,
	2005			2004
Revenues
Coal sales	$	277,416		$	139,848
Costs and expenses
Cost of coal sales		209,105			111,092
Depreciation, depletion and amortization		25,519			16,636
Selling, general and administrative expenses		5,690			4,211

		240,314			131,939


Other operating income
Income from equity investment		—			1,272
Other operating income		2,293			4,327

		2,293			5,599

Income from operations		39,395			13,508
Interest expense, net:
Interest expense		(15,989	)		(12,900	)
Interest income primarily from Arch Coal, Inc.		8,781			3,702

		(7,208	)		(9,198	)


Other non-operating income (expense):
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps		(3,388	)		(3,388	)

Income before minority interest		28,799			922
Minority interest		(2,728	)		—

Net income	$	26,071		$	922

Net income attributable to redeemable equity interests		130			5
Net income attributable to non-redeemable equity interests	$	25,941		$	917

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

ARCH WESTERN RESOURCES, LLC

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)


	Three Months Ended
	March 31,
	2005			2004
Operating activities
Net income	$	26,071		$	922
Adjustments to reconcile to cash provided by operating activities:
Depreciation, depletion and amortization		25,519			16,636
Prepaid royalties expensed		5,617			5,682
Accretion on asset retirement obligations		2,854			2,077
Net gain on disposition of assets		(1,646	)		(3	)
Income from equity investment		—			(1,272	)
Net distributions from equity investment		—			832
Minority interest		2,728			—
Other nonoperating expense		3,388			3,388
Changes in:
Receivables		(30,963	)		4,491
Inventories		1,165			(2,275	)
Accounts payable and accrued expenses		(5,855	)		(9,998	)
Note receivable from Arch Coal, Inc.		(1,227	)		(31,487	)
Accrued postretirement benefits other than pension		10			581
Asset retirement obligations		(1,936	)		(1,383	)
Accrued workers’ compensation benefits		(634	)		(34	)
Other		3,933			3,812

Cash provided by (used in) operating activities		29,024			(8,031	)

Investing activities
Capital expenditures		(21,913	)		(16,955	)
Proceeds from dispositions of property, plant and equipment		1,933			6
Additions to prepaid royalties		(10,000	)		(10,000	)

Cash (used in) investing activities		(29,980	)		(26,949	)

Financing activities
Debt financing costs		(51	)		(97	)

Cash (used in) financing activities		(51	)		(97	)

Decrease in cash and cash equivalents		(1,007	)		(35,077	)
Cash and cash equivalents, beginning of period		1,351			35,171

Cash and cash equivalents, end of period	$	344		$	94

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

ARCH WESTERN RESOURCES, LLC

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2005
(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 March 31, 2005 are not necessarily indicative of results to be expected for the year ending December 31, 2005. 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, 2004 included in Arch Western Resources, LLC’s Form 10-K as filed with the Securities and Exchange Commission.

Arch Western Resources, LLC (the “Company”) was formed as a joint venture on June 1, 1998 when Arch Coal, Inc. (“Arch Coal”) acquired the United States coal operations of Atlantic Richfield Company and combined these operations with Arch Coal’s western operations. Arch Western’s membership interests are owned 99% by Arch Coal and 1% by an affiliate of BP Amoco (“BP”), the successor to Atlantic Richfield Company. Arch Coal’s ownership is comprised entirely of common membership interests, while BP’s ownership is comprised of a 0.5% common membership interest and a 0.5% preferred membership interest.

Under the terms of the Company’s membership agreement, net profits and losses are allocated only to the common membership interests on the basis of 99.5% to Arch Coal and 0.5% to BP. No profit or loss is allocated to the preferred membership interest of BP. Except for a Preferred Return, distributions to members are allocated on the basis of 99.5% to Arch Coal and 0.5% to BP. The Preferred Return entitles BP to receive an annual distribution from the common membership interests equal to 4% of the preferred capital account balance at the end of the year. The Preferred Return is payable at the Company’s discretion.

The Company mines and markets steam coal from surface and deep mines for sale to utility and industrial customers in the United States and certain export markets. The Company’s principal subsidiaries are Thunder Basin Coal Company, L.L.C., which operates a surface coal mine and owns one idle mine in the Powder River Basin in Wyoming; Mountain Coal Company, L.L.C., which operates one underground coal mine in Colorado; and Arch of Wyoming LLC, which operated two surface coal mines in the Hanna Basin in Wyoming. Both Arch of Wyoming mines were put into reclamation mode in 2004. In addition to these wholly owned operating units, the Company has a 65% interest in Canyon Fuel Company, LLC (“Canyon Fuel”). Canyon Fuel operates three underground mines in Utah. Through July 31, 2004, the Company’s interest in Canyon Fuel was accounted for on the equity method as a result of certain super-majority voting rights in the Canyon Fuel joint venture agreement. On July 31, 2004, Arch Coal purchased the remaining 35% interest in Canyon Fuel not owned by the Company. Upon Arch Coal’s acquisition of the 35% interest, Canyon Fuel’s joint venture agreement was amended to eliminate the super-majority voting rights. As a result, for periods subsequent to July 31, 2004, the Company has consolidated 100% of the results of Canyon Fuel in its financial statements and recorded minority interest for Arch Coal’s 35% interest in Canyon Fuel.

