MASSEY ENERGY CO - 10-K Annual Report

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

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

The aggregate market value of the Common Stock held by non-affiliates of the registrant on June 30, 2003, was approximately $990,345,000 based on the last sales price reported that date on the New York Stock Exchange of $13.15 per share. In determining this figure, the Registrant has assumed that all of its directors and executive officers are affiliates. Such assumptions should not be deemed to be conclusive for any other purpose.

Common Stock, $0.625 par value, outstanding as of February 27, 2004—75,779,279 shares.

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2004 annual meeting of shareholders, which proxy statement will be filed no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2003.

From time to time, Massey Energy Company (except as the context otherwise requires, the terms “Massey” or the “Company” as used herein shall include Massey Energy Company, its wholly owned subsidiary, A.T. Massey Coal Company, Inc. (“A.T. Massey”) and A.T. Massey’s subsidiaries) makes certain comments and disclosures in reports and statements, including this report, or statements made by its officers which may be forward-looking in nature. Examples include statements related to the Company’s future outlook, anticipated capital expenditures, future cash flows and borrowings, and sources of funding. These forward-looking statements could also involve, among other things, statements regarding the Company’s intent, belief or expectation with respect to:

Any forward-looking statements are subject to the risks and uncertainties that could cause actual cash flows, results of operations, financial condition, cost reductions, acquisitions, dispositions, financing transactions, operations, expansion, consolidation and other events to differ materially from those expressed or implied in such forward-looking statements. Any forward-looking statements are also subject to a number of assumptions regarding, among other things, future economic, competitive and market conditions generally. 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 the Company’s control.

The Company wishes to caution readers that forward-looking statements, including disclosures which use words such as the Company “believes,” “anticipates,” “expects,” “estimates” 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 the Company about its businesses, including without limitation the risk factors more specifically described below in Item 1. Business, under the heading “Business Risks.”

Massey makes available free of charge on or through its Internet website, www.masseyenergyco.com, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as well as Section 16 reports on Forms 3, 4 and 5, as soon as reasonably practicable after they are electronically filed with, or furnished to, the Securities and Exchange Commission (the “SEC”). Copies of the Company’s filings, and the Company’s Corporate Governance Guidelines, Code of Ethics and the charters of the Audit, Compensation, and Governance and Nominating Committees, may be requested, at no cost, by telephone at (866) 814-6512 or by mail at: Massey Energy Company, 4 North 4th Street, Richmond, Virginia 23219, Attention: Investor Relations.

The 2004 Annual Meeting of Shareholders of Massey Energy Company will be held at 9:00 a.m. EDT on Tuesday, May 18, 2004 at the Charleston Town Center Marriott in Charleston, West Virginia.

Because certain terms used in the coal industry may be unfamiliar to many investors, the Company has provided a Glossary of Selected Terms at the end of Item 1, Business.

Massey produces, processes and sells bituminous, low sulfur coal of steam and metallurgical grades through its nineteen processing and shipping centers, called “resource groups,” many of which receive coal from multiple coal mines. Massey currently operates 30 underground mines (four of which employ both room and pillar and longwall mining) and 13 surface mines (with seven highwall miners in operation) in West Virginia, Kentucky and Virginia. The number of mines that Massey operates may vary from time to time depending on a number of factors, including the existing demand for and price of coal and exhaustion of economically recoverable reserves. Massey’s steam coal is primarily purchased by utilities and industrial clients as fuel for power plants. Its metallurgical coal is used primarily to make coke for use in the manufacture of steel. In the Energy Ventures Analysis (“EVA”) ranking of coal companies by 2002 revenue, Massey is the fourth largest coal company in the United States (the “U.S.”), and the largest in the Central Appalachian region.

A.T. Massey was originally incorporated in Richmond, Virginia in 1920 as a coal brokering business. In the late 1940s, A.T. Massey expanded its business to include coal mining and processing. In 1974, St. Joe Minerals acquired a majority interest in A.T. Massey. St. Joe Minerals was then acquired by Fluor Corporation in 1981. A.T. Massey was wholly owned by Fluor Corporation from 1987 until November 30, 2000, when the Company completed a reverse spin-off (the “Spin-Off”), which divided it into the spun-off corporation, “new” Fluor Corporation (“New Fluor”), and Fluor Corporation, subsequently renamed Massey Energy Company, which retained the Company’s coal-related businesses.

The Company changed to a calendar-year basis of reporting financial results effective January 1, 2002. For comparative purposes, the reported audited consolidated results of operations and cash flows for the 2001 annual period are for the twelve months ended October 31. As a requirement of the change in fiscal year, the Company is reporting consolidated results of operations and cash flows for a special transition period, the two months ended December 31, 2001.

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 50% of the electricity produced in the U.S. according to the Energy Information Administration, a statistical agency of the U. S. Department of Energy (“DOE”).

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

U.S. coal production has more than doubled during the last 30 years. In 2003, total coal production as estimated by DOE was 1.1 billion tons. The primary producing regions by tons were the Powder River Basin (38%), Central Appalachia (22%), Midwest (12%), Northern Appalachia (12%), West (other than the

Powder River Basin) (13%) and other (3%). All of the Company’s coal production comes from the Central Appalachian region. Approximately 68% of U.S. coal is produced by surface mining methods. The remaining 32% is produced by underground mining methods that include room and pillar mining and longwall mining (more fully described in Item 1, Business, under the heading “Mining Methods”).

Coal is used in the U.S. 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 U.S. coal consumption, as estimated by DOE, is as follows:

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. Resource Data International, Inc. (“RDI”) estimated the average total production costs of electricity, using coal and competing generation alternatives in 2002 as follows:

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 DOE, is as follows:

Demand for electricity has historically been driven by U.S. economic growth. 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.

The U.S. ranks sixth 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 61% between 1992 and 2002 as a result of increased international competition and the U.S. dollar’s historic strength in comparison to foreign currencies. In 2002, U.S. coal exports fell to a level not seen since 1961. According to DOE, the usage breakdown for 2002 U.S. exports of 40 million tons was 46% for electricity generation and 54% for steel making. U.S. coal exports were shipped to more than 25 countries. The largest purchaser of U.S. exported utility coal was Canada, which took 12 million tons or 67% of total utility coal exports. The largest purchasers of U.S. exported metallurgical coal were Canada, which imported 4.7 million tons, or 22%, and Brazil, which imported 3.5 million tons, or 16%. Depending on the relative strength of the U.S. dollar versus currencies in other coal producing regions of the world, U.S. producers may export more or less coal into foreign countries as they 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. In 2002, coal imported into the U.S. fell for the first time in five years.

Metallurgical grade coal is distinguished by special quality characteristics that include high carbon content, low expansion pressure, low sulfur content, and various other chemical attributes. High vol met coal is also high in heat content (as measured in Btus), and therefore is desirable to utilities as fuel for electricity generation. Consequently, high vol met 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 92% of domestic metallurgical coal and 82% 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 27% 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 (the “NMA”), in 2002 approximately two-thirds of U.S. coal production was 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 nor any of its subsidiaries is affiliated with or has any investment in the DOE, EVA, RDI or World Coal Institute. Massey is a member of the NMA.

Massey produces 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 (which is a type of underground 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 38% of Massey’s 2003 coal production.

Production from underground longwall mining operations constituted about 18% of Massey’s 2003 production. Massey operates four longwall units.

Surface mining represented approximately 35% of Massey’s 2003 coal production. Massey has established large-scale surface mines in Boone and Nicholas counties of West Virginia. Other Massey surface mines are smaller in scale. Massey surface mines also use highwall mining systems to produce coal from high overburden areas. Highwall mining represented approximately 9% of Massey’s 2003 coal production.

Because underground longwall mining, highwall mining and surface mining are high-productivity, low-cost mining methods, Massey will seek to increase production from its use of those methods to the extent permissible and cost-effective. From 1996 to 2003, underground longwall mining increased from 5% to 18% of Massey’s production, highwall mining increased from 0% to 9% of its production and surface mining increased from 14% to 35% of its production.

Massey currently has nineteen distinct resource groups or mining complexes, including fourteen in West Virginia, four in Kentucky and one in Virginia. These complexes blend, process and ship coal that is produced from one or more mines, with a single complex handling the coal production of as many as eight distinct underground or surface mines. These mines have been developed at strategic locations in close proximity to the Massey preparation plants and rail shipping facilities. Coal is transported from Massey’s mining complexes to customers by means of railroad cars or trucks, with rail shipments representing approximately 93% of 2003 coal shipments.

The following table provides key operational information on all Massey mining complexes (Resource Groups) that were active in 2003.

The following descriptions of the Company’s resource groups are current as of February 29, 2004.

Black Castle. The Black Castle mining complex includes a large surface mine, a highwall miner and an underground belt conveyor system that transports coal to the Omar preparation plant for CSX delivery. Coal is also crushed on-site then trucked to river docks for barge delivery or trucked directly to customers.

Delbarton. The Delbarton complex includes an underground room and pillar mine and a preparation plant. Production from this mine is transported to the Delbarton preparation plant via overland conveyor. The Delbarton preparation plant also processes coal from two surface mines of the Logan County resource group. Currently a slope into additional underlying reserves is being developed. The Delbarton preparation plant can process 600 tons per hour. The clean coal product is shipped to customers via the Norfolk Southern railway in unit trains of up to 110 railcars.

Eagle Energy. The Eagle Energy complex is currently inactive but has historically processed coal production from an adjacent underground longwall mine. The economically recoverable reserves in this mine were depleted in January 2000 and the operation was idled. The Eagle Energy preparation plant has a rated feed capacity of 750 tons per hour. Customers are served via CSX railway in unit trains of up to 90 railcars. Plans are under review to re-activate this complex using production from new mines on Massey controlled properties adjacent to the preparation plant.

Elk Run. Elk Run produces coal from four underground room and pillar mines, which deliver coal to its preparation plant by belt and truck. Additionally, Elk Run processes coal for shipment that is produced by surface mines of the Progress resource group. Coal from these mines is transported via underground conveyor system. The Elk Run preparation plant has a processing capacity of 2200 tons per hour. Elk Run also operates a 200 ton per hour stoker facility which produces screened, small dimension coal for certain of Massey’s industrial customers. Customer shipments are loaded on the CSX rail system in unit trains of up to 150 railcars.

Green Valley. The Green Valley complex includes two underground room and pillar mines and a preparation plant. The Green Valley preparation plant receives coal from the two mines via truck and has a processing capacity of 600 tons per hour. The rail loading facility services customers on the CSX rail system with unit train shipments of up to 75 railcars.

Independence. The Independence complex includes the Justice longwall mine, three room and pillar mines and a preparation plant. Production from two of the deep mines is transported via underground conveyor system directly to the Independence preparation plant. Additionally, Independence processes coal for shipment that is produced from the Black Castle resource group and the Progress resource group. Both the Black Castle surface mine and highwall miner, and the West Cazy surface mine and highwall miner of the Progress resource group transport coal requiring processing to the Independence preparation plant via truck. Two of the underground room and pillar mining operations of Independence ship coal via belt conveyor for processing, one to the preparation plant of the Performance resource group and another to the preparation plant of the Omar resource group. The Independence plant has a processing capacity of 2200 tons per hour. Customers are served via rail shipments on the CSX rail system in unit trains of up to 150 railcars.

Logan County. The Logan County complex includes five surface mines, two highwall miners, one underground room and pillar mine and the Aracoma longwall mine, plus the Bandmill preparation plant and the Feats loadout. The room and pillar mine was temporarily idled in early 2004 but is expected to resume production later in 2004. The surface mines and highwall miners deliver coal to the Bandmill plant via truck, while both underground mines belt coal directly to this plant. Two surface mines and one highwall miner also deliver direct-ship coal to the Feats loadout by truck. A portion of the coal from two of the surface mines and one highwall miner is also delivered to the Delbarton preparation plant by truck. The Bandmill preparation plant has a processing capacity of 1600 tons per hour. The Bandmill rail loading facility services customers via the CSX rail system with unit train shipments of up to 150 cars.

Marfork. The Marfork complex includes five underground room and pillar mines and a preparation plant. The largest production source for the Marfork complex is the Upper Big Branch longwall mine of the Performance resource group. Approximately half of the Marfork production is belted directly to the preparation plant via conveyor while the remainder is trucked on private haulroads. The Marfork preparation plant has a capacity of 2400 tons per hour. Customers are served via the CSX rail system with unit trains of up to 150 railcars.

