Exhibit 13.1
PART II — ANNUAL REPORT
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Forward-Looking Statements |
In this annual report, statements that are not reported financial results or other historical information are “forward-looking statements.” Forward-looking statements give current expectations or forecasts of future events and are not guarantees of future performance. They are based on our management’s expectations that involve a number of business risks and uncertainties, any of which could cause actual results to differ materially from those expressed in or implied by the forward-looking statements.
Forward-looking statements can be identified by the fact that they do not relate strictly to historic or current facts. They use words such as “anticipate,” “estimate,” “project,” “intend,” “plan,” “believe” and other words and terms of similar meaning in connection with any discussion of future operating or financial performance. In particular, these include statements relating to:
• | our expectation of continued growth in the demand for our coal by the domestic electric generation industry; | |
• | our belief that legislation and regulations relating to the Clean Air Act and other proposed environmental initiatives and the relatively higher costs of competing fuels will increase demand for our compliance and low sulfur coal; | |
• | our expectations regarding incentives to generators of electricity to minimize their fuel costs as a result of electric utility deregulation; | |
• | our expectation that we will continue to have adequate liquidity from cash flow from operations; | |
• | a variety of market, operational, geologic, permitting, labor and weather related factors; | |
• | our expectations regarding any synergies to be derived from the Triton acquisition; and | |
• | the other risks and uncertainties which are described below under “Contingencies” and “Certain Trends and Uncertainties,” including, but not limited to, the following: |
• | A reduction in consumption by the domestic electric generation industry may cause our profitability to decline. | |
• | Extensive environmental laws and regulations could cause the volume of our sales to decline. | |
• | The coal industry is highly regulated, which restricts our ability to conduct mining operations and may cause our profitability to decline. | |
• | We may not be able to obtain or renew our surety bonds on acceptable terms. | |
• | Unanticipated mining conditions may cause profitability to fluctuate. | |
• | Intense competition and excess industry capacity in the coal producing regions has adversely affected our revenues and may continue to do so in the future. | |
• | Deregulation of the electric utility industry may cause customers to be more price-sensitive, resulting in a potential decline in our profitability. | |
• | Our profitability may be adversely affected by the status of our long-term coal supply contracts. | |
• | Decreases in purchases of coal by our largest customers could adversely affect our revenues. | |
• | Unavailability of coal reserves would cause our profitability to decline. |
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• | Disruption in, or increased costs of, transportation services could adversely affect our profitability. | |
• | Numerous uncertainties exist in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower revenues, higher costs or decreased profitability. | |
• | Title defects or loss of leasehold interests in our properties could result in unanticipated costs or an inability to mine these properties. | |
• | Acquisitions that we have undertaken or may undertake involve a number of inherent risks, any of which could cause us not to realize the benefits anticipated to result. | |
• | Some of our agreements limit our ability to manage our western operations exclusively. | |
• | Our expenditures for postretirement medical and pension benefits have increased since 2002 and could further increase in the future. | |
• | Our inability to comply with restrictions imposed by our credit facilities and other debt arrangements could result in a default under these agreements. | |
• | Our estimated financial results may prove to be inaccurate. |
We cannot guarantee that any forward-looking statements will be realized, although we believe that we have been prudent in our plans and assumptions. Achievement of future results is subject to risks, uncertainties and assumptions that may prove to be inaccurate. Should known or unknown risks or uncertainties materialize, or should underlying assumptions prove to be inaccurate, actual results could vary materially from those anticipated, estimated or projected.
We undertake no obligation to publicly update forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by law. You are advised, however, to consider any additional disclosures that we or Arch Coal may make on related subjects in future filings with the SEC. You should understand that it is not possible to predict or identify all factors that could cause our actual results to differ. Consequently, you should not consider any such list to be a complete set of all potential risks or uncertainties.
Recent Development |
On March 3, 2005, shares of performance-contingent phantom stock granted in January 2004 to our executive officers vested and were paid out in a combination of cash and shares of our stock. The phantom stock grant vested when our average closing stock price exceeded $40 per share over 20 consecutive trading days. As a result of the payout, we will incur a charge of $9.9 million, or approximately $0.16 per share, during our quarter ending March 31, 2005.
Overview |
We are a producer and marketer of compliance and low-sulfur coal exclusively, which we supply to domestic electric utilities and independent power producers, as well as to steel producers and industrial facilities. We operate large, modern mines in each of the three major low-sulfur coal-producing basins in the United States. These mines are among the most productive in the regions in which they operate and are supported by an extensive, low-cost reserve base totaling 3.7 billion tons.
We derive approximately 70% of our revenues from long-term supply contracts (defined as having terms of one year or greater). These supply agreements typically have terms of one to three years, although certain contracts have much longer durations. The remainder of our coal sales result from sales on the spot market.
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The locations of our mining operations are as follows:
Powder River Basin (“PRB”) — We operate one surface mine, Black Thunder (into which the operations of the North Rochelle mine were integrated during 2004), and we own one idle surface mine, Coal Creek, in the Powder River Basin of Wyoming. The PRB is the nation’s largest and fastest growing coal supply basin.
Central Appalachia (“CAPP”) — We operate or control 22 mines in this coal basin (defined as southern West Virginia, eastern Kentucky and Virginia). Included in this total are 14 deep mines and 8 surface mines. We are in the process of developing a large longwall mine, Mountain Laurel, that is expected to ramp up to full production in 2007. CAPP is the principal source of low-sulfur coal in the eastern United States.
Western Bituminous Region (“WBIT”) — We operate three mines in this region (defined as Colorado, Utah and southern Wyoming), including a longwall mine in Colorado and two longwall mines in Utah. In addition, we have announced plans to begin development work on another longwall mine at the currently idle Skyline mine complex in Utah. Coal from WBIT can be used as a substitute for high-Btu eastern coal, which is in short supply.
Coal is the dominant fuel source for electric generation in the United States. Coal was the fuel source for 51% of the electricity generated in the United States in 2004. Furthermore, coal has significant advantages that should enable it to maintain or even increase market share over the course of the next two decades. First, coal is a low-cost fuel for electric generation, averaging less than one-third of the cost of natural gas or crude oil per megawatt hour of generation. In addition, there is significant excess capacity at existing coal-fired power plants, and this excess capacity represents a very low-cost source of electricity to the grid. At present, coal-fired power plants are operating at an average utilization rate of 71%. We believe that there is significant potential to increase those utilization rates and thus drive increased coal demand. In addition, power generators have announced plans to construct 65 gigawatts of new coal-fired generating capacity in future years, which would increase the installed base by roughly 20%.
The principal driver for U.S. coal demand is growth in domestic power generation. Domestic power needs are expected to grow over the next several years as the economy grows and the U.S. economy becomes increasingly electrified. The U.S. Energy Information Administration projects that power demand will grow at a rate of 1.9% annually over the course of the next two decades.
As energy demand grows, we believe that coal is well positioned to supply much of this demand. Competing fuels that have played a prominent role in meeting the nation’s power needs in recent years are starting to be confronted with obstacles that could impede their future growth.
America’s fleet of nuclear power plants, which is the second leading source of electric generation in the U.S. with a roughly 20% share, is operating near its effective capacity. Nuclear output has remained relatively flat since 2001. It appears unlikely that any new nuclear capacity will be constructed in the next five to 10 years.
Natural gas, the source of roughly 17% of U.S. electricity supply, is facing growing concerns about the ability to increase North American production sufficiently to keep pace with demand. While imports of liquefied natural gas (LNG) are expected to alleviate some of this supply pressure in the future; it will likely be several years before LNG will play a meaningful role in U.S. electric generation.
That means that coal will continue to act as the dominant fuel source for electric generation in the years ahead. In addition, we believe that low-sulfur coal will benefit disproportionately from future coal demand growth. Utilities have sought to comply with the sulfur dioxide standards contained in Phase II of the Clean Air Act by shifting increasingly to low sulfur coals rather than building expensive scrubbing capacity. At present, less than 30% of eastern coal-based power
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generation is equipped with scrubbers. Until a significant amount of new scrubbing capacity is added, we believe that low-sulfur coal will have a very pronounced advantage in the marketplace.
Our management has positioned the company to benefit from these trends by focusing on cost containment and growth in our core operating regions.
In recent quarters, operating costs have risen due in part to higher costs associated with medical benefits, workers’ compensation, insurance, explosives, diesel fuel, steel, permitting and surety bonding. We are focused on offsetting future cost increases with cost savings and productivity improvements elsewhere. During 2005, we plan to capture operating synergies created by recent acquisitions; continue our efforts to extend best practices across all mines; implement process improvements; apply cutting-edge maintenance programs; and invest in advanced technologies where appropriate and prudent.
During 2004, we committed — or made plans to commit — more than $1.2 billion in growth capital. Much of this capital will be invested in future periods as we make additional payments on reserve additions or continue mine development projects. We expect to fund most of our currently anticipated capital requirements through existing cash on the balance sheet and internally generated cash flow.
We currently anticipate that much of our future growth will be organic in nature. As demand for coal grows, we will evaluate the expansion of our existing operations and the development of new mines on our existing reserve base.
Results of Operations |
Acquisitions |
On August 20, 2004, we acquired (1) Vulcan Coal Holdings, L.L.C., which owned all of the common equity of Triton Coal Company, LLC (“Triton”), and (2) all of the preferred units of Triton for a purchase price of $382.1 million, including transaction costs and working capital adjustments. Immediately following the consummation of the transaction, we sold the smaller of Triton’s two mines, Buckskin, to Kiewit Mining Acquisition Company, at a net sales price of $73.1 million. After completion of these transactions, we integrated the operations of the larger of Triton’s two mines, North Rochelle, with our existing Black Thunder mine in the Powder River Basin.
On July 31, 2004, we purchased the remaining 35% interest in Canyon Fuel Company, LLC (“Canyon Fuel”) not owned by us from ITOCHU Corporation for a purchase price of $112.2 million, including related costs and fees. Net of cash acquired, the fair value of the transaction totaled $97.4 million. As a result of the acquisition, we own substantially all of the ownership interests of Canyon Fuel and no longer account for our investment in Canyon Fuel on the equity method but consolidate Canyon Fuel in our financial statements subsequent to the July 31, 2004 purchase date.
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Items Affecting Comparability of Reported Results |
The comparison of our operating results for the years ending December 31, 2004, 2003 and 2002 are affected by the following significant items:
Year Ended December 31, | ||||||||||||
2004 | 2003 | 2002 | ||||||||||
(Amount in millions) | ||||||||||||
Operating Income | ||||||||||||
Gain on sale of NRP units | $ | 91.3 | $ | 42.7 | $ | — | ||||||
Retroactive royalty rate reductions | 2.7 | — | 4.4 | |||||||||
Black lung excise tax refund | 2.1 | — | — | |||||||||
Severance costs — Skyline mine | (2.1 | ) | — | — | ||||||||
Gain from land sales | 6.7 | 3.8 | 0.8 | |||||||||
Long-term incentive compensation accrual | (5.5 | ) | (16.2 | ) | — | |||||||
Severance tax recoveries | — | 2.5 | — | |||||||||
Reduction in workforce | — | (2.6 | ) | — | ||||||||
Gain on contract buyout | — | — | 5.6 | |||||||||
Workers’ compensation premium adjustment | — | — | 4.6 | |||||||||
Net increase in operating income | $ | 95.2 | $ | 30.2 | $ | 15.4 | ||||||
Other | ||||||||||||
Expenses resulting from termination of hedge accounting for interest rate swaps | (8.3 | ) | (4.3 | ) | — | |||||||
Expenses resulting from early debt extinguishment | (0.7 | ) | (4.7 | ) | — | |||||||
Interest on federal income tax refund | 2.2 | — | — | |||||||||
Interest on black lung excise tax refund | 0.7 | — | — | |||||||||
Gain from mark-to-market adjustments on interest rate swaps that no longer qualify as hedges | — | 13.4 | — | |||||||||
Net increase in pre-tax income | $ | 89.1 | $ | 34.6 | $ | 15.4 | ||||||
Gain on Sale of NRP Units. During 2004, we sold our remaining limited partnership units of NRP resulting in proceeds of approximately $111.4 million and gains of $91.3 million. During 2003, we sold our general partner interest and subordinated units resulting in proceeds of $115.0 million and a gain of $42.7 million.
Retroactive Royalty Rate Adjustments. During 2004 and 2002, we filed a royalty rate reduction request with the Bureau of Land Management (“BLM”) for our West Elk mine in Colorado. The BLM notified us that we would receive a royalty rate reduction for a specified number of tons representing retroactive portions for the respective years totaling $2.7 million and $3.3 million. The retroactive portion was recognized as a component of cost of coal sales in both years. Additionally in 2002, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined representing a retroactive refund of $1.1 million. The retroactive amount was reflected in income from equity investments.
Black Lung Excise Tax Refunds. During 2004, we were notified by the IRS that we would receive additional black lung excise tax refunds and interest related to black lung claims that were originally denied by the IRS in 2002. We recognized a gain of $2.8 million ($2.1 million refund and $0.7 million of interest) related to the claims. The $2.1 million refund was recorded as a component of cost of coal sales, while the $0.7 million of interest was recorded as interest income.
