Exhibit 99.2

EX-99.2 4 dex992.htm EXHIBIT 99.2 Exhibit 99.2

Exhibit 99.2

MASSEY ENERGY COMPANY

Text of Certain Information Made Available to Potential Investors on May 22, 2003

In Connection with a Proposed Offering of Convertible Senior Notes due 2023

This information shall not constitute an offer to sell or the solicitation of an offer to buy any securities.

FORWARD-LOOKING STATEMENTS

We make certain comments and disclosures in this offering memorandum which may be forward-looking in nature. Examples include statements related to our growth, the adequacy of funds to service debt and our opinions about trends and factors that may impact future operating results. These forward-looking statements could also involve, among other things, statements regarding our intent, belief or expectation with respect to:

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our liquidity, results of operations and financial condition;

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the consummation of financing, acquisition or disposition transactions and the effect thereof on our business;

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governmental policies and regulatory actions;

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legal and administrative proceedings, settlements, investigations and claims;

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weather conditions or catastrophic weather-related damage;

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our production capabilities;

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market demand for coal, electricity and steel;

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competition;

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our relationships with our customers;

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employee workforce factors;

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our assumptions concerning economically recoverable coal reserve estimates;

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future economic or capital market conditions; and

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our plans and objectives for future operations and expansion or consolidation.

Any forward-looking statements are subject to the risks, uncertainties and assumptions that could cause actual results of operations, financial condition, or liquidity to differ materially from those expressed or implied in such forward-looking statements. These assumptions would be based on facts and conditions as they exist at the time such statements are made as well as predictions as to future facts and conditions, the accurate prediction of which may be difficult and involve the assessment of events beyond our control.

We wish to caution readers that forward-looking statements, including disclosures using words such as we “believe,” “anticipate,” “expect,” “estimate” and similar statements, are subject to certain risks and uncertainties, which could cause actual results to differ materially from expectations. Any forward-looking statements should be considered in context with the various disclosures made by us about our businesses, including without limitation the risk factors more specifically described under “Risk Factors.”

SUMMARY

Massey Energy Company

We produce, process and sell high quality, low sulfur coal of steam and metallurgical grades through our 19 processing and shipping centers, called “resource groups.” These resource groups support our 29 underground mines and 14 surface mines in West Virginia, Kentucky and Virginia. Steam coal, which accounts for approximately 65% of our produced coal sales volume, is primarily purchased by public utilities as fuel for electricity generation. Approximately 9% of our produced coal sales volume is generated by sales to industrial customers that use coal with certain quality characteristics for generation of electricity or for process steam. Metallurgical coal, which accounts for approximately 26% of our produced coal sales volume, is used primarily to make coke for use in the manufacture of steel and can also be marketed as an ultra high quality, low sulfur steam coal for electricity generation. Metallurgical coal generally sells at a premium over steam coal because of its unique quality characteristics. During our fiscal year ended December 31, 2002, we sold 42.1 million tons of coal, generating produced coal revenues of $1.3 billion, loss from operations of $26.7 million, and EBITDA of $181.0 million. For an explanation of EBITDA, please see footnote 2 in “Selected Consolidated Financial and Operating Data.”

We are one of the premier coal producers in the United States by several measures:

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We are the fourth largest coal company in the United States based on produced coal revenues and the sixth largest coal company in the United States based on production;

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We are the largest coal producer in the Central Appalachian region, the second largest coal-producing region in the United States;

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We are the largest producer of metallurgical coal in the United States; and

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We control approximately 2.2 billion tons of proven and probable coal reserves, which, based on current production levels, should last for more than 50 years.

Coal is one of the most abundant, efficient and affordable natural resources, and is primarily used to generate electricity and make coke for the manufacturing of steel. The United States is the world’s second largest producer of coal and is the largest holder of coal reserves in the world, with approximately 250 years of supply based on current production rates. In 2002, total U.S. coal production as estimated by the United States Department of Energy was 1.1 billion tons. We believe that the use of coal to generate electricity will grow as the demand for power increases and that Central Appalachian coal will be instrumental in filling that demand.

Competitive Strengths

We believe that our competitive strengths will enable us to enhance our position as one of the premier coal producers in the United States.

We are the leading coal producer in Central Appalachia. We are the leading coal producer in the Central Appalachian region with a proven reputation as a skilled, long-term operator. We believe our regional focus leads to operating efficiencies and provides us with an in-depth knowledge of the area’s coal reserves, mining conditions, customers, property owners and employee base.

We have a low level of long-term liabilities. Our employee related legacy liabilities are significantly lower than those of our coal industry peers. As of December 31, 2002, we had pension trust assets with a fair market value of $174 million, which were in excess of our plan liabilities of $169 million, despite three years of poor market returns. We do not expect to have to fund our pension plan until 2006 at the earliest. Our healthcare benefit liability (OPEB) of $121 million at December 31, 2002, was significantly lower than that of our coal industry peers.

We have strong, long-term relationships with a broad base of customers. We have strong relationships with a broad base of over 125 customers. The majority of these customers purchase coal under long-term contracts with terms of one year or longer. Approximately 94% of our produced coal sales volume in 2002 was derived from these long-term contracts. We believe that a similar amount of our produced coal sales volume in 2003 will be derived from these long-term contracts. We believe these contracts provide us with stable and predictable cash flow. Many of our customers are well-established public utilities who have been customers of ours for a number of years.

We have built a superior infrastructure and transportation system. Since 1998, we have expended over $1.0 billion to maintain, upgrade and expand our mining, processing and transporting capabilities. We believe these capital investments provide us with the necessary infrastructure to expand our production capacity with little or no additional investment to meet increases in demand for coal.

Strategy

Our primary objective is to continue to build upon our competitive strengths to enhance our position as one of the premier coal producers in the United States by:

Adjusting production in response to changes in market conditions. We are committed to a strategy of aligning our production with the needs of the market. The capital investments we have made during the past five years position us to quickly expand our production to meet increases in demand for coal. Our goal is to maximize profits not volume; therefore, our strategy is to only sell our coal at prices that generate the appropriate level of profitability.

Expanding use of more productive mining methods. Currently, we engage in four principal coal mining methods: underground “room and pillar” mining, underground longwall mining, highwall mining and surface mining. Because underground longwall mining, highwall mining and surface mining are high-productivity, low-cost mining methods, we will seek to increase production from our use of those methods to the extent permissible and cost-effective.

Pursuing strategic acquisitions. We believe that the coal industry will undergo increasing consolidation over the coming years. We plan to build on our position as the largest producer in Central Appalachia by pursuing growth through the opportunistic acquisition of additional coal reserves and mining facilities.

Refinancing

Our existing $375 million revolving credit facilities become due November 25, 2003. This offering is part of our initiative to refinance these revolving credit facilities. Proceeds of this offering will be used to repay outstanding borrowings and to permanently reduce commitments under our existing revolving credit facilities. We also recently have begun efforts to obtain a new revolving credit facility. We currently are seeking an aggregate of between $450 million and $550 million of financing pursuant to this offering and revolving and term loan facilities. The consummation of this offering is not contingent on successful completion of the refinancing of our existing revolving credit facilities.

On November 30, 2000, we completed a reverse spin-off, or the “spin-off,” that divided our operations into two companies: Fluor Corporation, or “New Fluor,” and Massey Energy Company. New Fluor retained all of the then-existing businesses except for the coal-related business conducted by A.T. Massey. We retained all of the coal-related business conducted by A.T. Massey.

Our primary executive offices are located at 4 North 4th Street, Richmond, Virginia 23219 and our telephone number is (804) 788-1800.

RISK FACTORS

Risks Related to Our Business

Our business, financial condition and results of operation could be adversely affected if our senior secured revolving credit facilities are not replaced.

Our existing $375 million revolving credit facilities serve as the primary source of our short-term liquidity. Both facilities expire on November 25, 2003. As of May 20, 2003, there was $278.7 million outstanding under these facilities. Proceeds from the sale of the notes will be used to repay outstanding borrowings and to permanently reduce commitments under our existing revolving credit facilities. We intend to replace these credit facilities prior to their expiration on November 25, 2003, and we have already begun refinancing syndication efforts with a number of banks and financial institutions. There can be no assurance that we can replace or extend our revolving credit facilities, or if we are able, what such terms will be. If we are unable to replace these credit facilities, we will be in default, and the banks under the revolving credit facilities will be entitled to the remedies provided thereunder, including the ability to proceed against the related collateral. Such an event would have a material adverse effect on our cash flows, financial condition and results of operations.

For our liquidity needs, we currently rely primarily on borrowings under our revolving credit facilities, which depend upon our compliance with the financial covenants contained in our revolving credit facilities.

For our liquidity needs, we currently rely primarily on borrowings under our revolving credit facilities. These facilities contain financial covenants requiring us to maintain specified financial ratios. The financial covenants consist of a maximum leverage ratio, a minimum interest coverage ratio and a minimum net worth test. The leverage ratio requires that we not permit the ratio of total indebtedness at the end of any quarter to adjusted EBITDA (as defined in the credit agreements) for the four quarters then ended to exceed a specific amount. The interest coverage ratio requires that we not permit the ratio of our adjusted EBITDA to interest expense for the four quarters then ended to be less than a specified amount. The net worth test requires that we not permit our net worth to be less than a specified amount. Our ability to meet these financial ratios can be affected by a deterioration in our operating results, as well as by events beyond our control, including economic conditions, and we cannot assure you that we will meet the financial ratios. We were in compliance with all material covenants at March 31, 2003 and during other periods reflected herein, other than at December 31, 2001, when we were not in compliance with the covenant related to the leverage ratio, but for which we subsequently obtained an amendment from lenders effective March 29, 2002. In the event we violate any of the financial covenants and do not receive an amendment or waiver from the lenders in our credit facilities, the credit agreements provide that the administrative agent under such agreements shall, if requested by at least four lenders holding at least 50% of the aggregate amount of the loans, declare the loans immediately due and payable.

Our indebtedness could adversely affect our ability to grow and compete and prevent us from fulfilling our obligations under the notes and our other indebtedness.

As of March 31, 2003, after giving effect to this offering and the use of the net proceeds thereof, we would have had approximately $ million of total indebtedness outstanding, including $ million of borrowings outstanding under our revolving credit facilities, $283.0 million aggregate principal amount of 6.95% Senior Notes due March 1, 2007, $42.2 million outstanding under an accounts receivable-based financing program, and $ aggregate principal amount of the notes offered hereby. As of March 31, 2003, our indebtedness, as adjusted to give effect to this offering, represented % of our total book capitalization. Our indebtedness could adversely affect our ability to grow and compete and prevent us from fulfilling our obligations under the notes and our other indebtedness.

We may not be able to maintain our competitive position because coal markets are affected by factors beyond our control.

Continued demand for our coal and the prices that we will be able to obtain will primarily depend upon coal consumption patterns of the domestic electric utility and steel industries. Consumption by the domestic utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price and availability of competing coal and alternative fuel supplies including nuclear, natural gas, oil and renewable energy sources. Consumption by the domestic steel industry is primarily affected by the demand for U.S. steel.

Approximately 26% of our production is metallurgical coal. As the largest supplier of metallurgical coal to the United States steel industry, we are subject to being adversely affected by any decline in the financial condition or production volume of United States steel producers. In recent years, United States steel producers experienced a substantial decline in the prices received for their products, due at least in part to a heavy volume of foreign steel imported into this country. The United States government determined that some steel producers in some foreign countries were selling steel products in the United States at below cost and has imposed tariffs on products from various foreign countries. The imposition of the tariffs has led to a moderate increase in the price of some steel products in the United States. However, several large United States producers filed for bankruptcy protection both before and after the tariffs were imposed, including two of our substantial customers: Wheeling-Pittsburgh Steel Corporation, which filed for bankruptcy protection in late 2000, accounted for approximately 3% of our produced coal revenue in 2002; and Bethlehem Steel Corporation, which filed for bankruptcy protection in mid-2001, accounted for approximately 2% of our produced coal revenue in 2002. In addition, Algoma Steel, Inc., a Canadian steel producer and one of our customers, filed for bankruptcy protection under Canadian law. Sales to Algoma accounted for approximately 2% of our produced coal revenue for 2002. We continue to sell to these financially distressed customers on very restrictive terms. Further deterioration in conditions in the steel industry could reduce the demand for our metallurgical coal and impact the collectibility of our accounts receivable from steel industry customers. Since our metallurgical grade coal can also be marketed as a high-Btu steam coal for use by utilities, a decline in the metallurgical market could result in coal being switched from the metallurgical market to the utility market.

As noted above, on March 5, 2002, President Bush announced a decision imposing tariffs on certain steel imports under Section 201 of the Trade Act of 1974. These tariffs are intended to provide protection against imports from certain countries; however, there are products and countries not covered by the tariffs. Imports of these exempt products or products from these countries may still have an adverse effect on United States steel producers. These tariffs may prompt other countries to impose tariffs or other trade restrictions on United States steel products. These actions could have an adverse effect on United States steel producers and reduce the demand for our metallurgical coal and thus adversely affect our cash flows, financial condition or results of operations. In May 2003, the World Trade Organization issued a final ruling against the Section 201 remedies. Although President Bush’s administration has indicated preliminarily that it will appeal the ruling, we cannot predict whether the administration will appeal the ruling or the likelihood of success of any appeal.

In addition, the steel industry is increasingly relying on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that we sell could further decrease. Since metallurgical coal is generally priced higher than steam coal, some of our mines may only operate profitably if all or a portion of their production is sold as metallurgical coal. If they are unable to sell metallurgical coal, these mines may not be economically viable and may close.

We may not be able to maintain our competitive position because the coal industry is highly competitive.

We compete with coal producers in various regions of the United States for domestic sales and with both domestic and foreign producers for sales to international markets. We compete with other producers primarily on the basis of price, coal quality, transportation cost and reliability of supply. Generally, the relative

competitiveness of coal vis-à-vis other fuels or other coals is evaluated on a delivered cost per heating value unit basis. In addition to competition from other fuels, coal quality, the marginal cost of producing coal in various regions of the country and transportation costs are major determinants of the price for which we can sell coal. Factors that directly influence production cost include geological characteristics (including seam thickness), overburden ratios, depth of underground reserves, transportation costs and labor availability and cost.

Central Appalachian coal is more expensive to mine than western coal due to thinner coal seams and greater reliance on underground mining, which typically has higher costs. In recent years, increased development of large surface mining operations, particularly in the western United States, and more efficient mining equipment and techniques have contributed to excess coal production capacity in the United States.

During the mid-1970s and early 1980s, increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which led to increased competition and lower coal prices. Increases in coal prices could encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce coal prices and therefore reduce our revenues.

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. This competition could adversely affect our business and results of operations.

Depending on the relative strength of the U.S. dollar versus currencies in other coal producing regions of the world, we may export more or less coal into foreign countries as we compete on price with other foreign coal producing sources. Additionally, the domestic coal market may be impacted due to the relative strength of the U.S. dollar to other currencies, as foreign sources could be cost advantaged based on a coal producing region’s relative currency position.

A significant decline in coal prices could adversely affect our operating results and cash flows.

Our results of operations are highly dependent upon the prices we receive for our coal and our ability to improve productivity and control costs. While recent demand for coal has increased due to the recent severe winter weather in 2002-2003, there is no assurance this demand will continue. Any decreased demand would cause spot prices to decline and require us to increase productivity and decrease costs in order to maintain our margins. If we are not able to maintain our margins, our operating results could be adversely affected. Price declines may adversely affect operating results for future periods and our ability to generate cash flows necessary to improve productivity and expand operations.

Coal mining is subject to unexpected disruptions, which could cause our quarterly or annual results to fluctuate.

Our mining operations are subject to certain events and operating conditions that could disrupt operations and affect production at particular mines for varying lengths of time. These events and conditions include:

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fires and explosions from methane;

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accidental minewater discharges;

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adverse weather and natural disasters, such as heavy rains or floods;

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equipment failures and maintenance problems;

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transportation delays;

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changes in geologic conditions;

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failure of reserve estimates to prove correct;

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inability to acquire or renew mining rights or permits; and

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governmental actions that suspend or revoke our permits.

We maintain property and general liability insurance policies that provide limited coverage for some, but not all, of these risks. Even where insurance coverage applies, there can be no assurance that these risks would be fully covered by our insurance policies. Any disruption of our operations could adversely affect our business and revenues.

Government laws, regulations and other legal requirements relating to protection of the environment increase our costs of doing business and may restrict our operations.

We incur substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species laws, including regulations and governmental enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. We may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from our operations.

New legislation and new regulations may be adopted that could materially adversely affect our mining operations, cost structure or our customers’ ability to use coal. New legislation and new regulations may also require us or our customers to change operations significantly or incur increased costs. The United States Environmental Protection Agency, or the “EPA,” has undertaken broad initiatives aimed at increasing compliance with emissions standards and providing incentives to customers for decreasing emissions, often by switching to an alternative fuel source.