Nicholas Energy. The Nicholas Energy complex includes a large surface mine, a highwall miner and a preparation plant. Coal from the highwall miner and the portion of surface mined coal requiring processing is transported to the preparation plant via overland conveyor system. The plant has a processing capacity of 1200 tons per hour. All coal shipments are loaded into rail cars for delivery via the Norfolk Southern railway in unit trains of up to 140 railcars.

Omar. The Omar mining complex processes coal as well as crushes and loads direct-ship coal at its preparation plant from the adjacent surface and highwall mining operations of the Black Castle resource group. Production is transported via underground conveyor system or trucked to the Omar facility. The Omar facility also processes coal from an Independence resource group room and pillar mine. The direct ship facility can crush 500 tons per hour and the preparation plant can process 800 tons per hour. Omar serves CSX rail system customers with unit train shipments of up to 110 railcars.

Performance. The Performance mining complex includes the Upper Big Branch longwall mine and the Goals preparation plant. All of the production from Upper Big Branch is shipped via overland conveyor to the preparation plant at the Marfork resource group. The Goals preparation plant processes the production, received by belt conveyor, of one adjacent underground mine and the new Edwight surface mine of the Progress resource group. The Goals preparation plant can process 800 tons per hour. The rail loading facility serves CSX railway customers with unit trains of up to 90 railcars.

Progress. The Progress mining complex includes three surface mines, the large Twilight MTR surface mine and two smaller surface mines, one highwall miner and a direct ship loadout. Production from the Twilight MTR surface mine is transported via underground conveyor to the Elk Run resource group for processing and rail shipment. Production from one smaller surface mine is transported by overland conveyor to the Performance resource group’s Goals preparation plant for processing and loading, while the remaining surface mine trucks direct ship coal to the railroad loadout. Production from these mines is loaded on the CSX rail system.

Rawl. The Rawl complex includes three active underground room and pillar mines, one surface mine and the Sprouse Creek preparation plant. The surface mine production requiring processing and production from one underground room and pillar mine is trucked to the Sidney resource group preparation plant. The direct ship coal from the surface mine is loaded out through the New Ridge resource group preparation plant. The other two underground mines transport coal to the Sprouse Creek plant via truck. The Sprouse Creek plant has a throughput capacity of 1450 tons per hour. Customers are served via the Norfolk Southern railway with unit trains of up to 150 railcars.

Stirrat. The Stirrat preparation plant was idled in January 2003 and plans are under review to reactivate this plant in 2004 using production from a planned surface mine. The plant has a rated capacity of 600 tons per hour. Customers are serviced via the CSX rail system with unit trains of up to 100 railcars.

Long Fork. The Long Fork preparation plant processes coal produced by an underground room and pillar mine and the Rockhouse longwall mine of the Sidney resource group. All production is transported via conveyor system to the Long Fork preparation plant. The Long Fork plant has a rated capacity of 1500 tons per hour. The rail loading facility services customers on the Norfolk Southern railway with unit trains of up to 150 railcars.

Martin County. Martin County includes one underground mine, a surface mine, a highwall miner and a preparation plant. The direct ship coal production from the surface mine and highwall miner is shipped to river docks via truck. The balance of the coal production is transported by conveyor belt to the preparation plant for processing. Martin County’s preparation plant has a throughput capacity of 1500 tons per hour, although such throughput capacity has been limited since the impoundment failure in October 2000 due to decreased impoundment availability. All coal from the preparation plant is shipped via the Norfolk Southern railway in unit trains of up to 125 railcars.

New Ridge. The New Ridge complex loads clean coal that is transported via truck from the Big Creek preparation plant of Massey’s Sidney resource group. The New Ridge preparation plant has a throughput capacity of 800 tons per hour. The preparation plant is currently idle but is expected to be reactivated in 2004. All coal is loaded for shipment to customers via the CSX rail system in unit trains of up to 100 railcars.

Sidney. The Sidney complex includes five underground room and pillar mines, the Rockhouse longwall mine, a surface mine, a highwall miner, the Big Creek preparation plant and the Sandlick direct-ship loadout facility. Two of the underground mines transport coal via underground conveyor to the Long Fork resource group for processing and shipment, and the remainder of the mines transport production via underground conveyor or truck to the Big Creek preparation plant. A portion of the coal from the plant and the direct-ship coal from the surface mine is trucked to the Sandlick loadout and to the New Ridge resource group for loading into railroad cars. The Big Creek preparation plant has a throughput capacity of 1500 tons per hour. The rail loading facility at the preparation plant and the direct-ship facility both serve customers on the Norfolk Southern rail system with unit trains of up to 140 railcars.

Knox Creek. Knox Creek includes the Tiller No. 1 underground room and pillar mine and a preparation plant. Production from the mine is belted directly to the preparation plant. The plant has a feed capacity of 650 tons per hour. The preparation plant serves customers on the Norfolk Southern rail system with unit trains of up to 100 railcars.

The following chart lists the active mines, by type, at the Company’s resource groups as of February 29, 2004.

Massey has other related operations and activities in addition to its normal coal production and sales business. The following business activities are included in this category:

Appalachian Synfuel Plant: One of Massey’s 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. Appalachian Synfuel, LLC (“Appalachian Synfuel”), the entity that owns the facility, became a wholly owned subsidiary of the Company in connection with the Spin-Off. Appalachian Synfuel has obtained a private letter ruling from the Internal Revenue Service (“IRS”) that provides that production from this synfuel facility qualifies the owner for tax credits pursuant to Section 29 of the Internal Revenue Code. These tax credits are scheduled to expire December 31, 2007.

The ownership interest in Appalachian Synfuel is divided into three tranches, Series A, Series B and Series C. In 2001 and 2002, the Company sold a total of 99% of its Series A and Series B interests, respectively, contingent upon favorable IRS rulings that were obtained. The Company received cash of $7.2 million, a recourse promissory note for $34.6 million that is being 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 $19.1 million and $23.8 million as of December 31, 2003 and December 31, 2002, respectively, are included in Other noncurrent liabilities to be recognized ratably through 2007. See Note 17 to the Consolidated Financial Statements for further information regarding Appalachian Synfuel, LLC.

Mead/Westvaco Coal Handling Facility: Massey subsidiaries own and operate the coal unloading, storage and conveying facilities at Mead/Westvaco Corporation’s paper manufacturing facility in Covington, Virginia (“Westvaco CHF”). The Westvaco CHF was constructed by Massey in 1992 as a means of reducing coal transportation and handling costs for Westvaco Corporation (now Mead/Westvaco Corporation), a long-standing industrial coal customer. The Westvaco CHF operating agreement extends through 2007, and provides for Massey to be paid a per ton fee (quarterly adjusted) for coal handling services and gives Massey the right to supply 100% of the coal required by Mead/Westvaco’s facility.

Eastman Chemical Company Coal Handling System: Massey subsidiaries own and operate coal unloading, storage and conveying facilities at Eastman Chemical Company’s facility in Kingsport, Tennessee (the “Eastman CHS”). The Eastman CHS was constructed by Massey subsidiaries and went into service in September 2002. The Eastman CHS operating agreement extends through 2017 and provides that Massey will be paid certain fixed and/or per ton fees for leasing equipment, coal handling services and for operating and maintaining the Eastman CHS. The Company does not currently supply coal to Eastman Chemical Company.

Gas Operations: The Company holds interests in operations that produce, gather and market natural gas from shallow reservoirs in the Appalachian Basin. In the eastern U.S., conventional natural gas reservoirs are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. The depths of the reservoirs drilled and operated by Massey range from 2,500 to 5,000 feet.

Nearly all of the Company’s gas production is from operations in southern West Virginia. In this region, the Company owns and operates approximately 150 wells, 180 miles of gathering line, and various small compression facilities. In addition, it owns a majority working interest in 46 wells operated by others, and minority working interests in approximately 30 wells operated by others. The Company’s southern West Virginia operations control approximately 27,000 acres of drilling rights. The December 2003 average daily production, from the 196 wells owned or controlled, was 1.9 million cubic feet per day. The Company does not consider its current production level to be material to the Company’s cash flows, results of operations or financial condition.

Other: From time to time, Massey also engages in the sale of certain non-strategic assets such as timber, oil and gas rights, surface properties and reserves. In addition, Massey has established several contractual arrangements with customers where services other than coal supply are provided on an ongoing basis. None of these contractual arrangements is considered to be material. Examples of such other services include Massey’s coal handling facility agreements with several customers (the largest of which are the Westvaco CHF and the Eastman CHS), and its arrangements with three steel companies and several industrial customers to coordinate shipment of coal to their stockpiles, maintain ownership of the coal inventory on their property and sell tonnage to them as it is consumed. The Company works closely with its customers to provide other services in response to the current needs of each individual customer.

The Massey marketing and sales force, based in the corporate office in Richmond, Virginia, includes sales managers, distribution/traffic managers and administrative personnel.

During the year ended December 31, 2003, Massey sold 41.0 million tons of produced coal for total produced coal revenue of $1.3 billion. The breakdown of produced tons sold by market served was 67% utility, 23% metallurgical and 10% industrial. Sales were concluded with over 125 customers. Export shipments (including Canada) represented approximately 12% of 2003 tonnage sold. Massey’s 2003 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.

Massey employs 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, mining facilities and transportation providers to establish shipping schedules that meet the customer’s needs.

Massey’s 2003 shipments of 41.0 million tons were loaded from 18 mining complexes. Rail shipments constituted 93% of total shipments, with 34% loaded on Norfolk Southern trains and 59% loaded on CSX trains. The 7% balance was shipped from Massey mining complexes via truck.

Approximately 21% of Massey’s production was 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. Massey also moved approximately 10% of its production to Great Lakes Ports for transport beyond to various U.S. and Canadian customers.

Massey has 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, Massey is able to serve a diverse customer base. This market diversity allows Massey to adjust to changing market conditions and sustain high sales volumes. The majority of Massey’s customers purchase coal for terms of one year or longer, but Massey also supplies coal on a spot basis for some of its customers. Massey’s biggest customer, affiliates of DTE Energy Corporation, accounted for 14% of Massey’s total fiscal year 2003 produced coal revenue.

Massey has contracts to supply coal to energy trading and brokering companies under which those companies sell such coal to the ultimate users. During 2002 and 2003, the creditworthiness of the energy trading and brokering companies with which Massey does business generally declined, with some of these customers declaring bankruptcy, increasing the risk that Massey 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, Massey maintains a credit policy, which requires scheduled reviews of customer creditworthiness and continuous monitoring of customer news events that 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 the largest supplier of metallurgical coal to the American steel industry, Massey may be adversely affected by any decline in the financial condition or production volume of American steel producers. In recent years, American 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. This caused further deterioration in steel industry conditions and impacted the collectibility of Massey’s accounts receivable from steel industry customers. Massey’s periodic review of the creditworthiness of its metallurgical coal customers has caused it, in certain cases, to sell the coal only on very restrictive terms. Massey’s metallurgical coal sales in 2003 fell to 9.6 million tons, the lowest level since 1994. Because some of Massey’s metallurgical grade coal can also be marketed as a

high-Btu steam coal for use by utilities, some metallurgical grade coal was switched in 2003 from the metallurgical market to the utility market.

In the latter part of 2003, demand for U.S. coal strengthened due to the relatively cold winter in the U.S., the weak U.S. dollar in comparison to the currencies of foreign coal producing regions, the improving U.S. economy and a worldwide shortage of coal exported from China and other countries. The shortage of metallurgical coal was particularly acute and in order to maximize its revenues in 2004, Massey has begun shifting some production from the utility market to the export metallurgical market.

As is customary in the coal industry, Massey enters into long-term contracts (one year or more in duration) with many of its customers. These arrangements allow customers to secure a supply for their future needs and provide Massey with greater predictability of sales volume and sales prices. For the year ended December 31, 2003, approximately 96% of Massey’s coal sales volume was pursuant to long-term contracts. The Company believes that in 2004, the percentage of sales pursuant to long-term arrangements will be comparable with the percentage of sales for 2003. Please see Item 7A., Quantitative and Qualitative Discussions, about Market Risk for further discussion on managing Massey’s commodity price risk through the use of long-term coal supply agreements.

The terms of Massey’s long-term contracts are a result of extensive negotiations with customers. As a result, the terms of these contracts vary with respect to price adjustment mechanisms, pricing terms, permitted sources of supply, force majeure provisions, quality adjustments and other parameters. Some of the contracts contain price adjustment mechanisms that allow for changes to prices based on statistics from the U.S. Department of Labor. Contracts contain specifications for coal quality, which may be especially stringent for steel customers. Many of these contracts also specify the approved locations from which the coal is to be sourced.