Severance Costs — Skyline Mine. During 2004, Canyon Fuel, which was accounted for under the equity method through July 31, 2004, began the process of idling its Skyline Mine (the idling
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process was completed in May 2004), and incurred severance costs of $3.2 million for the year ended December 31, 2004. Our share of these costs totals $2.1 million and is reflected in income from equity investments.
Gain from Land Sales. During the years ended December 31, 2004, 2003 and 2002, we recognized gains from land sales at our idle properties. These gains are reported as other operating income.
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps. On June 25, 2003, we repaid the term loans of our subsidiary, Arch Western, with the proceeds from the offering of senior notes. In connection with the repayment of the term loans, we recognized expenses related to the write-off of loan fees and other debt extinguishment costs. Additionally, we had designated certain interest rate swaps as hedges of the variable rate interest payments due under the Arch Western term loans. Pursuant to the requirements of Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“FAS 133”), historical mark-to-market adjustments related to these swaps through June 25, 2003 were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the contractual terms of the swap agreements. For the years ending December 31, 2004 and 2003, we recognized expenses of $8.3 million and $4.3 million, respectively, related to the amortization of previously deferred mark-to-market adjustments and expenses of $0.7 million and $4.7 million, respectively, related to early debt extinguishment costs.
Interest on federal income tax refunds. In connection with the settlement of tax audits for prior years, we recorded interest income in 2004 related to federal income tax refunds. This amount is reflected as interest income.
Long-term Incentive Compensation Plan Expense. During 2004, we accrued $5.5 million under long-term incentive compensation plans. Awards under these plans included restricted stock unit grants that vest over three years and performance unit awards that are earned if the Company meets certain financial, safety and environmental targets during the three years ending December 31, 2006. During the fourth quarter of 2003, our Board of Directors approved awards under a four-year performance unit plan that began in 2000. Amounts accrued for the plan totaled $16.2 million in 2003.
Severance Tax Recoveries. During 2003, we were notified by the State of Wyoming of a favorable ruling relating to our calculation of coal severance taxes. The ruling resulted in a refund of previously paid taxes and the reversal of previously accrued taxes payable. This amount was recorded as a component of cost of coal sales in the Consolidated Statement of Operations.
Reduction in Workforce. During the year ending December 31, 2003, we instituted cost reduction efforts throughout our operations. These cost reduction efforts included the termination of approximately 100 employees at our corporate office and CAPP mining operations. Of the expense recognized, $1.6 million was recognized as a component of cost of coal sales, with the remainder recognized as a component of selling, general and administrative expenses.
Mark-to-market adjustments on interest rate swaps that no longer qualify as hedges. We are a party to several interest rate swap agreements that were entered into in order to hedge the variable rate interest payments due under Arch Western’s term loans. Subsequent to the repayment of those term loans, the swaps no longer qualify for hedge accounting under FAS 133. As such, favorable changes in the market value of the swap agreements were recorded as a component of income and are included in other non-operating income in the Consolidated Statements of Operations. During the year ended December 31, 2003, we recognized income of $13.4 million related to the mark-to-market adjustments on these swap agreements.
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Gain on Contract Buyout. During 2002, we settled certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. The settlements resulted in a pre-tax gain, which was recognized in other operating income in the Consolidated Statements of Operations.
Workers’ Compensation Premium Adjustment. During 2002, we received a workers’ compensation premium adjustment refund from the State of West Virginia. During 1998, we entered into the West Virginia workers’ compensation plan at one of our subsidiary operations. The subsidiary paid standard base rates until the West Virginia Division of Workers’ Compensation could determine the actual rates based on claims experience. Upon review, the Division of Workers’ Compensation refunded $4.6 million in premiums. The refund is reflected as a reduction in cost of coal sales.
Year Ended December 31, 2004, Compared to Year Ended December 31, 2003 |
Summarized operating results for 2004 versus 2003 and additional discussion of the 2004 results are provided below.
Revenues |
Year Ended December 31, | Increase (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
(Amounts in thousands, except per ton data) | ||||||||||||||||
Coal sales | $ | 1,907,168 | $ | 1,435,488 | $ | 471,680 | 32.9 | % | ||||||||
Tons sold | 123,060 | 100,634 | 22,426 | 22.3 | % | |||||||||||
Coal sales realization per ton sold | $ | 15.50 | $ | 14.26 | $ | 1.24 | 8.7 | % |
Tons sold by operating segment |
Tons Sold | % of Total | |||||||||||||||
2004 | 2003 | 2004 | 2003 | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Powder River Basin | 81,857 | 64,050 | 66.5 | % | 63.6 | % | ||||||||||
Central Appalachia | 30,008 | 29,667 | 24.4 | % | 29.5 | % | ||||||||||
Western Bituminous Region | 11,195 | 6,917 | 9.1 | % | 6.9 | % | ||||||||||
Total operating regions | 123,060 | 100,634 | 100.0 | % | 100.0 | % |
Coal sales. The increase in coal sales resulted from the combination of higher pricing, increased volumes and the acquisitions of Triton and the remaining 35% interest in Canyon Fuel during the third quarter of 2004.
Volumes increased slightly in Central Appalachia (an increase of 1.2%), but increased more dramatically in the Powder River Basin (an increase of 27.8%) and at our Western Bituminous operations (an increase of 61.9%). Volumes in both the Powder River Basin and the Western Bituminous region benefited from the acquisitions that were completed in the third quarter of 2004.
Per ton realizations increased due primarily to higher contract prices in all three regions. In the Powder River Basin, per ton realization increased 11.3%, including above-market pricing on certain contracts acquired in the Triton acquisition. The Central Appalachia region experienced the largest per ton realization increase (an increase of 21.3%), as both contract and spot market prices were higher than in 2003. Additionally, a higher percentage of our sales were metallurgical coal sales in 2004 as compared to 2003. The Western Bituminous region’s per ton realization increased 13.4%. In addition to higher contract pricing, per ton realizations in the Western Bituminous region were also affected by the acquisition of the remaining 35% interest in Canyon Fuel. Excluding the effects of the Canyon Fuel acquisition, per ton realizations for Western Bituminous would have increased 10.4% over the prior year.
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On a consolidated basis, the increase in per ton realizations was partially offset by the change in mix of sales volumes among our operating regions. As reflected in the table above, Central Appalachia volumes (which have the highest average realization) decreased while volumes in the Powder River Basin and Western Bituminous Region increased from the prior year.
Costs and Expenses |
Year Ended December 31, | Increase (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
(Amounts in thousands, except per ton data) | ||||||||||||||||
Cost of coal sales | $ | 1,638,284 | $ | 1,280,608 | $ | 357,676 | 27.9 | % | ||||||||
Depreciation, depletion and amortization | 166,322 | 158,464 | 7,858 | 5.0 | % | |||||||||||
Selling, general and administrative expenses | 52,842 | 43,942 | 8,900 | 20.3 | % | |||||||||||
Long-term incentive compensation expense | 5,495 | 16,217 | (10,722 | ) | (66.1 | )% | ||||||||||
Other expenses | 35,758 | 18,245 | 17,513 | 96.0 | % | |||||||||||
$ | 1,898,701 | $ | 1,517,476 | $ | 381,225 | 25.1 | % | |||||||||
Cost of coal sales. The increase in cost of coal sales is primarily due to the increase in coal sales revenues discussed above. Specific factors contributing to the increase are as follows:
• | Production taxes and coal royalties (which are incurred as a percentage of coal sales realization) increased $71.8 million. | |
• | Poor rail performance during 2004 resulted in missed shipments and disruptions in production. | |
• | Our Central Appalachia operations incurred higher costs related to additional processing necessary to sell coal in metallurgical markets. | |
• | The cost of purchased coal increased $105.9 million, reflecting a combination of increased purchase volumes and higher spot market prices that were prevalent during 2004. During 2004, we utilized purchased coal to fulfill steam coal sales commitments in order to direct more of our produced coal into the metallurgical markets. | |
• | Costs for explosives and diesel fuel increased $9.5 million and $22.4 million, respectively. | |
• | Costs for operating supplies increased $16.9 million due primarily to increased commodity and steel prices during the year. | |
• | Repairs and maintenance costs increased $21.3 million due partially to the acquisitions made during the third quarter of 2004. |
During the first quarter of 2004, we reflected the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Act”), in accordance with the provisions of FASB Staff Position No. FAS 106-2,Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. Incorporation of the provisions of the Act resulted in a $68.0 million reduction of our postretirement medical benefit obligation. Postretirement medical expenses for fiscal year 2004 after incorporation of the provisions of the Act resulted in $18.2 million less expense than that previously anticipated (substantially all of which is recorded as a component of cost of coal sales). The benefit for the year ending December 31, 2004 was partially offset by increased costs resulting from changes to other actuarial assumptions that were incorporated at the beginning of the year.
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Depreciation, depletion and amortization. The increase in depreciation, depletion and amortization is due primarily to the property additions resulting from the acquisitions made during the third quarter of 2004.
Regional Analysis:
Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations. |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
Powder River Basin | $ | 6.19 | $ | 5.45 | $ | 0.74 | 13.6 | % | ||||||||
Central Appalachia | $ | 34.84 | $ | 30.87 | $ | 3.97 | 12.9 | % | ||||||||
Western Bituminous Region | $ | 15.71 | $ | 15.41 | $ | 0.30 | 1.9 | % |
Powder River Basin — On a per-ton basis, operating costs increased in the Powder River Basin primarily due to increased cost of purchased coal ($0.31 per ton), increased production taxes and coal royalties ($0.17 per ton) and to the higher explosives and diesel fuel costs discussed above. Additionally, average costs were higher due to the integration of the acquired North Rochelle mine into our Black Thunder mine. | |
Central Appalachia — Operating cost per ton increased due to increased costs for coal purchases ($2.52 per ton), increased diesel fuel ($0.38 per ton) and production taxes and coal royalties ($0.49 per ton) as well as the increased preparation costs for metallurgical coal discussed above. Additionally, poor rail performance at our Central Appalachia operations resulted in disruptions in production. As many of our costs are fixed in nature, the reduced volume did not result in reduced overall costs. | |
Western Bituminous Region — Operating cost per ton increased primarily due to increased production taxes and coal royalties ($0.27 per ton). |
Selling, general and administrative expenses. Selling, general and administrative expenses increased due primarily to legal and professional fees, franchise taxes and higher expenses resulting from amounts expected to be earned under our annual incentive plans.
Other expenses. The increase in other expenses is primarily a result of higher costs to terminate certain contractual obligations for the purchase of coal as compared to the prior year.
Other Operating Income |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Income from equity investments | $ | 10,828 | $ | 34,390 | $ | (23,562 | ) | (68.5 | )% | |||||||
Gain on sale of units of NRP | 91,268 | 42,743 | 48,525 | 113.5 | % | |||||||||||
Other operating income | 67,483 | 45,226 | 22,257 | 49.2 | % | |||||||||||
$ | 169,579 | $ | 122,359 | $ | 47,220 | 38.6 | % | |||||||||
Income from equity investments. Income from equity investments for 2004 consists of $8.4 million from our investment in Canyon Fuel (prior to our July 31, 2004 acquisition of the 35% interest we did not own) and $2.4 million from our investment in NRP (prior to the sale of NRP units in March 2004). For 2003, income from equity investments consisted of $19.7 million of income from our
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investment in Canyon Fuel and $14.7 million from our investment in NRP. The decline in income from our investment in Canyon Fuel results from the consolidation of Canyon Fuel into our financial statements subsequent to the July 31, 2004 purchase date, lower production and sales levels at Canyon Fuel prior to the acquisition and additional costs related to idling the Skyline Mine, including the severance costs noted above.
Other operating income. The increase in other operating income is primarily due to the recognition in 2004 of $13.9 million of previously deferred gains from the 2003 and 2004 NRP unit sales. These deferred gains are being recognized over the terms of our leases with NRP. The increase is also due to gains recognized on land sales of $6.7 million in 2004 compared to $3.8 million in 2003.
Interest Expense, Net |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Interest expense | $ | 62,634 | $ | 50,133 | $ | 12,501 | 24.9 | % | ||||||||
Interest income | (6,130 | ) | (2,636 | ) | (3,494 | ) | (132.5 | )% | ||||||||
$ | 56,504 | �� | $ | 47,497 | $ | 9,007 | 19.0 | % | ||||||||
Interest expense. The increase in interest expense results from a higher average interest rate in the first six months of 2004 as compared to the same period in 2003 as well as a higher amount of average borrowings from August through December 2004 as compared to the prior year. In 2004, the Company’s outstanding borrowings consisted primarily of fixed rate borrowings, while borrowings in the first half of 2003 were primarily variable rate borrowings. Short-term interest rates in 2003 were lower than the fixed rate borrowing that made up the majority of average debt balances in 2004.