SMCRA Litigation. On March 29, 2002, the U.S. District Court for the District of Columbia issued a ruling that could restrict underground mining activities conducted in the vicinity of public roads, within a variety of federally protected lands, within national forests and within certain proximity to occupied dwellings. The lawsuit, Citizens Coal Council v. Norton, was filed in February 2000 to challenge regulations issued by the Department of the Interior providing, among other things, that subsidence and underground activities that may lead to subsidence are not surface mining activities within the meaning of the Surface Mining Control and Reclamation Act or “SMCRA.” SMCRA generally contains restrictions and certain prohibitions on the locations where surface mining activities can be conducted. The District Court entered summary judgment upon the plaintiff’s claims that the Secretary of the Interior’s determination violated SMCRA. By order dated April 9, 2002, the court remanded the regulations to the Secretary of the Interior for reconsideration. The significance of this decision for the coal mining industry remains unclear because this ruling is subject to appellate review. The Department of the Interior and the National Mining Association, a trade group that intervened in this action, sought a stay of the order pending appeal to the U.S. Court of Appeals for the District of Columbia Circuit and the stay was granted. If the District Court’s decision is not overturned, or if some legislative solution is not enacted, this ruling could have a material adverse effect on all of our coal mine operations that utilize underground mining techniques. While it still may be possible to obtain permits for underground mining operations in these areas, the time and expense of that permitting process are likely to increase significantly. It is likely that room and pillar and longwall mining near certain structures will be more difficult and expensive for all coal producers and continued mining at some mines may no longer be practicable.

Show Cause Orders. Regulatory authorities implementing SMCRA may order surface mining permit holders to “show cause” why their permits should not be suspended or revoked because of alleged patterns of violations. A pattern of violations can be found when there are two or more violations of a same or similar type within a 12-month period. Under these “show cause orders,” if a pattern of violations is found and determined to have been caused by willful or unwarranted conduct under the surface mining laws, our surface mining permits may either be suspended or revoked. Some of our subsidiaries have been issued show cause orders that are

currently unresolved. The outcome of each of these actions remains uncertain, so the eventual cost to us, if any, cannot presently be reasonably estimated.

As of the date of this offering memorandum, show cause orders have been issued by the West Virginia Department of Environmental Protection, or the “WVDEP” with respect to active permits at our Marfork Coal Company, Independence Coal Company, Omar Mining Company, Bandmill Coal Corporation and Alex Energy subsidiaries. These orders have either been issued or are currently under appeal. A suspension of these operations could adversely affect our financial results to the extent we are unable to generate the lost production from our other operations. In addition, the WVDEP and Kentucky Natural Resources and Environment Protection Cabinet have issued show cause orders to certain of our subsidiaries with idled permits.

The potential impact on operations from a permit suspension in the show cause proceedings varies. For example, some of the operations are not currently mining or processing coal; therefore, a suspension at those operations would not impact earnings. At the active operations, suspensions could impact earnings to the extent that downtime cannot be offset by increases in production and/or coal sales at other times or at other operations. The impact of suspensions at these operations could also vary depending on when the suspensions are served. For example, suspensions served over weekends or during scheduled maintenance periods would have lesser impacts. We do not believe the impact of the suspensions or the cost of defending these matters is likely to be material.

If we are unsuccessful in defending or reaching an acceptable resolution of these orders, there is a possibility that a suspension of operations could have a significant effect on our overall operations. If a pattern of violations is found with respect to show cause orders that have not proceeded to a hearing, one or more of the permits for these operations could be revoked. If one or more of our permits are revoked, we could be prohibited from obtaining additional permits. In the event of future violations at these or other properties, the existence of these orders may increase the gravity of any sanctions sought in the event that the state decides to pursue any enforcement. For more detailed information concerning the show cause orders, see the documents incorporated by reference in this offering memorandum listed under “Documents Incorporated by Reference.”

Martin County Impoundment Discharge. On October 11, 2000, a partial failure of the coal refuse impoundment at Martin County Coal Corporation, one of our subsidiaries, released approximately 230 million gallons of coal slurry into adjacent underground mine workings. The slurry then discharged into two tributary streams of the Big Sandy River in eastern Kentucky. No one was injured in the discharge. Clean up efforts began immediately and are complete. Martin County Coal began processing coal again on April 2, 2001. We are continuing to seek approval from the applicable agencies for alternate refuse disposal options related to operations of Martin County Coal’s preparation plant. As of March 31, 2003, we had incurred a total of approximately $58.8 million of cleanup costs in connection with the spill, $52.5 million of which have been paid directly or reimbursed by insurance companies. We continue to seek insurance reimbursement of any and all covered costs. Most of the claims, fines, penalties and lawsuits from the impoundment failure have been satisfied or settled. Remaining issues (none of which we consider material) include:

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three remaining suits with 10 plaintiffs (one seeking class certification) alleging property damage claims and seeking unquantified compensatory and punitive damages allegedly resulting from the October 11, 2000 incident;

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a civil action filed by the WVDEP against Martin County Coal in the Circuit Court of Wayne County, West Virginia, alleging natural resources damages in West Virginia and alleged violations of law resulting from the impoundment discharge. The WVDEP’s alleged damages have not been quantified. The court ruled that WVDEP cannot collect statutory penalties, but has not yet ruled whether WVDEP can continue to assert its claims for punitive damages. We are continuing to defend this action vigorously and believe that we have numerous valid defenses to the claims;

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various citations issued by the Federal Mine Safety and Health Administration (or the “MSHA”) following the impoundment discharge, and assessed penalties totaling approximately $110,000. The citations allege that we violated the MSHA-approved plan for operation of the facility. We have contested the violations and penalty amount;

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a suit filed by the Town of Fort Gay, West Virginia against us and Martin County Coal, alleging that its water treatment and distribution plant was damaged when water, allegedly discharged from the Martin County Coal impoundment, was pumped into the facility. The plaintiff seeks unquantified compensatory and punitive damages. We deny the allegations and are defending the action vigorously; and

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a subpoena for our documents relating to the impoundment and impoundment discharge that we have received from a federal grand jury of the United States District Court for the Eastern District of Kentucky. We are in the process of responding to the subpoena.

We believe that we have insurance coverage applicable to these items, at least with respect to civil liabilities other than governmental penalties, such as those assessed by MSHA, and punitive damages, if any. One of our carriers has stated that it believes its policy does not provide coverage for governmental penalties or punitive damages.

Water Claims Litigation. Two cases were filed in the Circuit Court of Mingo County, West Virginia, alleging that our Delbarton Mining Company subsidiary’s mining activities destroyed nearby resident plaintiffs’ water supplies. One case was filed on behalf of 134 plaintiffs on July 1, 2002, and the other was filed on behalf of 54 plaintiffs on July 26, 2002 (an amended complaint, filed May 1, 2003, added 42 plaintiffs). The plaintiffs seek to recover compensatory and punitive damages, but their alleged damages have not been quantified. Delbarton has already provided many of the plaintiffs with a replacement water source. Each case is in the very early procedural stages and trial is scheduled for October 2003 in the first case and February 2004 in the second case.

West Virginia Flooding Cases. Five of our subsidiaries have been named, among others, in 17 separate complaints filed in the Circuit Courts of Boone, Fayette, Kanawha, McDowell, Mercer, Raleigh and Wyoming Counties, West Virginia. These cases collectively include numerous plaintiffs who filed suit on behalf of themselves and others similarly situated, seeking damages for property damage and personal injuries arising out of flooding that occurred in southern West Virginia in July 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 and interrupted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court of Appeals ruled that these cases, including several additional flood damage cases not involving our subsidiaries, will 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, West Virginia and will be handled by a panel of three circuit court judges. The panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts. While the plaintiffs’ alleged damages have not been quantified and 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 cash flows, financial condition or results of operations.

We are subject to the Clean Water Act and corresponding state laws that restrict how we conduct our business and may expose us to substantial penalties for failures to comply.

The federal Clean Water Act and corresponding state laws affect coal mining operations by imposing restrictions on discharging of pollutants into waters and on dredging and filling of wetlands. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of permits governing the discharge of pollutants into water. In addition, we may become subject to fines and other penalties, including suspension or revocation of our permits, for failure to comply with these statutes. In December 2002, Independence Coal and Omar Coal each pled guilty to charges that it had negligently violated the Clean Water Act. Each company has paid $200,000 in fees and agreed to a five-year probation

period. We, along with Independence Coal and Omar Coal, have also agreed to an environmental training and compliance program and to independent environmental audits.

We cannot assure you that compliance with the requirements of the Clean Water Act and corresponding state laws will not cause us to incur significant additional costs or that we will not become subject to fines or other penalties for failures to comply with these statutes.

Anti-degradation Litigation. 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 anti-degradation implementation policy. Under the 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. Anti-degradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. The plaintiffs in this lawsuit, Ohio Valley Environmental Coalition v. Whitman, challenge provisions in West Virginia’s antidegradation implementation policy that exempt current holders of National Pollutant Discharge Elimination System, or “NPDES”, permits and permits under Section 404 of the Clean Water Act, among other parties, from the anti-degradation-review process. We are exempt from antidegradation review under these provisions. Revoking this exemption and subjecting us to the anti-degradation review process could delay the issuance or reissuance of Clean Water Act permits to us or cause these permits to be denied. If the plaintiffs are successful and if we discharge into waters that have been designated as high-quality by the state, the costs, time and difficulty associated with obtaining and complying with Clean Water Act permits for surface mining could increase.

We must obtain governmental permits and approvals for mining operations, which can be a costly and time-consuming process and result in restrictions on our operations.

Our operations are principally regulated under surface mining permits issued pursuant to the SMCRA and state counterpart laws. Such permits are issued for terms of five years with the right of successive renewal. We currently have over 400 surface mining permits. In conjunction with the surface mining permits, most operations hold NPDES permits pursuant to the Clean Water Act and state counterpart water pollution control laws for the discharge of pollutants to waters. These permits are issued for terms of five years and also are renewed in conjunction with the surface mining permit renewals. Additionally, the Clean Water Act requires permits for operations that fill waters of the United States. Valley fills and refuse impoundments are typically authorized under Nationwide Permits that are revised and renewed periodically by the U.S. Corps of Engineers. Additionally, certain surface mines and preparation plants have permits issued pursuant to the Clean Air Act and state counterpart clean air laws allowing and controlling the discharge of air pollutants. These permits are primarily permits allowing initial construction (not operation) and they do not have expiration dates.

Regulatory authorities exercise considerable discretion in the timing of permit issuance. Requirements imposed by these authorities may be costly and time-consuming and may result in delays in the commencement or continuation of exploration or production operations. We often are required to prepare and present to federal, state and local authorities data pertaining to the effect or impact that proposed exploration for or production of coal may have on the environment. For example, the WVDEP is involved in litigation regarding its alleged failure to consider the hydrologic effects of mining operations in issuing mining permits. This suit could result in West Virginia imposing additional requirements on us and other mining companies relating to the assessment of potential hydrologic risks.

On August 21, 2001, the Kentuckians for the Commonwealth, an environmental group, sued the U.S. Army Corps of Engineers alleging that the Corps of Engineers lacks authority under its regulations pursuant to the Clean Water Act to issue permits for valley fills in the waters of the United States. On May 8, 2002, the United States District Court for the Southern District of West Virginia issued an order in Kentuckians for the Commonwealth v. Rivenburgh enjoining the Huntington, West Virginia office of the U.S. Army Corps of

Engineers from issuing permits under Section 404 of the Clean Water Act for the construction of valley fills for the disposal of overburden from mountaintop mining operations solely for the purpose of waste disposal. The court held that the filling of these waters solely for waste disposal is a violation of the Clean Water Act. The court’s injunction also prohibited the issuance of permits authorizing fill activities associated with types of mining activities other than mountaintop mining where the primary purpose or use of those fill activities is the disposal of waste. Such activities might include those associated with slurry impoundments and coal refuse disposal areas. On January 29, 2003, the United States Court of Appeals for the Fourth Circuit reversed the district court’s decision and lifted the injunction. The time for filing a possible appeal has not yet expired. If the decision of the Court of Appeals were reversed and the injunction reinstated, the effect would be to make mountaintop mining uneconomical in those areas subject to the injunction and call into question our ability to obtain permits with respect to other mining activities that use valley fills.

Further, 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 may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements which restrict our ability to conduct our mining operations or to do so profitably.

We are the subject of various legal proceedings.

We are the subject of the following legal proceedings:

Harman Case. On July 31, 1997, we acquired United Coal Company and its subsidiary, Wellmore Coal Corporation. Wellmore was party to a coal supply agreement with Harman Mining Corporation and certain of its affiliates, pursuant to which Harman sold coal to Wellmore. In December 1997, Wellmore declared force majeure under the coal supply agreement and reduced the amount of coal to be purchased from Harman as a result thereof. Wellmore declared force majeure because its major customer for the coal purchased under the coal supply agreement was forced to close its Pittsburgh, Pennsylvania coke plant due to regulatory action. We subsequently sold Wellmore, but retained responsibility for any claims relating to this declaration of force majeure. On October 29, 1998, Harman and its sole shareholder, Hugh Caperton, filed an action against us and certain of our subsidiaries in the Circuit Court of Boone County, West Virginia, alleging that we and our subsidiaries tortiously interfered with Harman’s contract with Wellmore and, as a result, caused Harman to go out of business. On August 1, 2002, the jury in the case awarded the plaintiffs $50 million in compensatory and punitive damages. We are vigorously pursuing post-judgment remedies, and various motions filed in the trial court have been fully briefed and argued. We will appeal to the West Virginia Supreme Court of Appeals, if necessary. We have a liability with respect to this case of $25.0 million, excluding interest, included in Other current liabilities, which we believe is a fair estimate of the eventual total payout in this case.

Preparation Plant Employees Litigation. Several of our subsidiaries, along with several other coal companies and several chemical companies, are defendants in an action styled Denver Pettry, et al. v. Peabody Holding Company, et al., filed April 17, 2002 in the Circuit Court of Boone County, West Virginia, in which the plaintiffs allege that they were excessively exposed to chemicals used in the coal preparation plants of the defendant coal companies, which were manufactured by the defendant chemical companies. The plaintiffs are attempting to attain class action status, and seek to recover unquantified compensatory and punitive damages. We believe we have significant defenses to the claims, and we are defending the case vigorously. The case is in the early stages of discovery. On July 25, 2002, one of our insurers filed a declaratory judgment action in the U.S. District Court for the Eastern District of Virginia, seeking a declaration that it has no duty to defend or indemnify us in the Pettry action. On October 2, 2002, we filed suit seeking a declaratory judgment in the Circuit Court of

Boone County, West Virginia, against that insurer and other insurers who provided policies to us that may cover the Pettry claims, and filed a motion to dismiss the action filed in Virginia. On February 25, 2003, the U.S. District Court for the Eastern District of Virginia entered an order dismissing the Virginia case. The insurer appealed the dismissal of the Virginia case to the United States Court of Appeals for the Fourth Circuit, and filed a motion in the West Virginia case seeking a stay of that proceeding until its appeal of the Virginia case is decided. By order entered May 2, 2003, the court in the West Virginia case granted that motion.

Shareholder derivative suit. On August 5, 2002, a shareholder derivative complaint was filed in the Circuit Court of Boone County, West Virginia, naming us, each of our directors and certain of our current and former officers. The complaint alleges (1) breach of fiduciary duties against all of the defendants for refusing to cause us to comply with environmental, labor and securities laws, and (2) improper insider trading by Don L. Blankenship, Jeffrey M. Jarosinski, Madeleine M. Curle and Bennett K. Hatfield. The plaintiff makes these allegations derivatively, and seeks to recover damages on behalf of our company. The damages claimed by the plaintiff have not been quantified. We and the other defendants removed the case to Federal District Court in Charleston, West Virginia, but the case has now been remanded to the Circuit Court of Boone County. The case is still in a very early procedural stage.

Dotco Energy Litigation. On June 14, 1999, Dotco Energy Company, Inc. filed suit against our subsidiary, Rawl Sales & Processing Co., in the Circuit Court of Pike County, Kentucky, alleging that Rawl miscalculated the payment that should have been made to Dotco for coal delivered to Rawl from years 1980 through 1996, when Dotco was a contract miner for Rawl. The complaint alleges that the wrongful calculations resulted in nonpayment for 263,117 tons of coal, for which allegedly $4,736,109 is due. The complaint also alleged fraud and asserted a claim for punitive damages. Subsequent rulings by the Court dismissed the fraud claim and the claim for punitive damages. Rawl has asserted a counterclaim for advances in the amount of $375,862. We believe Rawl has valid defenses to the claim and are defending the case vigorously. Trial is scheduled to begin July 22, 2003.