For 2004, Massey expects to sell 45 to 47 million tons of produced coal. In addition, the Company purchases coal from third-party coal producers from time to time to supplement production and resells this coal to its customers. As of February 29, 2004, the Company had commitments to purchase 2.8, 0.8 and 0.8 million tons during 2004, 2005 and 2006, respectively. The following table sets forth, as of February 29, 2004, the total tons of coal from produced and purchased coal sources the Company is committed to deliver at prices that are determined under existing contracts, including prices that are adjusted as often as quarterly based upon indices which are pre-negotiated, during calendar years 2004 through 2007.

The preceding table does not include an aggregate of 0.8 million and 0.3 million tons that the Company may be required to deliver in 2004 and 2005, respectively. These possible requirements relate to the exercise of rights by customers under existing contracts to buy more coal at previously agreed prices or the determination of the price by mutual agreement.

The coal industry in the U.S. is highly competitive. Massey competes with coal producers in various regions of the U.S. for domestic sales and with both domestic and foreign producers for sales to international markets. Massey competes with other producers primarily on the basis of price, coal quality, transportation cost and reliability of supply. Continued demand for coal is also dependent on factors outside Massey’s control, including demand for electricity, environmental and governmental regulations, weather, technological developments, the availability and cost of alternative fuel sources and general economic conditions.

The price at which the Company’s production can be sold is dependent upon a variety of factors, many of which are beyond the Company’s control. The Company sells coal under long-term contracts and on the spot market. See the “Customers and Coal Contracts” section above. 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 the Company’s production can be sold.

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. The Company’s Central Appalachian coal is more expensive to mine than western coal because there is a high percentage of underground coal in the east and eastern surface coal tends to have thinner coal seams. Additionally, underground mining has higher costs for labor (including reserves for future costs associated with labor benefits and health care) and capital (including modern mining equipment and construction of extensive ventilation systems) than those of surface mining. The lower production costs in the western mines are offset somewhat by the higher quality of many eastern coals and higher transportation costs from these western mines to many coal-fired power plants in the country. Demand for the Company’s low sulfur coal and the prices that the Company will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances. In addition, more widespread installation by electric utilities of technology that reduces sulfur emissions may make high sulfur coal more competitive with low sulfur coal. Intraregional and interregional competition is keen as producers seek to position themselves as the low-cost producer and supplier of coal to the electricity generating industry.

Transportation costs are another fundamental factor affecting coal industry competition. Coordination of the many eastern coal loadouts, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than shipments originating in the western U.S. However, the total cost of coal transportation from the western coal producing areas into Central Appalachian markets has historically 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. Barge transportation is the lowest cost method of transporting coal long distances in the eastern U.S., and the large numbers of eastern producers with river access help keep coal prices competitive. The Company believes that with close proximity to competitively-priced Central Appalachian coal and the ability to receive western coals, utilities with plants located on the Ohio River system will become price setters in the future. The ability of these utilities to blend western and eastern coal will also create a new, dynamic fuel procurement environment that could place western and eastern coals in even greater competition.

The cost of ocean transportation and the valuation of the U.S. dollar in relation to foreign currencies significantly impact the relative attractiveness of Massey’s coal as it competes on price with other foreign coal producing sources. Recently, a worldwide shortage of vessel capacity and high fuel costs have driven ocean freight rates to historically high levels. These cost increases, in addition to a weak U.S. dollar, have given European imports from U.S. producers a competitive advantage over more distant sources such as Australia. In addition, these high ocean freight rates make imported coal relatively less attractive to U.S. coal customers, reducing the amount of coal available to meet domestic demand.

Historically, 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 can lead 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 the Company’s revenues. However, in recent years, overcapacity has been limited by the increased costs of mining, high capital requirements, coal seam degradation and the difficulty of obtaining permits and bonding, which could contribute to firming coal prices.

As of December 31, 2003, Massey had 4,428 employees, including 193 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 ten years.

Massey is subject to federal, state and local laws and regulations relating to environmental protection and plant and mine safety and health, including but not limited to the Federal Surface Mining Control and Reclamation Act of 1977 (the “SMCRA”); Occupational Safety and Health Act; Mine Safety and Health Act of 1977; Water Pollution Control Act, as amended by the Clean Water Act; the Clean Air Act; Black Lung Benefits Revenue Act of 1977; and Black Lung Benefits Reform Act of 1977. Massey is rarely subject to permitting or enforcement under the Federal Resource Conservation and Recovery Act (“RCRA”) or the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and does not consider the effects of those statutes on its operations to be material for purposes of disclosure.

The SMCRA, which is administered by the Office of Surface Mining Reclamation and Enforcement (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. The SMCRA and similar state statutes require, among other things, the restoration of mined property in accordance with specified standards and an approved reclamation plan. In addition, the Abandoned Mine Land Fund, which is part of the SMCRA, imposes a fee on all current mining operations, the proceeds of which are used to restore mines closed before 1977. The maximum tax is $0.35 per ton on surface-mined coal and $0.15 per ton on deep-mined coal. A mine operator must submit a bond or otherwise secure the performance of its reclamation obligations. Mine operators must receive permits and permit renewals for surface mining operations from the OSM or, where state regulatory agencies have adopted federally approved state programs under the act, the appropriate state regulatory authority. The Company accrues for reclamation and mine-closing liabilities in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”) (See Note 3 to the Notes to the Consolidated Financial Statements).

On March 29, 2002, the U.S. District Court for the D.C. Circuit issued a ruling that could have restricted 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 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 SMCRA. The 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 the SMCRA. By order dated April 9, 2002, the Court remanded the regulations to the Secretary of the Interior for reconsideration. The Department of Interior and the NMA, a trade group that intervened in this action, appealed the order to the U.S. Court of Appeals for the D.C. Circuit. On June 3, 2003, the Court of Appeals overturned the District Court’s order and upheld the Department of Interior’s regulations. On February 23, 2004, the U.S. Supreme Court elected not to hear the plaintiff’s appeal of this decision.

Section 301 of the Clean Water Act prohibits the discharge of a pollutant from a point source into navigable waters except in accordance with a permit issued under either Section 402 or Section 404 of the Clean Water Act. Navigable waters are broadly defined to include streams, even those that are not navigable in fact, and may

include wetlands. All mining operations in Appalachia generate excess material, which must be placed in fills in adjacent valleys and hollows. Likewise, coal refuse disposal areas and coal processing slurry impoundments are located in valleys and hollows. Almost all of these areas contain intermittent or perennial streams, which are considered navigable waters. An operator must secure a Clean Water Act permit before filling such streams. For approximately the past twenty-five years, operators have secured Section 404 fill permits to authorize the filling of navigable waters with material from various forms of coal mining. Operators have also obtained permits under Section 404 for the construction of slurry impoundments although the use of these impoundments, including discharges from them, requires permits under Section 402. Section 402 discharge permits are generally not suitable for authorizing the construction of fills in navigable waters.

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 approval by the U.S. Environmental Protection Agency (“EPA”) of West Virginia’s antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. The plaintiffs in this lawsuit, Ohio Valley Environmental Coalition v. Whitman, challenge provisions in West Virginia’s antidegradation implementation policy that exempt current holders of National Pollutant Discharge Elimination System (“NPDES”) permits and Section 404 permits, among other parties, from the antidegradation-review process. The Company is exempt from antidegradation review under these provisions. Revoking this exemption and subjecting the Company to the antidegradation review process could delay the issuance or reissuance of Clean Water Act permits to the Company or cause these permits to be denied. On August 29, 2003, the Court upheld some of the challenges to the policy and it appears that West Virginia will have to alter and EPA will have to re-approve the policy. Notably, the Court did not uphold challenges to provisions in the policy that exempt current holders of NPDES permits from anti-degradation review, but did uphold challenges to provisions in the policy that exempted applicants seeking permits under Section 404 of the Clean Water Act from the anti-degradation review process.

On October 23, 2003, the Ohio Valley Environmental Coalition and other environmental groups filed a lawsuit against the U.S. Army Corps of Engineers (“Corps”) in the United States District Court for the Southern District of West Virginia. The lawsuit seeks to invalidate Nationwide Permit 21 (“NWP 21”), which is a general permit issued by the Corps under the Clean Water Act that authorizes the discharge of fill material into streams for purposes such as the construction of excess spoil valley fills and refuse impoundments. The plaintiffs maintain that NWP 21 was improperly issued and that valley fills and refuse impoundments must receive individual permits, which require more detailed permit applications and reviews. If the lawsuit is successful, there could be further delays in obtaining necessary permits for valley fills and refuse impoundments. The coal industry will likely intervene to protect its interest and to support the continued use of NWP 21.

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 oxide and mercury. Although these regulations apply directly to impose certain requirements for the permitting and operation of Massey’s mining facilities, by far their greatest impact on Massey and the coal industry generally is the effect of emission limitations on utilities and other Massey customers. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these air pollution 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 oxide.

Nitrogen oxide is 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.

National Ambient Air Quality Standards. In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards (“NAAQS”) for very fine particulate matter and ozone. The Court of Appeals for the D.C. Circuit 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 U.S. Supreme Court agreed in January 2000 to review the case. On February 27, 2001, the U.S. 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 NAAQS. In April 2003, the EPA issued a memorandum stating that it would finalize the NAAQS by the end of 2004 and solicited recommendations from the states. As a result of the finalization of these NAAQS, states that are not in compliance will have until 2007 to revise their State Implementation Plans (“SIPs”) to include provisions for the control of ozone precursors and/or particulate matter. Revised SIPs could require electric power generators to further reduce nitrogen oxide and sulfur dioxide 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 the Company and a corresponding decrease in the Company’s revenue and profits.

Acid Rain Control Provisions. 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:

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.

Nitrogen Oxide Emissions Reduction. In October 1998, the EPA finalized a rule requiring 22 states in the eastern U.S. that have or contribute to ambient air quality problems to make substantial reductions in nitrogen oxide emissions by June 1, 2004. The final rule was largely upheld by the U.S. Court of Appeals for the D.C. Circuit. Litigation in that Court continues, however, on the appropriateness of the budgets that EPA has established for several states of interest to Massey and its customers. To timely achieve reductions in nitrogen oxide emissions, 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 SIPs, 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.

Regional Haze Program. Along with 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 oxide and particulate matter. EPA’s final rule concerning best available retrofit technology (“BART”) is currently on remand to the EPA from the U.S. Court of Appeals for the D.C. 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. States will be given until 2007 to submit revised SIPs to address regional haze.

New Source Review Program. The U.S. Department of Justice, on behalf of the EPA, filed lawsuits against most of the owners of coal-fired plants in the East alleging that the owners performed non-routine maintenance that caused increased emissions that should have triggered the application of new source standards. Subsequently, in December 2002, the Bush Administration announced proposed rules to be issued by the EPA for reforming the Clear Air Act’s New Source Review (“NSR”) program, to increase energy efficiency and encourage emissions reductions. These new rules would offer facilities greater flexibility to improve and modernize their operations, allowing the continued operation of plants that might otherwise have been rendered uneconomical.

On August 26, 2003, the EPA released new rules in an effort to clarify the NSR provisions. Under these new rules, which were to take effect on December 26, 2003, a company might repair, replace or upgrade production equipment without triggering new pollution controls if the cost of parts and repairs do not exceed 20% of the replacement value of the unit being fixed. In late October 2003, a coalition of 14 states, the District of Columbia and numerous local governments filed suit in the U.S. Court of Appeals for the D.C. Circuit seeking to block implementation of the rules regarding repair, replacement or upgrade of production equipment, and a federal appeals court granted an emergency stay pending a review, which may not take place until late 2004. It is not clear if the new rules and/or the stay will impact the resolution of the outstanding EPA litigation against the eastern U.S. utilities, a number of which have reached settlements, as these suits were being prosecuted under the old NSR rules. These lawsuits, and the uncertainty around the new NSR rules, could require utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures which could adversely impact their demand for coal.

