SECURITIES AND EXCHANGE COMMISSION

Form 10-Q

(Mark One)

ARCH COAL, INC.

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

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

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

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

At May 1, 2004, there were 54,628,085 shares of registrant’s common stock outstanding.

INDEX

PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ARCH COAL, INC. AND SUBSIDIARIES

See notes to condensed consolidated financial statements.

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ARCH COAL, INC. AND SUBSIDIARIES

See notes to condensed consolidated financial statements.

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ARCH COAL, INC. AND SUBSIDIARIES

See notes to condensed consolidated financial statements.

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 2004
(UNAUDITED)

Note A – General

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

Arch Coal, Inc. (the “Company”) is engaged in the production of steam and metallurgical coal from surface and deep mines throughout the United States, for sale to utility, industrial and export markets. The Company’s mines are primarily located in the central Appalachian and western regions of the United States. All subsidiaries (except as noted below) are wholly owned. Intercompany transactions and accounts have been eliminated in consolidation.

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

The membership interests in the Utah coal operations, Canyon Fuel Company, LLC (“Canyon Fuel”), are owned 65% by Arch Western and 35% by a subsidiary of ITOCHU Corporation. The Company’s 65% ownership of Canyon Fuel is accounted for on the equity method in the Condensed Consolidated Financial Statements as a result of certain super-majority voting rights in the joint venture agreement. Income from Canyon Fuel is reflected in the Condensed Consolidated Statements of Operations as income from equity investments (see additional discussion in Note E – “Equity Investments”).

Note B – Acquisition of Triton Coal Company, LLC

On May 29, 2003, the Company entered into a definitive agreement to acquire (1) Vulcan Coal Holdings, L.L.C. (“Vulcan”), which owns all of the common equity of Triton Coal Company, LLC (“Triton”), and (2) all of the preferred units of Triton, for an aggregate purchase price of $364.0 million, subject to working capital adjustments. Consummation of the transaction is subject to various conditions, including the receipt by the Company and Vulcan of all necessary governmental and regulatory consents and other customary conditions. The Company intends to finance the acquisition with cash, borrowings under its existing revolving credit facility and a $100.0 million term loan facility at its Arch Western subsidiary.

On January 30, 2004, the Company entered into an agreement to sell the Buckskin mine to Peter Kiewit and Sons’ Inc. for a purchase price of approximately $82.0 million. The completion of the sale of the Buckskin mine is contingent on, among other things, the completion of the Company’s acquisition of Triton.

In April 2004, the Federal Trade Commission filed a lawsuit in U.S. District Court to block the Company's proposed acquisition of Triton. The Company continues to view the acquisition of Triton as pro-competitive and plans to defend the transaction in a hearing scheduled to begin on June 21, 2004.

As of March 31, 2004, the Company has capitalized legal and other costs associated with the acquisition totaling $4.6 million. In addition, the Company is obligated to pay $2.9 million of retention bonuses to Vulcan employees. In the event the transaction is not consummated, these costs will be expensed.

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Note C – Adoption of FAS 143

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

The cumulative effect of the change on prior years resulted in a charge to income of $3.7 million (net of income taxes of $2.3 million), or $0.07 per share, which is included in the Company’s results of operations for the quarter ended March 31, 2003.

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

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Note D – Stock-Based Compensation

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

Note E – Equity Investments

The Company’s equity investments are comprised of its ownership interests in Canyon Fuel and Natural Resource Partners, LP (“NRP”). Amounts recorded in the Condensed Consolidated Financial Statements are as follows:

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Investment in Canyon Fuel

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

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.

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

Investment in NRP

During the quarter ended March 31, 2004, the Company sold the majority of its remaining limited partnership units of NRP for proceeds of approximately $100 million. The sale results in a gain of $81.5 million. Subsequent to the sale, the Company’s remaining investment in NRP totals approximately 279 thousand shares, representing 1.2% of NRP’s total equity interests. At this level of ownership, the investment is no longer accounted for on the equity method, but is accounted for in accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities (“FAS 115”). FAS 115 requires the investment to be marked to its market value at each reporting period. Because it is the Company’s intention to sell its remaining units, the units have been classified as trading securities. Changes in the value of trading securities are recorded as income or expense in the period of change. During the quarter ended March 31, 2004, the Company recorded a mark-to-market gain for its investment in NRP units of $8.2 million. The mark-to-market gain is recorded as a component of other operating income in the accompanying Condensed Consolidated Statements of Operations. At March 31, 2004, the Company has classified its remaining investment in NRP as a current asset based on management’s intention to sell the investment within the next year.

Prior to the sale of the limited partnership units, the Company recorded income under the equity method of accounting for its investment in NRP of $2.4 million for the period from December 2003 through February 2004.

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Note F – Employee Benefit Plans

Defined Benefit Pension and Other Postretirement Benefit Plans

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

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

Components of Net Periodic Benefit Cost

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

Employer Contributions

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

Impact of Medicare Prescription Drug, Improvement and Modernization Act of 2003

On December 8, the President signed into law the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”). The Act introduces a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree heath care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company has included the effects of the Act in its financial statements for the quarter ending March 31, 2004 in accordance with FASB Staff Position No. FAS 106-b, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“FSP 106-b”). Incorporation of the provisions of the Act resulted in a reduction of the Company’s postretirement benefit obligation of $68.0 million. Postretirement medical expenses for fiscal year 2004 after implementation are expected to be $18.1 million less than that previously anticipated. Results for the quarter ending March 31, 2004 include $4.5 million of this total.