Interest Income. The increase in interest income is partly due to interest on the federal income tax refunds discussed above. The remaining increase results primarily from interest on short-term investments.
Other non-operating income and expense |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Expenses resulting from early debt extinguishment and termination of hedge accounting for interest rate swaps | $ | 9,010 | $ | 8,955 | $ | 55 | 0.6 | % | ||||||||
Other non-operating income | (1,044 | ) | (13,211 | ) | 12,167 | 92.1 | % | |||||||||
$ | 7,966 | $ | (4,256 | ) | $ | 12,222 | 287.2 | % | ||||||||
Amounts reported as non-operating consist of income or expense resulting from the Company’s financing activities other than interest. As described above, the Company’s results of operations for the years ended December 31, 2004 and 2003 include expenses of $8.3 million and $4.3 million, respectively, related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred. Additionally, we incurred expenses of $0.7 million and $4.7 million related to early debt extinguishment costs in 2004 and 2003, respectively.
Other non-operating income in 2003 was primarily from mark-to-market adjustments on swaps as described above. During 2003, we terminated these positions or entered into offsetting positions.
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Income taxes |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Income tax benefit | $ | 130 | $ | 23,210 | $ | (23,080 | ) | (99.4 | )% |
Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The income tax benefit recorded in 2004 is due primarily to a $7.1 million benefit due to favorable tax settlements and a $9.7 million reduction in income tax reserves associated with the completion of the 1999 through 2002 federal income tax audits. The change is also the result of the tax benefit from percentage depletion offset by the tax impact from the sales of the NRP units throughout 2004.
Deferred tax assets and liabilities are recorded at the maximum effective tax rate. Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. We have historically been subject to alternative minimum tax (AMT), and it is more likely than not that we will remain an AMT taxpayer in the foreseeable future. Valuation allowances are established against deferred tax assets so as to value the asset to an amount that is realizable, as further described in “Management’s Discussion and Analysis of Financial Condition — Critical Accounting Policies.”
Net income before cumulative effect of accounting change |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Net income before cumulative effect of accounting change | $ | 113,706 | $ | 20,340 | $ | 93,366 | 459.0 | % |
The increase in net income before cumulative effect of accounting change is primarily due to higher coal sales revenues and the gain recognized from the sales of NRP units during 2004 (net of related tax provision).
Year Ended December 31, 2003, Compared to Year Ended December 31, 2002 |
Summarized operating results for 2003 versus 2002 and additional discussion of the 2003 results are provided below.
Revenues |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2003 | 2002 | $ | % | |||||||||||||
(Amounts in thousands, except per ton data) | ||||||||||||||||
Coal sales | $ | 1,435,488 | $ | 1,473,558 | $ | (38,070 | ) | (2.6 | )% | |||||||
Tons sold | 100,634 | 106,691 | (6,057 | ) | (5.7 | )% | ||||||||||
Coal sales realization per ton sold | $ | 14.26 | $ | 13.81 | $ | 0.45 | 3.3 | % |
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Percentage of tons sold by operating segment |
Tons Sold | % of Total | |||||||||||||||
2003 | 2002 | 2003 | 2002 | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Powder River Basin | 64,050 | 67,249 | 63.6 | % | 63.0 | % | ||||||||||
Central Appalachia | 29,667 | 32,054 | 29.5 | % | 30.1 | % | ||||||||||
Western Bituminous Region | 6,917 | 7,388 | 6.9 | % | 6.9 | % | ||||||||||
Total operating regions | 100,634 | 106,691 | 100.0 | % | 100.0 | % |
Coal sales. Coal sales revenues decreased in 2003 as compared to 2002 primarily as a result of a decline in sales volume in 2003. Volumes were depressed in large part because our utility customers reduced coal stockpile inventory levels throughout the year. Offsetting the volume decline was an increase in average realization, due primarily to higher pricing on contract shipments made in 2003 as compared to 2002. We experienced higher pricing in all of our operating basins, as average realizations increased 10.4% in the Powder River Basin, 2.6% in Central Appalachia and 2.8% in the Western Bituminous region.
Our consolidated coal sales revenues are impacted by the mix of sales among our operating regions, as Central Appalachia coal has higher pricing on a per-ton basis than either of our other operating regions. The comparison of revenues for 2003 and 2002 is relatively unaffected by the mix of sales between our operating regions.
Costs and Expenses |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2003 | 2002 | $ | % | |||||||||||||
(Amounts in thousands, except per ton data) | ||||||||||||||||
Cost of coal sales | $ | 1,280,608 | $ | 1,262,516 | $ | 18,092 | 1.4 | % | ||||||||
Depreciation, depletion and amortization | 158,464 | 174,752 | (16,288 | ) | (9.3 | )% | ||||||||||
Selling, general and administrative expenses | 43,942 | 37,999 | 5,943 | 15.6 | % | |||||||||||
Long-term incentive compensation expense | 16,217 | — | 16,217 | N/A | ||||||||||||
Other expenses | 18,245 | 29,595 | (11,350 | ) | (38.4 | )% | ||||||||||
$ | 1,517,476 | $ | 1,504,862 | $ | 12,614 | 0.8 | % | |||||||||
Cost of coal sales. Cost of coal sales increased despite a decrease in coal sales revenues and tonnage due primarily to increased costs related to our pension and postretirement medical plans of $34.0 million. This increase was a result of changes in the actuarial assumptions used to determine the liabilities and expenses related to the plans. Of the $34.0 million increase, $33.5 million related to our Central Appalachian operations. Additionally, cost of coal sales in 2003 was negatively impacted by the charges related to the reduction in force mentioned above and due to disruptions in production resulting from severe weather in the first quarter of 2003 at certain operations.
Depreciation, depletion and amortization. The decrease is due partially to a decline in depletion in 2003 as compared to 2002 that relates to a decrease in overall sales volumes of 5.7%. The decrease also relates to a decline in the amortization of coal supply agreements in 2003 as compared to 2002. This was primarily a result of the renegotiation of a significant contract in 2003. In April 2003, we agreed to terms with a customer seeking to buy out of the remaining term of an above-market supply contract. The buyout resulted in the receipt of $52.5 million in cash and the write off of the contract value of approximately $37.5 million. Amortization related to this contract was
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$0.9 million in 2003 compared to $2.8 million in 2002. Additionally, two other contracts were fully amortized in 2003. Amortization on these contracts totaled $2.5 million in 2003 versus $5.4 million in 2002.
Regional Analysis:
Our operating costs (reflected below on a per-ton basis) are defined as including all mining costs, which consist of all amounts classified as cost of coal sales (except pass-through transportation costs) and all depreciation, depletion and amortization attributable to mining operations. |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2003 | 2002 | $ | % | |||||||||||||
Powder River Basin | $ | 5.45 | $ | 5.31 | $ | 0.14 | 2.6 | % | ||||||||
Central Appalachia | $ | 30.87 | $ | 28.26 | $ | 2.61 | 9.2 | % | ||||||||
Western Bituminous Region | $ | 15.41 | $ | 14.53 | $ | 0.88 | 6.1 | % |
Powder River Basin — On a per-ton basis, operating costs increased slightly primarily a result of higher costs for certain operating supplies, including explosives and diesel fuel. | |
Central Appalachia — On a per-ton basis, operating costs increased 9.2% in 2003. As discussed above, Central Appalachia costs were negatively affected by the increased expense resulting from changes in actuarial assumptions on our pension and postretirement medical plans. | |
Western Bituminous Region — On a per-ton basis, operating costs increased 6.1% in 2003. Volumes declined as a result of our utility customers reducing inventory stockpiles throughout the year. As many of our costs are fixed in nature, the reduced volume did not result in reduced overall costs. |
Selling, general and administrative expenses. The increase in selling, general and administrative expenses is primarily due to an increase in compensation-related expenses and costs related to the reduction in force mentioned above. Our 2003 administrative expenses include approximately $2.7 million earned under our annual incentive plan. No amounts were earned under the annual incentive plan in 2002.
Other expenses. The decrease in other expenses is primarily a result of lower costs to terminate certain contractual obligations for the purchase of coal as compared to the prior year.
Other Operating Income |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2003 | 2002 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Income from equity investments | $ | 34,390 | $ | 10,092 | $ | 24,298 | 240.8 | % | ||||||||
Gain on sale of units of NRP | 42,743 | — | 42,743 | N/A | ||||||||||||
Other operating income | 45,226 | 50,489 | (5,263 | ) | (10.4 | )% | ||||||||||
$ | 122,359 | $ | 60,581 | $ | 61,778 | 102.0 | % | |||||||||
Income from equity investments. Income from equity investments for 2003 is comprised of $19.7 million from our investment in Canyon Fuel and $14.7 million from our investment in NRP. For 2002, income from Canyon Fuel was $7.8 million and income from NRP was $2.3 million. The improved results from Canyon Fuel are due primarily to improved operating margins, as reduced operating costs more than offset slightly lower realizations. The increase in income from NRP is due to
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the fact that 2003 includes a full year of income from NRP, while 2002 includes only that period from the formation of NRP in October 2002.
Other operating income. The decline in other operating income is due primarily to lower outlease royalty income resulting from the contribution of reserves and the related leases to NRP. The royalty income we recorded in 2003 was $7.1 million lower than that reported in 2002. This decline was partially offset by the gains on the sale of land described above.
Interest Expense, Net |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2004 | 2003 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Interest expense | $ | 50,133 | $ | 51,922 | $ | (1,789 | ) | (3.4 | )% | |||||||
Interest income | (2,636 | ) | (1,083 | ) | (1,553 | ) | (143.4 | )% | ||||||||
$ | 47,497 | $ | 50,839 | $ | (3,342 | ) | (6.6 | )% | ||||||||
Interest expense. The decline in interest expense is the result of lower average outstanding borrowings, as average debt levels declined more than 10% in 2003 as compared to 2002. During 2003, we reduced our overall debt levels through a public offering of preferred stock. This decline in debt levels was partially offset by higher interest rates. In June of 2003, we replaced Arch Western’s variable-rate term loans with fixed rate senior notes. The fixed-rate on the senior notes is higher than the variable rates that we paid in 2002.
Other non-operating income and expense |
Amounts reported as non-operating consist of income or expense resulting from our financing activities other than interest. As described above, our results of operations for 2003 include expenses of $4.7 million related to debt extinguishment costs and $4.3 million related to the termination of hedge accounting and resulting amortization of amounts that had previously been deferred.
Additionally, we recognized income of $13.4 million from mark-to-market adjustments for interest rate swap agreements which no longer qualify for hedge accounting.
Benefit from income taxes |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2003 | 2002 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Benefit from income taxes | $ | 23,210 | $ | 19,000 | $ | 4,210 | 22.2 | % |
Our effective tax rate is sensitive to changes in estimates of annual profitability and percentage depletion. The increase in the income tax benefit for 2003 is primarily due to the utilization of a capital loss which had previously been reserved. We were able to utilize the capital loss to offset a portion of the gain from the sale of units of NRP.
Deferred tax assets and liabilities are recorded at the maximum effective tax rate. Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. We have historically been subject to alternative minimum tax (AMT), and it is more likely than not that we will remain an AMT taxpayer in the foreseeable future. Valuation allowances are established against deferred tax assets so as to value the asset to an amount that is realizable, as further described in “Management’s Discussion and Analysis of Financial Condition — Critical Accounting Policies.”
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Net income (loss) before cumulative effect of accounting change |
Year Ended | Increase | |||||||||||||||
December 31, | (Decrease) | |||||||||||||||
2003 | 2002 | $ | % | |||||||||||||
(Amounts in thousands) | ||||||||||||||||
Net income (loss) before cumulative effect of accounting change | $ | 20,340 | $ | (2,562 | ) | $ | 22,902 | N/A |
The increase in net income before cumulative effect of accounting change is primarily due to the gain on the sale of units of NRP, offset by the long-term compensation plan expense, each of which is described above.
Cumulative effect of accounting change |
Effective January 1, 2003, we adopted Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations(“FAS 143”). FAS 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value at the time obligations are incurred. Upon initial recognition of a liability, that cost should be capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset. Application of FAS 143 resulted in a cumulative effect loss as of January 1, 2003 of $3.7 million, net of tax.
Outlook |
Railroad Transportation Disruptions. During 2004, rail service disruptions resulted in missed shipments in all of our operating regions, including some of our highest margin coal in Central Appalachia. In addition, we were periodically forced to curtail production at the West Elk mine in Colorado and the Black Thunder mine in Wyoming due to high inventory levels stemming from insufficient rail service. Inventory levels increased approximately 89% from the prior year to 16.1 million tons as of December 31, 2004.
The railroad disruptions, which initially resulted from inadequate staffing at the railroads, equipment shortages and an unexpected increase in overall rail shipments, improved somewhat during the third and fourth quarters, but suffered a setback following hurricane-related disruptions in the Southeast regions of the United States late in the third quarter. We anticipate continued challenges, with gradual improvement in rail service in the first half of 2005. We are working with our customers and the railroads in an effort to address these issues in a timely manner.