Hazardous Air Pollutants. In addition to emissions control requirements designed to control acid rain and to attain the more stringent NAAQS, the Clean Air Act also imposes standards on sources of hazardous air pollutants. Although these standards have not 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 would be required to control hazardous air pollution emissions, including mercury and other by-products of coal combustion, by no later than 2009. In December 2003, the EPA proposed a suite of

integrated air actions to significantly reduce levels of sulfur dioxide, nitrogen oxide and mercury. The Interstate Air Quality Rule would set a cap-and-trade program in 29 states to establish emissions limits for sulfur dioxide and nitrogen oxide by allowing utilities to buy and sell credits at a rate that would gradually cut emissions to 2.7 million tons of sulfur dioxide and 1.3 million tons of nitrogen oxide in 2015 to assist in achieving compliance with the NAAQS for 8-hour ozone and fine particulate. The Utility Mercury Reductions proposal would cut mercury emissions by nearly 70% through one of two possible methods. One option would involve cutting emissions through a cap-and-trade program and the other by installing maximum achievable control technology (“MACT”). Environmentalists have criticized the proposed cap-and-trade program, arguing that it falls short of the standards mandated by the Clean Air Act. Nevertheless, these proposals would directly affect coal producers, suppliers and utilities in the eastern and western regions of the U.S. and require revisions to the SIPs in many eastern states. The new proposal would set emissions limits based on coal rank, potentially giving the users of western sub-bituminous coal a significant competitive advantage over eastern bituminous coal users.

Other Proposals. 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 Clear Skies initiative, which remains before Congress. As proposed, this initiative is designed to reduce emissions of sulfur dioxide, nitrogen oxide and mercury from power plants. Alternative bills have been introduced that would place tighter 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 Bush Administration’s 2003 energy bill remains in the Senate after passing in the House in November 2003. The NMA supports this bill, which contains tax breaks for utilities to build new plants and retrofit existing plants with costly pollution controls for sulfur dioxide, nitrogen oxide and mercury, and contains further funds for clean coal programs that make federal funds, loans and loan guarantees available to utilities. It remains unclear if this, or an alternative energy bill, would be likely to pass in 2004.

The U.S. has not implemented the 1992 Framework Convention on Global Climate Change (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 U.S. would be required to reduce emissions to 93% of 1990 levels over a five-year period from 2008 through 2012. Although the U.S. 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 U.S. 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 voluntary reduction in greenhouse gas intensity over the next 10 years, approximately equivalent to the reduction that has occurred over each of the past two decades. If the U.S. were to enact comprehensive legislation focused on the mandatory reduction of greenhouse gas emissions, it would force a large reduction in coal-fired electricity generation, as technologies for carbon dioxide sequestration are not yet commercially available.

Massey’s 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. Massey currently has 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 federal Clean Water Act requires permits for operations that fill waters of the U.S. 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.

Massey believes it has obtained all the permits required for its current operations under the SMCRA, the Clean Water Act and the Clean Air Act and corresponding state laws. Massey believes that it is in compliance in all material respects with such permits, and routinely corrects in a timely fashion violations of which it receives notice in the normal course of operations. See Item 3, Legal Proceedings, for a discussion of orders issued to the Company’s subsidiaries to show cause why certain permits should not be revoked or suspended for alleged violations of surface mining laws. The expiration dates of the permits are largely immaterial as the law provides for a right of successive renewal. The cost of obtaining surface mining, clean water and air permits can vary widely depending on the scientific and technical demonstrations that must be made to obtain the permits. However, the cost of obtaining a permit is rarely more than $500,000 and the cost of obtaining a renewal is rarely more than $5,000. It is impossible to predict the full impact of future judicial, legislative or regulatory developments on Massey’s operations because the standards to be met, as well as the technology and length of time available to meet those standards, continue to develop and change.

In 2003, Massey spent approximately $23.9 million to comply with environmental laws and regulations of which $15 million was for surface reclamation. None of these expenditures was capitalized. Massey anticipates spending $20.6 million and $19.5 million in such non-capital expenditures in 2004 and 2005, respectively. Of these expenditures, $10.5 million and $9.5 million for 2004 and 2005, respectively, are anticipated to be for surface reclamation.

The Company believes, based upon present information available to it, that its accruals with respect to future environmental costs are adequate. For further discussion on costs, see Note 3 to the Notes to the Consolidated Financial Statements. However, the imposition of more stringent requirements under environmental laws or regulations, new developments or changes regarding site cleanup costs or the allocation of such costs among potentially responsible parties, or a determination that the Company is potentially responsible for the release of hazardous substances at sites other than those currently identified, could result in additional expenditures or the provision of additional accruals in expectation of such expenditures.

Safety. Stringent health and safety standards have been in effect since Congress enacted the Coal Mine Health and Safety Act of 1969. The Federal Mine Safety and Health Act of 1977 significantly expanded the enforcement of safety and health standards and imposed safety and health standards on all aspects of mining operations.

Most of the states in which Massey operates have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of U.S. industry. While regulation has a significant effect on Massey’s operating costs, its U.S. competitors are subject to the same degree of regulation.

Massey’s goal is to achieve excellent safety and health performance. Massey measures its success in this area primarily through the use of accident frequency rates. Massey believes that a superior safety and health regime is inherently tied to achieving productivity and financial goals. Massey seeks to implement this goal by: training employees in safe work practices; openly communicating with employees; establishing, following and improving safety standards; involving employees in establishing safety standards; and recording, reporting and investigating all accidents, incidents and losses to avoid reoccurrence.

Black Lung. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to: (i) current and former coal miners totally disabled from black lung disease; (ii) certain survivors of a miner who dies from black lung disease; and (iii) 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 addition to federal acts, the Company is 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 Massey’s exposure to black lung benefits liabilities. The Company, with the help of its consulting actuaries, intends to continue to monitor claims activity very closely and will modify the assumptions underlying the projection of its black lung liability should the results of such monitoring indicate it appropriate to do so.

Workers’ Compensation. The Company is liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in which it has operations. 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. In June 2003, the West Virginia legislature passed 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. The legislation, which became effective on July 1, 2003, is designed to improve practices within the Workers’ Compensation system by restructuring the Workers’ Compensation Division and limiting and tightening benefit payments. The legislation also authorizes additional funding to address solvency concerns. In Beirne v. Smith, the plaintiffs challenged provisions of this legislation that cut off workers’ compensation benefits at the age of 65 (or the “age necessary to receive federal old age retirement benefits” under the Social Security Act). On December 5, 2003, the Supreme Court of Appeals of West Virginia ruled that the legislation does not violate the equal protection clause of the West Virginia Constitution and upheld the statute. It is difficult to predict the impact the legislation will have on either future costs or premiums, nor can the Company predict how other judicial challenges to this legislation will be resolved.

Coal Industry Retiree Health Benefit Act of 1992. The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) provides for the funding of health benefits for certain United Mine Workers of America retirees. The Coal Act established the Combined Fund into which “signatory operators” and “related persons” are obligated to pay annual premiums for covered beneficiaries.

In 1995, in a case filed by the predecessor to the NMA on behalf of its members, the U.S. District Court for the Northern District of Alabama ordered the Social Security Administration (“SSA”) to recalculate the per-beneficiary premium that the Combined Fund charges assigned operators. The SSA applied the recalculated, lower premium to all assigned operators, including subsidiaries of the Company.

In 1996, the Combined Fund sued the SSA in the U.S. District Court for the District of Columbia seeking a declaration that the SSA’s original premium calculation was proper. On February 25, 2000, the Court ruled that the original, higher per beneficiary premium was proper. The SSA then retroactively applied the original, higher premium to various coal operators, including subsidiaries of the Company, for all plan years prior to October 1, 2003. However, the NMA and certain other coal operators, including subsidiaries of the Company, and the Combined Fund filed separate lawsuits in the U.S. District Courts for the Northern District of Alabama and the District of Columbia, respectively, seeking a determination regarding the SSA’s 2003 premium recalculation. These lawsuits have been transferred to the U.S. District Court for the District of Maryland. While it is difficult to predict the ultimate outcome of such litigation, the Company does not believe it will have a material impact on its cash flows, results of operations or financial condition. See Note 13 to the Notes to the Consolidated Financial Statements for further information.

In addition to the business risks described herein in Item 1, Business, under the headings “Customers and Coal Contracts,” “Competition,” “Environmental, Safety and Health Laws and Regulations” and in Item 7, Management’s Discussion and Analysis of Results of Operations and Financial Condition (“MD&A”) under “Critical Accounting Policies,” “Certain Trends and Uncertainties” and elsewhere in MD&A, Massey is subject to risk factors set forth below.

The level of Massey’s indebtedness could adversely affect its ability to grow and compete and prevent it from fulfilling its obligations under its contracts and agreements

At December 31, 2003, Massey had $788 million of total indebtedness outstanding, which represented 50.9% of its total book capitalization. The Company has significant debt, lease and royalty obligations. The Company’s ability to satisfy debt service, lease and royalty obligations and to effect any refinancing of its indebtedness will depend upon future operating performance, which will be affected by prevailing economic conditions in the markets that the Company serves as well as financial, business and other factors, many of which are beyond the Company’s control. The Company may be unable to generate sufficient cash flow from operations and future borrowings, or other financings may be unavailable in an amount sufficient to enable it to fund its debt service, lease and royalty payment obligations or its other liquidity needs.

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

The covenants in Massey’s credit facility and the indentures governing the notes impose restrictions that may limit Massey’s operating and financial flexibility

Massey’s asset based loan credit facility, entered into in January 2004, and the indentures governing its senior notes contain a number of significant restrictions and covenants that may limit the Company’s ability and its subsidiaries’ ability to, among other things:

Operating results below current levels or other adverse factors, including a significant increase in interest rates, could result in Massey being unable to comply with certain debt covenants. If Massey violates these covenants and is unable to obtain waivers from its lenders, Massey’s debt under these agreements would be in default and could be accelerated by the lenders. If the indebtedness is accelerated, Massey may not be able to repay its debt or borrow sufficient funds to refinance it. Even if Massey is able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to Massey. If Massey’s debt is in default for any reason, its cash flows, results of operations or financial condition could be materially and adversely affected. In addition, complying with these covenants may also cause Massey to take actions that are not favorable to holders of the notes and may make it more difficult for Massey to successfully execute its business strategy and compete against companies that are not subject to such restrictions.

Coal markets are highly competitive and affected by factors beyond Massey’s control

Massey competes with coal producers in various regions of the U.S. for domestic sales and with both domestic and overseas producers for sales to international markets. Continued domestic demand for Massey’s coal and the prices that it will be able to obtain primarily will depend upon coal consumption patterns of the domestic electric utility industry and the domestic steel industry. Consumption by the domestic utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel supplies including nuclear, natural gas, oil and renewable energy sources, including hydroelectric power. Consumption by the domestic steel industry is primarily affected by the demand for U.S. steel. Massey’s sales of metallurgical coal are dependent on the continued financial viability of domestic steel companies and their ability to compete with steel producers abroad. The cost of ocean transportation and the valuation of the U.S. dollar in relation to foreign currencies significantly impact the relative attractiveness of Massey’s coal as it competes on price with other foreign coal producing sources. See Item 1, Business, under the heading “Competition”, for further discussion.

Coal prices are affected by a number of factors and may vary dramatically by region

Coal prices are influenced by a number of factors and may vary dramatically by region. The two principal components of the price of coal are the price of coal at the mine, which is influenced by mine operating costs and coal quality, and the cost of transporting coal from the mine to the point of use. The cost of mining the coal is influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. Underground mining is generally more expensive than surface mining as a result of high capital costs, including costs for modern mining equipment and construction of extensive ventilation systems and higher labor costs due to lower productivity. Massey currently engages in four principal coal mining techniques: underground room and pillar mining, underground longwall mining, surface mining and highwall mining. Because underground longwall mining, surface mining and highwall mining are high-productivity, low-cost mining methods, Massey seeks to increase production from its use of these methods to the extent permissible and cost

effective. The Company presently operates 30 active underground mines, including 4 longwall mines, and 13 active surface mines, with 7 highwall miners. See Item 1, Business, under the headings “Mining Methods” and “Mining Operations” for further discussion.

Reduced demand from Massey’s largest customers could have an adverse impact on Massey’s ability to achieve its projected revenue. When Massey’s contracts with its customers reach expiration, there can be no assurance that the customers either will extend or enter into new long-term contracts or, in the absence of long-term contracts, that they will continue to purchase the same amount of coal as they have in the past or on terms, including pricing terms, as favorable as under existing agreements. See Item 1, Business, under the heading “Customers and Coal Contracts” for further discussion.