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Note G – Other Comprehensive Income

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

Other comprehensive income for the quarter ended March 31, 2004 consists primarily of the reclassification of previously deferred mark-to-market loss from other comprehensive income to net income and mark-to-market adjustments related to the Company’s financial derivatives which still qualify as effective hedges. Other comprehensive loss for the quarter ended March 31, 2003 represents mark-to-market adjustments related to the Company’s financial derivatives positions as all positions were deemed to be effective hedges in that period.

Note H – Inventories

Inventories consist of the following:

Note I – Debt

Debt consists of the following:

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

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payable on January 1 and July 1 each year commencing January 1, 2004. The senior notes are guaranteed by Arch Western and certain of Arch Western’s subsidiaries and are secured by a security interest in loans made to Arch Coal by Arch Western. The terms of the senior notes contain restrictive covenants that limit Arch Western’s ability to, among other things, incur additional debt, sell or transfer assets, and make investments.

On September 19, 2003, Arch Western established a $100 million term loan facility. The facility is subject to certain conditions of borrowing, including the consummation of the Company’s anticipated acquisition of Vulcan (Triton). Currently, no amount is available to the Company under the facility. If Arch Western borrows pursuant to the terms of the facility, the loan will be due in quarterly installments from October 2004 through April 2007.

Note J – Contingencies

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

Note K – Transactions or Events Affecting Comparability of Reported Results

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 the Company being assessed additional fees of $1.3 million and interest of $0.2 million. The additional fees have been recorded as a component of cost of coal sales in the accompanying Condensed Consolidated Statements of Operations, while the interest portion has been reflected as interest expense.

During the first quarter of 2004, Canyon Fuel, the Company’s equity method investment, 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 investments in the Condensed Consolidated Statements of Operations.

On June 25, 2003, Arch Western repaid its term loans with the proceeds from the offering of senior notes. The Company had designated certain interest rate swaps as hedges of the variable rate interest payments due under the Arch Western term loans. Pursuant to the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS 133”), historical mark-to-market adjustments related to these swaps through June 25, 2003 were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the contractual terms of the swap agreements. For the three months ending March 31, 2004, the Company recognized $2.1 million of expense related to the amortization of previously deferred mark-to-market adjustments.

In the quarter ended March 31, 2003, the Company received $1.4 million from a customer that did not meet its contractual purchase requirements. This amount has been recorded as other operating income in the accompanying Condensed Consolidated Statements of Operations.

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Note L — Earnings (Loss) per Share

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

For the three month period ending March 31, 2003, employee stock options did not have a dilutive impact because the Company incurred a loss in that period. The Company’s Perpetual Cumulative Convertible Preferred Stock was not considered in the calculation of the number of diluted shares outstanding at March 31, 2003 because the conditions necessary for the shares to become convertible had not been met at that time.

Note M – Guarantees

The Company holds a 17.5% general partnership interest in Dominion Terminal Associates (“DTA”), which operates a ground storage-to-vessel coal transloading facility in Newport News, Virginia. DTA leases the facility from Peninsula Ports Authority of Virginia (“PPAV”) for amounts sufficient to meet debt-service requirements. Financing is provided through $132.8 million of tax-exempt bonds issued by PPAV (of which the Company is responsible for 17.5%, or $23.2 million) which mature July 1, 2016. Under the terms of a throughput and handling agreement with DTA, each partner is charged its share of cash operating and debt-service costs in exchange for the right to use its share of the facility’s loading capacity and is required to make periodic cash advances to DTA to fund such costs. On a cumulative basis, costs exceeded cash advances by $13.4 million at March 31, 2004 (such amount is included in other noncurrent liabilities). Future payments for fixed operating costs and debt service are estimated to approximate $2.4 million annually through 2015 and $26.0 million in 2016.

In connection with the Company’s acquisition of the coal operations of Atlantic Richfield Company (“ARCO”) and the simultaneous combination of the acquired ARCO operations and the Company’s Wyoming operations into the Arch Western joint venture, the Company agreed to indemnify another member of Arch Western against certain tax liabilities in the event that such liabilities arise as a result of certain actions taken prior to June 1, 2013, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. Depending on the time at which any such indemnification obligation were to arise, it could have a material adverse effect on the business, results of operations and financial condition of the Company.

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Note N – Segment Information

The Company produces steam and metallurgical coal from surface and deep mines for sale in utility, industrial and export markets. The Company operates only in the United States, with mines in the major low-sulfur coal basins. The Company has two reportable business segments: Eastern Operations and Western Operations. The Company’s Eastern Operations are located in the Central Appalachian region (defined as southern West Virginia, eastern Kentucky, and Virginia) and include 15 underground mines and eight surface mines. The Company’s Western Operations are located in Wyoming, Colorado and Utah (through the Company’s equity investment in Canyon Fuel). Including Canyon Fuel, the Western Operations include four underground mines and three surface mines.