We are parties to a number of other legal proceedings incident to our normal business activities. While we cannot predict the outcome of these proceedings, in our opinion, any liability arising from these matters individually and in the aggregate should not have a material adverse effect upon our consolidated financial position, cash flows or results of operations.

Please refer to the documents incorporated by reference in this offering memorandum under “Documents Incorporated by Reference” for a description of other legal proceedings to which we are subject.

We have significant reclamation and mine closure obligations. If the assumptions underlying our accruals are materially inaccurate, we could be required to expend greater amounts than anticipated.

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. We adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”) effective January 1, 2003. Statement 143 requires that retirement obligations be recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows. In estimating future cash flows, we considered the estimated current cost of reclamation and applied inflation rates and a third-party profit, as necessary. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on behalf of us. The resulting estimated liability could change significantly if actual amounts change significantly from our assumptions.

New regulations have generally made it easier for claimants to assert and prosecute black lung claims, which could increase our liability for black lung benefits.

Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to: (1) current and former coal miners totally disabled from black lung disease; (2) certain survivors of a miner who dies from black lung disease; and (3) a trust fund for the payment of medical

expenses to claimants whose last mine employment was before January 1, 1970, where no responsible coal mine operator has been identified for claims (where a miner’s last coal employment was after December 31, 1969), or where the responsible coal mine operator has defaulted on the payment of such benefits. In recent years, legislation on black lung reform has been introduced but not enacted in Congress. It is possible that such legislation will be reintroduced for consideration by Congress. If any of the proposals included in such or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase. There can be no assurance that any such changes in black lung legislation, if approved, will not have a material adverse effect on our business, financial condition and results of operations. In addition to federal acts, we are also liable under various state statutes for black lung claims.

In addition, the United States Department of Labor issued a final rule, effective January 19, 2001, amending the regulations implementing federal black lung laws. The amendments give greater weight to the opinion of the claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which, according to the Department of Labor, result in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the black lung regulations could potentially increase our exposure to black lung benefits liabilities. We, with the help of our consulting actuaries, intend to monitor claims activity very closely and will modify the assumptions underlying the projection of our black lung liability should the results of such monitoring indicate that it is appropriate to do so.

The characteristics of coal may make it difficult for coal users to comply with various environmental standards related to coal combustion. As a result, they may switch to other fuels, which would affect the volume of our sales.

Coal contains impurities, including sulfur, mercury, chlorine, nitrogen oxide and other elements or compounds, many of which are released into the air when coal is burned. The Clean Air Act and corresponding state laws extensively regulate emissions into the air of particulate matter and other substances, including sulfur dioxide, nitrogen oxides and mercury. Although these regulations apply directly to impose certain requirements for the permitting and operation of our mining facilities, by far their greatest impact on us and the coal industry generally is the effect of emission limitations on utilities and our other customers. 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. The EPA has imposed or attempted to impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of such tighter restrictions could be to reduce demand for coal. In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for very fine particulate matter and ozone. The Court of Appeals for the District of Columbia issued an opinion in May 1999 limiting the manner in which the EPA can enforce these standards. After a request by the federal government for a rehearing by the Court of Appeals was denied, the Supreme Court agreed in January 2000 to review the case. On February 27, 2001, the Supreme Court found in favor of the EPA in material part and remanded the case to the Court of Appeals. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their state implementation plans to include provisions for the control of ozone precursors and/or particulate matter. Revised state implementation plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and the development of new mines by the Company. This in turn may result in decreased production by us and a

corresponding decrease in our revenue. Although the future scope of these ozone and particulate matter regulations cannot be predicted, future regulations regarding these and other ambient air standards could restrict the market for coal and the development of new mines.

Furthermore, in October 1998, the EPA finalized a rule that will require 19 states in the Eastern United States that have ambient air quality problems to make substantial reductions in nitrogen oxide emissions by the year 2004. The final rule was largely upheld by the United States Court of Appeals for the District of Columbia Circuit. To achieve reductions in nitrogen oxide emissions by 2004, many power plants would be required to install additional control measures such as capital-intensive selective catalytic reduction (SCR) devices. The installation of these measures would make it more costly to operate coal-fired power plants and, depending on the requirements of individual state implementation plans, could make coal a less attractive fuel. In addition, reductions in nitrogen oxide emissions can be achieved at a low capital cost through a combination of low nitrogen oxide burners and coal produced in Western U.S. coal mines. As a result, changes in current emissions standards could also impact the economic incentives for Eastern U.S. coal-fired power plants to consider using more coal produced in Western U.S. coal mines.

Along with these regulations addressing ambient air quality, the EPA has initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxides and particulate matter. The EPA’s final rule concerning best available retrofit technology (BART) is currently on remand to the EPA from the United States Court of Appeals for the District of Columbia Circuit. 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 and brought an administrative action against one government-owned electric utility 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 our other 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.

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

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

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

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reducing electricity generating levels; or

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purchasing or trading emission credits.

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

In addition to emissions control requirements designed to control acid rain and to attain the national ambient air quality standards, the Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not yet been extended to coal mining operations, the EPA recently announced that it will regulate hazardous air pollutants from coal-fired power plants. Under the Clean Air Act, coal-fired power plants will be required to control hazardous air pollution emissions by no later than 2009. These controls are likely to require significant new improvements in controls by power plant owners. The most prominently targeted pollutant is mercury, although other by-products of coal combustion may be covered by future hazardous air pollutant standards for coal combustion sources. However, the introduction of mercury emissions limits could place coal produced in Western U.S. mines at a competitive disadvantage to coal produced in Eastern U.S. mines, as current mercury-removal technology is more effective on Eastern U.S. coal. The EPA has announced that it intends to issue a proposed rule concerning maximum achievable control technology (MACT) for utilities by December 2003.

Other proposed initiatives may have an effect upon coal operations. Several so-called multi-pollutant bills, which could regulate a variety of air emissions, including carbon dioxide and mercury, have been proposed. 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. Senator James Jeffords has also introduced a bill that would place tight caps on coal-fired emissions, including mandatory limits on carbon dioxide emissions, and require shorter implementation time frames. While the details of these proposed initiatives vary, there is clearly a movement towards increased regulation of air emissions, including carbon dioxide and mercury, which could cause power plants to shift away from coal as a fuel source.

The Bush administration recently pledged $2 billion to the Clean Coal Technology (CCT) Program. The CCT Program is a government and industry co-funded effort to demonstrate a new generation of innovative coal-utilization processes in a series of “showcase” facilities built across the country. These projects are carried out in sufficiently large scale to prove commercial worthiness and generate data for design, construction, operation, and technical/economic evaluation of full-scale commercial applications. The goal of the CCT Program is to furnish the U.S. energy marketplace with advanced, more efficient coal-based technologies, technologies that are capable of mitigating some of the economic and environmental impediments that inhibit the use of coal as an energy source.

The passage of legislation responsive to the Framework Convention on Global Climate Change or similar governmental initiatives could result in restrictions on coal use.

The United States has not implemented the 1992 Framework Convention on Global Climate Change, or the “Kyoto Protocol”, which is intended to limit or reduce emissions of greenhouse gases, such as carbon dioxide. Under the terms of the Kyoto Protocol, which specific emission targets vary from country to country, the United States would be required to reduce emissions to 93% of 1990 levels over a five-year period from 2008 through 2012. Although the United States has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. In March 2001, President Bush reiterated his opposition to the Kyoto Protocol and further stated that he did not believe that the government should impose mandatory carbon dioxide emission reductions on power plants. In February 2002, President Bush announced a new approach to climate change, confirming the Administration’s opposition to the Kyoto Protocol and proposing voluntary actions to reduce the greenhouse gas intensity of the United States. Greenhouse gas intensity measures the ratio of greenhouse gas emissions, such as carbon dioxide, to economic output. The President’s climate change initiative calls for a reduction in greenhouse gas intensity over the next 10 years which is approximately equivalent to the reduction that has occurred over each of the past two decades. If this or other comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States, it would have the effect of restricting the use of coal. Other efforts to reduce emissions of greenhouse gases and federal initiatives to encourage the use of natural gas also may affect the use of coal as an energy source.

Weather conditions may affect our business.

Severe weather, including flooding and excessive ice or snowfall, when it occurs, can adversely affect our ability to produce, load and transport coal. In addition, unseasonable weather can adversely affect the demand and price for coal, which could adversely affect our business, financial condition and results of operations.

Foreign currency fluctuations could adversely affect the competitiveness of our coal abroad.

We rely on customers in other countries for a portion of our sales, with shipments to countries in Europe, North America and South America. We compete in these international markets against coal produced in other countries. Coal is sold internationally in U.S. dollars. As a result, mining costs in competing coal producing countries may be less in U.S. dollar terms because of currency exchange rates, providing an advantage to foreign coal producers. Currency fluctuations in coal producing countries could adversely affect the competitiveness of U.S. coal in international markets.

We face numerous uncertainties in estimating our economically recoverable coal reserves, and inaccuracies in our estimates could result in lower than expected revenues, higher than expected costs and decreased profitability.

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff.

Some of the factors and assumptions that impact economically recoverable reserve estimates include:

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geological conditions;

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historical production from the area compared with production from other producing areas;

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the assumed effects of regulations and taxes by governmental agencies;

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assumptions governing future prices; and

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future operating costs.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties may vary substantially. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and these variances may be material. As a result, our estimates may not accurately reflect our actual reserves.

Our acquisition strategy may not be realized or may require us to raise capital by incurring substantial debt or issuing additional equity.

We intend to pursue growth through opportunistic acquisitions. The coal industry is experiencing rapid consolidation, with many companies seeking to consummate opportunistic acquisitions and increase their market share. We compete and will continue to compete with many other buyers for acquisitions. Acquisitions involve a number of risks, including the time associated with identifying and evaluating future acquisitions, the diversion of management’s attention to the integration of the operations and personnel of the acquired companies, possible adverse short-term effects on our operating results and the loss of key employees of the acquired companies. We cannot provide any assurance that future acquisitions will be available on terms acceptable to us. Our ability to consummate any acquisition will be subject to various conditions, including the negotiation of satisfactory agreements, obtaining necessary regulatory approvals and financing.

Transportation disruptions could impair our ability to sell coal.

We rely on transportation providers to provide access to markets. Disruption of transportation services because of weather-related problems, strikes, lockouts or other events could temporarily impair our ability to supply coal to customers. In 2002, rail shipments constituted approximately 91% of our total shipments, with approximately 33% loaded on Norfolk Southern trains and approximately 58% loaded on CSX trains. If there are disruptions of the transportation services provided by Norfolk Southern or CSX and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

The State of West Virginia has recently increased enforcement of weight limits on coal trucks on its public roads. Also, West Virginia legislation, which raised coal truck weight limits in West Virginia, includes provisions supporting enhanced enforcement. Although we have historically avoided public road trucking of coal when possible by transporting coal by rail, barge and conveyor systems, such stepped up enforcement actions could result in shipment delays and increased costs. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production and adversely affect revenues.

On January 7, 2003, Coal River Mountain Watch, an advocacy group representing local residents in the Counties of Boone, Raleigh and Kanawha, West Virginia, and other plaintiffs, filed suit in the Circuit Court of Kanawha County, West Virginia against certain of our subsidiaries and various other coal and transportation companies alleging that the defendants illegally transport coal in overloaded trucks causing damage to state roads and interfering with the plaintiffs’ use and enjoyment of their properties and their right to use the public roads, and seeking injunctive relief and unquantified compensatory and punitive damages. The plaintiffs alleged damages have not been quantified. The case is in the very early procedural stages and we intend to vigorously pursue the defense of this case.

Fluctuations in transportation costs could adversely affect the demand for our coal and increase competition from coal producers in other parts of the country.

Transportation costs represent a significant portion of the delivered cost of coal and, as a result, are a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy. Such increases could have a material adverse effect on our ability to compete with other energy sources and on our business, financial condition and results of operations. On the other hand, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, coordination of the many eastern loading facilities, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the Eastern United States inherently more expensive on a per-mile basis than shipments originating in the Western United States. Historically, coal transportation rates from the western coal producing areas into Central Appalachian markets limited the use of western coal in those markets. More recently, however, lower rail rates from the western coal producing areas to markets served by eastern producers have created major competitive challenges for eastern producers. This increased competition could have a material adverse effect on our business, financial condition and results of operations.

We may have difficulty in attracting and retaining skilled managers.

From time to time, we experience the loss of senior managers who choose for various reasons to pursue other interests. There can be no assurance that we will not experience further management changes in the future, or that we will be able to attract and retain capable and experienced managers on terms acceptable to us and consistent with our compensation practices.

We depend on a small number of customers for a significant portion of our revenues and the loss of any of those customers could adversely affect us.

During our fiscal year ended December 31, 2002, we derived approximately 32%, of our total revenues from sales to our four largest customers. If we are unable to continue to sell coal to those customers on terms,

including volume and pricing, under existing agreements, or if we are unable to find another customer to purchase such lost volume, our cash flows, financial condition and results of operations could be adversely affected.

If our customers do not extend existing contracts or enter into new long-term contracts for coal, the stability and profitability of our operations could be affected.

During our fiscal year ended December 31, 2002, approximately 94% of the coal we sold was under contracts with terms of one year or more. The profitability of our long-term coal supply contracts depends on a variety of factors, which vary from contract to contract and fluctuate during the contract term, and includes our production costs and other factors. Price changes, if any, provided in long-term supply contracts are not intended to reflect our cost increases, and therefore increases in our costs may reduce our profit margins. In addition, in periods of declining market prices, provisions for adjustment or renegotiation of prices and other provisions may increase our exposure to short-term coal price volatility.

In addition, some supply contracts contain provisions that allow the customer to suspend or terminate performance under the contract upon the occurrence or continuation of specified events. These events typically include:

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our inability to deliver the volume or qualities of coal specified;

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changes in the Clean Air Act rendering use of coal inconsistent with the customer’s pollution control strategies; and

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the occurrence of events beyond the reasonable control of the affected party, including labor disputes, mechanical malfunctions and changes in government regulations.

If a substantial portion of our long-term contracts are terminated, we would be adversely affected to the extent that we are unable to find other customers at the same level of profitability.

As electric utilities adjust to the Phase II requirements of the Clean Air Act and the possible deregulation of their industry, they are becoming increasingly less willing to enter into coal supply contracts with terms of more than one year. Instead, these utilities are purchasing higher percentages of coal on the spot market. Spot market prices tend to be more volatile than contractual prices, which could make our results of operations more volatile.

Disputes with our customers concerning contracts can result in litigation, which could result in our paying substantial damages.

From time to time, we have disputes with our customers over the provisions of long-term contracts relating to, among other things, coal quality, pricing, quantity and delays in delivery. We may not be able to resolve these disputes in a satisfactory manner, which could result in our paying substantial damages or otherwise harm our relationships with our customers.

On April 16, 2002, Appalachian Power Company, a subsidiary of American Electric Power, filed suit against us alleging that we improperly claimed force majeure with respect to a tonnage shortfall under our contracts with Appalachian Power in 2000 and 2001 and seeks to recover the additional cost Appalachian Power incurred in purchasing substitute coal. The complaint further alleges that our claim of force majeure constitutes fraud and seeks to recover profits we made on sales to other customers of the coal Appalachian Power claims should have been delivered to it. By order entered July 25, 2002, the court dismissed the fraud claim, however, on December 20, 2002, the court granted Appalachian Power leave to file a second amended complaint to reassert the fraud claim. The trial for this matter is scheduled for June 4, 2003. Discovery is ongoing and Appalachian Power has indicated on a preliminary basis that it intends to seek approximately $20.3 million in damages for its cost of purchasing substitute coal. No other alleged damages have been quantified.

We have significant obligations for long-term employee benefits for which we accrue based upon assumptions which, if inaccurate, could result in our being required to expend greater amounts than anticipated.

We provide various long-term employee benefits to inactive and retired employees. We accrue amounts for these obligations. The current and non-current portions of these obligations, as reflected in our consolidated financial statements at December 31, 2002, included:

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post retirement medical and life insurance ($83.4 million);

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coal workers’ black lung benefits ($62.9 million);

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workers’ compensation ($37.4 million); and

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long-term disability ($8.9 million).

These obligations have been estimated based on assumptions, which are described in the notes to our consolidated financial statements. However, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. These obligations are not funded. In addition, several states in which we operate consider changes in workers’ compensation laws from time to time. Such changes, if enacted, could adversely affect us.