Massey faces numerous uncertainties in estimating its economically recoverable coal reserves, and inaccuracies in its 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 Massey’s control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about the Company’s reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by the Company’s staff. Some of the factors and assumptions that impact economically recoverable reserve estimates include:

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. As a result, the Company’s estimates may not accurately reflect its actual reserves. Actual production, revenues and expenditures with respect to its reserves will likely vary from estimates, and these variances may be material.

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

At December 31, 2003, less than 5% of Massey’s total workforce was represented by the United Mine Workers of America. Six of Massey’s coal preparation plants and one of its smaller surface mines have a workforce that is represented by a union. In fiscal 2003, these six preparation plants handled approximately 35% of Massey’s coal production. There may be an increased risk of strikes and other related work actions, in addition to higher labor costs, associated with these operations. Massey has experienced some union organizing campaigns at some of its open shop facilities within the past five years. If some or all of Massey’s current open shop operations were to become union represented, Massey could be subject to additional risk of work stoppages and higher labor costs. Increased labor costs or work stoppages could adversely affect the stability of production and reduce its net income.

Severe weather, including flooding and excessive ice or snowfall, when it occurs, can adversely affect Massey’s ability to produce, load and transport coal.

Shortages of skilled labor in the Central Appalachian coal industry may 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 the Company to hire a large number of mine workers with less experience than its existing workforce. While the Company did not experience a comparable shortage in 2003, if another such shortage of skilled labor were to arise, its productivity could decrease and its costs could increase. Such a lack of skilled miners could have an adverse impact on Massey’s labor productivity and cost and its ability to expand production in the event there is an increase in the demand for coal.

If the coal industry experiences overcapacity in the future, the Company’s profitability could be impaired

Historically, a growing coal market and increased demand for coal attract new investors to the coal industry, spur the development of new mines and result in added production capacity throughout the industry, all of which can lead to increased competition and lower coal prices. Similarly, an increase in future coal prices could encourage the development of expanded capacity by new or existing coal producers. Any overcapacity could reduce coal prices and therefore reduce the Company’s revenues.

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect the Company’s cash flows, results of operations or financial condition

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect the Company’s cash flows, results of operations or financial condition. The Company’s business is affected by general economic conditions, fluctuations in consumer confidence and spending, and market liquidity, which can decline as a result of numerous factors outside of its control, such as terrorist attacks and acts of war. Future terrorist attacks against U.S. targets, rumors or threats of war, actual conflicts involving the U.S. or its allies, or military or trade disruptions affecting the Company’s customers may materially adversely affect its operations. As a result, there could be delays or losses in transportation and deliveries of coal to the Company’s customers, decreased sales of its coal and extension of time for payment of accounts receivable from its customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the U.S. In addition, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could have a material impact on the Company’s cash flows, results of operations or financial condition.

Ash. Impurities consisting of iron, aluminum and other incombustible matter that are contained in coal. Since ash increases the weight of coal, it adds to the cost of handling and can affect the burning characteristics of coal.

Bituminous coal. The most common type of coal with moisture content less than 20% by weight and heating value of 10,500 to 14,000 Btu per pound. It is dense and black and often has well-defined bands of bright and dull material.

British thermal unit, or “Btu.” A measure of the thermal energy required to raise the temperature of one pound of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

Central Appalachia. Coal producing states and regions of eastern Kentucky, eastern Tennessee, western Virginia and southern West Virginia.

Coke. A hard, dry carbon substance produced by heating coal to a very high temperature in the absence of air. Coke is used in the manufacture of iron and steel. Its production results in a number of useful byproducts.

Continuous miner. A mining machine used in underground and highwall mining to cut coal from the seam and load it onto conveyors or into shuttle cars in a continuous operation.

Fossil fuel. Fuel such as coal, petroleum or natural gas formed from the fossil remains of organic material.

Highwall Mining. Described in Item 1, Business, under the heading “Mining Methods.”

High vol met coal. Coal that averages approximately 35% volatile matter. Volatile matter refers to the impurities that become gaseous when heated to certain temperatures.

Industrial coal. Coal used by industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

Longwall mining. Described in Item 1, Business, under the heading “Mining Methods.”

Low vol met coal. Coal that averages approximately 20% volatile matter. Volatile matter refers to the impurities that become gaseous when heated to certain temperatures.

Metallurgical coal. The various grades of coal suitable for carbonization to make coke for steel manufacture. Also known as “met” coal, it possesses four important qualities: volatility, which affects coke yield; the level of impurities, which affects coke quality; composition, which affects coke strength; and basic characteristics, which affect coke oven safety. Met coal has a particularly high Btu, but low ash content.

Nitrogen oxide (NOx). A gas formed in high temperature environments such as coal combustion. It is a harmful pollutant that contributes to acid rain.

Overburden. Layers of earth and rock covering a coal seam. In surface mining operations, overburden is removed prior to coal extraction.

Overburden ratio. The amount of overburden that must be removed to excavate a given quantity of coal. It is commonly expressed in cubic yards per ton of coal or as a ratio comparing the thickness of the overburden with the thickness of the coal bed.

Pillar. An area of coal left to support the overlying strata in a mine; sometimes left permanently to support surface structures.

Preparation plant. Usually located on a mine site, although one plant may serve several mines. A preparation plant is a facility for crushing, sizing and washing coal to prepare it for use by a particular customer. The washing process has the added benefit of removing some of the coal’s sulfur content.

Probable reserves. Described in Item 2, Properties, under the heading “Coal Reserves.”

Proven reserves. Described in Item 2, Properties, under the heading “Coal Reserves.”

Reclamation. The process of restoring land and the environment to their approximate original state following mining activities. The process commonly includes “recontouring” or reshaping the land to its approximate original appearance, restoring topsoil and planting native grass and ground covers. Reclamation operations are usually underway before the mining of a particular site is completed. Reclamation is closely regulated by both state and federal law.

Reserve. Described in Item 2, Properties, under the heading “Coal Reserves”.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place. Same as “top.”

Room and pillar mining. Described in Item 1, Business, under the heading “Mining Methods.”

Scrubber (flue gas desulfurization unit). Any of several forms of chemical/physical devices that operate to neutralize sulfur compounds formed during coal combustion. These devices combine the sulfur in gaseous emissions with other chemicals to form inert compounds, such as gypsum, that must then be removed for disposal. Although effective in substantially reducing sulfur from combustion gases, scrubbers require about 6% to 7% of a power plant’s electrical output and thousands of gallons of water to operate.

Steam coal. Coal used by power plants and industrial steam boilers to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

Sulfur. One of the elements present in varying quantities in coal that contributes to environmental degradation when coal is burned. Sulfur dioxide is produced as a gaseous by-product of coal combustion.

Sulfur content. Coal is commonly described by its sulfur content due to the importance of sulfur in environmental regulations. “Low sulfur” coal has a variety of definitions but typically is used to describe coal consisting of 1.0% or less sulfur. A majority of the Company’s Appalachian reserves are of low sulfur grades.

Sulfur dioxide (SO₂). A gas formed in high temperature environments such as coal combustion. It is a harmful pollutant that contributes to acid rain.

Surface mining. Described in Item 1, Business, under the heading “Mining Methods.”

Tons. A “short” or net ton is equal to 2,000 pounds. A “long” or British ton is 2,240 pounds; a “metric” tonne is approximately 2,205 pounds. The short ton is the unit of measure referred to in this Form 10-K.

Underground mine. Also known as a “deep” mine. Usually located several hundred feet below the earth’s surface, an underground mine’s coal is removed mechanically and transferred by shuttle car or conveyor to the surface.

Unit train. A train of a specified number of cars carrying only coal. A typical unit train can carry at least 10,000 tons of coal in a single shipment.

Utility coal. Coal used by power plants to produce electricity or process steam. It generally is lower in Btu heat content and higher in volatile matter than metallurgical coal.

Operations of Massey and its subsidiaries are conducted on both owned and leased properties totaling more than 900,000 acres in West Virginia, Kentucky, Virginia and Tennessee. In addition, certain owned or leased properties of Massey and its subsidiaries are leased or subleased to third party tenants. Massey’s current practice is to obtain a title review from a licensed attorney prior to purchasing or leasing property. It generally has not obtained title insurance in connection with acquisitions of coal reserves. In many cases, property title is warranted by the seller or lessor. Separate title confirmation sometimes is not required when leasing reserves where mining has occurred previously. Massey and its subsidiaries currently own or lease the equipment that is utilized in their mining operations. The following table describes the location and general character of the major existing facilities, exclusive of mines, coal preparation plants and their adjoining offices.

Massey estimates that, as of December 31, 2003, it had total recoverable reserves of approximately 2.2 billion tons consisting of both proven and probable reserves. “Reserves” are defined by the 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 Massey’s reserves are classified as proven reserves. “Proven (Measured) Reserves” are defined by the SEC Industry Guide 7 as reserves for which (a) 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 (b) 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 Massey’s reserves are classified as probable reserves. “Probable reserves” are defined by the 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 Massey’s 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 Massey’s 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 Massey’s reserve holdings are owned and require no royalty or per ton payment to other parties. The average royalties for coal reserves from the Company’s producing properties (owned and leased) was approximately 4.2% of produced coal revenue for the year ended December 31, 2003.

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, 2003:

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

See Item 1. Business, of this report for additional information regarding the coal operations and properties of Massey.

Certain information required by this Item 3 is contained in Note 20, “Contingencies and Commitments,” of the Consolidated Financial Statements in this report and is incorporated herein by reference.

On April 17, 2002, five subsidiaries of the Company, along with other coal and chemical companies, were sued in an action styled Denver Pettry, et al. v. Peabody Holding Company, et al., 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 against the chemical companies, and seek to recover unquantified compensatory and punitive damages. The Company believes it has significant defenses to the claims made by 7 plaintiffs against subsidiaries of the Company, and is defending the case vigorously. Discovery in this case continues. The Company does not view this case as material and does not plan to report on it in future filings absent unexpected developments that could have a material impact on the Company.

On April 23, 2002, the WVDEP filed a civil action against the Company and its subsidiary, Massey Coal Services, Inc., in connection with the discharge of approximately 135,000 gallons of coal slurry into a tributary

stream of the Big Sandy River in eastern Kentucky. In November 2003, the parties settled this action for a de minimus amount.

On October 22, 2003, WVDEP brought suit against three Massey subsidiaries, Independence Coal Company and Omar Mining Company in the Circuit Court of Boone County, West Virginia, and Marfork Coal Company in the Circuit Court of Raleigh County, West Virginia. The suits allege various violations of waste and clean water laws in 2001 and 2002 and seek unspecified amounts in fines as well as injunctive relief to compel compliance. Independence, Omar and Marfork believe that compliance has been achieved for these past violations and will defend the suits vigorously.

Regulatory authorities implementing the 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 the willful or unwarranted conduct of the Company under the surface mining laws, its surface mining permits may be either suspended or revoked. Some of the Company’s 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 the Company, if any, cannot presently be reasonably estimated.

As of March 1, 2004, the WVDEP had issued show cause orders with respect to active permits at the Company’s Alex Energy, Inc., Bandmill Coal Corporation, Green Valley Coal Company, Independence Coal Company, Inc., Marfork Coal Company, Inc. and Omar Mining Company subsidiaries. In addition, the Kentucky Natural Resources and Environmental Protection Cabinet (“KNREPC”) had issued a show cause order with respect to an active permit at Sidney Coal Company. A suspension of these operations could adversely affect the Company’s financial results to the extent it is unable to generate the lost production from its other operations. WVDEP has also issued show cause orders with respect to idled permits at certain of the Company’s subsidiaries.

The Company does not expect that these actions, either individually or collectively, will have a material impact on its cash flows, results of operations or financial condition.

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. The Company does not believe the impact of the suspensions is likely to be material. The Company has not accrued lost profits for any WVDEP or KNREPC show cause order mentioned herein because the outcome of these matters cannot be reasonably estimated. The cost of defending these matters is not material.

If the Company is 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 its overall operations. If a subsidiary has a permit revoked and a bond forfeited, it may be prohibited from obtaining permits for future operations. Additionally, pursuant to the ownership and control provisions of the surface mining laws, operations affiliated with that subsidiary may also be deemed ineligible to receive new permits. An inability by the Company to receive permits necessary to mine would be material. The Company does not expect that any of these proceedings will result in permit revocation or bond forfeiture.

The Company continues to make efforts to improve its environmental performance. At the direction of the Public and Environmental Policy Committee of the Company’s Board of Directors, the Company obtained a comprehensive environmental audit conducted by an independent environmental auditing firm and continues to conduct environmental audits that are regularly reviewed with the Committee. The Company has also implemented an improved environmental management system. The Company has retained an independent environmental auditing firm to conduct a follow-on audit in 2004 and believes that continuing follow-on audits should be conducted every 2 to 3 years.