Operating segment results for the quarters ending March 31, 2004 and 2003 are presented below. Results for the operating segments include all direct costs of mining. Corporate, Other and Eliminations includes corporate overhead, land management, other support functions, and the elimination of intercompany transactions.

March 31, 2004

March 31, 2003

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

Note O — Reclassifications

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

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

FORWARD-LOOKING STATEMENTS

Statements in this quarterly report which are not statements of historical fact are forward-looking statements within the “safe harbor” provision of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on the information available to, and the expectations and assumptions deemed reasonable by, us at the time the statements are made. Because these forward-looking statements are subject to various risks and uncertainties, actual results may differ materially from those projected in the statements. These expectations, assumptions and uncertainties include: our expectation of growth in the demand for electricity; belief that legislation and regulations relating to the Clean Air Act and the relatively higher costs of competing fuels will increase demand for our compliance and low-sulfur coal; expectation of improved market conditions for the price of coal; expectation that we will continue to have adequate liquidity from our cash flow from operations, together with available borrowings under our credit facilities, to finance our working capital needs; a variety of operational, geologic, permitting, labor and weather related factors; and the other risks and uncertainties which are described below under “Contingencies” and “Certain Trends and Uncertainties.”

RESULTS OF OPERATIONS

Quarter Ended March 31, 2004, Compared to Quarter Ended March 31, 2003

Items Affecting Comparability of Reported Results

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

Gain on sale of NRP units

During the quarter ended March 31, 2004, we sold the majority of our remaining limited partnership units of Natural Resource Partners, LP (“NRP”) for proceeds of approximately $100 million. The sale resulted in a gain of $81.5 million.

Mark-to-market adjustment for NRP units

Subsequent to the sale of NRP units described above, our remaining investment in NRP totals approximately 279 thousand shares, representing 1.2% of NRP’s total equity interests. At this level of ownership, the investment is no

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longer accounted for on the equity method, but is accounted for in accordance with Statement of Financial Accounting Standards No. 115, Accounting for Certain Investments in Debt and Equity Securities (“FAS 115”). FAS 115 requires the investment to be marked to its market value at each reporting period. Because it is our intention to sell the remaining units, the units have been classified as trading securities. Changes in the value of trading securities are recorded as income or expense in the period of change. During the quarter ended March 31, 2004, we recorded a mark-to-market gain for the investment in NRP units of $8.2 million. The mark-to-market gain is recorded as a component of 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, our equity method investment, 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 the term loans of our subsidiary, Arch Western, with the proceeds from the offering of senior notes. Prior to the repayment, we had designated certain interest rate swaps as hedges of the variable rate interest payments due under the Arch Western term loans. Pursuant to the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS 133”), historical mark-to-market adjustments related to these swaps through June 25, 2003 were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the contractual terms of the swap agreements. For the quarter ending March 31, 2004, we recognized expense of $2.1 million, related to the amortization of previously deferred mark-to-market adjustments.

Gain from Coal Sales Contract Shortfall

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

Key operating results for the first quarter of 2004 versus the first quarter of 2003 and additional discussion of the results for the first quarter of 2004 are summarized below.

Revenues

Coal sales. The increase in coal sales resulted from the combination of increased volumes and higher pricing. Volumes increased significantly in both the Eastern operations (an 11.9% increase) and Western operations (a 13.5% increase). Per ton realizations increased in both regions as well due to higher contract prices in both regions and to higher metallurgical sales from the Eastern operations. The impact on coal sales from the mix in sales between Eastern coal and Western coal was not significant, as the mix was fairly constant between the two periods.

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Costs and Expenses

Cost of coal sales. The increase in cost of coal sales is primarily due to the increase in coal sales revenues, as certain of our costs (including severance and other production taxes and coal royalties) are incurred as a percentage of coal sales realization. Production taxes and coal royalties increased $15.7 million in the first quarter of 2004 as compared to the first quarter of 2003. Additionally, the cost of purchased coal increased $4.6 million, reflecting the higher spot market prices that were prevalent during the first quarter of 2004. In addition, we faced increased costs for explosives ($3.2 million increase) and diesel fuel ($1.3 million increase) during the first quarter of 2004 as compared to the same period in 2003. We also incurred higher costs related to additional preparation necessary for coal sold in metallurgical markets.

On a per-ton basis, cost of coal sales at our Eastern Operations (including transportation costs and all costs related to idle operations) increased from $32.97 per ton in the first quarter of 2003 to $33.41 per ton in the first quarter of 2004. The increase in per ton costs at the Eastern Operations was due to increased production taxes and coal royalties ($7.8 million, or $0.88 per ton) as well as the increased preparation costs for metallurgical coal discussed above. These increases were partially offset by the impact of increased sales volumes (as fixed costs were spread over a larger sales volume) as well as cost savings realized from our 2003 cost cutting efforts and reduction in force.

At our Western Operations, cost of coal sales per ton (including transportation costs) increased to $7.18 per ton in the first quarter of 2004 from $6.84 per ton in the first quarter of 2003. The increase in per ton costs at the Western Operations is due primarily to increased production taxes and coal royalties ($8.2 million, or $0.23 per ton) and to the higher explosives and diesel fuel costs discussed above.