In the legislative session that ended on March 8, 2003, the West Virginia legislature failed to pass a workers’ compensation bill that was sponsored by the employer community to address growing issues surrounding the solvency of the state’s workers’ compensation program. Employer premiums are the primary source of revenue to cover program costs. Therefore, both subscribing employers to the state workers compensation fund as well as self-insured employers who pay premiums to cover the cost of second injury claims could face significant premium increases effective July 1, 2003 to help the state system meet its workers’ compensation program obligations unless reform legislation is passed in a special session or unless new sources of revenue are identified. As our West Virginia operations are either subscribers to the state fund or self-insured employers, the outcome of this issue may increase our workers’ compensation costs in West Virginia.

Union-represented labor creates an increased risk of work stoppages and higher labor costs.

Seven of our coal processing plants and one of our smaller surface mines have a workforce that is represented by the United Mine Workers of America. While less than 5% of our total workforce at December 31, 2002 was represented by the United Mine Workers of America, these seven processing plants handled approximately 35% of our coal production in fiscal 2002. There could be an increased risk of strikes and other related work actions, in addition to higher labor costs, associated with these operations. We have also experienced some union organizing campaigns at some of our open shop facilities within the past five years. If some or all of our current open shop operations were to become union represented, we could incur additional risk of work stoppages and higher labor costs. Increased labor costs or work stoppages could adversely affect the stability of production and reduce our revenues.

A shortage of skilled labor in the Central Appalachian region could pose a risk to achieving high labor productivity and competitive costs.

Coal mining continues to be a labor-intensive industry. In 2001, a shortage of trained coal miners developed in the Central Appalachian region causing us to hire a large number of mine workers with less experience than our existing workforce. While we did not experience this shortage in 2002, if another shortage of skilled labor were to arise, our productivity could decrease and our costs could increase. Such a lack of skilled miners could have an adverse impact on our labor productivity and cost and our ability to expand production in the event there is an increase in the demand for coal.

Deregulation of the electric utility industry could lead to efforts to reduce coal prices.

Deregulation of the electric utility industry, when implemented, will enable industrial, commercial and residential customers to shop for the lowest cost supply of electricity. This fundamental change in the power industry may result in efforts to reduce coal prices.

We are subject to being adversely affected by the potential inability to renew or obtain surety bonds.

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, and to satisfy other miscellaneous obligations. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material adverse effect on us. That failure could result from a variety of factors including:

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lack of availability, higher expense or unfavorable market terms of new bonds;

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restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of the notes, our senior notes or our revolving credit facilities; and

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the exercise by third-party surety bond issuers of their right to refuse to renew the surety.

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA

The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the years ended December 31, 2002 and October 31, 2001, 2000, 1999 and 1998, are derived from our audited consolidated financial statements. The selected consolidated financial data for, and as of the end of, the three months ended March 31, 2003 and 2002 and the two months ended December 31, 2001, are derived from our unaudited consolidated financial statements, and in the opinion of management include all adjustments, consisting only of normal recurring accruals, that are necessary for a fair presentation of our financial position and operating results for these periods. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for the entire year. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included or incorporated by reference in this offering memorandum.

Effective January 1, 2002, we changed our fiscal year end from October 31 to December 31 to enhance the financial community’s ability to analyze and compare our company to others within the coal industry. As a requirement of this change, we reported results for November and December 2001 as a separate transition period, with the results for the corresponding period of 2000 presented for comparative purposes. Certain amounts have been reclassified to conform with the 2003 presentation.

	Three Months Ended March 31,						Year Ended December 31, 2002			Year Ended October 31,												Two Months Ended December 31, 2001
	2003			2002			Year Ended December 31, 2002			2001			2000⁽¹⁾			1999			1998			Two Months Ended December 31, 2001
	(in millions, except ratios, per share amounts and operating data)
Produced coal revenue	$	303.0		$	323.5		$	1,318.9		$	1,203.3		$	1,081.0		$	1,076.1		$	1,121.1		$	204.8
Freight and handling revenue		24.0			26.0			112.0			129.9			131.3			106.2			130.7			18.9
Purchased coal revenue		27.0			23.2			117.1			49.5			39.6			41.4			6.0			17.0
Other revenue		20.0			19.9			78.8			49.2			60.8			39.3			34.6			5.7
Senior notes repurchase income		0.6			—			3.3			—			—			—			—			—

Total revenue		374.6			392.6			1,630.1			1,431.9			1,312.7			1,263.0			1,292.4			246.4

Cost of produced coal revenue		272.7			287.1			1,166.2			1,024.7			833.9			773.1			807.0			190.0
Freight and handling costs		24.0			26.0			112.0			129.9			131.3			106.2			130.7			18.9
Cost of purchased coal revenue		27.6			24.7			119.6			47.1			38.9			41.2			5.5			16.1
Depreciation, depletion and amortization applicable to:
Cost of produced coal revenue		45.9			46.4			203.9			177.4			169.5			165.8			148.8			30.3
Selling, general and administrative		1.2			0.5			3.8			3.9			1.8			1.8			1.7			0.9
Selling, general and administrative		9.7			8.4			40.1			31.7			35.3			32.7			27.5			7.5
Other expenses		3.3			3.1			11.2			7.7			5.5			4.3			1.1			1.9

Total costs and expenses		384.4			396.2			1,656.8			1,422.4			1,216.2			1,125.1			1,122.3			265.6

(Loss) Income from operations		(9.8	)		(3.6	)		(26.7	)		9.5			96.5			137.9			170.1			(19.2	)
Interest income		1.2			1.0			4.5			8.8			25.7			14.4			16.1			1.0
Interest expense		(9.2	)		(7.8	)		(35.3	)		(34.2	)		(0.4	)		(0.8	)		(0.5	)		(5.3	)

(Loss) Income before taxes		(17.8	)		(10.4	)		(57.5	)		(15.9	)		121.8			151.5			185.7			(23.5	)
Income tax (benefit) expense		(8.2	)		(6.2	)		(24.9	)		(10.5	)		43.3			49.0			57.4			(8.7	)

(Loss) Income before cumulative effect of accounting change		(9.6	)		(4.2	)		(32.6	)		(5.4	)		78.5			102.5			128.3			(14.8	)
Cumulative effect of accounting change, net of tax of $5.0 million		(7.9	)		—			—			—			—			—			—			—

Net (loss) income	$	(17.5	)	$	(4.2	)	$	(32.6	)	$	(5.4	)	$	78.5		$	102.5		$	128.3		$	(14.8	)

(Loss) income per share (basic and diluted):
(Loss) Income before cumulative effect of accounting change	$	(0.13	)	$	(0.06	)	$	(0.44	)	$	(0.07	)	$	1.07		$	1.40		$	1.75		$	(0.20	)
Net (loss) income per share	$	(0.23	)	$	(0.06	)	$	(0.44	)	$	(0.07	)	$	1.07		$	1.40		$	1.75		$	(0.20	)

Cash Flow Statement Data:
Net cash (used) provided by operating activities	$	(32.9	)	$	21.7		$	122.5		$	172.8		$	153.7		$	235.7		$	285.5		$	19.4
Net cash used in investing activities		(13.0	)		(44.3	)		(122.0	)		(212.6	)		(172.8	)		(222.8	)		(282.3	)		(37.3	)
Net cash provided (used) by financing activities		47.5			35.0			(3.3	)		38.6			18.0			(8.5	)		(3.1	)		17.7

	Three Months Ended March 31,						Year Ended December 31, 2002			Year Ended October 31,												Two Months Ended December 31, 2001
	2003			2002			Year Ended December 31, 2002			2001			2000⁽¹⁾			1999			1998			Two Months Ended December 31, 2001
	(in millions, except ratios, per share amounts and operating data)
Other Financial Data:
EBITDA⁽²⁾:
(Loss) Income from operations	$	(9.8	)	$	(3.6	)	$	(26.7	)	$	9.5		$	96.5		$	137.9		$	170.1		$	(19.2	)
Depreciation, depletion and amortization		47.1			46.9			207.7			181.3			171.3			167.6			150.5			31.2

EBITDA	$	37.3		$	43.3		$	181.0		$	190.8		$	267.8		$	305.5		$	320.6		$	12.0

Capital expenditures	$	17.3		$	46.1		$	135.1		$	247.5		$	204.8		$	230.0		$	307.9		$	37.7
Ratio of earnings to fixed charges⁽³⁾		⁽³	⁾		⁽³	⁾		1.0	x		⁽³	⁾		13.6	x		19.7	x		54.5	x		⁽³	⁾

Operating Data:
Tons sold		9.9			10.5			42.1			43.7			40.2			37.9			37.6			7.0
Tons produced		10.4			11.8			43.9			45.1			41.5			38.4			38.0			7.0
Total costs and expenses per ton sold	$	39.01		$	37.71		$	39.33		$	32.52		$	30.22		$	29.71		$	29.85		$	38.08
Average cash cost per ton sold⁽⁴⁾	$	28.66		$	28.13		$	28.64		$	24.15		$	21.60		$	21.28		$	22.19		$	28.33
Produced coal revenue per ton sold	$	30.74		$	30.80		$	31.30		$	27.51		$	26.86		$	28.40		$	29.83		$	29.36
Total coal reserves⁽⁵⁾		—			—			2,206			2,272			2,048			2,223			1,942			—
Number of employees		4,313			4,671			4,552			5,004			3,610			3,190			3,094			5,040

	As of March 31, 2003		As of December 31, 2002			As of October 31,									As of December 31, 2001
	As of March 31, 2003		As of December 31, 2002			2001			2000		1999		1998		As of December 31, 2001
	(in millions)
Consolidated Balance Sheet Data:
Working capital (deficit)	$	10.1	$	(63.4	)	$	(84.7	)	$	164.8	$	72.5	$	33.7	$	(93.3	)
Total assets		2,182.0		2,241.4			2,271.1			2,183.8		2,008.6		1,866.6		2,272.0
Short-term debt		263.7		264.0			248.2			—		—		—		263.1
Long-term debt		325.2		286.0			300.0			—		—		—		300.0
Shareholders’ equity		788.2		808.2			860.6			1,372.5		1,275.6		1,181.2		849.5

(1)

On November 30, 2000, Fluor Corporation, or “Fluor,” completed a reverse spin-off, which divided it into the spun-off corporation, “new” Fluor Corporation and Fluor, subsequently renamed Massey Energy Company, which retained Fluor’s coal-related businesses conducted by A.T. Massey. Further discussion of the spin-off may be found in the notes to our consolidated financial statements, which are incorporated by reference in this offering memorandum. As New Fluor is the accounting successor to Fluor Corporation, Massey Energy’s equity structure was impacted as a result of the spin-off. We retained $300 million of 6.95% Senior Notes, $278.5 million of Fluor commercial paper, other equity contributions from Fluor, and assumed Fluor’s common stock equity structure. Therefore, the selected consolidated financial and operating data for years prior to 2001 are not necessarily indicative of our results of operations, financial position and cash flows in the future or had we operated as a separate independent company during the periods prior to November 30, 2000.

(2)

EBITDA is defined as income (loss) from operations before deducting depreciation, depletion and amortization. Although EBITDA is not a measure of performance calculated in accordance with generally accepted accounting principles, our management believes that it is useful to an investor in evaluating Massey Energy because it is widely used in the coal industry as a measure to evaluate a company’s operating performance before debt expense and its cash flow. EBITDA does not purport to represent operating income, net income and cash generated by operating activities and should not be considered in isolation or as a substitute for measures of performance in accordance with generally accepted accounting principles. In addition, because EBITDA is not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies.

(3)

For purposes of computing the ratio of earnings to fixed charges, “earnings” consist of income from operations before income taxes plus fixed charges. “Fixed charges” consist of interest and debt expense, capitalized interest and a portion of rent expense we believe to be representative of interest. Earnings for the three-months ended March 31, 2003 and March 31, 2002, for the year ended October 31, 2001 and for the two months ended December 31, 2001, were inadequate to cover fixed charges, with a deficiency of $17.8 million, $10.4 million, $15.9 million and $23.5 million, respectively.

(4)

“Average cash cost per ton” is calculated as the sum of cost of produced coal revenue and selling, general and administrative expense (excluding depreciation, depletion and amortization applicable to both cost of produced coal revenue and selling, general and administrative expense), divided by total produced tons sold. Although average cash cost per ton is not a measure of performance calculated in accordance with generally accepted accounting principles, our management believes that it is useful to an investor in evaluating Massey Energy because it is widely used in the coal industry as a measure to evaluate a company’s control over its cash costs. Average cash cost per ton should not be considered in isolation or as a substitute for measures of performance in accordance with generally accepted accounting principles. In addition, because Average cash cost per ton is not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. The table below reconciles the most directly comparable generally accepted accounting principle measure of total costs and expenses per ton to average cash cost per ton.

	Three Months Ended March 31,								Year Ended December 31, 2002				Year Ended October 31,																Two Months Ended December 31, 2001
	2003				2002				Year Ended December 31, 2002				2001				2000				1999				1998				Two Months Ended December 31, 2001
	$		Per ton		$		Per ton		$		Per ton		$		Per ton		$		Per ton		$		Per ton		$		Per ton		$		Per ton
	($ in millions except per ton data)
Total Costs and expenses	$	384.4	$	39.01	$	396.2	$	37.71	$	1,656.8	$	39.33	$	1,422.4	$	32.52	$	1,216.2	$	30.22	$	1,125.1	$	29.71	$	1,122.3	$	29.85	$	265.6	$	38.08
Less: Freight and handling costs		24.0		2.44		26.0		2.47		112.0		2.66		129.9		2.97		131.3		3.26		106.2		2.80		130.7		3.48		18.9		2.71
Less: Cost of purchased coal revenue		27.6		2.80		24.7		2.35		119.6		2.84		47.1		1.08		38.9		0.97		41.2		1.09		5.5		0.15		16.1		2.31
Less: Depreciation, depletion and amortization		47.1		4.78		46.9		4.46		207.7		4.93		181.3		4.14		171.3		4.25		167.6		4.42		150.5		4.00		31.2		4.47
Less: Other expense		3.3		0.33		3.1		0.30		11.2		0.26		7.7		0.18		5.5		0.14		4.3		0.12		1.1		0.03		1.9		0.26

Average cash cost	$	282.4	$	28.66	$	295.5	$	28.13	$	1,206.3	$	28.64	$	1,056.4	$	24.15	$	869.2	$	21.60	$	805.8	$	21.28	$	834.5	$	22.19	$	197.5	$	28.33

(5)

Represents proven and probable reserves at fiscal year end. Reserves are measured at fiscal year end only.

MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS

You should read the following discussion and analysis together with our consolidated financial statements and related notes incorporated by reference in this offering memorandum.

Results of Operations

Three Months Ended March 31, 2003 Compared with Three Months Ended March 31, 2002

For the three months ended March 31, 2003, produced coal revenue decreased 6% to $303.0 million compared with $323.5 million for the three months ended March 31, 2002. Two factors that impacted produced coal revenue for the first quarter of 2003 compared to the first quarter of 2002 were:

•

the volume of produced tons sold decreased 6% from 10.5 million tons to 9.9 million tons, attributable to a reduction in utility and metallurgical tons sold of 7% and 4%, respectively; and

•

the average per ton sales price for produced coal decreased slightly from $30.80 to $30.74 per ton consisting of decreases of 10% and 2% in the prices for industrial and metallurgical coal, respectively, offset by a 2% increase in the price for utility coal.

The volume of produced tons sold decreased as severe winter weather disrupted operations and shipping at some of our surface mines and reduced productivity at three of our longwall mines due to panel moves during the quarter.

Freight and handling revenue decreased $2.0 million, or 8%, to $24.0 million for the first quarter of 2003 compared with $26.0 million for the first quarter of 2002, on lower shipped volume.

Purchased coal revenue increased $3.8 million, or 16%, to $27.0 million for the first quarter of 2003 from $23.2 million for the first quarter of 2002, due to an increase in spot prices for coal, as well as an increase in purchased tons sold. We purchase varying amounts of coal each quarter to supplement produced coal sales.

Other revenue, which consists of royalties, rentals, coal handling facility fees, gas well revenues, synfuel earnings, gains on the sale of non-strategic assets, contract buyout payments, and miscellaneous income, increased to $20.0 million for the first quarter of 2003 from $19.9 million for the first quarter of 2002. The increase was primarily due to increased earnings related to the operations of Appalachian Synfuel, LLC, in 2003, offset by a decrease in contract buyout payments from 2002.

Cost of produced coal revenue decreased approximately 5% to $272.7 million for the first quarter of 2003 from $287.1 million for the first quarter of 2002. Cost of produced coal revenue on a per ton of coal sold basis increased 1% in the first quarter of 2003 compared with the first quarter of 2002. This increase was due to lower productivity at several of our longwall and surface mining operations due to the move of three of our longwalls, the severe winter weather in 2003, and higher wage and benefit levels. Tons produced in the first quarter of 2003 were 10.4 million compared to 11.8 million in the first quarter of 2002.

Freight and handling costs decreased $2.0 million, or 8%, to $24.0 million for the first quarter of 2003 compared with $26.0 million for the first quarter of 2002, on lower shipped volume.