Massey and its subsidiaries, incident to their normal business activities, are parties to a number of other legal proceedings. While Massey cannot predict the outcome of these proceedings, it does not believe that any liability arising from these matters individually or in the aggregate should have a material impact upon the consolidated cash flows, results of operations or financial condition of Massey. The Company also is party to lawsuits and other legal proceedings related to the non-coal businesses previously conducted by Fluor Corporation (renamed Massey Energy Company) but now conducted by New Fluor. Under the terms of the Distribution Agreement entered into by the Company and New Fluor as of November 30, 2000, in connection with the Spin-Off of New Fluor by the Company, New Fluor has agreed to indemnify the Company with respect to all such legal proceedings and has assumed their defense.

There were no matters submitted to a vote of security holders of the Company through a solicitation of proxies or otherwise during the fourth quarter of the Company’s fiscal year ended December 31, 2003.

Mr. Blankenship has been a Director since 1996 and the Chairman, Chief Executive Officer and President of Massey since November 30, 2000. He has been Chairman, Chief Executive Officer and President of A.T. Massey since 1992. He was formerly the President and Chief Operating Officer of A.T. Massey from 1990 and President of the Company’s subsidiary, Massey Coal Services, Inc., from 1989. He joined the Company’s subsidiary, Rawl Sales & Processing Co., in 1982. He is also a director of the National Mining Association.

Mr. Gardner has been Executive Vice President and Chief Administrative Officer of Massey and A.T. Massey since July 1, 2002. From February 26, 2000 to June 30, 2002, he was engaged in the private practice of law as a sole practitioner. Mr. Gardner first joined A.T. Massey in 1993 as General Counsel and served in that position until February 25, 2000. Mr. Gardner also served as a director of Massey from November 30, 2000 until August 1, 2002.

Mr. Adkins has been Senior Vice President and Chief Operating Officer of Massey since July 1, 2003. Mr. Adkins joined the Company’s subsidiary, Rawl Sales & Processing Co., in 1985 to work in underground mining. Since that time, he has served in positions of increasing responsibility with the Company, including section foreman, plant supervisor, President of Massey’s Eagle Energy subsidiary, Director of Production of Massey Coal Services and, most recently, Vice President of Underground Production.

Mr. Phillips has been Senior Vice President and Chief Financial Officer of Massey since September 1, 2003. Previously, he served as Vice President and Treasurer of Massey since November 30, 2000. He also has been Vice President and Treasurer of A.T. Massey since October 2000. He served as Vice President of A.T. Massey from January 1992 with responsibilities for purchasing, risk management, benefits and administration. Mr. Phillips joined A.T. Massey in 1981 and through 1992, served in the roles of Corporate Treasurer, Manager of Export Sales and Corporate Human Resources Manager. Prior to joining A.T. Massey, Mr. Phillips’ background included banking and investments.

Mr. Short has been Senior Vice President, Group Operations of Massey since November 30, 2000. He also has been Senior Vice President, Group Operations of A.T. Massey since May 1995. Mr. Short was formerly Chairman of the Board and Chief Coordinating Officer of Massey Coal Services from April 1991 to April 1995. Mr. Short joined A.T. Massey in 1981.

Mr. Dostart has been Vice President, General Counsel & Secretary of Massey since May 5, 2003. Prior to joining Massey, he served from 1997 to 2003 as General Counsel & Assistant Secretary for Alliance Coal, LLC and its subsidiaries in Lexington, Kentucky. Mr. Dostart previously served as Vice President, General Counsel & Secretary for National Auto Credit, Inc. (formerly Agency Rent-A-Car), and as an attorney with Amoco Corporation, Diamond Shamrock, Inc., and the law firms of Jones, Day, Reavis & Pogue and Arter & Hadden.

Mr. Jarosinski has been Vice President, Finance of Massey since November 30, 2000 and Chief Compliance Officer of Massey since December 9, 2002. He also has been Vice President, Finance of A.T. Massey since September 1998. From November 30, 2000 through December 9, 2002, Mr. Jarosinski was Chief Financial Officer of Massey and served in the same role for A.T. Massey from September 1998 through December 2002. Mr. Jarosinski was formerly Vice President, Taxation of A.T. Massey from 1997 to August 1998 and Assistant Vice President, Taxation of A.T. Massey from 1993 to 1997. Mr. Jarosinski joined A.T. Massey in 1988. Prior to joining A.T. Massey, Mr. Jarosinski held various positions in public accounting.

Mr. Poma has been Vice President, Human Resources of Massey since April 1, 2003. Mr. Poma served as Corporate Counsel for A.T. Massey from 1996 until March 2000 and as Senior Corporate Counsel for A.T. Massey from March 2000, and Massey from November 30, 2000 through March 2003. Prior to joining A.T. Massey in 1996, Mr. Poma practiced law from 1993 to 1996 at the firm of Midkiff & Hiner in Richmond, Virginia, specializing in employment law. From 1989 to 1993, he practiced law at the firm of Jenkins, Fenstermaker, Krieger, Kayes & Farrell in Huntington, West Virginia.

Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters

The Company’s stock is listed on the New York Stock Exchange. The Company’s Common Stock trading symbol is MEE.

At February 27, 2004, there were 75,779,279 shares outstanding and approximately 9,078 shareholders of record of Massey’s common stock.

The dividends paid and the stock prices of Massey stock for the past two fiscal years is set forth below.

The following table sets forth the high and low sales prices per share of Common Stock on the New York Stock Exchange, based upon published financial sources, and the dividends declared on each share of Common Stock for the quarter indicated.

The Company’s current dividend policy anticipates the payment of quarterly dividends in the future. The Company is restricted by its asset based revolving credit facility and its 6.625% senior notes to paying dividends not in excess of $25 million annually so long as no default exists under the facility or the 6.625% senior notes, as the case may be, or would result thereunder from paying such dividend. There are no other restrictions, other than those set forth under Delaware law, the Company’s state of incorporation, on the Company’s ability to declare and pay dividends. The declaration and payment of dividends to holders of Common Stock will be at the discretion of the Board of Directors and will be dependent upon the future earnings, financial condition, and capital requirements of the Company.

Mellon Investor Services LLC acts as transfer agent and registrar for the Massey Common Stock.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Effective January 1, 2002, the Company changed to a calendar-year basis of reporting financial results. For comparative purposes, the reported audited consolidated results of operations and cash flows for the 2001 annual period is for the twelve months ended October 31. As a requirement of the change in fiscal year, the Company is reporting consolidated results of operations and cash flows for a special transition period, the two months ended December 31, 2001.

Massey operates coal mines and processing facilities in Central Appalachia, which generate revenues and cash flow through the mining, processing and selling of low sulfur coal of steam and metallurgical grades. The Company also generates income and cash flow through other coal-related businesses, including the operation of material handling facilities and a synfuel production plant.

The Company experienced a significant increase in costs during the past 5-year period, with Average cash cost per ton sold increasing from $21.28 in fiscal 1999 to $28.23 in fiscal 2003 (a reconciliation of these non-GAAP figures is presented in footnote 6 of Item 6. Selected Financial Data). The increased cost level is mainly due to materially higher supply, labor and benefit costs, and lower operating productivity. The Company’s management is focused on reducing costs and employing higher productivity mining methods, such as longwall mining, surface mining and highwall mining.

The Company reported an after-tax loss for the year ended December 31, 2003 of $32.3 million, or $0.43 per share, before a $7.9 million, or $0.11 per share, charge to record the cumulative effect of an accounting change. Including this charge, the Company reported a loss of $40.2 million, or $0.54 per share, compared to a loss of $32.6 million, or $0.44 per share, in 2002. The 2003 loss included a pre-tax gain of $17.7 million related to the settlement of a property and business interruption claim and a pre-tax charge of $6.3 million related to the write off of deferred financing costs, having a net impact of $0.09 per share. The 2002 loss included pre-tax charges totaling $49.4 million, or $0.42 per share, related to the reserve taken subsequent to the Harman jury verdict, the Duke arbitration award and the write-off of capitalized development costs.

During 2003, the Company began a realignment of its debt structure. It issued $132 million of 4.75% convertible senior notes and replaced its prior secured credit facilities with an issuance of $360 million of unsecured 6.625% senior notes. On January 20, 2004, the Company established an asset-based revolving credit facility that provides for borrowings of up to $130 million, depending on the level of eligible inventory and accounts receivable, and provides a $100 million sublimit for the issuance of letters of credit.

In the second half of 2003, demand for coal increased significantly due to a combination of conditions in the U.S. and worldwide that caused a shortage of certain grades of coal, with a particularly acute shortage of metallurgical grade coal. This situation has continued and accelerated in early 2004. Prices for the grades of coal sold by Massey have consequently risen materially since mid-2003. Massey’s ability to benefit from these price increases will be limited in 2004, as the majority of the Company’s planned coal production was committed prior to the market improvements. In order to maximize its revenues in 2004, the Company has begun shifting some production from the utility market to the export metallurgical market. These tons were replaced primarily by steam coal purchased at current market prices. The Company is also focused on increasing its capacity of surface mine utility grade coal to meet increased market demand.

Produced coal revenue for the year ended December 31, 2003 decreased 4 percent to $1,262.1 million compared with $1,318.9 million for the year ended December 31, 2002. Two factors that impacted produced coal revenue for 2003 compared to 2002 were:

The average per ton sales price decreased as some of the higher priced contracts signed in 2001 expired in 2002 and were replaced by lower priced contracts, and as a result of lower shipments of metallurgical and other higher quality coal in 2003 compared to 2002. Metallurgical coal demand fell in 2003 due to weakness in the domestic steel industry throughout most of the year.

Freight and handling revenue decreased $20.2 million, or 18 percent, to $91.8 million for 2003 compared with $112.0 million for 2002, due to a decrease in tons sold over the comparable periods and less shipments to customers where freight and handling costs are paid by the Company.

Purchased coal revenue decreased $1.7 million to $115.3 million for 2003 from $117.0 million for 2002, as the Company purchased and sold 3.1 million tons of coal in 2003 compared to 3.3 million tons in 2002. Massey purchases varying amounts of coal each year 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, decreased to $65.9 million for 2003 from $78.8 million for 2002. The decrease was primarily due to a decrease in contract buyout payments from 2002, offset by increased earnings related to the operations of Appalachian Synfuel, LLC, in 2003.

Insurance settlement revenue consists of $21 million of proceeds received for the settlement of a property and business interruption claim, which, after adjusting for a previously booked receivable and claim settlement expenses, resulted in a gain of $17.7 million (pre-tax) during 2003.

Cost of produced coal revenue decreased approximately 4 percent to $1,115.9 million for 2003 from $1,166.2 million for 2002. Cost of produced coal revenue on a per ton of coal sold basis decreased slightly in 2003 compared with 2002, primarily as the result of a charge of $25.6 million (pre-tax) related to an adverse jury verdict in the Harman Mining Corporation action in West Virginia and a charge of $10.6 million (pre-tax) related to the Duke arbitration award. The Company experienced lower costs during the second quarter of 2003, while costs in the other three quarters were negatively impacted by a variety of operational and shipping issues. The most significant source of higher costs related to the Company’s longwall operations. Several longwall equipment moves took longer than planned, hard cutting at certain locations was experienced, and a methane gas pocket closed one of the mines for a period of time, reducing overall productivity at various times during the year. The Company is attempting to improve productivity at the longwall mines by adding higher horsepower shearers in order to facilitate cutting in more difficult coal seams. In addition, bad weather slowed some surface mine operations and prevented timely shipments by rail or truck. Surface mine production was also impacted by higher than anticipated overburden ratios, slow receipt of required permits, higher diesel fuel costs and increased trucking costs due to new West Virginia regulations. The Company purchased new surface mine equipment in late 2003 and early 2004 to increase capacity and productivity at several surface mines, including several newly permitted surface mines that are expected to have low overburden ratios and less trucking required. Expenses were further impacted by the continuation of employee medical cost inflation, including workers’ compensation costs and higher bonding and insurance costs. In response to the higher medical costs, in 2003 the Company implemented a new employee medical plan that it anticipates will significantly mitigate the effects of medical cost inflation in 2004.