Our results for the quarter ending March 31, 2004 reflect the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”), in accordance with the provisions of FASB Staff Position No. FAS 106-b, Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. Incorporation of the provisions of the Act resulted in a reduction of our postretirement medical benefit obligation of $68.0 million. Postretirement medical expenses for fiscal year 2004 after incorporation of the provisions of the Act are expected to be $18.1 million less than that previously anticipated. Results for the quarter ending March 31, 2004 include $4.5 million of this total (substantially all of which is recorded as a component of cost of coal sales). The benefit for the quarter ending March 31, 2004 was offset by increased costs resulting from changes to other actuarial assumptions that were incorporated at the beginning of the year.

Selling, general and administrative expenses. Selling, general and administrative expenses increased during the quarter due primarily to higher expenses resulting from amounts expected to be earned under our annual and long-term incentive plans. During the quarter ended March 31, 2004, expenses related to annual bonus and long-term incentive plans totaled $4.5 million, as compared to expenses of $0.1 million in 2003.

Amortization of coal supply agreements. The decrease in amortization of coal supply agreements is due to the expiration of five contracts during the past year. During the first quarter of 2003, amortization of $5.2 million was recorded for these contracts, compared to no amortization in 2004.

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Other Operating Income

(Amounts in thousands)

     Income from equity investments. Income from equity investments for the quarter ending March 31, 2004 consists of $1.3 million from our investment in Canyon Fuel and $2.4 million from our investment in NRP (prior to the sale of NRP units in March). For the quarter ended March 31, 2003, income from equity investment consisted of $8.2 million of income from our investment in Canyon Fuel and $2.9 million from our investment in NRP. The decline in income from our investment in Canyon Fuel results from lower production and sales levels at Canyon Fuel and the costs related to idling the Skyline Mine, including the severance costs noted above.

     Other operating income. The increase in other operating income is primarily due to the mark-to-market gain on the remaining investment in NRP, as described above. Additionally, 2004 results include the recognition of $3.2 million of previously deferred gains from the 2003 NRP unit sale.

Interest Expense, Net

(Amounts in thousands)

Interest expense. The increase in interest expense results from a higher average interest rate in 2004 as compared to the same period in 2003. In 2004, the Company’s outstanding borrowings consist entirely of fixed rate borrowings, while 2003 borrowings were primarily variable rate borrowings. Short-term interest rates in 2003 were lower than the fixed rate of borrowing in 2004.

Other Non-operating Income and Expense

Amounts reported as non-operating consist of income or expense resulting from the Company’s financing activities other than interest. As described above, the Company’s results of operations for the quarter ended March 31, 2004 include expenses of $2.1 million related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred.

Income taxes

(Amounts in thousands)

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

Net income (loss) before cumulative effect of accounting change

(Amounts in thousands)

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

Cumulative effect of accounting change

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

DISCLOSURE CONTROLS

An evaluation was performed under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2004. Based on that evaluation, our management, including the CEO and CFO, concluded that the disclosure controls and procedures were effective as of such date. There have been no significant changes in our internal controls or in other factors that could significantly affect internal controls subsequent to March 31, 2004.

OUTLOOK

Vulcan Acquisition. On May 29, 2003, we entered into a definitive agreement to acquire (1) Vulcan Coal Holdings, L.L.C. (“Vulcan”), which owns all of the common equity of Triton Coal Company, LLC (“Triton”), and (2) all of the preferred units of Triton, for an aggregate purchase price of $364.0 million, subject to working capital adjustments. Consummation of the transaction is subject to various conditions, including the receipt by us and by Vulcan of all necessary governmental and regulatory consents and other customary conditions.

Triton is the nation’s seventh largest coal producer and the operator of two mines in the Powder River Basin. These mines, North Rochelle and Buckskin, produced a combined total of 42.2 million tons of coal in 2002 and were supported at that time by approximately 744 million tons of proven and probable reserves.

On January 30, 2004, we entered into an agreement to sell the Buckskin mine to Peter Kiewit and Sons’ Inc. for a purchase price of approximately $82.0 million. The completion of the sale of the Buckskin mine is contingent, among other things, on the completion of our acquisition of Triton.

In April 2004, the Federal Trade Commission filed a lawsuit in U.S. District Court to block our proposed acquisition of Triton. We view the acquisition of Triton as pro-competitive and plan to defend the transaction in a hearing scheduled to begin on June 21, 2004.

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In 2002, the North Rochelle mine produced 23.9 million tons of 8,800 Btu super-compliance quality coal on a reserve base of approximately 250 million tons. The acquisition of the North Rochelle mine will increase our total reserves in the Powder River Basin by approximately 15%, from 1.6 billion tons to 1.84 billion tons (based on 2002 Triton reserve estimates). North Rochelle and Black Thunder are contiguously located, sharing a 5.5-mile property line. We have identified expected synergies, based on Triton’s 2002 earnings, of approximately $18 million to $22 million annually that may be realized through the elimination of overhead and the operational integration of Triton’s North Rochelle mine and the Black Thunder mine. We intend to finance the acquisition with cash, borrowings under our existing revolving credit facility and a $100 million term loan at our Arch Western subsidiary.