Note B - Recent Accounting Pronouncements

On March 30, 2005, the Financial Accounting Standards Board (“FASB”) ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on issue No. 04-06, Accounting for Stripping Costs in the Mining Industry. This issue applies to stripping costs incurred in the production phase of a mine for the removal of overburden or waste materials for the purpose of obtaining access to coal which will be extracted. Under the new rule, stripping costs incurred during the production phase of the mine are variable production costs that are included in the cost of inventory produced and extracted during the period the stripping costs are incurred. The guidance in this EITF consensus is effective for fiscal years beginning after December 15, 2005. The Company is evaluating what impact, if any, this guidance will have on its consolidated financial statements.

In March 2005, the FASB issued FASB Interpretation (FIN) 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. This interpretation clarifies that the term, conditional asset retirement obligation, as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair

value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred, generally upon acquisition, construction, or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. SFAS No. 143 acknowledges that, in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. The Company does not expect this guidance to have a material impact on its financial statements.

Note C - Contribution of North Rochelle Mine

On August 20, 2004, Arch Coal 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 total purchase price of $382.1 million. Upon acquisition, Arch Coal contributed the assets and liabilities of Triton’s North Rochelle mine (excluding coal reserves) to the Company. Upon contribution the North Rochelle mine was integrated with the Company’s Black Thunder mine in the Powder River Basin.

Concurrently with the contribution, the Company entered into a sublease transaction with Arch Coal for the right to mine the former North Rochelle coal reserves. Under the terms of the sublease agreement, the Company pays a production royalty of $0.05 per ton to Arch Coal for tons mined on the North Rochelle property. For the three months ended March 31, 2005, the Company paid royalties of $0.3 million to Arch Coal under this sublease. Arch Coal’s depletion expense related to the North Rochelle reserves totaled $4.3 million in the quarter ended March 31, 2005. The Company and Arch Coal will amend the sublease upon final valuation of the North Rochelle reserves. The Company expects the amended royalty rate to be higher than that currently being charged.

The effects of the contribution have been recorded in the accompanying consolidated financial statements as of and for the periods subsequent to August 20, 2004. The contributed assets and liabilities have been recorded at their estimated fair value. 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 in the second quarter of 2005.

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


Cash	$	407
Accounts receivable		14,233
Materials and supplies		4,161
Coal inventory		4,874
Other current assets		3,792
Property, plant, equipment and mine development		81,059
Coal supply agreements		8,486
Accounts payable and accrued expenses		(72,326	)
Other non-current assets and liabilities, net		(18,236	)

Total contribution	$	26,450

Amounts preliminarily allocated to coal supply agreements noted in the table above represent the value attributed to the net above-market coal supply agreements to be amortized over the remaining terms of the contracts. The amortization period on these acquired coal supply agreements ranges from nine to 21 months.

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

Pro Forma Financial Information

If the North Rochelle mining operations and Canyon Fuel (net of Arch Coal’s minority interest) had been included in the Company’s results of operations during the three months ended March 31, 2004, its unaudited pro forma revenues would have been $233.8 million and the unaudited pro forma net loss would have been $2.4 million.

Note D - Transactions or Events Affecting Comparability of Reported Results

During the quarter ended March 31, 2005, the Company recognized a gain of $1.6 million from the sale of equipment. The gain is reported as other operating income.

During the quarter ended March 31, 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 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, while the interest portion has been reflected as interest expense.

During the first quarter of 2004, Canyon Fuel, while accounted for under the equity method, began the process of temporarily idling its Skyline Mine, and incurred severance costs of $1.9 million. The Company’s share of these costs totals $1.2 million and is reflected in income from equity investment in the Condensed Consolidated Statements of Operations.

On June 25, 2003, the Company 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 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 months ending March 31, 2005 and 2004, the Company recognized $3.4 million of expense related to the amortization of previously deferred mark-to-market adjustments.

Note E - Investment in Canyon Fuel

As of March 31, 2005, the Company held no equity investments. Arch Coal 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. The following table presents unaudited summarized financial information for Canyon Fuel, for periods in which it was accounted for on the equity method:


	Three Months Ended
	March 31,
Condensed Income Statement Information	2005		2004
	(in thousands)
Revenues	$	—	$	53,382
Total costs and expenses		—		52,808

Net income	$	—	$	574


65% of Canyon Fuel net income	$	—	$	373
Effect of purchase adjustments		—		899

Arch Western’s income from its equity investment in Canyon Fuel	$	—	$	1,272

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.

Note F - Other Comprehensive Income

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


	Three Months Ended
	March 31,
	2005		2004
	(in thousands)
Net income	$	26,071	$	922
Other comprehensive income		4,726		4,895

Total comprehensive income	$	30,797	$	5,817

Other comprehensive income for the quarters ended March 31, 2005 and 2004 consists primarily of the reclassification of previously deferred mark-to-market adjustments from other comprehensive income to net income.

Note G - Employee Benefit Plans

Defined Benefit Pension and Other Postretirement Benefit Plans

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

The Company also currently provides certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The 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
Quarter Ended March 31,	2005			2004			2005		2004
	(In thousands)
Service cost	$	1,606		$	775		$	505	$	240
Interest cost		863			953			440		263
Expected return on plan assets*		(1,097	)		(1,020	)		—		—
Other amortization and deferral		816			375			81		3

	$	2,188		$	1,083		$	1,026	$	506

* The Company does not fund its other postretirement liabilities.