Freight and handling costs decreased $20.2 million, or 18 percent, to $91.8 million for 2003 compared with $112.0 million for 2002, due to a decrease in tons sold over the comparable periods and fewer shipments to customers where freight and handling costs are paid by the Company.

Cost of purchased coal revenue decreased $2.3 million to $117.3 million for 2003 from $119.6 million for 2002, due to the decrease in purchased tons sold.

Depreciation, depletion and amortization decreased by 5 percent to $196.5 million in 2003 compared to $207.7 million for 2002. The decrease was primarily due to a $13.2 million (pre-tax) write-off of mine development costs at certain idled mines in 2002. See Note 17 to the Notes to Consolidated Financial Statements for further discussion of impairment charges.

Selling, general and administrative expenses were $39.7 million for 2003 compared to $40.1 million for 2002. Professional fees and corporate bonus accruals were less in 2003 compared to 2002, while long term executive compensation expense increased due to the increase in Massey’s stock price during 2003.

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, decreased $1.4 million from $11.2 million for 2002 to $9.8 million for 2003.

Interest expense increased to $48.3 million for 2003 compared with $35.3 million for 2002. The increase was primarily due to a higher weighted average interest rate on our variable rate borrowings and higher levels of debt outstanding in 2003 compared to 2002. In addition, as the Company realigned its debt in the fourth quarter of 2003 to obtain longer maturities and favorable longer term rates, $6.3 million of deferred financing costs related to the cancellation of its bank debt arranged in the third quarter of 2003 were written off.

Income tax benefit was $28.3 million for 2003 compared with $24.9 million for 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 2003 related to the required adoption of Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”) effective January 1, 2003. As a result of adopting Statement 143, the Company recognized a decrease in total reclamation liability of $13.1 million and a decrease in net deferred tax liability of $5.0 million. The Company 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, the Company recognized a decrease in mining properties owned in fee and leased 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 liabilities. See Note 3 to the Notes to Consolidated Financial Statements for further information.

Produced coal revenue for the year ended December 31, 2002, increased 10 percent 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:

Realized prices for the Company’s 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 the Company was 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 U.S. during the winter of 2001-2002 significantly reduced demand for all grades of coal.

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

Revenue from purchased coal sales increased $67.5 million, or 58 percent, from $49.5 million in 2001 to $117 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. Massey purchases 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 percent 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 19 percent

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 Harman Mining Corporation lawsuit in West Virginia, 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 the Company’s longwalls and 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, the Company increased staffing and benefits costs in order to increase production. However, due to the subsequent market weakness, the Company reduced total workforce during the first quarter of 2002 by approximately 7 percent 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.

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

Costs of purchased coal revenue increased $72.5 million to $119.5 million in 2002 from $47 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 percent 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. See Note 17 to the Notes to Consolidated Financial Statements for further discussion of impairment charges.

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 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, increased $3.5 million from $7.7 million for 2001 to $11.2 million for 2002.

Interest income decreased to $4.5 million for 2002 compared with $8.7 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 Harman Mining Corporation action in Virginia 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.

At December 31, 2003, the Company’s available liquidity was $149.4 million, which consisted of cash and cash equivalents of $88.8 million and $60.6 million availability under the Company’s then existing accounts receivable securitization program.

On January 31, 2003, the Company entered into a borrowing program secured by its accounts receivable. The amount available to be borrowed under the program was up to $80 million, depending on the level of eligible receivables and restrictions on concentrations of receivables. At December 31, 2003, there were no borrowings outstanding under the program. The program was scheduled to expire in July 2004. In January 2004, the Company cancelled this facility and replaced it with a $130 million asset-based revolving credit facility, which is discussed below.

In February 2003, Massey made an open market purchase and retired $3 million of principal amount of 6.95% senior notes due 2007 (the “6.95% Senior Notes”) at a cost of $2.4 million plus accrued interest. At December 31, 2003, the Company had $283 million of 6.95% Senior Notes outstanding (see Note 8 in the Notes to the Consolidated Financial Statements for further discussion of the 6.95% Senior Notes).

In May 2003, the Company began an extensive effort to realign its balance sheet and take advantage of prevailing low interest rates and high investor demand for corporate debt. On May 29, 2003, the Company issued $132.0 million of 4.75% convertible senior notes due 2023 (the “4.75% Convertible Senior Notes”) in a private placement. The proceeds of this transaction were used to pay down outstanding borrowings under the $400 million aggregate revolving credit facilities in effect at that time. The Company subsequently filed a Registration Statement on Form S-3 with the SEC to register these notes. The 4.75% Convertible Senior Notes are unsecured obligations ranking equally with all other unsecured senior indebtedness of the Company. Massey may redeem some or all of the 4.75% Convertible Senior Notes at any time on or after May 20, 2009 (see Note 8 to the Notes to the Consolidated Financial Statements for further discussion on the 4.75% Convertible Senior Notes). Additionally, see the Indenture and the First Supplemental Indenture, both dated May 29, 2003, filed as Exhibits 4.1 and 4.2, respectively, to the Company’s current report on Form 8-K filed with the SEC on May 30, 2003, for further information on the 4.75% Convertible Senior Notes issuance.

On July 2, 2003, the Company completed the refinancing of its $400 million aggregate revolving credit facilities that were scheduled to expire on November 25, 2003. The Company executed a $355 million secured financing package consisting of a $105 million revolving credit facility and a $250 million term loan, secured by substantially all of the assets of the Company. Proceeds of the secured term loan were used to repay borrowings under the revolving credit facilities and also to collateralize the issuance of letters of credit (see Note 8 to the Notes to the Consolidated Financial Statements for further discussion of the refinancing).

On November 10, 2003, the Company issued $360 million of 6.625% senior notes due 2010 (the “6.625% Senior Notes”) in a private placement. The Company subsequently filed a Registration Statement on Form S-4 with the SEC to register these notes. The 6.625% Senior Notes are unsecured obligations ranking equally with all other unsecured senior indebtedness of the Company and are guaranteed by substantially all of Massey’s current and future subsidiaries. At any time after November 15, 2007, the Company may redeem all or part of the 6.625% Senior Notes. Part of the proceeds of this issuance was used to permanently repay the $249.4 million outstanding under its $250 million secured term loan and to collateralize the $34.3 million letters of credit then outstanding under the revolving credit facility sublimit. The Company then cancelled its $105 million

revolving credit facility, effectively terminating the $355 million secured facility (see Note 8 to the Notes to the Consolidated Financial Statements for further discussion of the 6.625% Senior Notes issuance). Additionally, see the Indenture dated November 10, 2003, filed as Exhibit 4.1 to the Company’s current report on Form 8-K filed with the SEC on November 12, 2003, for further information on the 6.625% Senior Notes issuance.

On November 10, 2003, the Company entered into a fixed interest rate to floating interest rate swap agreement with a highly rated financial institution covering a notional amount of debt of $240 million. The Company designated this swap as a fair value hedge of a portion of its 6.625% Senior Notes. Under the swap, the Company will receive interest payments at a fixed rate of 6.625% and will pay a variable rate that is based on six-month LIBOR plus 216 basis points. The initial term of this swap agreement expires on November 15, 2010, however the counterparty to the swap agreement has an option to terminate the swap, in whole or in part, after November 15, 2007 upon payment of an early termination fee equal to the early redemption premium on the 6.625% Senior Notes.

On January 20, 2004, the Company established a new asset-based revolving credit facility, which replaced the existing $80 million accounts receivable-based financing program and provided for borrowings of up to $130 million, depending on the level of eligible inventory and accounts receivable. It includes a $100 million sublimit for the issuance of letters of credit. Initially, this facility will support $35.7 million of letters of credit previously supported by cash collateral. The facility is secured by the Company’s accounts receivable, eligible coal inventories located at its facilities and on consignment at customers’ facilities, and other intangibles. At February 29, 2004, total availability was approximately $111 million based on qualifying inventory and accounts receivable. This new facility will provide the Company with increased liquidity and letter of credit capacity. The credit facility has a five-year term ending in January 2009.

Moody’s and S&P rate Massey’s long-term debt. As of February 29, 2004, Moody’s and S&P rated the 6.95% Senior Notes and the 4.75% Convertible Senior Notes B1 and B+, respectively, and the 6.625% Senior Notes Ba3 and BB, respectively. On March 11, 2004, S&P placed the Company’s ratings on Credit Watch with negative implications.

Net cash provided by operating activities was $15.4 million for 2003 compared to $122.5 million for 2002. Cash provided by operating activities reflects net losses adjusted for non-cash charges and changes in working capital requirements. The decrease of $107.1 million in net cash provided by operating activities in 2003 compared with 2002 is primarily due to an increase in the amount of restricted funds pledged as collateral to support outstanding letters of credit and other obligations of $110.1 million.

Net cash utilized by investing activities was $144.0 million and $122.0 million for 2003 and 2002, respectively. The cash used in investing activities reflects capital expenditures in the amount of $164.4 million and $135.1 million for 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 2003 the Company leased $6.4 million of mining equipment through operating leases and $16.3 million of mining equipment through capital leases, compared to $10.6 million through operating leases for 2002. Additionally, 2003 and 2002 included $20.4 million and $13.1 million, respectively, of proceeds provided by the sale of assets.

Financing activities primarily reflect changes in short- and long-term financing for 2003 and 2002, as well as the exercising of stock options and payment of dividends. Net cash provided by financing activities in 2003 was $214.6 million. Net cash utilized by financing activities in 2002 was $3.3 million. The increase in 2003 from 2002 was due to proceeds from the issuance of the 4.75% Convertible Senior Notes and the 6.625% Senior Notes of $128.0 million and $353.7 million, respectively, offset by the repayment of $264.0 million outstanding under the prior revolving credit facilities.

Massey believes that cash on hand, cash generated from operations and its borrowing capacity will be sufficient to meet its working capital requirements, anticipated capital expenditures (other than major

acquisitions), scheduled debt payments and anticipated dividend payments for at least the next few years. Nevertheless, the ability of Massey to satisfy its debt service obligations, to fund planned capital expenditures or pay dividends will depend upon its future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond Massey’s control. Massey frequently evaluates potential acquisitions. In the past, Massey has funded acquisitions primarily with cash generated from operations, but Massey 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 Massey on terms that Massey finds acceptable, or at all.

The Company has various contractual obligations that are recorded as liabilities within the Consolidated Financial Statements. Other obligations, such as certain purchase commitments, operating lease agreements, and other executory contracts are not recognized as liabilities within the Consolidated Financial Statements but are required to be disclosed. The following table is a summary of the Company’s significant obligations as of December 31, 2003 and the future periods in which such obligations are expected to be settled in cash. The table does not include current liabilities accrued within the Company’s Consolidated Financial Statements, such as Accounts payable and Payroll and employee benefits.

Additionally, the Company has liabilities relating to pension and other postretirement benefits, work related injuries and illnesses, and mine reclamation and closure. As of December 31, 2003, payments related to these items are estimated to be:

The Company’s 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 the Company’s assumptions are inaccurate, the Company could be required to expend greater amounts than anticipated. Moreover, in particular for periods after 2003, the Company’s estimates may change from the amounts included in the table, and may change significantly, if its assumptions change to reflect changing conditions. These assumptions are discussed in the Notes to the Consolidated Financial Statements and in the Critical Accounting Estimates and Assumptions of the Management’s Discussion and Analysis of Financial Condition and Results of Operation section.

Inability to satisfy contractual obligations may adversely affect Massey’s profitability

From time to time, Massey has disputes with customers over the provisions of long-term contracts relating to, among other things, coal quality, pricing, quantity and delays in delivery. In addition, Massey may not be able to produce sufficient amounts of coal to meet customer commitments to meet their demand. Massey’s inability to satisfy its contractual obligations could result in the Company purchasing coal from third party sources to satisfy those obligations or may result in customers initiating claims against Massey. The Company may not be able to resolve all of these disputes in a satisfactory manner, which could result in substantial damages or otherwise harm its relationships with customers.

Massey is subject to being adversely affected by a decline in the financial condition and creditworthiness of the companies with which it does business

Massey has contracts to supply coal to energy trading and brokering companies pursuant to which those companies sell such coal to the ultimate users. Massey is subject to being adversely affected by any decline in the financial condition and creditworthiness of these energy trading and brokering companies. As the largest supplier of metallurgical coal to the American steel industry, Massey is subject to being adversely affected by any decline in the financial condition or production volume of American steel producers. See Item 1, Business, under the heading “Customers and Coal Contracts” for further discussion.