We have capitalized the legal and other costs associated with our acquisition of Vulcan as part of its purchase price. In the event the transaction is not consummated, such costs will be immediately expensed. As of March 31, 2004, costs associated with the Vulcan acquisition totaled $4.6 million. In addition, whether or not the transaction is consummated, we will be obligated to pay $2.9 million in retention bonuses to key Vulcan employees.

Production Levels. Our 65% owned Canyon Fuel subsidiary previously announced that its Skyline mine is scheduled to be idled by June 30, 2004. The Skyline mine produced 2.8 million tons of coal and contributed $5.6 million to our operating income in 2003. Canyon Fuel anticipates increasing production from its other two mines to make up a portion of the scheduled production decrease associated with the idling.

Expenses Related to Interest Rate Swaps. We had designated certain interest rate swaps as hedges of the variable rate interest payments due under Arch Western’s term loans. Pursuant to the requirements of FAS 133, historical mark-to-market adjustments related to these swaps through June 25, 2003 of $27.0 million were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the original contractual terms of the swap agreements. As of March 31, 2004, the remaining deferred amounts will be recognized as expense in the following periods: $6.2 million for the remainder of 2004; $7.7 million in 2005; $4.8 million in 2006; and $1.9 million in 2007.

Chief Objectives. We continue to focus on taking steps to increase shareholder returns by improving earnings, strengthening cash generation, and improving productivity at our large-scale mines, while building on our strategic position in our target coal-producing basins, the Powder River Basin and the Central Appalachian Basin. In addition, we are aggressively pursuing savings in both overhead and operating costs. We instituted personnel cutbacks at our corporate headquarters and Eastern operations in the first half of 2003 and recently initiated a cost reduction effort targeting key cost drivers at each of our captive mines.

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, 2004 and 2003:

Cash provided by operating activities declined in the quarter ended March 31, 2004 as compared to the same period in 2003 primarily as a result of increased investment in working capital. Trade accounts receivable represented the largest use of funds, increasing by more than $28 million in the first quarter of 2004. This increase is due to higher sales levels during the quarter, and specifically during the month of March (March coal sales totaled $148.6 million).

Cash provided by investing activities in the first quarter of 2004 reflects proceeds of $100.1 million from the sale of the NRP units. Capital expenditures and advance royalty payments were $31.7 million and $21.2 million,

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respectively. Cash used in investing activities during the three months ended March 31, 2003 reflects capital expenditures of $48.1 million and advance royalty payments of $20.4 million. During the first quarter of 2003, we made the fifth and final annual payment of $31.6 million under the Thundercloud federal lease, which is part of the Black Thunder mine in Wyoming.

Cash provided by financing activities during the quarter ended March 31, 2004 consists of proceeds from the issuance of common stock under our employee stock incentive plan, offset by payments on long-term debt and dividend payments. Cash provided by financing activities during the first quarter of 2003 reflects the proceeds from the sale of preferred stock, offset by the pay-down of amounts outstanding under our revolving credit facility. On January 31, 2003, we utilized our Universal Shelf and completed the sale of 2,875,000 shares of 5% Perpetual Cumulative Convertible Preferred Stock. The net proceeds from the offering of approximately $139.1 million were used to reduce indebtedness under our revolving credit facility and for working capital and general corporate purposes.

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

Capital expenditures were $31.7 million and $48.1 million for the quarters ended March 31, 2004 and 2003, respectively. Capital expenditures are made to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We estimate that our capital expenditures will be approximately $170.0 million in total for 2004. This estimate assumes no significant expansions of our existing mining operations or additions to our reserve base. We anticipate that we will fund these capital expenditures with available cash and existing credit facilities.

At March 31, 2004, we had $68.9 million in letters of credit outstanding, which resulted in $281.1 million of unused capacity under our revolving credit facility. Sufficient unused capacity is currently available to fund all operating needs. At March 31, 2004, financial covenant requirements do not restrict the amount of unused capacity available to us for borrowing and letters of credit.

Financial covenants contained in our revolving credit facility consist of a maximum leverage ratio, a minimum fixed charge coverage ratio and a minimum net worth test. The leverage ratio requires that we not permit the ratio of total indebtedness at the end of any calendar quarter to adjusted EBITDA for the four quarters then ended exceed a specified amount. The fixed charge coverage ratio requires that we not permit the ratio of adjusted EBITDA plus lease expense to interest expense plus lease expense for the four quarters then ended to be less than a specified amount. The net worth test requires that we not permit our net worth to be less than a specified amount plus 50% of cumulative net income. At March 31, 2004, we were in compliance with all financial covenants and the financial covenant requirements did not limit our borrowing capacity under our revolving credit facility.

On June 25, 2003, Arch Western Finance, LLC, a subsidiary of Arch Western, completed the offering of $700 million of senior notes. The proceeds of the offering were primarily used to repay Arch Western’s existing term loans. The senior notes bear a fixed rate of interest of 6.75% and are due in full on July 1, 2013. Interest on the senior notes is payable on January 1 and July 1 each year commencing January 1, 2004. The senior notes are guaranteed by Arch Western and certain of Arch Western’s subsidiaries and are secured by a security interest in promissory notes we issued to Arch Western evidencing cash loaned to us by Arch Western. The terms of the senior notes contain restrictive covenants that limit Arch Western’s ability to, among other things, incur additional debt, sell or transfer assets, and make investments.