Expenses Related to Interest Rate Swaps. We had designated certain interest rate swaps as hedges of the variable rate interest payments due under Arch Western’s term loans. Pursuant to the requirements of FAS 133, historical mark-to-market adjustments related to these swaps through June 25, 2003 of $27.0 million were deferred as a component of Accumulated Other Comprehensive Loss. Subsequent to the repayment of the term loans, these deferred amounts will be amortized as additional expense over the original contractual terms of the swap agreements. As of December 31, 2004, the remaining deferred amounts will be recognized as expense in the following periods: $7.7 million in 2005; $4.8 million in 2006; and $1.9 million in 2007.
Chief Objectives. We are focused on taking steps to increase shareholder returns by improving earnings, strengthening cash generation, and improving productivity at our large-scale mines, while building on our strategic position in each of the nation’s three principal low-sulfur coal basins. We believe that success in the coal industry is largely dependent on leadership in three crucial areas of performance — safety, environmental stewardship and return on investment — and we are pursuing such leadership aggressively. At the same time, we are sustaining our longstanding focus on being a low-cost producer in the regions where we operate. We are also seeking to enhance our position as a preferred supplier to U.S. power producers by acting as a reliable and highly ethical partner. We plan to focus on organic growth by continuing to develop our existing reserve base, which is large and
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highly strategic. We also plan to evaluate acquisitions that represent a good fit with our existing operations.
Disclosure and Internal Controls |
An evaluation was performed under the supervision and with the participation of our management, including the CEO and CFO, of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2004. Based on that evaluation, our management, including the CEO and CFO, concluded that the disclosure controls and procedures were effective as of such date. There were no changes in internal control over financial reporting that occurred during our fiscal quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Liquidity and Capital Resources |
The following is a summary of cash provided by or used in each of the indicated types of activities during the past three years:
Year Ended December 31, | |||||||||||||
2004 | 2003 | 2002 | |||||||||||
(In thousands) | |||||||||||||
Cash provided by (used in): | |||||||||||||
Operating activities | $ | 146,728 | $ | 162,361 | $ | 176,417 | |||||||
Investing activities | (595,294 | ) | 6,832 | (128,303 | ) | ||||||||
Financing activities | 517,192 | 75,791 | (45,447 | ) |
Cash provided by operating activities declined in 2004 as compared to 2003 primarily as a result of increased investment in working capital. Trade accounts receivable represented the largest use of funds, increasing by more than $32.5 million (net of amounts acquired in business combinations) in 2004. This increase is due to higher sales levels during the period, as revenues have increased approximately 33% in 2004 as compared to 2003. Additionally, inventory increased by more than $12.0 million (net of amounts acquired in business combinations) in 2004. This increase is due primarily to the continued rail difficulties that resulted in missed shipments during the year. Cash provided by operating activities in 2003 declined as compared to 2002 due primarily to lower income levels (after adjusting for gains from the NRP unit sale in December 2003 and other asset sales).
Cash used in investing activities in 2004 is represented largely by payments for acquisitions of $387.8 million, net of cash acquired, during the third quarter of 2004. We acquired the 35% of the Canyon Fuel investment not owned by us and the North Rochelle operations from Triton in July and August 2004, respectively. The Canyon Fuel acquisition was funded with a $22.0 million five-year note and approximately $90 million of cash on hand. The Triton acquisition was funded with borrowings under our existing revolving credit facility of $22.0 million, a term loan in the amount of $100.0 million, and with cash on hand. Capital expenditures and advance royalty payments were $292.6 million and $33.8 million, respectively. Capital expenditures include $122.2 million related to the first of five annual payments under the lease of coal mineral reserves at Little Thunder discussed below. The remaining capital expenditures related to other various plant and equipment purchases, primarily at our Powder River Basin and Central Appalachia mines. These cash outlays were offset partially by proceeds of $111.4 million from the sale of the NRP units. Cash provided by investing activities in 2003 reflects the receipt of $115.0 million from the sale of the subordinated units and general partner interest of NRP and the receipt of $52.5 million from the buyout of a coal supply contract with above-market pricing. These non-recurring cash inflows offset our capital expenditures and advance royalty payments, which totaled $165.0 million. Cash used in investing activities in 2002 is due primarily to capital expenditures and advance royalty payments, which totaled $164.4 million,
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offset partially by the impact of the sale of limited partnership units of NRP in 2002, which generated proceeds of $33.6 million.
On September 22, 2004, the U.S. Bureau of Land Management (“BLM”) accepted our bid of $611.0 million for a 5,084-acre federal coal lease known as Little Thunder, which is adjacent to our Black Thunder mine in the Powder River Basin. According to the BLM, the lease contains approximately 719.0 million mineable tons of compliance coal. We paid the first of five annual payments at the time of the bid. The remaining four annual lease payments will be made in fiscal years 2006 through 2009.
Cash provided by financing activities in 2004 consists primarily of proceeds from the issuance of senior notes of $261.9 million and proceeds from the issuance of common stock through a public offering of $230.5 million (as described more fully below). Additionally, financing activities in 2004 also include net borrowings under our revolving credit facility of $25.0 million, proceeds of $37.0 million from the issuance of common stock under our employee stock incentive plan and dividend payments of $24.0 million. Cash provided by financing activities in 2003 reflects the proceeds from the issuance of the Arch Western Finance senior notes (which were used to retire Arch Western’s existing debt) and the proceeds from the sale of preferred stock (see additional discussion below). Cash used in financing activities during 2002 primarily represents net payments under our revolver and lines of credit, payments of dividends, and reductions of capital lease obligations. In addition, during 2002, we entered into a sale and leaseback of equipment that resulted in proceeds of $9.2 million.
On November 24, 2004, we filed a Universal Shelf Registration Statement on Form S-3 with the Securities and Exchange Commission. The Universal Shelf allows us to offer, from time to time, an aggregate of up to $1.0 billion in debt securities, preferred stock, depositary shares, purchase contracts, purchase units, common stock and related rights and warrants.
On October 28, 2004, we completed a public offering of 7,187,500 shares of our common stock, including the underwriters’ full over-allotment option, at a price of $33.85 per share. We used the net proceeds of the offering, totaling $230.5 million after the underwriters’ discount and expenses, to repay borrowings under our revolving credit facility incurred to finance our acquisition of Triton Coal Company and the first annual payment for the Little Thunder federal coal lease. We intend to use the remaining proceeds for general corporate purposes, including the development of the Mountain Laurel longwall mine in Central Appalachia.
On October 22, 2004, two subsidiaries of Arch Western, as co-obligors, issued $250 million of 63/4% senior notes due 2013 at a price of 104.75% of par, pursuant to Rule 144A under the Securities Act of 1933, as amended. The notes form a single series with Arch Western Finance’s existing 63/4% senior notes due 2013, except that the new notes are subject to certain transfer restrictions and are not fully fungible with the existing notes. We have an exchange offer underway for the notes; after completion of the exchange offer, the notes will be fully fungible with the previously issued notes. The net proceeds of the offering were used to repay and retire the outstanding indebtedness under Arch Western’s $100.0 million term loan maturing in 2007, to repay indebtedness under our revolving credit facility and for general corporate purposes.
On June 25, 2003, Arch Western Finance, LLC, a subsidiary of Arch Western, completed the offering of $700 million of 63/4% senior notes due 2013. The proceeds of the offering were primarily used to repay Arch Western’s existing term loans. Interest on the senior notes is payable on January 1 and July 1 each year commencing January 1, 2004. The senior notes are guaranteed by Arch Western and certain of Arch Western’s subsidiaries and are secured by a security interest in promissory notes we issued to Arch Western evidencing cash loaned to us by Arch Western. The terms of the senior notes contain restrictive covenants that limit Arch Western’s ability to, among other things, incur additional debt, sell or transfer assets, and make investments.
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On January 31, 2003, we completed a public offering of 2,875,000 shares of 5% Perpetual Cumulative Convertible Preferred Stock. The net proceeds from the offering of approximately $139.0 million were used to reduce indebtedness under our revolving credit facility and for working capital and general corporate purposes, including potential acquisitions.
Excluding any significant mineral reserve acquisitions, we generally satisfy our working capital requirements and fund capital expenditures and debt-service obligations with cash generated from operations. We believe that cash generated from operations and our borrowing capacity will be sufficient to meet working capital requirements, anticipated capital expenditures and scheduled debt payments for at least the next several years. Our ability to satisfy debt service obligations, to fund planned capital expenditures, to make acquisitions and to pay dividends will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond our control.
Capital expenditures were $292.6 million, $132.4 million and $137.1 million for 2004, 2003 and 2002, respectively. Capital expenditures are made to improve and replace existing mining equipment, expand existing mines, develop new mines and improve the overall efficiency of mining operations. We anticipate that capital expenditures during 2005 will range from $340 to $360 million. This estimate includes capital expenditures related to development work at certain of our mining operations, including the Mountain Laurel complex in West Virginia and the North Lease mine in Utah formerly known as Skyline. Also, this estimate assumes no other acquisitions, significant expansions of our existing mining operations or additions to our reserve base. We anticipate that we will fund these capital expenditures with available cash, existing credit facilities and cash generated from operations.
On December 22, 2004, we entered into a $700.0 million revolving credit facility that matures on December 22, 2009. The rate of interest on borrowings under the credit facility is a floating rate based on LIBOR. The credit facility is secured by substantially all of our assets as well as our ownership interests in substantially all of our subsidiaries, except our ownership interests in Arch Western and its subsidiaries. The credit facility replaced our existing $350.0 million revolving credit facility. At December 31, 2004, we had $69.0 million in letters of credit outstanding which, when combined with the $25.0 million of outstanding borrowings under the revolver, resulted in $606.0 million of unused borrowings under the revolver. At December 31, 2004, financial covenant requirements do not restrict the amount of unused capacity available to us for borrowing and letters of credit.
Financial covenants contained in our revolving credit facility consist of a maximum leverage ratio, a maximum senior secured leverage ratio and a minimum interest coverage ratio. The leverage ratio requires that we not permit the ratio of total net debt (as defined in the facility) at the end of any calendar quarter to EBITDA (as defined in the facility) for the four quarters then ended to exceed a specified amount. The interest coverage ratio requires that we not permit the ratio of EBITDA (as defined) at the end of any calendar quarter to interest expense for the four quarters then ended to be less than a specified amount. The senior secured leverage ratio requires that we not permit the ratio of total net senior secured debt (as defined) at the end of any calendar quarter to EBITDA (as defined) for the four quarters then ended to exceed a specified amount. We were in compliance with all financial covenants at December 31, 2004.
At December 31, 2004, debt amounted to $1,011.1 million, or 48% of capital employed, compared to $706.4 million, or 51% of capital employed, at December 31, 2003. Based on the level of consolidated indebtedness and prevailing interest rates at December 31, 2004, debt service obligations, which include the current maturities of debt and interest expense for 2005, are estimated to be $76.0 million.
We periodically establish uncommitted lines of credit with banks. These agreements generally provide for short-term borrowings at market rates. At December 31, 2004, there were $20.0 million of such agreements in effect, of which none were outstanding.
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We are exposed to market risk associated with interest rates due to our existing level of indebtedness. At December 31, 2004, substantially all of our outstanding debt bore interest at fixed rates.
Additionally, we are exposed to market risk associated with interest rates resulting from our interest rate swap positions. Prior to the June 25, 2003 Arch Western Finance senior notes offering and subsequent repayment of Arch Western’s term loans, we utilized interest rate swap agreements to convert the variable-rate interest payments due under the term loans and our revolving credit facility to fixed-rate payments.
At December 31, 2004, our net interest rate swap position is as follows:
• | Swaps with a notional value of $25.0 million which are designated as hedges of future interest payments to be made under our revolving credit facility. Under these swaps, we pay a fixed rate of 5.96% (before the credit spread over LIBOR) and receive a variable rate based upon 30-day LIBOR. The remaining term of the swap agreements at December 31, 2004 was 30 months. | |
• | Swaps with a total notional value of $500.0 million consisting of offsetting positions of $250.0 million each. Because of the offsetting nature of these positions, we are not exposed to significant market interest rate risk related to these swaps. Under these swaps, we pay a weighted average fixed rate 5.72% on $250.0 million of notional value and receive a weighted average fixed rate of 2.71% on $250.0 million of notional value. The remaining terms of these swap agreements at December 31, 2004 ranged from 8 to 31 months. |
As of December 31, 2004, the fair value of our net interest rate swap position was a liability of $12.4 million. This liability is included in other noncurrent liabilities in the accompanying Consolidated Balance Sheets.
We are also exposed to commodity price risk related to our purchase of diesel fuel. We enter into forward purchase contracts and heating oil swaps to reduce volatility in the price of diesel fuel for our operations. The swap agreements essentially fix the price paid for diesel fuel by requiring us to pay a fixed heating oil price and receive a floating heating oil price. The changes in the floating heating oil price highly correlate to changes in diesel fuel prices.
The discussion below presents the sensitivity of the market value of our financial instruments to selected changes in market rates and prices. The range of changes reflects our view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen. The major accounting policies for these instruments are described in Note 1 to the consolidated financial statements.