Employer Contributions

While the Company did not make any contributions to the pension plan during the quarter ended March 31, 2005, it is currently considering a contribution to the plan in 2005 but has not yet made a determination as to the timing and the amount of the potential contribution.

Note H - Inventories

Inventories consist of the following:


	March 31,		December 31,
	2005		2004
	(in thousands)
Coal	$	41,806	$	46,538
Repair parts and supplies		35,401		31,834

	$	77,207	$	78,372

Note I - Debt

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 debt offering was issued under an

indenture dated June 25, 2003, under which the Company previously issued $700.0 million of 6.75% Senior Notes due 2013. The senior notes are guaranteed by the Company and certain of the Company’s subsidiaries and are secured by a security interest in the Company’s receivable from Arch Coal. The terms of the senior notes contain restrictive covenants that limit the Company’s ability to, among other things, incur additional debt, sell or transfer assets, and make investments. The net proceeds were used to repay $100.0 million in borrowings under the Company’s term loan facility maturing in 2007, with the remainder loaned to Arch Coal.

Note J - Related Party Transactions

The Company pays selling, general and administrative services fees to Arch Coal. Expenses are allocated based on Arch Coal’s best estimates of proportional or incremental costs, whichever is more representative of costs incurred by Arch Coal on behalf of the Company. Amounts allocated to the Company by Arch Coal were $5.7 million and $4.2 million for the quarters ended March 31, 2005 and 2004, respectively. These amounts are reported as selling, general and administrative expenses in the accompanying Condensed Consolidated Statements of Operations.

Note K - Segment Information

The Company produces steam and metallurgical coal from surface and deep mines for sale to utility, industrial and export markets. The Company operates only in the United States, with mines in the major western low-sulfur coal basins. The Company has two reportable 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) and Western Bituminous (WBIT). The Company’s operations in the Powder River Basin are located in Wyoming and include one operating surface mine and one idle surface mine. The Company’s operations in the Western Bituminous region are located in southern Wyoming, Colorado and Utah and include four underground mines and two surface mines (which were both put into reclamation mode in 2004).

Operating segment results for the quarters ending March 31, 2005 and 2004 are presented below. Results for the operating segments include all direct costs of mining. Corporate, Other and Eliminations includes overhead, other support functions, and the elimination of intercompany transactions.


March 31, 2005					Corporate,
					Other and
(Amounts in thousands, except per ton amounts)	PRB		WBIT		Eliminations			Consolidated
Coal sales	$	179,706	$	97,710	$	—		$	277,416
Income from operations		33,660		12,360		(6,625	)		39,395
Total assets		1,200,686		1,657,317		(819,004	)		2,038,999
Depreciation, depletion and amortization		17,189		8,330		—			25,519
Capital expenditures		8,494		13,419		—			21,913
Operating cost per ton		6.37		15.20


March 31, 2004					Corporate,
					Other and
(Amounts in thousands, except per ton amounts)	PRB		WBIT		Eliminations			Consolidated
Coal sales	$	110,245	$	29,603	$	—		$	139,848
Income from equity investments		—		1,272		—			1,272
Income from operations		15,066		2,520		(4,078	)		13,508
Total assets		1,001,701		926,903		(520,300	)		1,408,304
Equity investments		—		146,846		—			146,846
Depreciation, depletion and amortization		12,551		4,085		—			16,636
Capital expenditures		16,240		715		—			16,955
Operating cost per ton		6.01		16.86

Reconciliation of segment income from operations to consolidated income before minority interest:


	Three Months Ended
	2005			2004
	(in thousands)
Total segment income from operations	$	39,395		$	13,508
Interest expense		(15,989	)		(12,900	)
Interest income		8,781			3,702
Other non-operating expense		(3,388	)		(3,388	)

Income before minority interest	$	28,799		$	922

Note L - Reclassifications

Certain amounts in the 2004 financial statements have been reclassified to conform with the classifications in the 2005 financial statements with no effect on previously reported net income or members’ equity

Note M — Supplemental Condensed Consolidating Financial Information

In accordance with the indenture governing the Arch Western Finance senior notes, certain wholly-owned subsidiaries of the Company have fully and unconditionally guaranteed the senior notes on a joint and several basis. The following tables present condensed consolidating financial information for (i) the Company, (ii) the issuer of the senior notes (Arch Western Finance, LLC, a wholly-owned subsidiary of the Company), (iii) the Company’s wholly-owned subsidiaries (Thunder Basin Coal Company, L.L.C., Mountain Coal Company, L.L.C., and Arch of Wyoming, LLC), on a combined basis, which are guarantors under the Notes, and (iv) its majority owned subsidiary (Canyon Fuel Company, LLC) which is not a guarantor under the Notes. Amounts included in the following consolidating condensed financial statements for Canyon Fuel represent amounts recorded by the Company under the equity method of accounting through July 31, 2004 and amounts consolidated by the Company subsequent to that date.