On September 19, 2003, Arch Western established a $100 million term loan facility. The facility is subject to certain conditions of borrowing, including the consummation of our acquisition of Vulcan (Triton). Currently, no amount is

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available to us under the facility. If Arch Western borrows pursuant to the terms of the facility, the loan will be due in quarterly installments from October 2004 through April 2007.

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

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

Additionally, we are exposed to market risk associated with interest rates resulting from our interest rate swap positions. Prior to the June 25, 2003 Arch Western senior notes offering and subsequent repayment of Arch Western’s term loans, we utilized interest rate swap agreements to convert the variable-rate interest payments due under the term loans and our revolving credit facility to fixed-rate payments. As of March 31, 2004, our net interest rate swap position is as follows:

•		Swaps with a notional value of $25.0 million which are designated as hedges of future interest payments to be made under our revolving credit facility. Under these swaps, we pay a fixed rate of 5.96% (before the credit spread over LIBOR) and receives a variable rate based upon 30-day LIBOR. The remaining term of the swap agreements at March 31, 2004 was 38 months.
•		Swaps with a total notional value of $500.0 million consisting of offsetting positions of $250.0 million each. Because of the offsetting nature of these positions, we are not exposed to significant market interest rate risk related to these swaps. Under these swaps, we pay a weighted average fixed rate 5.72% on $250.0 million of notional value and receive a weighted average fixed rate of 2.71% on $250.0 million of notional value. The remaining terms of these swap agreements at March 31, 2004 ranged from 17 to 40 months.

As of March 31, 2004, the fair value of our net interest rate swap position was a liability of $21.1 million.

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

The discussion below presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices. The range of changes reflects our view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen. The major accounting policies for these instruments are described in Note 1 to our consolidated financial statements as of and for the year ended December 31, 2003 as filed on our Annual Report on Form 10-K with the Securities and Exchange Commission.

At March 31, 2004, our debt portfolio consisted substantially 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, 2004, with all other variables held constant. A 100-basis-point increase in market interest rates would result in a $45.6 million decrease in the fair value of the Company’s fixed rate debt at March 31, 2004.

As it relates to our interest rate swap positions, a change in interest rates impacts the net financial instrument position. A 100-basis point increase in market interest rates would result in a $0.8 million decrease in the fair value of our liability under the interest rate swap positions at March 31, 2004.

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CONTINGENCIES

Reclamation

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

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

Legal Contingencies

Permit Litigation Matters. A group of local and national environmental organizations filed suit against the U.S. Army Corps of Engineers in the U.S. District Court in Huntington, West Virginia on October 23, 2003. In its complaint, Ohio Valley Environmental Coalition, et al v. Bullen, et al, the plaintiffs allege that the Corps has violated its statutory duties arising under the Clean Water Act, the Administrative Procedure Act and the National Environmental Policy Act in issuing the Nationwide 21 (NWP 21) general permit. The plaintiffs allege that the procedural requirements of the three federal statutes identified in their complaint have been violated, and that the Corps may not utilize the mechanism of a nationwide permit to authorize valley fills. Among specific fills identified in the complaint as not meeting the requirements of the NWP 21 are valley fills associated with several of our operating subsidiaries. If the plaintiffs prevail in this litigation, it may delay our receipt of these permits.

A separate matter involves a surface mining permit issued by the West Virginia Department of Environmental Protection (DEP) to our Coal-Mac subsidiary on September 29, 2003. This permit has been challenged in an administrative proceeding brought by the West Virginia Highlands Conservancy. The appeal alleges that the permit is incomplete and inaccurate, and thereby not in compliance with the DEP’s regulations. Specifically, the petition alleges that the proposal to construct a valley fill is inconsistent with a provision of the state regulations known as the “buffer zone rule”, that the operation has failed to provide for suitable topsoil material for use in its reclamation, and that the state agency failed to evaluate the consequences to the water quality from the alleged discharge of one substance from the mine site. The DEP is required by state law to defend the issuance of the permit. We have filed a notice to intervene in the proceeding. While the outcome of this litigation is subject to various uncertainties, we believe that the permit was validly issued. If the plaintiffs prevail in this proceeding, Coal-Mac may be required to cease mining operations when it exhausts its permitted coal reserves, which is expected to be within three years at current mining rates.

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

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

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

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

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

Certain Trends and Uncertainties

Substantial Leverage — Covenants

As of March 31, 2004, we had outstanding consolidated indebtedness of $704.3 million, representing approximately 47% of our capital employed. Despite making substantial progress in reducing debt, we continue to have significant debt service obligations, and the terms of our credit agreements limit our flexibility and result in a number of limitations on us. We also have significant lease and royalty obligations. Our ability to satisfy debt service, lease and royalty obligations and to effect any refinancing of our indebtedness will depend upon future operating performance, which will be affected by prevailing economic conditions in the markets that we serve as well as financial, business and other factors, many of which are beyond our control. We may be unable to generate sufficient cash flow from operations and future borrowings, or other financings may be unavailable in an amount sufficient to enable us to fund our debt service, lease and royalty payment obligations or our other liquidity needs.