At December 31, 2004, our debt portfolio consisted of substantially fixed rates. A change in interest rates on the fixed rate debt impacts the net financial instrument position but has no impact on interest incurred or cash flows. The sensitivity analysis related to our fixed rate debt assumes an instantaneous 100-basis point move in interest rates from their levels at December 31, 2004, with all other variables held constant. A 100-basis point increase in market interest rates would result in a $58.4 million decrease in the fair value of the Company’s fixed rate debt at December 31, 2004. At December 31, 2004, a $.05 per gallon increase in the price of heating oil would result in a $0.1 million increase in the fair value of the financial position of the heating oil swap agreements.
As it relates to our interest rate swap positions, a change in interest rates impacts the net financial instrument position. A 100-basis point increase in market interest rates would result in a $0.6 million decrease in the fair value of our liability under the interest rate swap positions at December 31, 2004.
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Contractual Obligations |
The following is a summary of our significant contractual obligations as of December 31, 2004 (in thousands):
Payments Due by Period | ||||||||||||||||
2005 | 2006-2007 | 2008-2009 | After 2009 | |||||||||||||
Long-term debt, including related interest | $ | 75,069 | $ | 136,317 | $ | 162,250 | $ | 1,174,438 | ||||||||
Operating leases | 25,282 | 44,767 | 35,786 | 29,066 | ||||||||||||
Royalty leases | 32,227 | 309,320 | 297,987 | 72,715 | ||||||||||||
Unconditional purchase obligations | 539,107 | 163,975 | 100,113 | — | ||||||||||||
Other long-term obligations | — | — | — | 23,200 | ||||||||||||
Total contractual cash obligations | $ | 671,685 | $ | 654,379 | $ | 596,136 | $ | 1,299,419 | ||||||||
Royalty leases represent non-cancelable royalty lease agreements as well as federal lease bonus payments due under the Little Thunder lease. Payments due under the Little Thunder lease total $611.0 million, to be paid in five equal annual installments of $122.2 million. The first installment was paid in September 2004 with the remaining four annual payments due in fiscal years 2006 through 2009. Unconditional purchase obligations represent amounts committed for purchases of materials and supplies, payments for services, purchased coal, and capital expenditures. Other long-term obligations represent our contractual amounts owed in conjunction with our ownership interest in Dominion Terminal Associates as described in Note 20 to the Consolidated Financial Statements.
We currently do not anticipate making any contributions to our pension plan in 2005. We believe that our on-hand cash balance, cash generated from operations, and borrowing capacity under our revolving credit facility and other debt facilities will be sufficient to meet these obligations and our requirements for working capital and capital expenditures.
Contingencies |
Reclamation |
The federal Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes require that mine property be restored in accordance with specified standards and an approved reclamation plan. We accrue for the costs of reclamation in accordance with the provisions of FAS 143, which was adopted as of January 1, 2003. These costs relate to reclaiming the pit and support acreage at surface mines and sealing portals at deep mines. Other costs of reclamation common to surface and underground mining are related to reclaiming refuse and slurry ponds, eliminating sedimentation and drainage control structures, and dismantling or demolishing equipment or buildings used in mining operations. The establishment of the asset retirement obligation liability is based upon permit requirements and requires various estimates and assumptions, principally associated with costs and productivities.
We review our entire environmental liability periodically and make necessary adjustments, including permit changes and revisions to costs and productivities to reflect current experience. Our management believes it is making adequate provisions for all expected reclamation and other associated costs.
Legal Contingencies |
Permit Litigation Matters. A group of local and national environmental organizations filed suit against the U.S. Army Corps of Engineers in the U.S. District Court in Huntington, West Virginia on October 23, 2003. In its complaint,Ohio River Valley Environmental Coalition, et al v. Bulen, et al, the plaintiffs allege that the Corps has violated its statutory duties arising under the Clean Water Act, the
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Administrative Procedure Act and the National Environmental Policy Act in issuing the Nationwide 21 (“NWP 21”) general permit. The plaintiffs allege that the procedural requirements of the three federal statutes identified in their complaint have been violated, and that the Corps may not utilize the mechanism of a nationwide permit to authorize valley fills. Among specific fills identified in the complaint as not meeting the requirements of the NWP 21 are valley fills associated with several of our operating subsidiaries, although none are party to this litigation. If the plaintiffs prevail in this litigation, it may delay our receipt of these permits.
On July 8, 2004, the District court entered a final order enjoining the Corps from authorizing new valley fills using the mechanism of its nationwide permit. The Court also ordered the Corps to suspend current authorizations issued for fills that had not yet commenced construction on the date of the order. The district court modified its earlier decision on August 13 when it directed the Corps to suspend all permits for fills that had not commenced construction as of July 8, 2004.
A total of three permits at two of our operating subsidiaries will be affected by the Court’s July 8 order. Because the Court found that it is the Corps’ procedure in issuing the permits, and not defects in the fills themselves, our affected subsidiaries will be able to re-apply for individual permits under section 404 of the Clean Water act to construct each fill. We currently do not believe that the individual permit process will have an impact on our mining operations.
The Corps and several intervening trade associations, of which we are a member of three, filed an appeal with the U.S. Court of Appeals for the Fourth circuit in this matter on September 16, 2004.
West Virginia Flooding Litigation. We and three of our subsidiaries have been named, among others, in 17 separate complaints filed in Wyoming, McDowell, Fayette, Upshur, Kanawha, Raleigh, Boone and Mercer Counties, West Virginia. These cases collectively include approximately 1,780 plaintiffs who are seeking damages for property damage and personal injuries arising out of flooding that occurred in southern West Virginia in July of 2001. The plaintiffs have sued coal, timber, railroad and land companies under the theory that mining, construction of haul roads and removal of timber caused natural surface waters to be diverted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that these cases, along with several additional flood damages cases not involving our subsidiaries, be handled pursuant to the Court’s Mass Litigation rules. As a result of this ruling, the cases have been transferred to the Circuit Court of Raleigh County in West Virginia to be handled by a panel consisting of three circuit court judges, which certified certain legal issues back to the West Virginia Supreme Court. The West Virginia Supreme Court has resolved these issues, and the panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts.
While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our financial condition or results of operations.
Ark Land Company v. Crown Industries. In response to a declaratory judgment action filed by Ark Land Company, a subsidiary of ours, in Mingo County, West Virginia against Crown Industries involving the interpretation of a severance deed under which Ark Land controls the coal and mining rights on property in Mingo County, West Virginia, Crown Industries filed a counterclaim against Ark Land and a third party complaint against us and two of our other subsidiaries seeking damages for trespass, nuisance and property damage arising out of the exercise of rights under the severance deed on the property by our subsidiaries. The defendant has alleged that our subsidiaries have insufficient rights to haul certain foreign coals across the property without payment of certain wheelage or other fees to the defendant. In addition, the defendant has alleged that we and our subsidiaries have violated West Virginia’s Standards for Management of Waste Oil and the West Virginia Surface Coal Mining and Reclamation Act by spilling and disposing of hydrocarbon and other wastes on and in the property and
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by failing to return the property to its approximate original contour. It also alleges that we or our contractor have improperly disposed of explosive components. This case is set for trial in May 2005.
While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on it, we believe this matter will be resolved without a material adverse effect on our financial condition or results of operations.
We are a party to numerous other claims and lawsuits with respect to various matters. We provide for costs related to contingencies, including environmental matters, when a loss is probable and the amount is reasonably determinable. After conferring with counsel, it is the opinion of management that the ultimate resolution of these claims, to the extent not previously provided for, will not have a material adverse effect on our consolidated financial condition, results of operations or liquidity.
Certain Trends and Uncertainties |
Substantial Leverage — Covenants |
As of December 31, 2004, we had outstanding consolidated indebtedness of $1,011.1 million, representing approximately 48% of our capital employed. Despite making substantial progress in reducing debt, we continue to have significant debt service obligations, and the terms of our credit agreements limit our flexibility and result in a number of limitations on us. We also have significant lease and royalty obligations. Our ability to satisfy debt service, lease and royalty obligations and to effect any refinancing of our indebtedness will depend upon future operating performance, which will be affected by prevailing economic conditions in the markets that we serve as well as financial, business and other factors, many of which are beyond our control. We may be unable to generate sufficient cash flow from operations and future borrowings, or other financings may be unavailable in an amount sufficient to enable us to fund our debt service, lease and royalty payment obligations or our other liquidity needs.
Our relative amount of debt and the terms of our credit agreements could have material consequences to our business, including, but not limited to: (i) making it more difficult to satisfy debt covenants and debt service, lease payment and other obligations; (ii) making it more difficult to pay quarterly dividends as we have in the past; (iii) increasing our vulnerability to general adverse economic and industry conditions; (iv) limiting our ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general corporate requirements; (v) reducing the availability of cash flows from operations to fund acquisitions, working capital, capital expenditures or other general corporate purposes; (vi) limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we compete; or (vii) placing us at a competitive disadvantage when compared to competitors with less relative amounts of debt.
The agreements governing our outstanding debt impose a number of restrictions on us. For example, the terms of our credit facilities and leases contain financial and other covenants that create limitations on our ability to, among other things, borrow the full amount under our credit facilities, effect acquisitions or dispositions and incur additional debt, and require us to, among other things, maintain various financial ratios and comply with various other financial covenants. Our ability to comply with these restrictions may be affected by events beyond our control and, as a result, we may be unable to comply with these restrictions. A failure to comply with these restrictions could adversely affect our ability to borrow under our credit facilities or result in an event of default under these agreements. In the event of a default, our lenders could terminate their commitments to us and declare all amounts borrowed, together with accrued interest and fees, immediately due and payable. If this were to occur, we might not be able to pay these amounts, or we might be forced to seek an amendment to our debt agreements which could make the terms of these agreements more onerous for us.
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Any downgrade in our credit ratings could adversely affect our ability to borrow and result in more restrictive borrowing terms, including increased borrowing costs, more restrictive covenants and the extension of less open credit. This in turn could affect our internal cost of capital estimates and therefore operational decisions.
Profitability |
Our mining operations are inherently subject to changing conditions that can affect levels of production and production costs at particular mines for varying lengths of time and can result in decreases in our profitability. We are exposed to commodity price risk related to our purchase of diesel fuel, explosives and steel. In addition, weather conditions, equipment replacement or repair, fires, variations in thickness of the layer, or seam, of coal, amounts of overburden, rock and other natural materials and other geological conditions have had, and can be expected in the future to have, a significant impact on our operating results. Prolonged disruption of production at any of our principal mines, particularly our Black Thunder mine, would result in a decrease in our revenues and profitability, which could be material. Other factors affecting the production and sale of our coal that could result in decreases in our profitability include:
• | continued high pricing environment for our raw materials, including, among other things, diesel fuel, explosives and steel; | |
• | expiration or termination of, or sales price redeterminations or suspension of deliveries under, coal supply agreements; | |
• | disruption or increases in the cost of transportation services; | |
• | changes in laws or regulations, including permitting requirements; | |
• | litigation; | |
• | work stoppages or other labor difficulties; | |
• | labor shortages | |
• | mine worker vacation schedules and related maintenance activities; and | |
• | changes in coal market and general economic conditions. |
Environmental and Regulatory Factors |
The coal mining industry is subject to regulation by federal, state and local authorities on matters such as:
• | the discharge of materials into the environment; | |
• | employee health and safety; | |
• | mine permits and other licensing requirements; | |
• | reclamation and restoration of mining properties after mining is completed; | |
• | management of materials generated by mining operations; | |
• | surface subsidence from underground mining; | |
• | water pollution; | |
• | legislatively mandated benefits for current and retired coal miners; | |
• | air quality standards; | |
• | protection of wetlands; | |
• | endangered plant and wildlife protection; | |
• | limitations on land use; |
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• | storage of petroleum products and substances that are regarded as hazardous under applicable laws; and | |
• | management of electrical equipment containing polychlorinated biphenyls, or PCBs. |
In addition, the electric generating industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities, which could affect demand for our coal. The possibility exists that new legislation or regulations may be adopted or that the enforcement of existing laws could become more stringent, either of which may have a significant impact on our mining operations or our customers’ ability to use coal and may require us or our customers to significantly change operations or to incur substantial costs.
While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.
Clean Air Act. The federal Clean Air Act and similar state and local laws, which regulate emissions into the air, affect coal mining and processing operations primarily through permitting and emissions control requirements. The Clean Air Act also indirectly affects coal mining operations by extensively regulating the emissions from coal-fired industrial boilers and power plants, which are the largest end-users of our coal. These regulations can take a variety of forms, as explained below.
The Clean Air Act imposes obligations on the Environmental Protection Agency, or EPA, and the states to implement regulatory programs that will lead to the attainment and maintenance of EPA-promulgated ambient air quality standards, including standards for sulfur dioxide, particulate matter, nitrogen oxides and ozone. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standard for ozone. In particular, coal-fired power plants will be affected by state regulations designed to achieve attainment of the ambient air quality standard for ozone. Ozone is produced by the combination of two precursor pollutants: volatile organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead.