BALANCE SHEETS
March 31, 2005
(in thousands of dollars)
(Unaudited)


	Parent						Guarantor		Non-Guarantor
	Company			Issuer			Subsidiaries		Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—		$	—		$	336	$	8	$	—		$	344
Trade accounts receivable		97,852			—			538		16,259		—			114,649
Other receivables		—			—			1,292		3,943		—			5,235
Inventories		—			—			61,217		15,990		—			77,207
Prepaid royalties		—			—			7,082		5,094		—			12,176
Other current assets		4,769			—			3,341		3,999		—			12,109

Total current assets		102,621			—			73,806		45,293		—			221,720

Property, plant and equipment, net		—			—			827,279		267,907		—			1,095,186

Investment in subsidiaries		1,440,479			—			—		—		(1,440,479	)		—
Receivable from Arch Coal, Inc.		679,055			—			—		—		—			679,055
Intercompanies		(1,493,939	)		956,228			505,845		31,866		—			—
Other		319			17,669			25,050		—		—			43,038

Total other assets		625,914			973,897			530,895		31,866		(1,440,479	)		722,093

Total assets	$	728,535		$	973,897		$	1,431,980	$	345,066	$	(1,440,479	)	$	2,038,999

Accounts payable		8,218			—			43,474		11,971		—			63,663
Accrued expenses		3,893			16,031			90,102		6,420		—			116,446

Total current liabilities		12,111			16,031			133,576		18,391		—			180,109
Long-term debt		—			961,272			—		—		—			961,272
Accrued postretirement benefits other than pension		14,535			—			2,485		7,632		—			24,652
Asset retirement obligations		—			—			117,280		11,823		—			129,103
Accrued workers’ compensation		6,125			—			1,173		4,817		—			12,115
Other noncurrent liabilities		4,831			—			5,129		30,855		—			40,815

Total liabilities		37,602			977,303			259,643		73,518		—			1,348,066

Minority interest		112,128			—			—		—		—			112,128

Redeemable equity interests		5,125			—			—		—		—			5,125
Non-redeemable members’ equity		573,680			(3,406	)		1,172,337		271,548		(1,440,479	)		573,680

Total liabilities, redeemable equity interests and non-redeemable members’ equity	$	728,535		$	973,897		$	1,431,980	$	345,066	$	(1,440,479	)	$	2,038,999

BALANCE SHEETS
December 31, 2004
(in thousands of dollars)
(Unaudited)


	Parent						Guarantor		Non-Guarantor
	Company			Issuer			Subsidiaries		Subsidiaries		Eliminations			Consolidated
Cash and cash equivalents	$	—		$	—		$	1,185	$	166	$	—		$	1,351
Trade accounts receivable		70,443			—			449		12,338		—			83,230
Other receivables		—			—			1,040		4,651		—			5,691
Inventories		—			—			58,815		19,557		—			78,372
Prepaid royalties		—			—			2,660		5,132		—			7,792
Other current assets		4,894			—			2,034		4,601		—			11,529

Total current assets		75,337			—			66,183		46,445		—			187,965

Property, plant and equipment, net		—			—			834,265		267,409		—			1,101,674

Investment in subsidiaries		1,393,809			—			—		—		(1,393,809	)		—
Receivable from Arch Coal, Inc.		677,934			—			—		—		—			677,934
Intercompanies		(1,451,422	)		973,310			449,449		28,663		—			—
Other		1,225			18,246			26,392		—		—			45,863

Total other assets		621,546			991,556			475,841		28,663		(1,393,809	)		723,797

Total assets	$	696,883		$	991,556		$	1,376,289	$	342,517	$	(1,393,809	)	$	2,013,436

Accounts payable		8,854			—			35,942		11,816		—			56,612
Accrued expenses		4,482			33,360			84,660		6,933		—			129,435

Total current liabilities		13,336			33,360			120,602		18,749		—			186,047
Long-term debt		—			961,613			—		—		—			961,613
Accrued postretirement benefits other than pension		14,576			—			2,485		7,582		—			24,643
Asset retirement obligations		—			—			116,627		11,557		—			128,184
Accrued workers’ compensation.		6,018			—			1,527		5,204		—			12,749
Other noncurrent liabilities		5,523			—			5,128		32,119		—			42,770

Total liabilities		39,453			994,973			246,369		75,211		—			1,356,006

Minority interest		109,401			—			—		—		—			109,401

Redeemable equity interests		4,971			—			—		—		—			4,971
Non-redeemable members’ equity		543,058			(3,417	)		1,129,920		267,306		(1,393,809	)		543,058

Total liabilities, redeemable equity interests and non-redeemable members’ equity	$	696,883		$	991,556		$	1,376,289	$	342,517	$	(1,393,809	)	$	2,013,436

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

o   Any inability to comply with restrictions imposed by the Indenture governing our debt could result in a default under this agreement.

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

Quarter Ended March 31, 2005, Compared to Quarter Ended March 31, 2004

Items Affecting Comparability of Reported Results

The comparison of our operating results for the quarters ending March 31, 2005 and 2004 are affected by the following significant items:


	Quarter ended March 31
(Amounts in millions)	2005			2004
Operating Income
Gain from equipment sale	$	1.6		$	—
Reclamation fee assessment		—			(1.3	)
Severance costs — Skyline Mine		—			(1.2	)

Net increase (decrease) in operating income	$	1.6		$	(2.5	)
Other
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps		(3.4	)		(3.4	)
Reclamation fee assessment — interest portion		—			(0.2	)

Net (decrease) in pre-tax income	$	(1.8	)	$	(6.1	)

Gain from equipment sale

During the quarter ended March 31, 2005, we recognized a gain of $1.6 million from the sale of equipment. The gain is reported as other operating income.