Cost of purchased coal revenue increased $2.9 million to $27.6 million for the first quarter of 2003 from $24.7 million for the first quarter of 2002, due to an increase in purchased tons sold. We purchase varying amounts of coal each quarter to supplement produced coal sales.

Depreciation, depletion and amortization increased by 0.4% to $47.1 million in the first quarter of 2003 compared to $46.9 million for the first quarter of 2002.

Selling, general and administrative expenses were $9.7 million for the first quarter of 2003 compared to $8.4 million for the first quarter of 2002. The increase was primarily attributable to a reduction in bad debt reserves in 2002 for a receivable from a large bankrupt customer, Wheeling Pittsburgh Steel, totaling $2.5 million on a pre-tax basis.

Other expense, which consists of costs associated with the generation of other revenue, such as costs to operate the coal handling facilities, gas wells, and other miscellaneous expenses, remained virtually unchanged from the first quarter 2002 to the first quarter 2003, as the associated revenues remained constant.

Interest expense increased to $9.2 million for the first quarter of 2003 compared with $7.8 million for the first quarter of 2002. The higher interest expense was primarily due to the increase in the weighted average interest rate for the combined variable rate credit facility and receivables-based borrowings to 3.73% at March 31, 2003 from the 2.56% interest rate available in the commercial paper markets at March 31, 2002.

Income tax benefit was $8.2 million for the first quarter of 2003 compared with $6.2 million for the first quarter of 2002. The first quarter of 2002 included a refund for the settlement of a state tax dispute in the amount of $2.4 million, net of federal tax.

Cumulative effect of accounting change was a charge of $7.9 million, net of tax of $5.0 million for the first quarter of 2003 related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”), as required, effective January 1, 2003. As a result of adoption of Statement 143, we recognized a decrease in total reclamation liability of $13.1 million and a decrease in net deferred tax liability of $5.0 million. We capitalized asset retirement costs by increasing the carrying amount of the related long lived assets recorded in property, plant and equipment, net of the associated accumulated depreciation, by $22.7 million. Additionally, we recognized a decrease in mining properties and mineral rights, net of accumulated depletion, of $48.7 million related to amounts recorded in previous asset purchase transactions from assumption of pre-acquisition reclamation liability. See “—Critical Accounting Estimates and Assumptions—Reclamation and Mine Closure Obligations” below, and Note 3 of the notes to our condensed consolidated financial statements incorporated by reference in the offering memorandum for further information.

Fiscal Year Ended December 31, 2002 Compared with Fiscal Year Ended October 31, 2001

Produced coal revenue for the year ended December 31, 2002, increased 10% to $1,318.9 million compared with $1,203.3 million for the year ended October 31, 2001. Two factors that impacted produced coal revenue for 2002 compared to 2001 were:

•

the volume of produced tons sold decreased 4% to 42.1 million tons in 2002 from 43.7 million tons in 2001, attributable to a reduction in metallurgical and industrial tons sold of 18% and 13%, respectively; and

•

the produced coal revenue per ton sold increased 14% to $31.30 per ton in 2002 from $27.51 per ton in 2001, consisting of 17%, 14%, and 13% increases to the prices for utility, metallurgical and industrial coal, respectively.

Realized prices for our produced tonnage sold in 2002 reflected the improvement seen in the market during 2001, as spot market prices of Central Appalachian coal increased to 20-year highs, and we were able to obtain

sales commitments at relatively higher prices. However, during 2002 the soft economic environment, weak steel demand and the higher stockpiles built by the utilities due to the unusually mild weather that prevailed in the Eastern United States during the winter of 2001-2002 significantly reduced demand for all grades of coal.

Freight and handling revenue decreased 14% to $112 million in 2002 compared with $129.9 million in 2001.

Revenue from purchased coal sales increased $67.6 million, from $49.5 million in 2001 to $117.1 million in 2002. This increase was due to an increase in purchased tons sold, which grew by 2 million tons to 3.3 million in 2002 from 1.3 million in 2001. We purchase varying amounts of coal each year to supplement produced coal.

Other revenue, which consists of royalties, rentals, coal handling facility fees, gas well revenue, synfuel earnings, gains on the sale of non-strategic assets, contract buyout payments, and miscellaneous income, increased to $78.8 million for 2002 from $49.2 million for 2001. The increase was primarily due to 2002 contract buyout payments of $23.5 million from several customers, including $5.1 million from one large customer, as well as increased earnings related to the sale of an interest in, and the operation of, Appalachian Synfuel, LLC. The contract buyout payments in 2002 were a result of several customers negotiating settlement of above market price contracts for 2002 tonnage in lieu of accepting delivery.

Cost of produced coal revenue increased approximately 14% to $1,166.2 million for 2002 from $1,024.7 million for 2001. Cost of produced coal revenue on a per ton of coal sold basis increased by 18% in 2002 compared with 2001. This increase was partially due to a pre-tax charge taken in the second quarter of 2002 in the amount of $25.6 million related to an adverse jury verdict in the West Virginia Harman Mining Corporation lawsuit, as well as a fourth quarter charge of $10.6 million related to an arbitration award in a contract dispute. Additionally, the reduction in tons sold, poor productivity at our longwalls, as well as at some room and pillar and surface mining operations, and higher wage and benefit costs contributed to the increase. During 2001, in response to the market improvement, we increased staffing and benefits costs in order to increase production. However, due to the subsequent market weakness, we reduced total workforce during the first quarter of 2002 by approximately 7% and idled 15 continuous miner sections. Cost of produced coal revenue for 2001 includes pre-tax charges of $7.6 million related to the write-off of longwall panel development costs at the Jerry Fork longwall mine, $6.9 million related to the settlement with the State of West Virginia regarding Worker’s Compensation liabilities incurred by independent contractors, and $2.5 million related to an increase in reserves for a wrongful employee discharge suit. These costs in 2001 were partially offset by a $9.5 million pre-tax refund related to black lung excise taxes paid on coal export sales tonnage. Tons produced in 2002 were 43.9 million compared to 45.1 million in 2001.

Freight and handling costs decreased 14% to $112 million in 2002 compared with $129.9 million in 2001.

Costs of purchased coal revenue increased $72.5 million to $119.6 million in 2002 from $47.1 million in 2001. This was due to the 2 million ton increase in purchased tons sold to 3.3 million in 2002 from 1.3 million in 2001, as well as the higher cost per ton paid for the purchased coal.

Depreciation, depletion and amortization increased by approximately 15% to $207.7 million in 2002 compared to $181.3 million for 2001. The increase of $26.4 million was primarily due to a $13.2 million (pre-tax) write-off of mine development costs at certain idled mines in 2002, as well as increased capital expenditures made in recent years in an effort to increase production.

Selling, general and administrative expenses were $40.1 million for 2002 compared to $31.7 million for 2001. The increase was primarily attributable to increases in accruals related to long-term executive compensation programs and costs of legal services, offset by a reduction in bad debt reserves for a receivable from a large bankrupt customer, Wheeling-Pittsburgh Steel Corporation, which totaled $2.5 million (pre-tax) during the first quarter of 2002.

Other expenses, which consists of costs associated with the generation of other revenue, such as costs to operate the coal handling facilities, gas wells, and other miscellaneous expenses, increased $3.5 million to $11.2 million in 2002 from $7.7 million in 2001.

Interest income decreased to $4.5 million for 2002 compared with $8.8 million for 2001. This decrease was due to $3.2 million (pre-tax) of interest income in 2001 for interest due on the black lung excise tax refund.

Interest expense increased to $35.3 million for 2002 compared with $34.2 million for 2001. The higher interest expense was due to interest of $1.2 million (pre-tax) paid in the fourth quarter of 2002 on the judgment in the Virginia Harman Mining Corporation action after the dismissal of the appeal in the third quarter of 2002.

Income tax benefit was $24.9 million for 2002 compared with income tax benefit of $10.5 million for 2001. The 2002 benefit includes a refund for the settlement of a state tax dispute in the amount of $2.4 million, net of federal tax.

Fiscal Year Ended October 31, 2001 Compared with Fiscal Year Ended October 31, 2000

Produced coal revenue increased 11% to $1,203.3 million in 2001 as compared to $1,081.0 million for the previous year. Two factors that impacted produced coal revenue for 2001 compared to 2000 were:

•

the volume of produced tons sold increased by 9% from 40.2 million tons in 2000 to 43.7 million tons in 2001. This increase consisted of a 17% increase in utility tons sold and a 19% increase in industrial tons sold, offset in part by a decrease of 8% in metallurgical tons sold; and

•

the produced coal revenue per ton sold increased by 2% from $26.86 in 2000 to $27.51 in 2001.

The market for utility coal continued to improve during the fiscal year 2001 as spot market prices of Central Appalachian coal increased to 20-year highs. Unfortunately, most of our tonnage sold in 2001 was committed prior to the upturn in the market.

Freight and handling revenue decreased $1.4 million to $129.9 million in 2001 compared with $131.3 million in 2000.

Revenue from purchased coal sales increased 25% to $49.5 million in 2001 from $39.6 million in 2000, due to an increase in spot prices for coal, as purchased tons sold were 1.3 million in 2001 and 2000. We purchase varying amounts of coal each year to supplement produced coal.

Other revenue, which consists of royalties, rentals, miscellaneous income and gains on the sale of non-strategic assets, decreased 19% to $49.2 million for 2001 compared with $60.8 million for 2000. The decrease was primarily due to a decrease in income from dispositions of non-strategic mineral reserves, which generated $26.5 million in 2000 compared to $1.1 million in 2001. As part of our management of coal reserves, we regularly sell non-strategic reserves or exchange them for reserves located in more synergistic locations. In 2000, we sold certain non-strategic coal reserves (“Scarlet/Duncan Fork reserves”) with a net book value of $1.9 million. We received $32 million in consideration in the form of cash. A gain of $26.5 million was recognized in 2000, as $3.6 million was deferred due to a leaseback option of a portion of the reserves sold. In 1999, we sold certain non-strategic coal reserves (“Dials Branch reserves”) with a net book value of $1.8 million. We received consideration in the amount of $10.7 million. The consideration was comprised of a note receivable in the amount of $11.0 million for guaranteed deferred royalty payments through 2008, less $0.3 million of assumed liabilities. The Dials Branch reserves sale resulted in a gain of $8.9 million being recognized in 1999. We recognized an additional $1.3 million of gains in 1999 from several smaller asset sales.

Cost of produced coal revenue increased 23% to $1,024.7 million for 2001 from $833.9 million in 2000. This was partially due to the increase in tons sold. Cost of produced coal revenue on a per ton sold basis increased by 13% for the fiscal year 2001 compared with 2000. This increase in cost was related to both the direct cost of labor and the decreases in productivity resulting from a greater percentage of inexperienced miners. This was due, in part, to our efforts to increase production. In addition, heavy rains in southern West Virginia in July increased employee absenteeism and disrupted loading operations and rail service, slowing coal shipping.

Other operational problems impacted production and costs throughout the fiscal year. Operating difficulties and problematic geologic conditions were encountered at several longwall mines and during the expansion of our two large surface mines, where we experienced higher than expected overburden ratios in the first half of the year. The Ellis Eagle longwall mine experienced flooding that caused significant disruption to coal production during April and May. The flooding caused reduced shipments from both the Marfork and Goals preparation plants. Increases in operating costs related to the Martin County Coal slurry spill and the idling of the Martin County Coal preparation plant from October 11, 2000, to April 2, 2001, also negatively impacted cost of sales.

Cost of produced coal revenue for 2001 and 2000 includes credits of $9.5 million and $15.0 million, respectively, related to refunds of black lung excise taxes paid on coal export sales tonnage. Black lung excise taxes on exported coal were determined to be unconstitutional by a 1998 federal district court decision. During 2001, the Internal Revenue Service substantially completed its audit of our requested refund of black lung excise tax payments. Cost of produced coal revenue for 2001 also includes pre-tax charges of $7.6 million related to the write-off of longwall panel development costs at the Jerry Fork longwall mine, $6.9 million related to the settlement with the State of West Virginia regarding Worker’s Compensation liabilities incurred by independent contractors, and $2.5 million related to an increase in reserves for a wrongful employee discharge suit. These costs in 2001 were partially offset by a $4.1 million benefit arising from the settlement of insurance claims from the August 2000 Upper Cedar Grove longwall failure.

Freight and handling costs decreased $1.4 million to $129.9 million in 2001 compared with $131.3 million in 2000.

Costs of purchased coal revenue increased 21% to $47.1 million in 2001 from $38.9 million in 2000. This was due to the increase in spot prices for coal, as purchased tons sold were 1.3 million in 2001 and 2000. We purchase varying amounts of coal each year to supplement produced coal.

Depreciation, depletion and amortization increased to $181.3 million for 2001 from $171.3 million in 2000. The increase of $10 million was primarily due to the level of capital expenditures in recent years.

Selling, general and administrative expenses decreased 10% to $31.7 million for 2001 compared with $35.3 million for 2000. This was due in part to a $7.1 million bad debt expense in 2000 associated with the bankruptcy of a major steel industry customer as well as a reduction in accruals related to long-term executive compensation plans, partially offset by additions to the administrative workforce associated with running a stand-alone publicly traded company.

Other expenses, which consists of costs associated with the generation of other revenue, such as costs to operate the coal handling facilities, gas wells, and other miscellaneous expenses, increased $2.2 million to $7.7 million in 2001 from $5.5 million in 2000.

Interest income decreased to $8.8 million for 2001 compared to $25.7 million for 2000. This decrease was primarily due to the elimination of our loans with Fluor Corporation in connection with the spin-off transaction on November 30, 2000. Additionally, in the second quarter of 2001, $3.2 million was accrued for interest due on the black lung excise tax refund as noted above, while in the third fiscal quarter of 2000, $5.3 million was accrued for interest on the black lung excise tax refund.

Interest expense increased to $34.2 million for 2001. The increase was due to the addition of the 6.95% Senior Notes due 2007 and commercial paper borrowings subsequent to the spin-off.

Income tax benefit was $10.5 million for 2001 compared to an income tax expense of $43.3 million for 2000. This primarily reflects the loss before taxes for 2001 compared to income before taxes for 2000, as well as a depletion accounting income tax benefit of $4.5 million in 2001.

Critical Accounting Estimates and Assumptions

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported amounts. These

estimates and assumptions are based on information available as of the date of the financial statements. Accounting measurements at interim dates inherently involve greater reliance on estimates than at year-end. The results of operations for the quarterly period ended March 31, 2003 are not necessarily indicative of results that can be expected for the full year. The following critical accounting estimates and assumptions used in the preparation of the financial statements are materially impacted by estimates and assumptions:

Defined Benefit Pension

We have noncontributory defined benefit pension plans, which cover substantially all of our administrative and non-union employees. Benefits are generally based on the employee’s years of service and compensation, or under a cash balance formula with contribution credits based on hours worked. Funding for the plan is generally at the minimum annual contribution level required by applicable regulations. We account for our defined benefit plans in accordance with Statement of Financial Accounting Standard No. 87, “Employer’s Accounting for Pensions” (“Statement 87”), which requires amounts recognized in the financial statements to be determined on an actuarial basis. The estimated cost and benefits of our non-contributory defined benefit pension plans are determined by independent actuaries, who, with our input, use various actuarial assumptions, including discount rate, future rate of increase in compensation levels and expected long-term rate of return on pension plan assets. The discount rate is determined each year at the measurement date. In estimating the discount rate, we look to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. At December 31, 2002, the discount rate was determined to be 6.75% compared to the discount rate at October 31, 2001 of 7.25%. The rate of increase in compensation levels is determined based upon our long-term plans for such increases. The rate of increase in compensation levels was determined to be 4% at December 31, 2002, and October 31, 2001. Expected long-term rate of return on plan assets is based on long-term historical return information for the mix of investments that comprise plan assets and future estimates of long-term investment returns. The expected long-term rate of return on plan assets used to determine expense in each period was 9.0% and 9.5% for the years ended December 31, 2002 and October 31, 2001, respectively. We expect to adjust the expected long-term rate of return on plan assets to 8.5% for determination of 2003 expense. Significant changes to these rates introduce substantial volatility to our costs. The fair value of the defined benefit pension plan assets is an important factor in the determination of defined benefit pension expense. The fair value of plan assets at December 31, 2002 was $174 million compared to $196 million at October 31, 2001, a reduction of $22 million. As a result of the decrease in discount rate, the reduction in expected long-term rate of return on plan assets, and the decline in defined benefit pension plan assets during 2002, costs for the defined benefit pension plans are expected to increase in 2003 compared to 2002 related expense.