In July 1997, the EPA adopted more stringent ambient air quality standards for particulate matter and ozone. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. In April 2004, the EPA issued final nonattainment designations for the eight-hour ozone standard, and, in December 2004, issued the final nonattainment standard for PM25. States will have to reuse their State Implementation Plans to require electric power generators to further reduce nitrogen oxide and particulate matter emissions, particularly in designated nonattainment areas. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and our development of new mines. This in turn may result in decreased production and a corresponding decrease in our revenues. Although the future scope of these ozone and particulate
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matter regulations cannot be predicted, future regulations regarding these and other ambient air standards could restrict the market for coal and the development of new mines.
The EPA has also initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. By imposing limitations upon the placement and construction of new coal-fired power plants, the EPA’s regional haze program could affect the future market for coal.
Additionally, the U.S. Department of Justice, on behalf of the EPA, has filed lawsuits against several investor-owned electric utilities for alleged violations of the Clean Air Act. The EPA claims that these utilities have failed to obtain permits required under the Clean Air Act for alleged major modifications to their power plants. We supply coal to some of the currently affected utilities, and it is possible that other of our customers will be sued. These lawsuits could require the utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures, which could adversely impact their demand for coal.
New regulations concerning the routine maintenance provisions of the New Source Review program were published in October 2003. Fourteen states, the District of Columbia and a number of municipalities filed lawsuits challenging these regulations, and in December 2003 the Court stayed the effectiveness of these rules. Oral agreement was heard on this matter in January 2005. In January 2004, the EPA Administrator announced that EPA would be taking new enforcement actions against utilities for violations of the existing New Source Review requirements, and shortly thereafter, EPA issued enforcement notices to several electric utility companies.
In January 2004, the EPA proposed two new rules pursuant to the Clean Air Act that, once final, may require additional controls and impose more stringent requirements at coal-fired power generation facilities. First, EPA is seeking to lower nickel and mercury emissions at new and existing sources by requiring the use of Maximum Achievable Control Technology (“MACT”) or by implementing a nationwide “cap and trade” program. Second, EPA has proposed to require the submission of State Implementation Plans by 29 states and the District of Columbia to include control measures to reduce the emissions of sulfur dioxide and/or nitrogen oxides, pursuant to the eight-hour ozone and PM25 standards established pursuant to the Clean Air Act. The EPA has stated that it will issue new rules in 2005. Should either or both of these proposed rules become final, additional costs may be associated with operating coal-fired power generation facilities that may render coal a less attractive fuel source.
Other Clean Air Act programs are also applicable to power plants that use our coal. For example, the acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur dioxide reductions can affect coal mining operations. Title IV imposes a two phase approach to the implementation of required sulfur dioxide emissions reductions. Phase I, which became effective in 1995, regulated the sulfur dioxide emissions levels from 261 generating units at 110 power plants and targeted the highest sulfur dioxide emitters. Phase II, implemented January 1, 2000, made the regulations more stringent and extended them to additional power plants, including all power plants
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of greater than 25 megawatt capacity. Affected electric utilities can comply with these requirements by:
• | burning lower sulfur coal, either exclusively or mixed with higher sulfur coal; | |
• | installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal; | |
• | reducing electricity generating levels; or | |
• | purchasing or trading emissions credits. |
Specific emissions sources receive these credits, which electric utilities and industrial concerns can trade or sell to allow other units to emit higher levels of sulfur dioxide. Each credit allows its holder to emit one ton of sulfur dioxide.
In addition to emissions control requirements designed to control acid rain and to attain the national ambient air quality standards, the Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA recently announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009. These controls are likely to require significant new improvements in controls by power plant owners. The most prominently targeted pollutant is mercury, which is already the subject of a proposed rule, although other by-products of coal combustion may be covered by future hazardous air pollutant standards for coal combustion sources.
Other proposed initiatives may have an effect upon coal operations. One such proposal is the Bush Administration’s recently announced Clear Skies Initiative. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxides, and mercury from power plants. Other so-called multi-pollutant bills, which could regulate additional air pollutants, have been proposed by various members of Congress. While the details of all of these proposed initiatives vary, there appears to be a movement towards increased regulation of a number of air pollutants. Were such initiatives enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements.
Mine Health and Safety Laws. Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Safety and Health Act of 1969. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Safety and Health Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Safety and Health Acts of 1969 and 1977, the Black Lung Act requires payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dies from this disease.
Surface Mining Control and Reclamation Act. SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. SMCRA requires that comprehensive environmental protection and reclamation standards be met during the course of and upon completion of mining activities. In conjunction with mining the property, we are contractually obligated under the terms of our leases to comply with all laws, including SMCRA and equivalent state and local laws. These obligations include reclaiming and restoring the mined areas by grading, shaping, preparing the soil for seeding and by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.
SMCRA also requires us to submit a bond or otherwise financially secure the performance of our reclamation obligations. The earliest a reclamation bond can be completely released is five years after reclamation has been achieved. Federal law and some states impose on mine operators the responsibility for repairing the property or compensating the property owners for damage occurring
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on the surface of the property as a result of mine subsidence, a consequence of longwall mining and possibly other mining operations. In addition, the Abandoned Mine Lands Act, which is part of SMCRA, imposes a tax on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton of coal produced from surface mines and $0.15 per ton of coal produced from underground mines.
We also lease some of our coal reserves to third party operators. Under SMCRA, responsibility for unabated violations, unpaid civil penalties and unpaid reclamation fees of independent mine lessees and other third parties could potentially be imputed to other companies that are deemed, according to the regulations, to have “owned” or “controlled” the mine operator. Sanctions against the “owner” or “controller” are quite severe and can include civil penalties, reclamation fees and reclamation costs. We are not aware of any currently pending or asserted claims against us asserting that we “own” or “control” any of our lessees’ operations.
Framework Convention on Global Climate Change. The United States and more than 160 other nations are signatories to the 1992 Framework Convention on Global Climate Change, commonly known as the Kyoto Protocol, that is intended to limit or capture emissions of greenhouse gases such as carbon dioxide and methane. The U.S. Senate has neither ratified the treaty commitments, which would mandate a reduction in U.S. greenhouse gas emissions, nor enacted any law specifically controlling greenhouse gas emissions and the Bush Administration has withdrawn support for this treaty. Nonetheless, future regulation of greenhouse gases could occur either pursuant to future U.S. treaty obligations or pursuant to statutory or regulatory changes under the Clean Air Act. Efforts to control greenhouse gas emissions could result in reduced demand for coal if electric power generators switch to lower carbon sources of fuel.
West Virginia Antidegradation Policy. In January 2002, a number of environmental groups and individuals filed suit in the U.S. District Court for the Southern District of West Virginia to challenge the EPA’s approval of West Virginia’s antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. In August 2003, the Southern District of West Virginia vacated the EPA’s approval of West Virginia’s anti-degradation procedures, and remanded the matter to the EPA. On March 29, 2004, EPA Regions III sent a letter to the WVDEP that approved portions of the state’s anti-degradation program, denied approval of portions pending further study, and recommended removal of certain language on the state’s regulations. Depending upon the outcome of the DEP review, the issuance or re-issuance of Clean Water Act permits to us may be delayed or denied, and may increase the costs, time and difficulty associated with obtaining and complying Clean Water Act permits for surface mining operations.
Comprehensive Environmental Response, Compensation and Liability Act. CERCLA and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Thus, coal mines that we currently own or have previously owned or operated, and sites to which we sent waste materials, may be subject to liability under CERCLA and
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similar state laws. In particular, we may be liable under CERCLA or similar state laws for the cleanup of hazardous substance contamination at sites where we own surface rights.
Mining Permits and Approvals. Mining companies must obtain numerous permits that strictly regulate environmental and health and safety matters in connection with coal mining, some of which have significant bonding requirements. In connection with obtaining these permits and approvals, we may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations. Regulations also provide that a mining permit can be refused or revoked if an officer, director or a shareholder with a 10% or greater interest in the entity is affiliated with another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.
Regulatory authorities exercise considerable discretion in the timing of permit issuance. Also, private individuals and the public at large possess rights to comment on and otherwise engage in the permitting process, including through intervention in the courts. Accordingly, the permits we need for our mining operations may not be issued, or, if issued, may not be issued in a timely fashion, or may involve requirements that may be changed or interpreted in a manner which restricts our ability to conduct our mining operations or to do so profitably.
In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including us, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically we submit the necessary permit applications several months before we plan to begin mining a new area. In our experience, permits generally are approved several months after a completed application is submitted. In the past, we have generally obtained our mining permits without significant delay. However, we cannot be sure that we will not experience difficulty in obtaining mining permits in the future.
Future legislation and administrative regulations may emphasize the protection of the environment and, as a consequence, the activities of mine operators, including us, may be more closely regulated. Legislation and regulations, as well as future interpretations of existing laws, may also require substantial increases in equipment expenditures and operating costs, as well as delays, interruptions or the termination of operations. We cannot predict the possible effect of such regulatory changes.
Under some circumstances, substantial fines and penalties, including revocation or suspension of mining permits, may be imposed under the laws described above. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.
Surety Bonds. Federal and state laws require us to obtain surety bonds to guarantee performance or payment of certain long-term obligations including mine closure and reclamation costs, federal and state workers’ compensation benefits, coal leases and other miscellaneous obligations. It has become increasingly difficult for us to secure new surety bonds or retain existing bonds without the posting of collateral. In addition, surety bond costs have increased and the market terms of such bonds have generally become more unfavorable. We may be unable to maintain our surety bonds or acquire new bonds in the future due to lack of availability, higher expense, unfavorable market terms, or an inability to post sufficient collateral. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material adverse impact on us.
Endangered Species. The federal Endangered Species Act and counterpart state legislation protects species threatened with possible extinction. Protection of endangered species may have the
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effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.
Other Environmental Laws Affecting Us. We are required to comply with numerous other federal, state and local environmental laws in addition to those previously discussed. These additional laws include, for example, the Resource Conservation and Recovery Act, the Safe Drinking Water Act, the Toxic Substance Control Act and the Emergency Planning and Community Right-to-Know Act. We believe that we are in substantial compliance with all applicable environmental laws.
Competition |
The coal industry is intensely competitive, primarily as a result of the existence of numerous producers in the coal-producing regions in which we operate, and some of our competitors may have greater financial resources. We compete with several major coal producers in the Central Appalachian and Powder River Basin areas. We also compete with a number of smaller producers in those and other market regions. Additionally, we are subject to the continuing risk of reduced profitability as a result of excess industry capacity.
Electric Industry Factors; Customer Creditworthiness |
Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which has accounted for approximately 90% of domestic coal consumption in recent years. These coal consumption patterns are influenced by factors beyond our control, including the demand for electricity (which is dependent to a significant extent on summer and winter temperatures and the strength of the economy); government regulation; technological developments and the location, availability, quality and price of competing sources of coal; other fuels such as natural gas, oil and nuclear; and alternative energy sources such as hydroelectric power. Demand for our low-sulfur coal and the prices that we will be able to obtain for it will also be affected by the price and availability of high-sulfur coal, which can be marketed in tandem with emissions allowances in order to meet federal Clean Air Act requirements. Any reduction in the demand for our coal by the domestic electric generation industry may cause a decline in profitability.
Electric utility deregulation is expected to provide incentives to generators of electricity to minimize their fuel costs and is believed to have caused electric generators to be more aggressive in negotiating prices with coal suppliers. Deregulation may have an adverse effect on our profitability to the extent it causes our customers to be more cost-sensitive.
In addition, our ability to receive payment for coal sold and delivered depends on the creditworthiness of our customers. In general, the creditworthiness of our customers has deteriorated. If such trends continue, our acceptable customer base may be limited.
Terms of Long-Term Coal Supply Contracts |
During 2004, sales of coal under long-term contracts, which are contracts with a term greater than 12 months, accounted for 70% of our total revenues. The prices for coal shipped under these contracts may be below the current market price for similar type coal at any given time. For the year ended December 31, 2004, the weighted average price of coal sold under our long-term contracts was $15.15 per ton. As a consequence of the substantial volume of our sales which are subject to these long-term agreements, we have less coal available with which to capitalize on stronger coal
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prices if and when they arise. In addition, because long-term contracts may allow the customer to elect volume flexibility, our ability to realize the higher prices that may be available on the spot market may be restricted when customers elect to purchase higher volumes under such contracts. Our exposure to market-based pricing may also be increased should customers elect to purchase fewer tons. In addition, the increasingly short terms of sales contracts and the consequent absence of price adjustment provisions in such contracts make it more likely that we will not be able to recover inflation related increases in mining costs during the contract term.