Reclamation fee assessment

During the quarter ended March 31, 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.

Severance costs — Skyline Mine

During the first quarter of 2004, Canyon Fuel, while accounted for under the equity method, began the process of idling its Skyline Mine, and incurred severance costs of $1.9 million. Our share of these costs totals $1.2 million and is reflected in income from equity investments.

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

On June 25, 2003, we repaid our term loan 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 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 quarters ending March 31, 2005 and 2004, we recognized expense of $3.4 million for both periods, related to the amortization of previously deferred mark-to-market adjustments.

Revenues


	Three Months Ended
	March 31,				Increase (Decrease)
	2005		2004		$		%
			(Amounts in thousands, except per ton data)
Coal sales	$	277,416	$	139,848	$	137,568		98.4	%
Tons sold		27,916		17,903		10,013		55.9	%
Coal sales realization per ton sold	$	9.94	$	7.81	$	2.13		27.3	%

Tons sold by operating segment


	Tons Sold				% of Total
	March 31, 2005		March 31, 2004		March 31, 2005			March 31, 2004
	(Amounts in thousands)
Powder River Basin		23,117		16,159		82.8	%		90.3	%
Western Bituminous Region		4,799		1,744		17.2	%		9.7	%

Total operating regions		27,916		17,903		100.0	%		100.0	%

Coal sales. The increase in coal sales resulted from the combination of higher pricing and increased volumes primarily from the addition of the North Rochelle mining operations and the consolidation of Canyon Fuel.

Volumes increased dramatically in both the Powder River Basin (an increase of 43.1%) and at our Western Bituminous operations (an increase 175.2%). These increases were primarily due to additional volumes from the Black Thunder mine following the contribution of the North Rochelle assets and to the consolidation of Canyon Fuel volumes in the current quarter.

Per ton realizations increased due primarily to higher contract prices in both regions. In the Powder River Basin, per ton realization increased 13.9%, including above-market pricing on certain contracts that were contributed to us through Arch Coal’s acquisition of the North Rochelle operations. The Western Bituminous region’s per ton realization increased 19.9%. In addition to higher contract pricing, per ton realizations in the Western Bituminous Basin were also affected by the consolidation of Canyon Fuel during the third quarter of 2004.

Costs and Expenses


	Three Months Ended
	March 31,				Increase (Decrease)
	2005		2004		$		%
	(Amounts in thousands)
Cost of coal sales	$	209,105	$	111,092	$	98,013		88.2	%
Depreciation, depletion and amortization		25,519		16,636		8,883		53.4	%
Selling, general and administrative expenses		5,690		4,211		1,479		35.1	%

	$	240,314	$	131,939	$	108,375		82.1	%

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 (note that the increases discussed below are partially due to the addition of the North Rochelle operations and the consolidation of Canyon Fuel during the third quarter of 2004):

•   Production taxes and coal royalties (which are incurred as a percentage of coal sales realization) increased $24.2 million.

•   Repairs and maintenance costs increased $13.1 million.

•   Costs for diesel fuel and utilities increased $5.6 million and $2.5 million, respectively.

• Costs for operating supplies increased $13.7 million due partially to increased commodity and steel prices during the current quarter compared to the prior year’s comparable quarter.

Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property additions resulting from the consolidation of Canyon Fuel and the contribution of North Rochelle during the third quarter of 2004.

Regional Analysis:

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


	Three Months Ended March 31,				Increase (Decrease)
	2005		2004		$			%
Powder River Basin	$	6.37	$	6.01	$	0.36			6.0	%
Western Bituminous Region	$	15.20	$	16.86	$	(1.66	)		(9.8	)%

Powder River Basin — On a per-ton basis, operating costs increased in the Powder River Basin primarily due to increased production taxes and coal royalties ($0.17 per ton) and repairs and maintenance charges ($0.14 per ton) and to the utilities 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 in the third quarter of 2004.

Western Bituminous Region — Operating cost per ton decreased primarily due to increased production activity as a result of the consolidation of Canyon Fuel during the third quarter of 2004. Canyon Fuel’s mines in the aggregate have a lower operating cost per ton than the West Elk mine.

Selling, general and administrative expenses. Selling, general and administrative expenses represent expenses allocated to us from Arch Coal. The increase is due primarily to increases in compensation-related expenses at Arch Coal.

Other Operating Income


	Three Months Ended
	March 31,				Increase (Decrease)
	2005		2004		$			%
	(Amounts in thousands)
Income from equity investment	$	—	$	1,272	$	(1,272	)		(100.0	)%
Other operating income		2,293		4,327		(2,034	)		(47.1	)%

	$	2,293	$	5,599	$	(3,306	)		(59.0	)%

Other operating income. The decrease in other operating income is primarily due to $2.0 million in administration charges and production payments received from Canyon Fuel in the first quarter of 2004 (these payments ceased as of the July 31, 2004 consolidation of Canyon Fuel in our financial statements).

Interest Expense, Net


	Three Months Ended
	March 31,						Increase (Decrease)
	2005			2004			$			%
	(Amounts in thousands)
Interest expense	$	(15,989	)	$	(12,900	)	$	(3,089	)		23.9	%
Interest income		8,781			3,702			5,079			137.2	%

	$	(7,208	)	$	(9,198	)	$	1,990			(21.6	)%

Interest expense. The increase in interest expense results from a higher amount of average borrowings in first three months of 2005 as compared to the same period in 2004.