Coal Workers’ Pneumoconiosis

We are responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, and various states’ statutes, for the payment of medical and disability benefits to eligible recipients resulting from occurrences of coal workers’ pneumoconiosis disease (black lung). After review and consultation with us, an annual evaluation is prepared by our independent actuaries based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and interest rates. We record expense related to this obligation using the service cost method. The discount rate is determined each year at the measurement date. At December 31, 2002, the discount rate was determined to be 6.75% compared to the discount rate at October 31, 2001 of 7.25%. Significant changes to these interest rates introduce substantial volatility to our costs. In January 2001, the United States Department of Labor amended the regulations implementing the federal black lung laws to give greater weight to the opinion of a claimant’s treating physician, expand the definition of black lung disease and limit the amount of medical evidence that can be submitted by claimants and respondents. The amendments also alter administrative procedures for the adjudication of claims, which according to the Department of Labor, results in streamlined procedures that are less formal, less adversarial and easier for participants to understand. These and other changes to the federal black lung regulations could result in changes in assumptions used in our actuarial determination of the liability, including interest, disability and mortality assumptions. These changes could significantly increase our exposure to black lung benefits liabilities.

Workers’ Compensation

Workers’ compensation is a system by which individuals who sustain physical or mental injuries due to their jobs are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation, and by which the survivors of workers who are killed receive compensation for lost financial support. The workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. Our operations are covered by a combination of either a self-insurance program, as a participant in a state run program, or by an insurance policy. We accrue for the self-insured liability by recognizing cost when it is probable that the liability has been incurred and the cost can be reasonably estimated. To assist in the determination of this estimated liability we utilize the services of third party administrators. These third parties provide information to independent actuaries, who after review and consultation with us with regards to actuarial rate assumptions, including discount rate, prepare an evaluation of the self-insured program liabilities. Actual losses could differ from these estimates, which could increase our costs.

Other Post Employment Benefits

Our sponsored defined benefit health care plans provide retiree health benefits to eligible union and non-union retirees who have met certain age and service requirements. Depending on year of retirement, benefits may be subject to annual deductibles, coinsurance requirements, lifetime limits, and retiree contributions. These plans are not funded. Costs are paid as incurred by participants. The estimated cost and benefits of our retiree health care plans are determined by independent actuaries, who, with our input, use various actuarial assumptions, including discount rate, expected trend in health care costs and per capita costs. The discount rate is determined each year at the measurement date. The discount rate is an estimate of the current interest rate at which the other post employment benefit liabilities could be effectively settled at the measurement date. In estimating this rate, we look to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. At December 31, 2002, the discount rate was determined to be 6.75% compared to the discount rate at October 31, 2001 of 7.25%. Significant changes to these interest rates introduce substantial volatility to our costs. At December 31, 2002 our assumptions of our company health care cost trend were projected at an annual rate of 11.0% ranging down to 5.0% by 2009, and remaining level thereafter, compared to the health care cost trend rate of 8.0% ranging down to 5.0% by 2007 used at December 31, 2001. If the actual increase in the cost of medical services or other post retirements benefits are significantly greater or less than the projected trend rates, the cost assumptions would need to be adjusted which could have a significant effect on the costs and liabilities recognized in the financial statements. As a result of the reduction in discount rate discussed above and the increase in health care cost trend rate, absent any plan changes, costs for the retiree health benefits plans are expected to increase in 2003 compared to 2002 related expense.

Reclamation and Mine Closure Obligations

The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by our management and engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. We adopted Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”) effective January 1, 2003. Statement 143 requires that retirement obligations be recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows. In estimating future cash flows, we considered the estimated current cost of reclamation and applied inflation rates and a third party profit, as necessary. The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on behalf of our company. The resulting estimated liability could change significantly if actual amounts change significantly from our assumptions.

Contingencies

We are the subject of, or a party to, various suits and pending or threatened litigation involving governmental agencies or private interests. We have accrued the probable and reasonably estimable costs for the resolution of these claims based upon management’s best estimate of potential results, assuming a combination of litigation and settlement strategies. Unless otherwise noted, management does not believe that the outcome or timing of current legal or environmental matters will have a material impact to its results of operations, financial position or cash flows. Also, our operations are affected by federal, state and local laws and regulations regarding environmental matters and other aspects of our business. The impact, if any, of pending legislation or regulatory developments on future operations is not currently estimable.

Deferred Taxes

We account for income taxes in accordance with Statement of Financial Accounting Standard No. 109, “Accounting for Income Taxes” (“Statement 109”) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Statement 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2002, we had deferred tax liabilities in excess of deferred tax assets of approximately $231 million. The deferred tax assets are evaluated annually to determine if a valuation allowance is necessary. As of December 31, 2002, we had recorded a valuation allowance of approximately $86 million, primarily related to alternative minimum tax credits. At December 31, 2002, we believe that it is more likely than not that the net balance of deferred tax assets will be realized.

Coal Reserve Values

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves. Many of these uncertainties are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our staff. Some of the factors and assumptions that impact economically recoverable reserve estimates include:

•

geological conditions;

•

historical production from the area compared with production from other producing areas;

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the assumed effects of regulations and taxes by governmental agencies;

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assumptions governing future prices; and

•

future operating costs.

Each of these factors may in fact vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material.

Capitalized Development Costs

Development costs applicable to the opening of new coal mines and certain mine expansion projects are capitalized and reported in property, plant and equipment. Pursuant to Statement of Financial Accounting Standard No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“Statement 144”), the continuing economic viability of capitalized development costs are assessed when the indicators of impairment exist. This assessment includes a consideration of the future operating cashflows as measured using various potential operating plans and market assumptions of future coal demand and prices.

Liquidity and Capital Resources

At March 31, 2003, our available liquidity was $118.3 million, including cash and cash equivalents of $4.4 million and $113.9 million availability under our revolving credit facilities. We had $263.7 million outstanding under our primary credit facilities, which is included in short-term debt. The total debt-to-book capitalization ratio was 42.8% at March 31, 2003.

On November 26, 2002, we and our lenders concluded the extension and amendment of the $150 million 364-day and $250 million multi-year revolving credit facilities, which have been guaranteed by our subsidiary A.T. Massey Coal Company, Inc. and its subsidiaries, that serve as the primary source of our short-term liquidity. The credit facilities now provide the lenders with selected assets as collateral for borrowings under the facilities. The selected assets that are collateral for the credit facilities include all capital stock of our subsidiaries and substantially all of our assets, now owned or at any time hereafter acquired by us, excluding among other things, all coal, oil and gas reserves and mining permits, certain properties (e.g., the Eastman Chemical Company Coal Handling System and Westvaco Coal Handling Facility, and the value of properties that might exceed the lien threshold established in the indenture related to the Senior Notes discussed below) and certain other assets associated with our accounts receivable securitization program discussed below. Both facilities have been renewed through November 25, 2003. We intend to replace these credit facilities prior to their expiration on November 25, 2003, and have already launched refinancing syndication efforts with a number of banks and financial institutions. Borrowings under these facilities bear interest based on (1) the London Interbank Offer Rate (LIBOR) or (2) the Base Rate (as defined in the credit facility agreements) plus a margin, which is based on our senior secured debt credit rating as determined by Moody’s and S&P. Currently, our senior secured debt ratings determined by Moody’s and S&P are Ba1 and BB+, respectively.

The revolving credit facilities contain financial covenants requiring that we maintain various financial ratios. Our failure to comply with these covenants could result in an event of default, which if not cured or waived could have a material adverse effect on our company. The financial covenants consist of a maximum leverage ratio, a minimum interest coverage ratio, and a minimum net worth test. The leverage ratio requires that we not permit the ratio of total indebtedness at the end of any quarter to consolidated EBITDA (as defined in the credit facility agreements) for the four quarters then ended to exceed a specific amount. The interest coverage ratio requires that we not permit the ratio of our consolidated EBITDA to interest expense for the four quarters then ended to be less than a specified amount. The net worth test requires that we not permit our net worth to be less than a specified amount. We were in compliance with all material covenants at March 31, 2003 and during all other periods reflected herein, other than at December 31, 2001 when we were not in compliance with the covenant related to leverage ratio, but for which we subsequently obtained an amendment from our lenders effective March 29, 2002. In the event we violate any of the debt covenants and do not affect a timely cure or receive a waiver from the lenders in the credit facilities, the debt agreements provide that the administrative agent under such agreements shall, if requested by at least four lenders holding at least 50% of the aggregate amount of the loans, declare the loans immediately due and payable.

In determining consolidated EBITDA for use in computing the leverage ratio, we have excluded certain items, including the $25.6 million charge relative to the Harman litigation described in Note 11 of the notes to our condensed consolidated financial statements incorporated by reference in this offering memorandum and the $10.6 million charge relative to the Duke Energy Corporation arbitration award discussed in our Annual Report on Form 10-K/A for the period ended December 31, 2002. We believe that the exclusion of such items is appropriate and have notified the lenders’ administrative agent of this exclusion. If the charges for the Harman litigation and Duke arbitration were to be included in the consolidated EBITDA calculation and no further adjustments were made, we would still be in compliance with the covenant at March 31, 2003. For further detail on the financial covenants, see Section 5.02 of the Amended and Restated Credit Agreement, which was filed as Exhibit 10.1 to our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2002.

On January 31, 2003, we entered into a borrowing program secured by the accounts receivable of several of our subsidiaries. The amount eligible to be borrowed under the program is up to $80 million, depending on the

level of eligible receivables and restrictions on concentrations of receivables. At March 31, 2003, the borrowings outstanding under the program totaled $42.2 million. The program expires in July 2004. The receivables outstanding under this program and the corresponding debt is included as “Trade and other accounts receivable” and “Long-term debt,” respectively, on our condensed consolidated balance sheets. As collections reduce previously pledged interests, new receivables will be pledged. A portion of the cost of the accounts receivable- based financing program is based on the creditors’ level of investment and borrowing costs. The total cost of the program is classified as interest expense on the condensed consolidated statements of income for the period ended March 31, 2003.

We had $325.2 million of long-term debt as of March 31, 2003, which consisted of $283 million of 6.95% Senior Notes due March 1, 2007, and $42.2 million outstanding under the accounts receivable-based financing program. Initially, $300 million of the 6.95% Senior Notes were issued in March 1997 at a discount, for aggregate proceeds of $296.7 million. During the fourth quarter of 2002 and the first quarter of 2003, we made several open-market purchases, retiring a total principal amount of $17.0 million 6.95% Senior Notes at a cost of $13.1 million plus accrued interest. Interest is payable semiannually on March 1 and September 1 of each year, commencing September 1, 1997. The 6.95% Senior Notes are redeemable in whole or in part, at our option at any time at a redemption price equal to the greater of (1) 100 percent of the principal amount of the 6.95% Senior Notes or (2) as determined by a Quotation Agent as defined in the offering prospectus. On November 27, 2002, Moody’s and S&P reduced the credit ratings on the 6.95% Senior Notes to Ba3 and B+, respectively, citing the structural subordination caused by the secured status of the $150 million 364-day and $250 million multi-year revolving credit facilities.

Additionally, we have available a $500 million debt shelf registration filed with the SEC in March 1999, all of which remains unused. An updated filing with the SEC would be required to issue debt under this shelf registration.

Net cash utilized by operating activities was $32.9 million for the first quarter of 2003 compared to net cash provided by operating activities of $21.7 million for the first quarter of 2002. Cash utilized/provided by operating activities reflects net losses adjusted for non-cash charges and changes in working capital requirements.

Net cash utilized by investing activities was $13.0 million and $44.3 million for the first quarters of 2003 and 2002, respectively. The cash used in investing activities reflects capital expenditures in the amount of $17.3 million and $46.1 million for the first quarters of 2003 and 2002, respectively. These capital expenditures are for replacement of mining equipment, the expansion of mining and shipping capacity, and projects to improve the efficiency of mining operations. In addition to the cash spent on capital expenditures, during the first quarter of 2003, we leased, through operating leases, $5.6 million of longwall and surface mining equipment compared to $4.6 million for the first quarter of 2002. Additionally, the first quarters of 2003 and 2002 included $4.2 million and $1.9 million, respectively, of proceeds provided by the sale of assets.

Financing activities primarily reflect changes in short term financing for the first quarter of 2003 and 2002, as well as the exercising of stock options. Net cash provided by financing activities was $47.5 million and $35.0 million for the first quarter of 2003 and 2002, respectively. In addition, net cash provided by financing activities for 2003 includes a net increase of $42.2 million in the receivables-based financing program, which began in January 2003, as well as $11.1 million of proceeds from sale-leaseback transactions.

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements including guarantees, indemnifications, and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in our consolidated balance sheets, and we do not expect any material adverse effects on our financial condition, results of operations or cash flows to result from these off-balance sheet arrangements.

We use surety bonds to secure reclamation, workers’ compensation, wage payments, and other miscellaneous obligations. As of March 31, 2003, we had $260 million of outstanding surety bonds with third parties. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $232 million, workers’ compensation bonds of $10 million, wage payment and collection bonds of $9 million, and other miscellaneous obligation bonds of $9 million. Recently, surety bond costs have increased, while the market terms of surety bonds have generally become less favorable. To the extent that surety bonds become unavailable, we will seek to secure obligations with letters of credit, cash deposits, or other suitable forms of collateral.

From time to time we use bank letters of credit to secure our obligations for worker’s compensation programs, various insurance contracts and other obligations. Issuing banks currently require that such letters of credit be secured by funds deposited into restricted accounts pledged to the banks under reimbursement agreements. At March 31, 2003, we had $46.4 million of letters of credit outstanding, collateralized by $45.4 million of cash deposited in restricted, interest bearing accounts, and no claims were outstanding against those letters of credit.

We believe that cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments and anticipated dividend payments for at least the next several years. Nevertheless, our ability to satisfy our debt service obligations, to fund planned capital expenditures or pay dividends will depend upon our future operating performance, our ability to refinance our short-term debt, and other factors, 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. We frequently evaluate potential acquisitions. In the past, we have funded acquisitions primarily with cash generated from operations, but we may consider a variety of other sources, depending on the size of any transaction, including debt or equity financing. There can be no assurance that such additional capital resources will be available to us on terms that we find acceptable, or at all.

The following is a summary of our significant obligations as of March 31, 2003:

	Payments Due by Years
In Thousands	Total		Within 1 Year		2-3 Years		4-5 Years		After 5 Years
Long-term debt	$	325,175	$	—	$	42,175	$	283,000	$	—
Operating lease obligations		215,465		64,791		115,944		32,030		2,700

Total obligations	$	540,640	$	64,791	$	158,119	$	315,030	$	2,700

Additionally, we have noncurrent liabilities relating to other post-employment benefits, work related injuries and illnesses, and mine reclamation and closure. As of March 31, 2003, payments related to these items are estimated to be:

Payments Due by Years (In thousands)
Within 1 Year	2-3 Years		4-5 Years
$33,068	$	64,289	$	61,100

Our determination of these noncurrent liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Moreover, in particular, for periods after 2003, our estimates may change from the amounts included in the table, and may change significantly, if our assumptions change to reflect changing conditions.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the periods presented.

New Accounting Standards

In December 2002, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation—Transition and Disclosure” (“Statement 148”). Statement 148 amends the disclosure requirements of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” and provides alternative methods for accounting for stock-based compensation. We have adopted the disclosure requirements for the quarter ended March 31, 2003 (see Note 9 of the notes to our condensed consolidated financial statements incorporated by reference in this offering memorandum) and the year ended December 31, 2002.

Market Risk

Our interest expense is sensitive to changes in the general level of interest rates in the United States. At March 31, 2003, we had outstanding $283 million aggregate principal amount of long-term debt under fixed-rate instruments; however, our primary exposure to market risk for changes in interest rates relates to our short-term debt financing and our long-term accounts receivable-based financing program. At March 31, 2003, we had $263.7 million outstanding under the revolving credit facilities and $42.2 million outstanding under the accounts receivable program. At March 31, 2003, the weighted average interest rate under the combined variable-rate facilities was approximately 3.73%. Based on the short-term debt balance outstanding at March 31, 2003, a 100 basis point increase in the average issuance rate for our borrowings would increase our annual interest expense by approximately $3.1 million.

We manage our commodity price risk through the use of long-term coal supply agreements, which are contracts with a term of greater than 12 months, rather than through the use of derivative instruments. For our fiscal year ended December 31, 2002, approximately 94% of our coal sales volume was pursuant to long-term contracts. We anticipate that in 2003, the percentage of sales pursuant to long-term arrangements will be comparable with the percentage of sales for 2002. The prices for coal shipped under long-term contracts may be below the current market price for similar types of coal at any given time. As a consequence of the substantial volume of its sales, which are subject to these long-term agreements, we have less coal available with which to capitalize on stronger coal prices if and when they arise. In addition, because long-term contracts typically allow the customer to elect volume flexibility, our ability to realize the higher prices that may be available in the spot market may be restricted when customers elect to purchase higher volumes under such contracts, or our exposure to market-based pricing may be increased should customers elect to purchase fewer tons.