Reserve Degradation and Depletion |
Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs. Replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. We have in the past acquired and will in the future acquire coal reserves for our mine portfolio from third parties. We may not be able to accurately assess the geological characteristics of any reserves that we acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines can also have an adverse effect on operating results that is disproportionate to the percentage of overall production represented by such mines. Mingo Logan’s Mountaineer Mine is estimated to exhaust its longwall mineable reserves in the first quarter of 2007, although we expect to make up the lost production with our planned opening of our Mountain Laurel complex in Logan County, West Virginia which should ramp up to full production in mid-2007. The Mountaineer Mine generated $30.5 million and $26.1 million of our total operating income in the years ended 2004 and 2003, respectively.
Potential Fluctuations in Operating Results — Factors Routinely Affecting Results of Operations |
Our mining operations are inherently subject to changing conditions that can affect levels of production and production costs at particular mines for varying lengths of time and can result in decreases in profitability. Weather conditions, equipment replacement or repair, fuel and supply prices, insurance costs, fires, variations in coal seam thickness, amounts of overburden rock and other natural materials, and other geological conditions have had, and can be expected in the future to have, a significant impact on operating results. A prolonged disruption of production at any of our principal mines, particularly the Mingo Logan operation in West Virginia or Black Thunder mine in Wyoming, would result in a decrease, which could be material, in our revenues and profitability.
The geological characteristics of Central Appalachia coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. In addition, as compared to mines in the Powder River Basin, permitting and licensing and other environmental and regulatory requirements are more costly and time-consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and customers’ ability to use coal produced by, operators in Central Appalachia, including us.
Other factors affecting the production and sale of our coal that could result in decreases in profitability include: (i) expiration or termination of, or sales price redeterminations or suspension of deliveries under, coal supply agreements; (ii) disruption or increases in the cost of transportation services; (iii) changes in laws or regulations, including permitting requirements; (iv) litigation; (v) work stoppages or other labor difficulties; (vi) mine worker vacation schedules and related maintenance activities; and (vii) changes in coal market and general economic conditions.
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Transportation |
The coal industry depends on rail, trucking and barge transportation to deliver shipments of coal to customers, and transportation costs are a significant component of the total cost of supplying coal. Disruption or insufficient availability of these transportation services could temporarily impair our ability to supply coal to customers and thus adversely affect our business and the results of our operations. In addition, increases in transportation costs associated with our coal, or increases in our transportation costs relative to transportation costs for coal produced by our competitors or of other fuels, could adversely effect our business and results of operations.
Reserves — Title; Leasehold Interests |
We base our reserve information on geological data assembled and analyzed by our staff, which includes various engineers and geologists, and periodically reviewed by outside firms. The reserve estimates are annually updated to reflect production of coal from the reserves and new drilling or other data received. There are numerous uncertainties inherent in estimating quantities of recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, such as geological and mining conditions which may not be fully identified by available exploration data or may differ from experience in current operations, historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies, and assumptions concerning coal prices, operating costs, severance and excise taxes, development costs, and reclamation costs, all of which may cause estimates to vary considerably from actual results.
For these reasons, estimates of the economically recoverable quantities attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties, and revenues and expenditures with respect to our reserves, may vary from estimates, and such variances may be material. These estimates thus may not accurately reflect our actual reserves.
Most of our mining operations are conducted on properties we lease. The loss of any lease could adversely affect our ability to develop the associated reserves. Because title to most of our leased properties and mineral rights is not usually verified until we have made a commitment to develop a property, which may not occur until after we have obtained necessary permits and completed exploration of the property, our right to mine certain of our reserves may be adversely affected if defects in title or boundaries exist. In order to obtain leases or mining contracts to conduct mining operations on property where these defects exist, we have had to, and may in the future have to, incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases or mining contracts for properties containing additional reserves or maintain our leasehold interests in properties on which mining operations are not commenced during the term of the lease.
Acquisitions |
We continually seek to expand our operations and coal reserves in the regions in which we operate through acquisitions of businesses and assets, including leases of coal reserves. Acquisition transactions involve inherent risks, such as:
• | uncertainties in assessing the value, strengths, weaknesses, contingent and other liabilities and potential profitability of acquisition or other transaction candidates; | |
• | the potential loss of key personnel of an acquired business; | |
• | the ability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction; |
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• | problems that could arise from the integration of the acquired business; | |
• | unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction rationale; and | |
• | unexpected development costs, such as those related to the development of the Little Thunder reserves, that adversely affect our profitability. |
Any one or more of these factors could cause us not to realize the benefits anticipated to result from the acquisition of businesses or assets.
Pension and Postretirement Benefits |
We estimate our future postretirement medical and pension benefit obligations based on various assumptions, including:
• | actuarial estimates; | |
• | assumed discount rates; | |
• | estimates of mine lives; | |
• | expected returns on pension plan assets; and | |
• | changes in health care costs. |
Based on changes in our assumptions, our annual postretirement health and pension benefit costs have increased. If our assumptions relating to these benefits change in the future, our costs could further increase, which would reduce our profitability. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse effect on our financial results.
On January 1, 1998, we replaced our existing pension plans with a new cash balance pension plan. The accrued benefits of active participants under the former plans were vested as of that date and the participant’s cash balance account was credited with the present value of the participant’s earned pension benefit, payable at normal retirement age. On February 12, 2004, the United States District Court for the Southern District of Illinois affirmed its earlier ruling that the cash balance formula used in IBM’s conversion to a cash balance plan violated the age discrimination provisions under ERISA. IBM has announced that it will appeal the decision to the Seventh Circuit Court of Appeals. The Illinois District Court’s decision conflicts with the decisions of two other district courts and with proposed regulations for cash balance plans issued by Treasury and the IRS in December 2002. In addition, on February 2, 2004, the Treasury Department proposed legislation that would clarify that cash balance plans do not violate the age discrimination rules that apply to pension plans as long as they treat older workers at least as well as younger workers. The retirement account formula used for our pension plan may not meet the standard ultimately set forth in the IBM Court’s decision. Consequently, the IBM decision may have an impact on our and other companies’ cash balance pension plans. The effect of the IBM decision on our cash balance plan or our financial position has not been determined at this time.
Certain Contractual Arrangements |
Our affiliate, Arch Western Resources, LLC, is the owner of our reserves and mining facilities in the Powder River Basin and Western Bituminous regions of the United States. The agreement under which Arch Western was formed provides that a subsidiary of ours, as the managing member of Arch Western, generally has exclusive power and authority to conduct, manage and control the business of Arch Western. However, consent of BP p.l.c., the other member of Arch Western, would generally be required in the event that Arch Western proposes to make a distribution, incur indebtedness, sell properties or merge or consolidate with any other entity if, at such time, Arch Western has a debt
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rating less favorable than specified ratings with Moody’s Investors Service or Standard & Poor’s or fails to meet specified indebtedness and interest ratios.
In connection with our June 1, 1998 acquisition of Atlantic Richfield Company’s (“ARCO”) coal operations, we entered into an agreement under which we agreed to indemnify ARCO against specified tax liabilities in the event that these liabilities arise as a result of certain actions taken prior to June 1, 2013, including the sale or other disposition of certain properties of Arch Western, the repurchase of certain equity interests in Arch Western by Arch Western, or the reduction under certain circumstances of indebtedness incurred by Arch Western in connection with the acquisition. ARCO was acquired by BP p.l.c. in 2000. Depending on the time at which any such indemnification obligation were to arise, it could impact our profitability for the period in which it arises.
Our Amended and Restated Certificate of Incorporation requires the affirmative vote of the holders of at least two-thirds of outstanding common stock voting thereon to approve a merger or consolidation and certain other fundamental actions involving or affecting control of us. Our Bylaws require the affirmative vote of at least two-thirds of the members of our Board of Directors in order to declare dividends and to authorize certain other actions.
Critical Accounting Policies |
Our financial statements are prepared in accordance with accounting principles that are generally accepted in the United States. The preparation of these financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses as well as the disclosure of contingent assets and liabilities. Management bases its estimates and judgments on historical experience and other factors that are believed to be reasonable under the circumstances. Additionally, these estimates and judgments are discussed with our Audit Committee on a periodic basis. Actual results may differ from the estimates used under different assumptions or conditions. Note 1 to the Consolidated Financial Statements provides a description of all significant accounting policies. We believe that of these significant accounting policies, the following may involve a higher degree of judgment or complexity:
Asset Retirement Obligations |
Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We account for the costs of our reclamation activities in accordance with the provisions of FAS 143. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon historical internal or third-party costs, depending on how the work is expected to be performed. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. In accordance with the provisions of FAS 143, we determine the fair value of our asset retirement obligations. In order to determine fair value, we must also estimate a discount rate and third-party margin. Each is discussed further below:
• | Discount rate — FAS 143 requires that asset retirement obligations be recorded at fair value. In accordance with the provisions of FAS 143, we utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing. |
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• | Third-party margin — FAS 143 requires the measurement of an obligation to be based upon the amount a third-party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin is added to the estimated costs of these activities. This margin is estimated based upon our historical experience with contractors performing certain types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than the estimates of our cost to perform the reclamation activities with internal resources. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed. |
On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2004, we had recorded asset retirement obligation liabilities of $199.6 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2004, we estimate that the aggregate undiscounted cost of final mine closure is approximately $354.7 million.
Employee Benefit Plans |
We have non-contributory defined benefit pension plans covering certain of our salaried and non-union hourly employees. Benefits are generally based on the employee’s age and compensation. We fund the plans in an amount not less than the minimum statutory funding requirements nor more than the maximum amount that can be deducted for federal income tax purposes. For the years ended December 31, 2004 and 2003, we contributed $21.6 million and $18.9 million to the plan. We account for our defined benefit plans in accordance with FAS 87,Employer’s Accounting for Pensions,which requires amounts recognized in the financial statements to be determined on an actuarial basis.
The calculation of our net periodic benefit costs (pension expense) and benefit obligation (pension liability) associated with our defined benefit pension plans requires the use of a number of assumptions that we deem to be “critical accounting estimates.” Changes in these assumptions can result in different pension expense and liability amounts, and actual experience can differ from the assumptions.
• | The expected long-term rate of return on plan assets is an assumption reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The pension plan’s investment targets are 65% equity, 30% fixed income securities and 5% cash. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine pension expense was 8.5% and 9.0% for the years ended December 31, 2004 and 2003, respectively, which is less than the plan’s actual life-to-date returns. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuarial gain or loss and amortized into the future. The impact of lowering the expected long-term rate of return on plan assets from 8.5% to 8.0% for 2004 would have been an increase to expense of approximately $0.9 million. | |
• | The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic pension cost. In estimating that rate, Statement No. 87 requires rates of return on high quality, fixed income investments. We utilize a bond portfolio model that includes |
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bonds that are rated “AA” or higher with maturities that match the expected benefit payments under the plan. The discount rates used to determine pension expense for 2004 and 2003 were 6.5% and 7.0%, respectively. The impact of lowering the discount rate from the 6.5% utilized in 2004 to an assumed 6.0% would have resulted in an approximate $1.3 million increase in expense in 2004. |
The differences generated in changes in assumed discount rates and returns on plan assets are amortized into earnings over a five-year period.
For the measurement of our year-end pension obligation for 2004 (and pension expense for 2005), we maintained our long-term rate of return assumption at 8.5% and changed our discount rate to 6.0%.
We also currently provide certain postretirement medical/life insurance coverage for eligible employees. Generally, covered employees who terminate employment after meeting eligibility requirements are eligible for postretirement coverage for themselves and their dependents. The salaried employee postretirement medical/life plans are contributory, with retiree contributions adjusted periodically, and contain other cost-sharing features such as deductibles and coinsurance. The postretirement medical plan for retirees who were members of the United Mine Workers of America is not contributory. Our current funding policy is to fund the cost of all postretirement medical/life insurance benefits as they are paid. We account for our other postretirement benefits in accordance with FAS 106,Employer’s Accounting for Postretirement Benefits Other Than Pensions,which requires amounts recognized in the financial statements to be determined on an actuarial basis.
Various actuarial assumptions are required to determine the amounts reported as obligations and costs related to the postretirement benefit plan. These assumptions include the discount rate and the future medical cost trend rate.
• | The discount rate assumption reflects the rates available on high-quality fixed-income debt instruments at year-end and is calculated in the same manner as discussed above for the pension plan. The discount rate used to calculate the postretirement benefit expense for 2004 and 2003 was 6.5% and 7.0%, respectively. Had the discount rate been lowered from 6.5% to 6.0% in 2004, we would have incurred additional expense of $8.4 million. | |
• | Future medical trend rate represents the rate at which medical costs are expected to increase over the life of the plan. The health care cost trend rate is determined based upon our historical changes in health care costs as well as external data regarding such costs. We have implemented many effective programs that have resulted in actual increases in medical costs to fall far below the double-digit increases experienced by most companies in recent years. The postretirement expense in 2004 was based on an assumed medical inflationary rate of 8.0%, trending down in half percent increments to 5%, which represents the ultimate inflationary rate for the remainder of the plan life. This assumption was based on our then current three-year historical average of per capita increases in health care costs. If we had utilized a medical trend rate of 9.0% in 2004, we would have incurred $4.0 million of additional expense. |
For the measurement of our year-end other postretirement obligation for 2004 (and other postretirement expense for 2005), we maintained our medical inflationary rate assumption at 8.0% (trending down to 5%) and changed our discount rate to 6.0%.