Interest Income. Our cash transactions are managed by Arch Coal. Cash paid to or from us that is not considered a distribution or a contribution is recorded as a receivable from Arch Coal. The receivable balance earns interest from Arch Coal at the prime interest rate. The increase in interest income results primarily from a higher average receivable balance in the first three months of 2005 as compared to the same period in 2004.

Other Non-operating Income and Expense


	Three Months Ended
	March 31,						Increase (Decrease)
	2005			2004			$		%
				(Amounts in thousands)
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps	$	(3,388	)	$	(3,388	)	$	—		N/A

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 quarters ended March 31, 2005 and 2004 include expenses of $3.4 million for both periods, related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred.

Income before minority interest


	Three Months Ended
	March 31,				Increase (Decrease)
	2005		2004		$		%
			(Amounts in thousands)
Income before minority interest	$	28,799	$	922	$	27,877	N/A

The increase in net income is primarily due to higher operating margins resulting from higher coal sales revenues and the effects of the North Rochelle contribution.

DISCLOSURE AND INTERNAL CONTROLS

An evaluation was performed under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2005. 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 changes in our internal controls or in other factors that could significantly affect internal controls subsequent to March 31, 2005.

OUTLOOK

Railroad Transportation Disruptions. During 2004 and again in early 2005, rail service disruptions resulted in missed shipments in both of our operating regions. In addition, we were periodically forced to curtail production at the West Elk mine in Colorado and the Black Thunder mine in Wyoming due to high inventory levels stemming from insufficient rail service.

The railroad disruptions, which initially resulted from inadequate staffing at the railroads, equipment shortages and an unexpected increase in overall rail shipments, improved in both of our operating regions during the latter part of the first quarter of 2005. We anticipate continued improvement with rail service in the second quarter of 2005.

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 $44.0 million were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the original contractual terms of the swap agreements. As of December 31, 2004, the remaining deferred amounts will be recognized as expense in the following periods: $12.7 million in 2005 ($3.4 million was recognized in the first quarter of 2005); $7.9 million in 2006; and $3.1 million in 2007.

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 three months ended March 31, 2005 and 2004:


	2005			2004
	(in thousands)
Cash provided by (used in):
Operating activities	$	29,024		$	(8,031	)
Investing activities		(29,980	)		(26,949	)
Financing activities		(51	)		(97	)

Cash provided by operating activities increased in the quarter ended March 31, 2005 as compared to the same period in 2004 primarily as a result of improved operating performance and the change in the receivable from Arch Coal, which remained relatively flat during the three months ended March 31, 2005 compared to a $31.5 million increase in the prior year’s comparable quarter.

Cash used in investing activities in the first quarter of 2005 reflects capital expenditures and advance royalty payments of $21.9 million and $10.0 million, respectively, offset partially by proceeds from the sale of equipment of $1.9 million. Cash provided by investing activities in the first quarter of 2004 reflects capital expenditures and advance royalty payments of $17.0 million and $10.0 million, respectively.

Capital expenditures were $21.9 million and $17.0 million for the three months ended March 31, 2005 and 2004, 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 $140.0 million in total for 2005. This estimate includes capital expenditures related to development work at the North Lease mine in Utah at the currently idled Skyline complex. 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 cash generated from operations.

We generally satisfy our working capital requirements and fund our capital expenditures and debt-service obligations with cash generated from operations and, if necessary cash from Arch Coal. We believe that cash generated from operations will be sufficient to meet our working capital requirements and anticipated capital expenditures for the next several years. Our ability to fund planned capital expenditures and meet our debt-service obligations will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry, and by financial, business and other factors, some of which are beyond our control.

On October 22, 2004, Arch Western Finance issued $250 million of 6-3/4% senior notes due 2013 at a price of 104.75% of par. The notes form a single series with Arch Western Finance’s existing $700 million, 6-3/4% senior notes due 2013. The net proceeds of the offering were used to repay and retire the outstanding indebtedness under our $100.0 million term loan maturing in 2007, with the remainder loaned to Arch Coal.

The terms of our LLC Agreement provide for a preferred return distribution in an amount equal to 4% of the preferred capital balance, which was $2.4 million as of December 31, 2004. Except for the preferred return distribution, distributions may generally be made at such times and in such amounts as Arch Coal, as the managing member, determines. We have historically made no distributions other than the preferred return.

We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At March 31, 2005, all of our outstanding debt bore interest at fixed rates.

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

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

instruments are described in Note 2 to our consolidated financial statements as of and for the year ended December 31, 2004 as filed on our Annual Report on Form 10-K with the Securities and Exchange Commission.

At March 31, 2005, our debt portfolio consisted entirely of fixed rate debt. A change in interest rates on the fixed rate debt impacts the net financial instrument position but has no impact on interest incurred or cash flows. The sensitivity analysis related to our fixed rate debt assumes an instantaneous 100-basis point move in interest rates from their levels at March 31, 2005, with all other variables held constant. A 100-basis point increase in market interest rates would result in a $57.2 million decrease in the fair value of the Company’s fixed rate debt at March 31, 2005. At March 31, 2005, a $.05 per gallon increase in the price of heating oil would result in a $0.2 million increase in the fair value of the financial position of the heating oil swap agreements.