Almost all of our transactions are denominated in U.S. dollars, and, as a result, we do not have material exposure to currency exchange-rate risks.

We have not engaged in any interest rate, foreign currency exchange rate or commodity price-hedging transactions.

COAL INDUSTRY OVERVIEW

A major contributor to the world energy supply, coal represents approximately 23% of the world’s primary energy consumption, according to the World Coal Institute. The primary use for coal is to fuel electric power generation. In calendar year 2002, it is estimated that coal generated 51% of the electricity produced in the United States, according to the Energy Information Administration, a statistical agency of the United States Department of Energy.

The United States is the second largest coal producer in the world, exceeded only by China. Other leading coal producers include India, South Africa and Australia. The United States is the largest holder of coal reserves in the world, with over 250 years of supply at current production rates. United States coal reserves are more plentiful than oil or natural gas, with coal representing approximately 70% of the nation’s fossil fuel reserves, according to Energy Ventures Analysis. Total coal reserves are estimated by comparing the total probable heat value (British thermal units (“Btus”) per pound) of the demonstrated coal reserve tonnage reported by the Department of Energy to the heat value of other fossil fuel energy resources reported by the Department of Energy.

U.S. coal production has more than doubled during the last 30 years. In 2002, total coal production as estimated by the United States Department of Energy, or the “DOE,” was 1.1 billion tons. The primary producing regions were the Powder River Basin (38%), Central Appalachia (23%), Midwest (14%), Northern Appalachia (12%), West (other than the Powder River Basin) (12%) and other (1%). All of our coal production comes from the Central Appalachian region. Approximately 66% of U.S. coal is produced by surface mining methods. The remaining 34% is produced by underground mining methods that include room and pillar mining and longwall mining discussed under “Business—Mining Methods” below.

Coal is used in the United States by utilities to generate electricity, by steel companies to make products with blast furnaces, and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Significant quantities of coal are also exported from both east and west coast terminals. The breakdown of 2002 United States coal demand, as estimated by Resource Data International, Inc., or “RDI,” is as follows:

End Use	Tons (millions)	% of Total
Electrical generation	982	86	%
Industrial users	66	6	%
Exports	64	6	%
Steel making	27	2	%
Residential & commercial	5	—

Total	1,144	100	%

Coal has long been favored as an electricity generating fuel by regulated utilities because of its basic economic advantage. The largest cost component in electricity generation is fuel. This fuel cost is typically lower for coal than competing fuels such as oil and natural gas on a Btu-comparable basis. RDI estimated the average total production costs of electricity, using coal and competing generation alternatives in 2002 as follows:

Electrical Generation Type	Cost per million Kilowatt Hours
Oil	$	4.854
Natural Gas	$	4.422
Coal	$	1.819
Nuclear	$	1.785
Other (solar, wind, etc.)	$	0.979
Hydroelectric	$	0.527

According to RDI, 15 of the 25 lowest operating cost power plants in the United States during 2001 were fueled by coal. Coal used as fuel to generate electricity is commonly referred to as “steam coal.”

There are factors other than fuel cost that influence each utility’s choice of electricity generation mode, including facility construction cost, access to fuel transportation infrastructure, environmental restrictions, and other factors. The breakdown of U.S. electricity generation by fuel source in 2002, as estimated by the Energy Information Administration, is as follows:

Electricity Generation Source	% of Total Electricity Generation
Coal	51	%
Nuclear	21	%
Natural Gas	17	%
Hydro	6	%
Oil	3	%
Other	2	%

Total	100	%

RDI projects that generators of electricity will increase their demand for coal as demand for electricity increases. Because coal-fired generation is used in most cases to meet base load requirements, coal consumption has generally grown at the pace of electricity demand growth. Demand for electricity has historically grown in proportion to U.S. economic growth.

The United States ranks fifth among worldwide exporters of coal. Australia is the largest exporter, with other major exporters including South Africa, Indonesia, Canada, China, Russia and Colombia. U.S. exports have decreased by over 46% since 1991 as a result of increased international competition and the U.S. dollar’s strength in comparison to foreign currencies. According to the Department of Energy, the usage breakdown for 2000 U.S. exports of 59 million tons was 44% for electricity generation and 56% for steel making. U.S. coal exports were shipped to more than 40 countries. The largest purchaser of exported steam coal was Canada, which took 15 million tons or 58% of total steam coal exports. The largest purchaser of exported metallurgical coal was Europe, which represented 20 million tons or 61% of total metallurgical coal exports. Depending on the relative strength of the U.S. dollar versus currencies in other coal producing regions of the world, we may export more or less coal into foreign countries as we compete on price with other foreign coal producing sources. Additionally, the domestic coal market may be impacted due to the relative strength of the U.S. dollar to other currencies, as foreign sources could be cost advantaged based on a coal producing region’s relative currency position.

The type of coal used in steel making is referred to as metallurgical coal, and is distinguished by special quality characteristics that include high carbon content, low expansion pressure, low sulfur content, and various other chemical attributes. Metallurgical coal is also high in heat content (as measured in Btus), and therefore is desirable to utilities as fuel for electricity generation. Consequently, metallurgical coal producers have the ongoing opportunity to select the market that provides maximum revenue. The premium price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content. The primary concentration of U.S. metallurgical coal reserves is located in the Central Appalachian region. RDI estimates that the Central Appalachian region supplied 88% of domestic metallurgical coal and 96% of U.S. exported metallurgical coal during 2002.

Industrial users of coal typically purchase high Btu products with the same type of quality focus as utility coal buyers. The primary goal is to maximize heat content, with other specifications like ash content, sulfur content, and size varying considerably among different customers. Because most industrial coal consumers use considerably less tonnage than electric generating stations, they typically prefer to purchase coal that is screened and sized to specifications that streamline coal handling processes. Due to the more stringent size and quality specifications, industrial customers often pay a 10% to 15% premium above utility coal pricing (on comparable

quality). The largest regional supplier to the industrial market sector has historically been Central Appalachia, which supplied approximately 35% of all U.S. industrial coal demand in 2002.

Coal shipped for North American consumption is typically sold at the mine loading facility with transportation costs being borne by the purchaser. Offshore export shipments are normally sold at the ship-loading terminal, with the purchaser paying the ocean freight. According to the National Mining Association, approximately two-thirds of U.S. coal production is shipped via railroads. Final delivery to consumers often involves more than one transportation mode. A significant portion of U.S. production is delivered to customers via barges on the inland waterway system and ships loaded at Great Lakes ports.

Neither Massey Energy nor any of our subsidiaries is affiliated with or has any investment in the World Coal Institute, RDI, the Energy Information Administration or Energy Ventures Analysis.

BUSINESS

We are one of the largest coal companies in the United States and the largest in the Central Appalachian coal region. We produce, process and sell high quality, low sulfur coal of steam and metallurgical grades through our 19 processing and shipping centers, called “resource groups.” These resource groups support our 29 underground mines and 14 surface mines in West Virginia, Kentucky and Virginia. Based on current production levels, our approximately 2.2 billion tons of proven and probable coal reserves should last for more than 50 years. Steam coal, which accounts for approximately 65% of our produced coal sales volume, is primarily purchased by public utilities as fuel for electricity generation. Approximately 9% of our produced coal sales volume is generated by sales to industrial customers that use coal with certain quality characteristics for generation of electricity or for process steam. Metallurgical coal, which accounts for approximately 26% of our produced coal sales volume, is used primarily to make coke for use in the manufacturing of steel and can also be marketed as an ultra high quality, low sulfur steam coal for electricity generation. Metallurgical coal generally sells at a premium over steam coal because of its unique quality characteristics. During our fiscal year ended December 31, 2002, we sold 42.1 million tons of coal, generating produced coal revenues of $1.3 billion, loss from operations of $26.7 million and EBITDA of $181.0 million. For an explanation of EBITDA, please see footnote 2 in “Selected Consolidated Financial and Operating Data.”

Competitive Strengths

We believe that our competitive strengths will enable us to enhance our position as one of the premier coal producers in the United States.

We are the leading coal producer in Central Appalachia. We are the leading coal producer in the Central Appalachian region with a proven reputation as a skilled, long-term operator. Our leading position in Central Appalachia is an advantage with customers, who look for a reliable supplier, and with property owners, who seek to lease their land to operators likely to develop production from the reserves and generate royalty income. We believe that we benefit from concentrating our coal mining activities in Central Appalachia. This regional focus leads to operating efficiencies and provides us with an in-depth knowledge of the area’s coal reserves, mining conditions, customers, property owners and employee base. In addition, our mining operations are located in close proximity to many of our customers and on or near rail transportation, which we believe gives us a transportation cost advantage.

We have a large, high quality, diverse reserve base. We control approximately 2.2 billion tons of proven and probable coal reserves. Our reserves include both high quality, low sulfur steam coal desired by public utility and industrial customers, and metallurgical coal demanded by steel manufacturers. Metallurgical coal sales to steel customers have always been an important niche for us, but this coal can also be marketed as ultra high quality, low sulfur steam coal for electrical generation. Our diverse reserve base and flexible product line allows us to adjust to changing market conditions and sustain high sales volume by supplying a wide range of customers. Approximately 44% of our coal reserves are made up of compliance coal that complies with the low sulfur requirements of the Clean Air Act. Compliance coal is critically important to utility customers seeking to reduce emissions and lower their costs of compliance with the Clean Air Act.

We have a low level of long-term liabilities. We had pension trust assets with a fair market value of $174 million at December 31, 2002, which were in excess of plan liabilities of $169 million despite three years of poor market returns. We have not had to fund our defined benefit pension plan and do not expect to do so under the current law until 2006 at the earliest. Our healthcare benefit liability (OPEB) of $121 million at December 31, 2002 was significantly lower than that of our coal industry peers. Our employee related legacy liabilities are significantly lower than those of our coal industry peers, partially due to our minimal union membership (96% of our workforce is union-free).

We have strong, long-term relationships with a broad base of customers. We have strong relationships with a broad base of over 125 customers. The majority of these customers purchase coal under long-term contracts with terms of one year or longer. Approximately 94% of our produced coal sales volume in 2002 was derived from these long-term contracts. We believe that a similar amount of our produced coal sales volume in 2003 will be derived from these long-term contracts. We believe these contracts provide us with stable and predictable cash flow and limit our exposure to fluctuations in the spot market prices for coal. Many of our customers are well-established public utilities who have been customers of ours for a number of years.

We have built a superior infrastructure and transportation system. Since 1998, we have expended over $1.0 billion to maintain, upgrade and expand our mining, processing and transporting capabilities. These projects include investments in new mining equipment, expansion of processing plant capacity and development of systems to reduce our reliance on trucking, the most expensive transportation method, including the construction of conveyor belt systems and investments in our train loading facilities. We believe these capital investments provide us with the necessary infrastructure to expand our production capacity with little or no additional investment to meet increases in demand for coal.

We have demonstrated our ability to grow our coal reserves and production through acquisitions and other strategic transactions. We have grown our reserve base and production capacity through the strategic acquisition and integration of several coal operations as well as through reserve swaps and coal leases. Our reserve base has grown from approximately 720 million tons in 1987 to approximately 2.2 billion tons today, and our annual production has grown from approximately 13 million tons to approximately 44 million tons during the same period. We have utilized a disciplined acquisition strategy that has helped us to avoid the difficulties often associated with the integration of acquisitions. We make selective purchases of mines and reserves that are close to our existing operations. This allows us to use our existing infrastructure as new operations are developed.

Strategy

Our primary objective is to continue to build upon our competitive strengths to enhance our position as one of the premier coal producers in the United States by:

Enhancing profitability through continued safety improvements, productivity gains and cost measurement. We will seek to reduce operating costs and increase profitability at our mines through our safety, productivity and measurement initiatives. We continue to implement safety measures designed to improve our profitability by lowering worker compensation costs and reducing job inefficiencies. In addition, we seek to enhance productivity by applying best practices, including optimizing mining sequences, staffing levels and equipment configuration, at each of our operations. We also manage costs by generating critical data in a timely manner to measure performance, cost and usage in our mining operations and communicating that data to managers who can identify and correct problems.

Adjusting production in response to changes in market conditions. We are committed to a strategy of aligning our production with the needs of the market. The capital investments we have made during the past five years position us to quickly expand production to meet increases in demand for coal. Our goal is to maximize profits not volume; therefore, our strategy is to only sell our coal at prices that generate the appropriate level of profitability.

Expanding use of more productive mining methods. Currently, we engage in four principal coal mining techniques: underground “room and pillar” mining, underground longwall mining, highwall mining and surface mining. Each method is employed where appropriate throughout our operations. Because underground longwall mining, highwall mining and surface mining are high-productivity, low-cost mining methods, we will seek to increase production from our use of those methods to the extent permissible and cost-effective. From 1996 to 2002, underground longwall mining increased from 5% to 16% of our production, highwall mining increased from 0% to 10% of our production and surface mining increased from 14% to 35% of our production.

Pursuing strategic acquisitions. We believe that the coal industry will undergo increasing consolidation over the coming years. We plan to build on our position as the largest producer in Central Appalachia by pursuing growth through the acquisition of additional coal reserves and mining facilities. Our acquisition strategy has been highly selective. We intend to continue to expand our business through this focused growth strategy, as well as consider other possible growth opportunities in future years.

Forming strategic contractual arrangements with major customers. We will continue to seek contractual arrangements with customers to provide services in addition to coal. For example, we have coal handling facility agreements with two customers. We will continue to work closely with our customers to develop opportunities for contractual arrangements in order to benefit both our customers and us. These initiatives strengthen our relationships with our customers and provide opportunities to increase sales.

Mining Operations

We currently have 19 distinct resource groups, including 14 in West Virginia, four in Kentucky and one in Virginia. These resource groups receive, blend, process and ship coal that is produced from one or more mines, using four distinct mining methods: underground room and pillar, underground longwall, highwall mining and surface mining. A single complex may handle the coal production of as many as eight distinct underground or surface mines. Within each resource group, mines have been developed at strategic locations in close proximity to our preparation plants and rail shipping facilities. Coal is transported from our resource groups to customers by means of railroad cars or trucks.

Mining Methods

We produce coal using four distinct mining methods: underground room and pillar, underground longwall, surface and highwall mining, which are explained as follows:

In the underground room and pillar method of mining, continuous mining machines cut three to nine entries into the coal bed and connect them by driving crosscuts, leaving a series of rectangular pillars, or columns of coal, to help support the mine roof and control the flow of air. Generally, openings are driven 20 feet wide and the pillars are 40 to 100 feet wide. As mining advances, a grid-like pattern of entries and pillars is formed. When mining advances to the end of a panel, retreat mining may begin. In retreat mining, as much coal as is feasible is mined from the pillars that were created in advancing the panel, allowing the roof to cave. When retreat mining is completed to the mouth of the panel, the mined panel is abandoned.

In longwall mining, a shearer (cutting head) moves back and forth across a panel of coal typically about 1000 feet in width, cutting a slice 3.5 feet deep. The cut coal falls onto a flexible conveyor for removal. Longwall mining is performed under hydraulic roof supports (shields) that are advanced as the seam is cut. The roof in the mined out areas falls as the shields advance.

Surface mining is used when coal is found close to the surface. This method involves the removal of overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, loading out the coal, replacing the overburden and topsoil after the coal has been excavated and reestablishing vegetation and plant life and making other improvements that have local community benefit.

Highwall mining is used in connection with surface mining. A highwall mining system consists of a remotely controlled continuous mining machine, which extracts coal and conveys it via augers or belt conveyors to the surface. The cut is typically a rectangular, horizontal opening in the highwall (the unexcavated face of exposed overburden and coal in a surface mine) 11-feet wide and reaching depths of up to 1000 feet. Multiple, parallel openings are driven into the highwall, separated by narrow pillars that extend the full depth of the hole.

Use of continuous mining machines in the room and pillar method of underground mining represented approximately 39% of our 2002 coal production.

Production from underground longwall mining operations constituted about 16% of our 2002 production. We now operate four longwall units.

Surface mining represented approximately 35% of our 2002 coal production. We have established large-scale surface mines in Boone and Nicholas counties of West Virginia. Our other surface mines are smaller in scale. Our surface mines also use highwall mining systems to produce coal from high overburden areas. Highwall mining represented approximately 10% of our 2002 coal production.