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

Terms of our credit facilities and leases contain financial and other covenants that create limitations on our ability to, among other things, effect acquisitions or dispositions and borrow additional funds, and require us to, among other things, maintain various financial ratios and comply with various other financial covenants. Our failure to comply

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with such covenants could result in an event of default under these agreements which, if not cured or waived, would enable our lenders to declare amounts borrowed due and payable, or otherwise result in unanticipated costs.

Losses

We reported a net loss available to common shareholders of $2.6 million for the year ended December 31, 2002 and $12.0 for the first nine months of 2003. The losses in 2002 and the first three quarters of 2003 were primarily attributable to our decision to scale back production during the period in response to a weak market environment and increased costs at certain of our operations. The decision to scale back production came after we had prepared most of the operations to maximize production in order to capitalize on higher market prices for coal that we had previously projected. Therefore, certain costs incurred to maximize production did not result in higher revenues but did increase the cost of coal sales.

Because the coal mining industry is subject to significant regulatory oversight and affected by the possibility of adverse pricing trends or other industry trends beyond our control, we may suffer losses in the future if legal and regulatory rulings, mine idlings and closures, adverse pricing trends or other factors affect our ability to mine and sell coal profitably.

Environmental and Regulatory Factors

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

•		the discharge of materials into the environment;
•		employee health and safety;
•		mine permits and other licensing requirements;
•		reclamation and restoration of mining properties after mining is completed;
•		management of materials generated by mining operations;
•		surface subsidence from underground mining;
•		water pollution;
•		legislatively mandated benefits for current and retired coal miners;
•		air quality standards;
•		protection of wetlands;
•		endangered plant and wildlife protection;
•		limitations on land use;
•		storage of petroleum products and substances that are regarded as hazardous under applicable laws; and
•		management of electrical equipment containing polychlorinated biphenyls, or PCBs.

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

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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. Revised State Implementation Plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and our development of new mines. This in turn may result in decreased production and a corresponding decrease in our revenues. Although the future scope of these ozone and particulate matter regulations cannot be predicted, future regulations regarding these and other ambient air standards could restrict the market for coal and the development of new mines.

Furthermore, in October 1998, the EPA finalized a rule that will require 19 states in the Eastern United States that have ambient air quality problems to make substantial reductions in nitrogen oxide emissions by the year 2004. To achieve these reductions, many power plants would be required to install additional control measures. The installation of these measures would make it more costly to operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel. A number of states have already submitted to EPA revisions of their State Implementation Plans including provisions for reducing nitrogen oxide emissions, and the remaining states that have not revised their Implementation Plans must do so by May 1, 2004.

Along with these regulations addressing ambient air quality, the EPA has 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

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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 the Court stayed the effectiveness of these rules. In January 2004, the EPA Administrator announced that EPA would be taking new enforcement actions against utilities for violations of the existing New Source Review requirements, and shortly thereafter, EPA issued enforcement notices to several electric utility companies.

In January 2004, EPA proposed two new rules pursuant to the Clean Air Act that, once final, may require additional controls and impose more stringent requirements at coal-fired power generation facilities. First, EPA is seeking to lower nickel and mercury emissions at new and existing sources by requiring the use of Maximum Achievable Control Technology (“MACT”) and by implementing a nationwide “cap and trade” program. Second, EPA has proposed to require the submission of State Implementation Plans by 29 states and the District of Columbia to include control measures to reduce the emissions of sulfur dioxide and/or nitrogen oxides, pursuant to the 8-hour ozone standard established pursuant to the Clean Air Act. Should either or both of these proposed rules become final, additional costs may be associated with operating coal-fired power generation facilities that may render coal a less attractive fuel source.

Other Clean Air Act programs are also applicable to power plants that use our coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur dioxide reductions can affect coal mining operations. Title IV imposes a two phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants of greater than 25 megawatt capacity. Affected electric utilities can comply with these requirements by:

•		burning lower sulfur coal, either exclusively or mixed with higher sulfur coal;
•		installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal;
•		reducing electricity generating levels; or
•		purchasing or trading emissions credits.

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

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

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mercury, although other by-products of coal combustion may be covered by future hazardous air pollutant standards for coal combustion sources.

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

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

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

SMCRA also requires us to submit a bond or otherwise financially secure the performance of our reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the property or compensating the property owners for damage occurring on the surface of the property as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from underground mines.

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

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

West Virginia Antidegradation Policy. In January 2002, a number of environmental groups and individuals filed suit in the U.S. District Court for the Southern District of West Virginia to challenge the EPA’s approval of West

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Virginia’s antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. The plaintiffs in this lawsuit, Ohio Valley Environmental Coalition v. Whitman, challenge provisions in West Virginia’s antidegradation implementation policy that exempt current holders of National Pollutant Discharge Elimination System (NPDES) permits and Section 404 permits, among other parties, from the antidegradation review process. We were exempt from antidegradation review under these provisions. In August 2003, the Southern District of West Virginia vacated EPA’s approval of West Virginia’s antidegradation procedures, and remanded the matter to EPA. The court’s decision may delay the issuance or reissuance of Clean Water Act permits to us or cause these permits to be denied, and may increase the costs, time and difficulty associated with obtaining and complying Clean Water Act permits for surface mining operations.