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 Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (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.

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 March 31, 2005, we had outstanding consolidated indebtedness of $961.3 million, representing approximately 62% of our capital employed. We also have significant lease and royalty obligations. Our ability to satisfy our debt, lease and royalty obligations, and our ability to refinance our indebtedness, will depend upon our future operating performance, which will be affected by prevailing economic conditions in the markets that we serve and 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 financing may be unavailable in an amount sufficient to enable us to fund our future financial obligations or our other liquidity needs. The amount and terms of our debt could have material consequences to our business, including, but not limited to:

•   making it more difficult for us to satisfy our debt covenants and debt service, lease payment and other obligations;

•   increasing our vulnerability to general adverse economic and industry conditions;

•   limiting our ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general operating requirements;

•   reducing the availability of cash flow from operations to fund acquisitions, working capital, capital expenditures or other general operating purposes;

•   limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; and

•   placing us at a competitive disadvantage when compared to competitors with less relative amounts of debt.

The indenture governing our Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to:

•   incur more debt;

•   make distributions;

•   make investments;

•   create liens;

•   issue and sell capital stock of subsidiaries;

•   sell assets;

•   enter into restrictions affecting the ability of restricted subsidiaries to make distributions, loans or advances to us;

•   engage in transactions with affiliates;

•   enter into sale and leasebacks; and

•   merge or consolidate or transfer and sell assets.

These restrictions on operations and financings, as well as those that may be contained in future debt agreements, may limit our ability to execute preferred business strategies.

Profitability

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

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

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

•   disruption or increases in the cost of transportation services;

•   changes in laws or regulations, including permitting requirements;

•   litigation;

•   work stoppages or other labor difficulties;

•   labor shortages;

•   mine worker vacation schedules and related maintenance activities; and

•   changes in coal market and general economic conditions.

Environmental and Regulatory Factors

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

•   the discharge of materials into the environment;

•   employee health and safety;

•   mine permits and other licensing requirements;

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

•   management of materials generated by mining operations;

•   surface subsidence from underground mining;

•   water pollution;

•   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.

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

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

The EPA has also initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired

power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. By imposing limitations upon the placement and construction of new coal-fired power plants, the EPA’s regional haze program could affect the future market for coal.

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

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

In March 2005, the EPA issued (i) the Clean Air Interstate Rule (CAIR), which permanently caps emissions of sulfur dioxide (SO2) and nitrogen oxides (NOx) in the eastern United States; and (ii) the Clean Air Mercury Rule (CAMR) to permanently cap and reduce mercury emissions from coal-fired power plants. CAIR requires reductions of SO2 and/or NOx emissions across 28 eastern states and the District of Columbia and, when fully implemented in 2015, CAIR will reduce SO2 emissions in these states by over 70 percent and NOx emissions by over 60 percent from 2003 levels. Under the new mercury emissions rule, which takes effect in May 2005, coal-fired power plants have until 2010 to cut mercury emission levels to 38 tons a year from 48 tons. Plants then have until 2018 to bring that level down to 15 tons, a 69 percent reduction. Utility analysts have estimated meeting those goals will cost power generators approximately $50 billion to install the required filtration systems, or “scrubbers,” on their smokestacks. Both rules also provide power plant operators a market-based system (“cap and trade program”) in which plants that exceed federal requirements can sell pollution credits to plant operators who need more time to comply with the stricter rules. The additional costs that may be associated with operating coal-fired power generation facilities due to the implementation of these new rules 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.

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

Surface Mining Control and Reclamation Act. SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we are contractually obligated under the terms of our leases to comply with all laws, including SMCRA and equivalent state and local

laws. These obligations include reclaiming and restoring the mined areas by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.

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

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 trigger 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 or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

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

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically we submit the necessary permit applications several months before we plan to begin mining a new area. In our experience, permits generally are approved several months after a completed application is submitted. In the past, we

have generally obtained our mining permits without significant delay. However, we cannot be sure that we will not experience difficulty in obtaining mining permits in the future.

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

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

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

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

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

Competition

The coal industry is intensely competitive, primarily as a result of the existence of numerous producers in the coal-producing regions in which we operate, and some of our competitors may have greater financial resources. We compete with several major and smaller coal producers.

Electric Industry Factors

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

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

Terms of Long-Term Coal Supply Contracts

During 2004, sales of coal under long-term contracts, which are contracts with a term greater than 12 months, accounted for 67% 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 three months ended March 31, 2005, the weighted average price of coal sold under our long-term contracts was $10.36 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 may allow the customer to elect volume flexibility, our ability to realize the higher prices that may be available on the spot market may be restricted when customers elect to purchase higher volumes under such contracts. Our exposure to market-based pricing may also be increased should customers elect to purchase fewer tons. In addition, the increasingly short terms of sales contracts and the consequent absence of price adjustment provisions in such contracts make it more likely that we will not be able to recover inflation related increases in mining costs during the contract term.

Reserve Depletion

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We have in the past acquired and will in the future acquire coal reserves for our mine portfolio from third parties. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition.

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 Black Thunder mine in Wyoming, would result in a decrease, which could be material, in our revenues and profitability.

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 reserves, may vary from estimates, and such variances may be material. These estimates thus may not accurately reflect our actual reserves.