Coal Reserves

We estimate that, as of December 31, 2002, we had total recoverable reserves of approximately 2.2 billion tons consisting of both proven and probable reserves. “Reserves” are defined by SEC Industry Guide 7 as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves means coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. Approximately 1.5 billion tons of our reserves are classified as proven reserves. “Proven (Measured) Reserves” are defined by SEC Industry Guide 7 as reserves for which (1) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (2) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. The remaining 0.7 billion tons of our reserves are classified as probable reserves. “Probable reserves” are defined by SEC Industry Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by its internal engineers, geologists and finance associates. Reserve estimates are updated annually using geologic data taken from drill holes, adjacent mine workings, outcrop prospect openings and other sources. Coal tonnages are categorized according to coal quality, seam thickness, mineability and location relative to existing mines and infrastructure. In accordance with applicable industry standards, proven reserves are those for which reliable data points are spaced no more than 2,700 feet apart. Probable reserves are those for which reliable data points are spaced 2,700 feet to 7,900 feet apart. Further scrutiny is applied using geological criteria and other factors related to profitable extraction of the coal. These criteria include seam height, roof and floor conditions, yield and marketability.

As with most coal-producing companies in Central Appalachia, the majority of our coal reserves are controlled pursuant to leases from third party landowners. These leases convey mining rights to the coal producer in exchange for a per ton or percentage of gross sales price royalty payment to the lessor. However, a significant portion of our reserve holdings are owned and require no royalty or per ton payment to other parties. The average royalties for coal reserves from our producing properties (owned and leased) was approximately 4.2% of produced coal revenue for the year ended December 31, 2002.

The following table provides proven and probable reserve data by “status” (i.e., location, owned or leased, assigned or unassigned, etc.) as of December 31, 2002:

Recoverable Reserves

	Location	Total	Proven	Probable	Assigned⁽²⁾	Unassigned	Owned	Leased
	(in thousands of tons)⁽¹⁾
Resource Groups:
West Virginia
Delbarton	Mingo County	310,332	139,036	171,297	155,343	154,989	10,394	299,938
Black Castle	Boone County	53,214	37,817	15,397	35,899	17,315	—	53,214
Eagle Energy	Boone County	—	—	—	—	—	—	—
Elk Run	Boone County	78,148	39,083	39,064	64,975	13,173	6,233	71,914
Green Valley	Nicholas County	9,117	9,117	—	8,197	920	—	9,117
Independence	Boone County	58,994	57,662	1,331	54,084	4,910	6,344	52,649
Logan County	Logan County	89,457	89,457	—	45,871	43,586	—	89,457
Marfork	Raleigh County	73,221	72,713	508	40,214	33,006	551	72,670
Nicholas Energy	Nicholas County	108,107	98,197	9,910	66,116	41,991	67,487	40,620
Omar	Boone County	35,946	16,400	19,546	—	35,946	2,229	33,717
Performance	Raleigh County	38,192	38,192	—	37,446	746	38,192	—
Progress	Boone County	92,748	83,862	8,885	92,748	—	30,914	61,834
Rawl	Mingo County	113,460	82,742	30,718	64,994	48,466	1,420	112,040
Stirrat	Logan County	5,482	3,595	1,886	422	5,060	—	5,482

Kentucky
Long Fork	Pike County	5,616	3,273	2,343	610	5,006	—	5,616
Martin County	Martin County	46,752	22,854	23,899	9,146	37,606	1,589	45,163
New Ridge	Pike County	—	—	—	—	—	—	—
Sidney	Pike County	162,703	105,679	57,024	135,390	27,313	8,771	153,932

Virginia
Knox Creek	Tazewell Co.	54,333	39,913	14,420	34,509	19,824	—	54,333

Other	N/A	91,683	45,149	46,534	25,187	66,495	25,904	65,779

Subtotal		1,427,505	984,741	442,762	871,151	556,352	200,028	1,227,475

Land Management Companies:⁽³⁾
Black King	Boone Co., WV Raleigh, WV	60,764	60,764		395	60,368	23,037	37,727
Boone East	Boone Co., WV Kanawha, WV	212,483	173,639	38,845	89,682	122,802	93,755	118,728
Boone West	Boone Co., WV Logan Co., WV	258,397	100,924	157,473	10,595	247,802	67,128	191,269
Ceres Land	Raleigh, WV	12,397	10,142	2,255	—	12,397	—	12,397
Lauren Land	Mingo Co., WV Logan Co., WV	142,640	94,383	48,257	11,447	131,194	20,360	122,281
New Market	Wyoming, WV	60,202	23,708	36,494	—	60,202	6,030	54,172
Raven Resources	Boone Co., WV Raleigh, WV	31,890	21,893	9,997	—	31,890	—	31,890

Subtotal		778,773	485,453	293,321	112,119	666,655	210,310	568,464

Total		2,206,278	1,470,194	736,083	983,270	1,223,007	410,338	1,795,939

(1)

Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present on our delivered coal.

(2)

Assigned Reserves represent recoverable reserves that are dedicated to a specific permitted mine. Otherwise, the reserves are considered Unassigned.

(3)

Land management companies are our subsidiaries whose primary purposes are to acquire and hold our reserves.

The categorization of the “quality” (i.e., sulfur content, Btu, coal type, etc.) of our coal reserves is as follows:

Recoverable Reserves

	Recoverable Reserves	Sulfur content			Average Btu as received	Coal Type⁽³⁾
	Recoverable Reserves	+1%	-1%	Compliance⁽²⁾	Average Btu as received	Coal Type⁽³⁾
	(in thousands of tons except Average Btu as received)⁽¹⁾
Resource Groups:
West Virginia
Delbarton	310,332	119,784	190,549	138,830	13,476	Low Sulfur Utility Low Sulfur Industrial
Black Castle	53,214	8,454	44,760	37,819	12,552	High Vol Met Low Sulfur Utility Low Sulfur Industrial
Eagle Energy	—	—	—	—	—	N/A

Elk Run	78,148	16,526	61,622	51,704	13,210	High Vol Met Low Sulfur Utility Low Sulfur Industrial
Green Valley	9,117	—	9,117	9,117	12,903	High Vol Met Low Sulfur Utility Low Sulfur Industrial
Independence	58,994	7,455	51,539	8,801	13,011	High Vol Met Low Sulfur Utility Low Sulfur Industrial
Logan County	89,457	18,492	70,965	51,240	12,889	Low Sulfur Utility Low Sulfur Industrial
Marfork	73,221	33,803	39,418	17,064	13,602	High Vol Met Low Sulfur Utility Low Sulfur Industrial
Nicholas Energy	108,107	50,991	57,116	28,387	12,579	High Vol Met Low Sulfur Utility Low Sulfur Industrial
Omar	35,946	16,045	19,901	444	12,937	Low Sulfur Utility Low Sulfur Industrial
Performance	38,192	5,188	33,004	19,792	13,752	High Vol Met

Progress	92,748	11,460	81,287	60,309	11,880	Low Sulfur Utility Low Sulfur Industrial
Rawl	113,460	36,870	76,589	53,876	12,784	High Vol Met Low Sulfur Utility Low Sulfur Industrial
Stirrat	5,482	—	5,482	5,482	13,087	High Vol Met Low Sulfur Utility Low Sulfur Industrial

Kentucky
Long Fork	5,616	3,728	1,888	—	12,809	Low Sulfur Utility Low Sulfur Industrial
Martin County	46,752	35,888	10,864	3,515	12,724	Low Sulfur Utility Low Sulfur Industrial
New Ridge	—	—	—	—	—	N/A

Sidney	162,703	63,165	99,538	63,639	13,170	Low Sulfur Utility Low Sulfur Industrial High Vol Met

Virginia
Knox Creek	54,333	—	54,333	54,333	13,351	High Vol Met Low Sulfur Utility Low Sulfur Industrial
Other	91,683	27,433	64,249	58,000	12,999	Various

Subtotal	1,427,505	455,282	972,221	662,352

	Recoverable Reserves	Sulfur content			Average Btu as received
	Recoverable Reserves	+1%	-1%	Compliance⁽²⁾	Average Btu as received	Coal Type⁽³⁾
	(in thousands of tons except Average Btu as received)⁽¹⁾
Land Management Companies:⁽⁴⁾
Black King	60,764	37,821	22,942	19,730	12,365	High Vol Met Low Sulfur Utility
Boone East	212,483	37,299	175,184	60,831	13,202	High Vol Met Low Sulfur Utility Low Vol Met
Boone West	258,397	137,300	121,097	81,277	13,047	High Vol Met Low Sulfur Utility
Ceres Land	12,397	3,807	8,589	8,589	13,730	High Vol Met Low Sulfur Utility
Lauren Land	142,640	45,123	97,517	79,772	13,137	High Vol Met Low Sulfur Utility
New Market Land	60,202	5,046	55,156	55,156	14,423	Low Vol Met High Vol Met
Raven Resources	31,890	18,483	13,407	4,069	13,683	High Vol Met

Subtotal	778,773	284,879	493,892	309,424

Total	2,206,278	740,161	1,466,113	971,776

(1)	Reserve information reflects a moisture factor of 6.5%. This moisture factor represents the average moisture present on the Company’s delivered coal.

(2)	Compliance coal is any coal that emits less than 1.2 pounds of sulfur dioxide per million Btu when burned. Compliance coal meets sulfur emission standards imposed by Title IV of the Clean Air Act.

(3)	Reserve holdings include metallurgical coal reserves. Although these metallurgical coal reserves receive the highest selling price in the current coal market when marketed to steel-making customers, they can also be marketed as an ultra high Btu, low sulfur steam coal for electricity generation.

(4)	Land management companies are our subsidiaries whose primary purposes are to acquire and hold our reserves.

Marketing and Sales

Our marketing and sales force, based in our corporate office in Richmond, Virginia, includes sales managers, distribution/traffic managers and administrative personnel. During the fiscal year ended December 31, 2002, we sold 42.1 million tons of coal and generated produced coal revenues of $1.3 billion. The breakdown of tons sold by market served was 65% utility, 26% metallurgical and 9% industrial. We sold coal to over 125 customers. Export shipments (including Canada) represented approximately 14% of 2002 tons sold. Our 2002 export shipments serviced customers in 7 countries across North America, South America and Europe. Almost all sales are made in U.S. dollars, which eliminates foreign currency risk.

We have established several contractual arrangements with customers wherein services other than coal supply are provided on an ongoing basis. Examples of such other services include our coal handling facility agreements with two customers, and our arrangements with three steel companies and several steam and industrial customers to coordinate shipment of coal to their stockpile, maintain ownership of the coal inventory on their property and sell tonnage to them as it is consumed. We work closely with our customers to provide other services in response to the current needs of each individual customer.

Distribution

We employ transportation specialists who negotiate freight and terminal agreements with various providers, including railroads, barge lines, steamship lines, bulk motor carriers and terminal facilities. Transportation specialists also coordinate with customers, resource groups and transportation providers to establish shipping schedules that meet the customer’s needs. Our 2002 shipments of 42.1 million tons were loaded from 19 resource

groups. Rail shipments constituted 91% of total shipments. The 9% balance was shipped from our resource groups via truck.

Approximately 14% of our production is ultimately delivered via the inland waterway system. Coal is transported by rail or truck to docks on the Ohio, Big Sandy and Kanawha Rivers and then ultimately transported by barge to electric utilities, integrated steel producers and industrial consumers served by the inland waterway system. We also move approximately 8% of our coal production to Great Lakes Ports for transport beyond to various U.S. and Canadian customers.

Customers and Coal Contracts

We have coal supply commitments with a wide range of electric utilities, steel manufacturers, industrial customers and energy traders and brokers. By offering coal of both steam and metallurgical grades, we are able to serve a diverse customer base. This market diversity allows us to adjust to changing market conditions and sustain high sales volumes. Many of our larger customers are well-established public utilities who have been customers of ours for a number of years.

We have contracts to supply coal to energy trading and brokering companies under which those companies sell such coal to the ultimate users. During 2002, the creditworthiness of the energy trading and brokering companies with which we do business declined, increasing the risk that we may not be able to collect payment for all coal sold and delivered to or on behalf of these energy trading and brokering companies. To mitigate credit-related risks in all customer classifications, we maintain a credit policy, which requires scheduled reviews of customer creditworthiness and continuous monitoring of customer news events which might have an impact on their financial condition. Negative credit performance or events may trigger the application of tighter terms of sale, requirements for collateral or, ultimately, a suspension of credit privileges.

As is customary in the coal industry, we continually enter into long-term contracts (exceeding one year in duration) with many of our customers. These arrangements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. For the year ended December 31, 2002, approximately 94% of our coal sales volume was pursuant to long-term contracts. We believe that in 2003, the percentage of sales pursuant to long-term arrangements will be comparable with the percentage of sales for 2002.

For 2003, we expect to produce 40 to 45 million tons of coal. In addition, we purchase coal from third-party coal producers from time to time to supplement production and resell this coal to our customers. As of December 31, 2002, we had commitments to purchase 2.0 million tons during 2003 and 0.7 million tons in 2004 and 2005. As of April 30, 2003, we had sales commitments for calendar years 2003 and 2004 of approximately 42 million tons and approximately 26 million tons, respectively.

Other Related Operations

We have other related operations and activities in addition to our normal coal production and sales business, including:

Appalachian Synfuel Plant

One of our subsidiaries, Marfork Coal Company, manages a synthetic fuel manufacturing facility located adjacent to the Marfork complex in Boone County, West Virginia. This facility converts coal products to synthetic fuel and has operated since June 1998. Appalachian Synfuel, LLC, the entity that owns the facility, became a wholly owned subsidiary of our company in connection with the spin-off. Appalachian Synfuel has obtained a private letter ruling from the Internal Revenue Service that provides that production from this synfuel facility qualifies the owner for tax credits pursuant to Section 29 of the Internal Revenue Code.

Because of our tax position, we were unable to utilize the tax credits generated by Appalachian Synfuel. In order to monetize the value of our investment, we sought to sell an interest in Appalachian Synfuel to an entity that could benefit currently from the tax credits generated. In order to facilitate such a transaction, the limited liability company agreement was amended to divide the ownership interest into three traunches, Series A, Series B and Series C.

Under the amended limited liability company agreement, the Series A owner generally is entitled to the risks and rewards of the first 475,000 tons of production, including the right to the related tax credits. The Series B owner is generally entitled to the risks and rewards of all excess production up to the rated capacity of 1.2 million tons. The Series C owner is entitled to the amount of working capital on the day of the sales transaction. The Series C owner is responsible for providing recourse working capital loans to Appalachian Synfuel going forward at a specified indexed interest rate. As a result, the Series C owner will fund the daily operations of Appalachian Synfuel. The Series C owner also has the responsibility at the end of the term of the operating agreement to wind up the affairs of Appalachian Synfuel, disposing of all assets and settling liabilities.

On March 15, 2001, and May 9, 2002, we, in a two-part transaction, sold 99% of our Series A and Series B interests, respectively, in Appalachian Synfuel, contingent upon favorable Internal Revenue Service rulings, which were received in September 2001 and in June 2002, respectively. We received cash of $7.2 million, a recourse promissory note for $34.6 million that will be paid in quarterly installments of $1.9 million including interest, and a contingent promissory note that is paid on a cents per Section 29 credit dollar earned based on synfuel tonnage shipped. Deferred gains of $23.8 million and $11.9 million as of December 31, 2002 and October 31, 2001, respectively, are included in other noncurrent liabilities to be recognized ratably though 2007.

Westvaco Coal Handling Facility

We own and operate the coal unloading, storage and conveying facilities at Westvaco Corporation’s paper manufacturing facility in Covington, Virginia. We built the Westvaco coal handling facility in 1992 as a means of reducing coal transportation and handling costs for Westvaco Corporation, a long term industrial coal customer. The Westvaco coal handling facility operating agreement extends through 2007, and provides for fees to be paid to us on a per ton basis (annually adjusted) for coal handling services and allows us to supply 100% of the coal required by Westvaco’s paper manufacturing facility.

Eastman Chemical Company Coal Handling System

We own and operate coal unloading, storage and conveying facilities at Eastman Chemical Company’s facility in Kingsport, Tennessee. This facility, which we built, went into service in September 2002. The Eastman coal handling facility operating agreement extends through 2017 and provides that we will be paid certain fixed and/or per ton fees for leasing equipment, coal handling services and for operating and maintaining the Eastman coal handling facility.

Miscellaneous

We also engage in the sale of certain non-strategic assets such as timber, gas and oil rights as well as the sale of non-strategic surface properties and reserves.

Employee and Labor Relations

As of March 31, 2002, we had 4,313 employees, including 164 employees affiliated with the United Mine Workers of America. Relations with employees are generally good, and there have been no material work stoppages in the past 10 years.

Legal Proceedings

For information regarding certain legal proceedings to which we are parties, see “Risk Factors” and the documents incorporated by reference in this offering memorandum listed under “Documents Incorporated by Reference.”

We are also party to numerous lawsuits and other legal proceedings related to the non-coal businesses previously conducted by us but now conducted by New Fluor. Under the terms of the distribution agreement entered into by us and New Fluor in connection with the spin-off, New Fluor has agreed to indemnify us with respect to all such legal proceedings and has assumed their defense.