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

Mining Permits and Approvals. Numerous governmental permits or approvals are required for mining operations. 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.

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.

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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 or reclamation, 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 while the markets providing surety bonds are limited.

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 coal producers in the Central Appalachian and Powder River Basin areas. We also compete with a number of smaller producers in those and other market regions.

Electric Industry Factors; Customer Creditworthiness

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

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

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

Reliance on and Terms of Long-Term Coal Supply Contracts

During 2003, sales of coal under long-term contracts, which are contracts with a term greater than 12 months, accounted for 83% of our total revenues. The prices for coal shipped under these contracts may be below the current

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market price for similar type coal at any given time. As a consequence of the substantial volume of our sales which are subject to these long-term agreements, we have less coal available with which to capitalize on stronger coal prices if and when they arise. In addition, because long-term contracts typically allow the customer to elect volume flexibility, our ability to realize the higher prices that may be available in the spot market may be restricted when customers elect to purchase higher volumes under such contracts, or our exposure to market-based pricing may be increased should customers elect to purchase fewer tons. The increasingly short terms of sales contracts and the consequent absence of price adjustment provisions in such contracts also make it more likely that we will not be able to recover inflation related increases in mining costs during the contract term.

Reserve Degradation and Depletion

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We have in the past acquired and will in the future acquire, coal reserves for our mine portfolio from third parties. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines can also have an adverse effect on operating results that is disproportionate to the percentage of overall production represented by such mines. Mingo Logan’s Mountaineer Mine is estimated to exhaust its longwall mineable reserves in 2006. The Mountaineer Mine generated $26.1 million and $33.7 million of our total operating income in the year ended 2003 and 2002, respectively.

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

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

Reserves — Title

We base our reserve information on geological data assembled and analyzed by our staff, which includes various engineers and geologists, and 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

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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.

We continually seek to expand our operations and coal reserves in the regions in which we operate through acquisitions of businesses and assets. Certain acquisitions are subject to governmental review which may inhibit our ability to complete a desirable acquisition. Completed acquisition transactions also involve various inherent risks, such as 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; and unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction. Any one or more of these factors could impair our ability to realize the benefits anticipated to result from the acquisition of businesses or assets.

A significant part 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.

Cash Balance Plan

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

Certain Contractual Arrangements

Our affiliate, Arch Western Resources, LLC, is the owner of our reserves and mining facilities in the western United States. The agreement under which Arch Western was formed provides that a subsidiary of ours, as the managing member of Arch Western, generally has exclusive power and authority to conduct, manage and control the business of Arch Western. However, consent of BP p.l.c., the other member of Arch Western, would generally be required in the event that Arch Western proposes to make a distribution, incur indebtedness, sell properties or merge or consolidate with any other entity if, at such time, Arch Western has a debt rating less favorable than specified ratings with Moody’s Investors Service or Standard & Poor’s or fails to meet specified indebtedness and interest ratios.

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

The membership interests in Canyon Fuel, which operates three coal mines in Utah, are owned 65% by Arch Western and 35% by a subsidiary of ITOCHU Corporation of Japan. The agreement that governs the management and operations of Canyon Fuel provides for a management board to manage its business and affairs. Some major business decisions concerning Canyon Fuel require the vote of 70% of the membership interests and therefore limit 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

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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 contains various restrictions on the transfer of membership interests in Canyon Fuel.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

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

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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 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS

(a) The Company’s Annual Meeting of Stockholders was held on April 22, 2004, at the Company’s headquarters at One CityPlace Drive, Suite 300, St. Louis, Missouri.

(b) At such Annual Meeting, the holders of the Company’s common stock elected the following nominees for director for a three year term ending at the 2007 Annual Meeting:

The terms of office of the remaining directors continued after the meeting.

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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a)

3.1		Amended and Restated Certificate of Incorporation of Arch Coal, Inc. (incorporated herein by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q for the Quarter Ended March 31, 2000)
3.2		Amended and Restated Bylaws of Arch Coal, Inc. (incorporated herein by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K for the Year Ended December 31, 2000)
3.3		Certificate of Designations Establishing the Designations, Powers, Preferences, Rights, Qualifications, Limitations and Restrictions of the Company’s 5% Perpetual Cumulative Convertible Preferred Stock (incorporated herein by reference to Exhibit 3 to current report on Form 8-A filed on March 5, 2003)
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 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.)
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-Orley 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-Orley Act of 2002.
(b)		Reports on Form 8-K: The following reports on Form 8-K were filed by the Company in the quarter ended March 31, 2004:

(1)		A report dated January 30, 2004 announcing the Company’s fourth quarter 2003 earnings and operating results.
(2)		A report dated March 11, 2004 announcing the Company’s sale of 2.6 million common units in Natural Resource Partners, LLP.
(3)		A report dated March 31, 2004 announcing the Company’s response to the FTC’s intent to block the Triton acquisition.

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     SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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