The majority 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.

Certain Contractual Arrangements

The agreement under which we were formed provides that Arch Western Acquisition Corporation, as managing member, generally has exclusive power and authority to conduct, manage and control our business. However, consent of BP p.l.c., our other member would generally be required in the event that we propose to make a distribution, incur indebtedness, sell properties or merge or consolidate with any other entity if, at such time, we have a debt rating less favorable than specified ratings with Moody’s Investors Service or Standard & Poor’s or fail to meet specified indebtedness and interest ratios.

The membership interests in Canyon Fuel, which operates three coal mines in Utah, were owned 65% by us and 35% by a subsidiary of ITOCHU Corporation of Japan until July 30, 2004 when Arch Coal 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.

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

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 6. EXHIBITS

(a)


3.1		Certificate of Formation (incorporated herein by reference to Exhibit 3.3 to the Form S-4 (File No. 333-107569) filed on August 1, 2003 by Arch Western Finance, LLC, Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., and Thunder Basin Coal Company, L.L.C.).

3.2		Limited Liability Company Agreement (incorporated herein by reference to Exhibit 3.4 to the Form S-4 (File No. 333-107569) filed on August 1, 2003 by Arch Western Finance, LLC, Arch Western Resources, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., and Thunder Basin Coal Company, L.L.C.).

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

4.2		First Supplemental Indenture, dated October 22, 2004, by and among Arch Western Finance, LLC, Arch Western Resources, LLC, Arch Western Bituminous Group, LLC, Arch of Wyoming, LLC, Mountain Coal Company, L.L.C., Thunder Basin Coal Company, L.L.C., Triton Coal Company, LLC and The Bank of New York, as trustee (incorporated herein by reference to Exhibit 4.4 to the Current Report on Form 8-K filed by Arch Coal, Inc. and Arch Western Resources, LLC on October 23, 2004).

4.3		Form of 6 3/4% Senior Notes due 2013 (included in Exhibit 4.1).

4.4		Form of Guarantee of 6 3/4% Senior Notes due 2013 (included in Exhibit 4.1).


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		Statement Under Oath 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		Statement Under Oath of Principal Financial Officer Pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002.


	PAGE
PART I. FINANCIAL INFORMATION		3
Item 1. Financial Statements		3
Condensed Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004		3
Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2005 and 2004		4
Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2005 and 2004		5
Notes to Condensed Consolidated Financial Statements		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3. Quantitative and Qualitative Disclosures About Market Risk		32
Item 4. Controls and Procedures		33
PART II. OTHER INFORMATION		33
Item 1. Legal Proceedings		33
Item 6. Exhibits		33
Certification of Principal Executive Officer
Certification of Principal Financial Officer
Statement Under Oath of Principal Executive Officer
Statement Under Oath of Principal Financial Officer


		ARCH WESTERN RESOURCES, LLC (Registrant)

Date: May 12, 2005		/s/ Robert J. Messey

		Robert J. Messey
		Vice President
		(Chief Accounting Officer)

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						Guarantor			Non-Guarantor
	Parent Company			Issuer		Subsidiaries			Subsidiaries			Consolidated
Operating Activities
Cash provided by (used in) operating activities	$	(734	)	$	—	$	(8,128	)	$	831		$	(8,031	)
Investing Activities
Capital expenditures		—			—		(16,955	)		—			(16,955	)
Proceeds from dispositions of capital assets		—			—		6			—			6
Additions to prepaid royalties		—			—		(10,000	)		—			(10,000	)

Cash (used in) investing activities		—			—		(26,949	)		—			(26,949	)

Financing Activities
Debt financing costs		(97	)		—		—			—			(97	)
Transactions with affiliates		831			—		—			(831	)		—

Cash provided by (used in) financing activities		734			—		—			(831	)		(97	)

Decrease in cash and cash equivalents		—			—		(35,077	)		—			(35,077	)
Cash and cash equivalents, beginning of period		—			—		35,171			—			35,171

Cash and cash equivalents, end of period	$	—		$	—	$	94		$	—		$	94

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

	o	Any inability to comply with restrictions imposed by the Indenture governing our debt could result in a default under this agreement.

	•	Production taxes and coal royalties (which are incurred as a percentage of coal sales realization) increased $24.2 million.

	•	Repairs and maintenance costs increased $13.1 million.

	•	Costs for diesel fuel and utilities increased $5.6 million and $2.5 million, respectively.

	•	making it more difficult for us to satisfy our debt covenants and debt service, lease payment and other obligations;

	•	increasing our vulnerability to general adverse economic and industry conditions;

	•	limiting our ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general operating requirements;

	•	reducing the availability of cash flow from operations to fund acquisitions, working capital, capital expenditures or other general operating purposes;

	•	limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; and

	•	placing us at a competitive disadvantage when compared to competitors with less relative amounts of debt.

	•	incur more debt;

	•	make distributions;

	•	make investments;

	•	create liens;

	•	issue and sell capital stock of subsidiaries;

	•	sell assets;

	•	enter into restrictions affecting the ability of restricted subsidiaries to make distributions, loans or advances to us;

	•	engage in transactions with affiliates;

	•	enter into sale and leasebacks; and

	•	merge or consolidate or transfer and sell assets.

	•	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.

	•	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;

	•	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.

	•	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.

	•	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.