Income Taxes |
We record deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of assets and liabilities. A valuation allowance is recorded to reflect the amount of future tax benefits that management believes are not likely to be realized. In determining the appropriate valuation allowance, we take into account the level of expected future
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taxable income and available tax planning strategies. If future taxable income was lower than expected or if expected tax planning strategies were not available as anticipated, we may record additional valuation allowance through income tax expense in the period such determination was made.
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SELECTED FINANCIAL INFORMATION
Year Ended December 31, | |||||||||||||||||||||
2004 | 2003 | 2002 | 2001 | 2000 | |||||||||||||||||
(1,2,3,5) | (1,2,4,5) | (6,7,8) | (9,10,11) | (9,10,12,13) | |||||||||||||||||
(In thousands, except per share data) | |||||||||||||||||||||
Statement of Operations Data: | |||||||||||||||||||||
Coal sales revenues | $ | 1,907,168 | $ | 1,435,488 | $ | 1,473,558 | $ | 1,403,370 | $ | 1,342,171 | |||||||||||
Income from operations | 178,046 | 40,371 | 29,277 | 62,456 | 73,984 | ||||||||||||||||
Income (loss) before cumulative effect of accounting change | 113,706 | 20,340 | (2,562 | ) | 7,209 | (12,736 | ) | ||||||||||||||
Cumulative effect of accounting change | — | (3,654 | ) | — | — | — | |||||||||||||||
Net income (loss) | 113,706 | 16,686 | (2,562 | ) | 7,209 | (12,736 | ) | ||||||||||||||
Preferred stock dividends | (7,187 | ) | (6,589 | ) | — | — | — | ||||||||||||||
Net income (loss) available to common shareholders | $ | 106,519 | $ | 10,097 | $ | (2,562 | ) | $ | 7,209 | $ | (12,736 | ) | |||||||||
Basic earnings (loss) per common share before cumulative effect of accounting change | $ | 1.91 | $ | .26 | $ | (0.05 | ) | $ | .15 | $ | (0.33 | ) | |||||||||
Diluted earnings (loss) per common share before cumulative effect of accounting change | $ | 1.78 | $ | .26 | $ | (0.05 | ) | $ | .15 | $ | (0.33 | ) | |||||||||
Basic earnings (loss) per common share | $ | 1.91 | $ | .19 | $ | (0.05 | ) | $ | .15 | $ | (0.33 | ) | |||||||||
Diluted earnings (loss) per common share | $ | 1.78 | $ | .19 | $ | (0.05 | ) | $ | .15 | $ | (0.33 | ) | |||||||||
Balance Sheet Data: | |||||||||||||||||||||
Total assets | $ | 3,256,535 | $ | 2,387,649 | $ | 2,182,808 | $ | 2,203,559 | $ | 2,232,614 | |||||||||||
Working capital | 355,803 | 237,007 | 37,799 | 49,813 | (37,556 | ) | |||||||||||||||
Long-term debt, less current maturities | 1,001,323 | 700,022 | 740,242 | 767,355 | 1,090,666 | ||||||||||||||||
Other long-term obligations | 800,332 | 722,954 | 653,789 | 625,819 | 606,628 | ||||||||||||||||
Stockholders’ equity | $ | 1,079,826 | $ | 688,035 | $ | 534,863 | $ | 570,742 | $ | 219,874 | |||||||||||
Common Stock Data: | |||||||||||||||||||||
Dividends per share | $ | .2975 | $ | .23 | $ | .23 | $ | .23 | $ | .23 | |||||||||||
Shares outstanding at year-end | 62,143 | 53,205 | 52,434 | 52,353 | 38,173 | ||||||||||||||||
Cash Flow Data: | |||||||||||||||||||||
Cash provided by operating activities | $ | 146,728 | $ | 162,361 | $ | 176,417 | $ | 145,661 | $ | 135,772 | |||||||||||
Depreciation, depletion and amortization | 166,322 | 158,464 | 174,752 | 177,504 | 201,512 | ||||||||||||||||
Capital expenditures | 292,605 | 132,427 | 137,089 | 123,414 | 115,080 | ||||||||||||||||
Dividend payments | 24,043 | 17,481 | 12,045 | 11,565 | 8,778 | ||||||||||||||||
Operating Data: | |||||||||||||||||||||
Tons sold | 123,060 | 100,634 | 106,691 | 109,455 | 105,519 | ||||||||||||||||
Tons produced | 115,861 | 93,966 | 99,641 | 104,471 | 100,060 | ||||||||||||||||
Tons purchased from third parties | 12,572 | 6,602 | 8,060 | 5,569 | 5,084 |
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(1) | During 2004 and 2003, the Company sold its investment in Natural Resource Partners in four separate transactions occurring in December 2003 and March, June and October 2004. The Company recognized a gain of $42.7 million in the fourth quarter of 2003 and gains of $91.3 million during 2004. |
(2) | In connection with the Company’s repayment of Arch Western’s term loans in 2003, the Company recognized expenses of $8.3 million and $4.3 million in 2004 and 2003, respectively, related to the costs resulting from the termination of hedge accounting for interest rate swaps. During 2004 and 2003, the Company also recognized expenses of $0.7 million and $4.7 million, respectively, related to early debt extinguishment costs. Additionally, subsequent to the termination of hedge accounting for interest rate swaps, the Company recognized income of $13.4 million in 2003 related to changes in the market value of the swaps. |
(3) | During 2004, the Company assigned its rights and obligations on a parcel of land to a third party resulting in a gain of $5.8 million. The gain is reflected in other operating income. |
(4) | On January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Asset Retirement Obligations. Implementation of this pronouncement resulted in a cumulative effect of accounting change of $3.7 million (net of tax). |
(5) | As discussed in Note 15, “Stock Incentive Plan and Other Incentive Plans,” the Company recognized expenses of $5.5 million and $16.2 million under long-term incentive compensation plans in 2004 and 2003, respectively. |
(6) | During the year ended December 31, 2002, the Company settled certain coal contracts with a customer that was partially unwinding its coal supply position and desired to buy out of the remaining terms of those contracts. The settlements resulted in a pre-tax gain of $5.6 million which was recognized in other revenues in the Consolidated Statement of Operations. |
(7) | The Company recognized a pre-tax gain of $4.6 million during the year ended December 31, 2002 as a result of a workers’ compensation premium adjustment refund from the State of West Virginia. During 1998, the Company entered into the West Virginia workers’ compensation plan at one of its subsidiary operations. The subsidiary paid standard base rates until the West Virginia Division of Workers’ Compensation could determine the actual rates based on claims experience. Upon review, the Division of Workers’ Compensation refunded $4.6 million in premiums which was recognized as an adjustment to cost of coal sales in the Consolidated Statement of Operations. |
(8) | During 2002, the Company filed a royalty rate reduction request with the BLM for its West Elk mine in Colorado. The BLM notified the Company that it would receive a royalty rate reduction for a specified number of tons representing a retroactive portion for the year totaling $3.3 million. The retroactive portion was recognized as a component of cost of coal sales in the Consolidated Statement of Operations. Additionally in 2002, Canyon Fuel was notified by the BLM that it would receive a royalty rate reduction for certain tons mined at its Skyline mine. The rate reduction applies to certain tons mined representing a retroactive refund of $1.1 million. The retroactive amount was reflected in income from equity investments in the Consolidated Statement of Operations. |
(9) | At the West Elk underground mine in Gunnison County, Colorado, following the detection of combustion-related gases in a portion of the mine, the Company idled its operation on January 28, 2000. On July 12, 2000, after controlling the combustion-related gases, the Company resumed production at the West Elk mine and started to ramp up to normal levels of production. The Company recognized partial pre-tax insurance settlements of $31.0 million during 2000 and a final pre-tax insurance settlement related to the event of $9.4 million during 2001. |
(10) | The IRS issued a notice outlining the procedures for obtaining tax refunds on certain excise taxes paid by the industry on export sales tonnage. The notice was the result of a 1998 federal court decision that found such taxes to be unconstitutional. The Company recorded $12.7 million of |
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pre-tax income related to these excise tax recoveries during 2000. During 2001, the Company recorded an additional $4.6 million of pre-tax income resulting from additional favorable developments associated with these tax refunds. | |
(11) | The Company recognized a $7.4 million pre-tax gain during 2001 from a state tax credit covering prior periods. |
(12) | As a result of adjustments to employee postretirement medical benefits, the Company recognized $9.8 million of pre-tax curtailment gains in 2000 resulting from previously unrecognized postretirement benefit changes which occurred in prior years. |
(13) | During 2000, the Company settled certain workers’ compensation liabilities with the state of West Virginia partially offset by adjusting other workers’ compensation liabilities resulting in a net pre-tax gain of $8.3 million. |
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CORPORATE GOVERNANCE AND STOCKHOLDER INFORMATION
Common Stock |
Our common stock is listed and traded on the New York Stock Exchange and also has unlisted trading privileges on the Chicago Stock Exchange. The ticker symbol is ACI. The following table sets forth for each period indicated the dividends paid per common share, the high and low sale prices of our common stock and the closing price of our common stock on the last trading day of the period indicated.
March 31, | June 30, | September 30, | December 31, | |||||||||||||
Quarter Ended | 2004 | 2004 | 2004 | 2004 | ||||||||||||
Dividends per common share | $ | .0575 | $ | .0800 | $ | .0800 | $ | .0800 | ||||||||
High | $ | 32.89 | $ | 36.99 | $ | 36.93 | $ | 39.00 | ||||||||
Low | $ | 26.20 | $ | 27.73 | $ | 30.10 | $ | 31.86 | ||||||||
Close | $ | 31.39 | $ | 36.59 | $ | 35.49 | $ | 35.54 |
March 31, | June 30, | September 30, | December 31, | |||||||||||||
Quarter Ended | 2003 | 2003 | 2003 | 2003 | ||||||||||||
Dividends per common share | $ | .0575 | $ | .0575 | $ | .0575 | $ | .0575 | ||||||||
High | $ | 22.50 | $ | 24.55 | $ | 23.60 | $ | 32.20 | ||||||||
Low | $ | 16.50 | $ | 17.18 | $ | 19.12 | $ | 22.06 | ||||||||
Close | $ | 19.01 | $ | 22.98 | $ | 22.21 | $ | 31.17 |
On March 1, 2005, our common stock closed at $43.50 on the New York Stock Exchange. At that date, there were 9,902 holders of record of our common stock.
Dividends |
In 2004, we paid dividends totaling $16.9 million, or $.2975 per share, on our outstanding shares of common stock. In 2003, we paid dividends totaling $12.1 million, or $.23 per share, on our outstanding shares of common stock. There is no assurance as to the amount or payment of dividends in the future because they are dependent on our future earnings, capital requirements and financial condition.
Code of Business Conduct |
We have established a Code of Business Conduct which operates as our Code of Ethics and which applies to all of our salaried employees, including our CEO, CFO and Controller. The Code of Business Conduct is available on our website at www.archcoal.com under the “Investors” section.
Corporate Governance Guidelines |
Our Board of Directors has adopted Corporate Governance Guidelines which address various matters pertaining to Director selection and duties. The Guidelines are available on our website at www.archcoal.com under the “Investors” section.
Committee Charters |
Each of the Audit, Personnel & Compensation and Nominating & Corporate Governance Committees of our Board of Directors has adopted and maintains a written Charter. Each of these Charters is available on our website at www.archcoal.com under the “Investors” section.
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Stock Information |
Questions by stockholders regarding stockholder records, stock transfers, stock certificates, dividends or other stock inquiries (other than our Dividend Reinvestment and Direct Stock Purchase Plan) should be directed to:
American Stock Transfer & Trust Company
59 Maiden Lane
Plaza Level
New York, NY 10038
Toll-free Telephone: (800) 360-4519
Web Site: www.amstock.com
Requests for information about our Dividend Reinvestment and Direct Stock Purchase and Sale Plan should be directed to:
American Stock Transfer & Trust Company
P.O. Box 922
Wall Street Station
New York, NY 10269-0560
Toll-free Telephone: (877) 390-3073
Website: www.amstock.com
Independent Registered Public Accounting Firm |
Ernst & Young LLP
190 Carondelet Plaza, Suite 1300
St. Louis, MO 63105
Certifications |
The most recent certifications by our Chief Executive and Chief Financial Officers pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 are filed as exhibits to our Form 10-K for 2004. Our Chief Executive Officer’s most recent certification to the New York Stock Exchange was submitted on May 20, 2004.
Document Copies |
Copies of the above documents and the Company’s Securities and Exchange Commission Form 10-K are available without charge. Requests for these documents, as well as inquires from stockholders and security analysis, should be directed to:
Investor Relations
Arch Coal, Inc.
One CityPlace Drive, Suite 300
St. Louis, MO 63141
(314) 994-2717
Fax: (314) 994-2878
www.archcoal.com
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