Massey is subject to being adversely affected by the potential inability to renew or obtain surety bonds

Federal and state laws require bonds to secure the Company’s 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. The Company’s failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material impact on the Company. That failure could result from a variety of factors including the following:

Government regulations increase Massey’s costs and may discourage customers from burning coal

Massey incurs 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 the Company’s operations. It may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from its operations. See Item 1, Business, under the headings “Environmental, Safety and Health Laws and Regulations” for further discussion.

New legislation and new regulations may be adopted which could materially adversely affect Massey’s mining operations, cost structure or its customers’ ability to use coal. New legislation and new regulations may also require Massey or its customers to change operations significantly or incur increased costs. The EPA has undertaken broad initiatives aimed at increasing compliance with emissions standards and to provide incentives to customers for decreasing emissions, often by switching to an alternative fuel source.

Massey’s operations are subject to certain events and conditions that could disrupt operations, including fires and explosions from methane, accidental minewater discharges, natural disasters, equipment failures, maintenance problems and flooding. Massey maintains 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 Massey’s insurance policies.

Massey’s transportation providers are important in order to provide access to markets. Disruption of transportation services because of weather-related problems, strikes, lockouts or other events could temporarily impair Massey’s ability to supply coal to customers.

The State of West Virginia recently enacted legislation raising coal truck weight limits, including provisions supporting enhanced enforcement. Although Massey has 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.

Certain of Massey’s subsidiaries and other coal and transportation companies have been named as defendants in a lawsuit 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 damages. See Item 3, Legal Proceedings for further discussion of this litigation.

Fluctuations in transportation costs could affect the demand for Massey’s coal

Transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is 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 impact on Massey’s ability to compete with other energy sources and on its cash flows, results of operations or financial condition. 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, coal mines in the western U.S. could become an attractive source of coal to consumers in the eastern part of the country if the costs of transporting coal from the west were significantly reduced.

Foreign currency fluctuations could adversely affect the competitiveness of Massey’s coal abroad

Massey relies on customers in other countries for a portion of its sales, with shipments to countries in Europe, North America, South America and Asia. Massey competes 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 producing countries may be reduced in U.S. dollar terms based on currency exchange rates, providing an advantage to foreign coal producers. Currency fluctuations in producing countries could adversely affect the competitiveness of U.S. coal in international markets.

In the normal course of business, the Company is a party to certain off-balance sheet arrangements including guarantees, operating leases, 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 the Company’s consolidated balance sheets, and, except for the operating leases, the Company does not expect any material impact on its cash flows, results of operations or financial condition to result from these off-balance sheet arrangements.

The Company uses surety bonds to secure reclamation, workers’ compensation, wage payments, and other miscellaneous obligations. As of December 31, 2003, the Company had $274.6 million of outstanding surety bonds with third parties. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $246.6 million, workers’ compensation bonds of $10.0 million, wage payment and collection bonds of $8.8 million, and other miscellaneous obligation bonds of $9.2 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, the Company would seek to secure obligations with letters of credit, cash deposits, or other suitable forms of collateral. As of December 31, 2003, the Company had secured $34.8 million of surety obligations with letters of credit.

From time to time the Company uses bank letters of credit to secure its obligations for worker’s compensation programs, various insurance contracts and other obligations. At December 31, 2003, the Company had $136.7 million of letters of credit outstanding (including the $34.8 million noted above that secure surety obligations) collateralized by $141.6 million of cash deposited in restricted, interest bearing accounts pledged to issuing banks. No claims were outstanding against those letters of credit as of December 31, 2003. In January 2004, concurrent with the closing of the asset-based revolving credit facility, $35.7 million of the previously cash collateralized letters of credit were rolled under the new credit facility, resulting in the return of $36.6 million of cash collateral to the Company.

Inflation in the U.S. has been relatively low in recent years and did not have a material impact on Massey’s cash flows, results of operations or financial condition for the years presented.

The combination of high natural gas prices, an improving U.S. economy, strong economic growth in China, the weak U.S. dollar, higher ocean freight rates and limited coal supply from Central Appalachia has contributed to marked improvement in the coal industry environment. Demand for steam and metallurgical grade coals in both the domestic and export markets is expected to be strong in 2004 and support rising coal prices. While Massey’s 2004 production is largely sold, the higher market prices should enable term contracts to be negotiated at higher levels for future years and as existing contracts expire. The Company expects produced coal sales of 45 to 47 million tons in 2004. However, it projects a first quarter loss due to weather-related operational and shipping issues and the fact that all four of its longwall mines are projected to move to new panels in the quarter.

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. 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. The following critical accounting estimates and assumptions were used in the preparation of the financial statements:

The estimated cost and benefits of the Company’s non-contributory defined benefit pension plans are determined by independent actuaries, who, with the Company’s review and approval, 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. In estimating the discount rate, the Company looks 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, 2003, the discount rate used to determine the obligation was 6.25% compared to the discount rate used at December 31, 2002 of 6.75%. A decrease in the assumed discount rate increases the defined pension benefit expense. The rate of increase in compensation levels is determined based upon the Company’s long-term plans for such increases. The rate of increase in compensation levels used was 4.0% and 4.5% for the years ended December 31, 2003 and 2002, respectively. The expected long-term rate of return on pension plan assets is based on long-term historical return information and future estimates of long-term investment returns for the target asset allocation of investments that comprise plan assets. The expected long-term rate of return on plan assets used to determine expense in each period was 8.5%, 9.0% and 9.5% for the years ended December 31, 2003, December 31, 2002 and October 31, 2001, respectively. Significant changes to these rates introduce substantial volatility to the Company’s costs.

The Company is 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 approval by the Company, an annual evaluation is prepared by the Company’s independent actuaries using various assumptions regarding disability incidence, medical costs trend, cost of living trend, mortality, death benefits, dependents and interest rates. The Company records expense related to this obligation using the service cost method. At December 31, 2003, the discount rate used to determine the obligation was 6.25% compared to 6.75% at December 31, 2002. A decrease in the assumed discount rate increases black lung expense. Included in Note 12 to the Notes to the Consolidated Financial Statements is a medical cost trend and cost of living trend sensitivity analysis.

The Company’s operations have workers’ compensation coverage through a combination of either self-insurance, participation in a state run program, or commercial insurance. The Company accrues 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 the Company utilizes the services of third party administrators who derive claim reserves from historical experience. These third parties provide information to independent actuaries, who after review and consultation with the Company with regards to actuarial assumptions, including discount rate, prepare an evaluation of the self-insured liabilities. At December 31, 2003, the discount rate used to determine liability was 6.25% compared to 7.25% at December 31, 2002. A decrease in the assumed discount rate increases the workers’ compensation self-insured liability and related expense. Actual experience could differ from these estimates, which could increase the Company’s costs.

The Company’s sponsored 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 the Company’s retiree health care plans are determined by independent actuaries, who, with the Company’s input, use various actuarial assumptions, including discount rate, expected trend in health care costs and per capita costs. The discount rate is an estimate of the current interest rate at which the other postretirement benefit liabilities could be effectively settled as of the measurement date. In estimating this rate, the Company looks 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, 2003, the discount rate used to determine the obligation was 6.25% compared to 6.75% at December 31, 2002. A decrease in the assumed discount rate increases retiree medical expense. At December 31, 2003 the Company’s assumptions of the company health care cost trend were projected at an annual rate of 11.0% ranging down to 5.0% by 2010 (11.0% ranging down to 5.0% by 2009 at December 31, 2002), and remaining level thereafter. Significant changes to these rates introduce substantial volatility to the Company’s costs. Included in Note 13 to the Notes to the Consolidated Financial Statements is a sensitivity analysis on the health care trend rate assumption.

The SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. The Company’s total reclamation and mine-closing liabilities are based upon permit requirements and its engineering estimates related to these requirements. The Company adopted Statement 143 effective January 1, 2003. Statement 143 requires that asset retirement obligations be recorded as a liability based on fair value, which is calculated as the present value of the estimated future cash flows. The estimate of ultimate reclamation liability and the expected period in which reclamation work will be performed is reviewed periodically by the Company’s management and engineers. In estimating future cash flows, the Company 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 the Company. The discount rate is based on the rates of treasury bonds with maturities similar to the estimated future cash flow, adjusted for our credit standing. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly.

The Company is the subject of, or a party to, various suits and pending or threatened litigation involving governmental agencies or private interests. The Company has 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 on its cash flows, results of operations or financial condition. Also, the Company’s operations are affected by federal, state and local laws and regulations regarding environmental matters and other aspects of its business. The impact, if any, of pending legislation or regulatory developments on future operations is not currently estimable. See Item 3, Legal Proceeding’s and Note 20 to the Notes to the Consolidated Financial Statements for further discussion on the Company’s contingencies.

We account for income taxes in accordance with SFAS 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. In evaluating the need for a valuation allowance, we take into account various factors, including the expected level of future taxable income and available tax

planning strategies. If actual results differ from the assumptions made in the evaluation of our valuation allowance, we record a change in valuation allowance through income tax expense in the period such determination is made.

The Company has a reserve for taxes that may become payable as a result of audits in future periods with respect to previously filed tax returns included in deferred tax liabilities (separate disclosure has not been made because the amount is not considered material). It is the Company’s policy to establish reserves for taxes that may become payable in future years as a result of an examination by tax authorities. The Company establishes the reserves based upon management’s assessment of exposure associated with permanent tax differences (i.e., tax depletion expense, etc.), tax credits and interest expense applied to temporary difference adjustments. The tax reserves are analyzed periodically (at least annually) and adjustments are made as events occur to warrant adjustment to the reserve. The Company is currently under audit from the Internal Revenue Service (the “IRS”) for the fiscal years ended October 31, 1999 and October 31, 2001. It is expected that the IRS audit will be completed in 2004 and may provide a favorable adjustment to the tax reserve. The Company’s federal income tax returns have been examined by the IRS, or statutes of limitations have expired through 1998.

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

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, revenue and expenditures with respect to reserves will likely vary from estimates, and these variances may be material.

In January 2003, the Financial Accounting Standards Board (the “FASB”) issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”) and subsequently revised FIN 46 in December 2003. As revised, FIN 46’s consolidation provisions apply to interest in variable interest entities (“VIEs”) that are referred to as special-purpose entities for periods ending after December 15, 2003. For all other VIEs, FIN 46’s consolidation provisions apply for periods ending after March 15, 2004, or as of March 31, 2004 for the Company. The Company does not have any interests in special-purpose entities. The Company did not apply any of the FIN 46 consolidation provisions in 2003. The Company is continuing to evaluate the effect of FIN 46 but does not expect that it will have a material impact.

On July 1, 2003, the Company adopted the provision of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (“Statement 150”), which requires an issuer to classify and measure certain freestanding financial instruments with characteristics of both liabilities and equity as a liability if that financial instrument embodies an obligation requiring the issuer to redeem the financial instrument by transferring its assets. The adoption of this provision of Statement 150 did not have a material impact on the Company’s cash flows, results of operations or financial condition. Additionally, Statement 150 contains a second provision that impacts the accounting for minority interests in limited life subsidiaries and requires that those interests be measured at settlement value. The effective date of the second provision of

Statement 150 has been deferred for an indefinite period. The Company does not expect the application of the second provision of Statement 150 to have a material impact on the Company’s cash flows, results of operation or financial condition.

Historical practice in extractive industries has been to classify leased mineral rights as tangible assets, which is consistent with the balance sheet classification of mining properties owned in fee. The Company and others in extractive industries have historically taken the position that rights under such long-term mineral leases are the functional equivalent of fee ownership of the underlying coal because the lessee has the exclusive right to extract the coal during the term of the lease and because the lessee owns the extracted coal in fee. SFAS No. 141, “Business Combinations” (“Statement 141”), provides leased mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of Statement 141 (and SFAS No. 142, “Goodwill and Other Intangible Assets”) in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the Emerging Issues Task Force (the “EITF”) of the Financial Accounting Standards Board has established a Mining Industry Working Group that is currently considering this issue. The classification of our leased mineral rights in our consolidated balance sheet may be revised depending upon the conclusions reached by the Mining Industry Working Group and the EITF.

Massey’s interest expense is sensitive to changes in the general level of short-term interest rates. At December 31, 2003, the outstanding $788.0 million aggregate principal amount of long-term debt was under fixed-rate instruments; however, the primary exposure to market risk for changes in interest rates relates to an interest rate swap entered into on November 10, 2003, covering a notional amount of debt of $240 million. Based on the notional amount outstanding of $240 million, a hypothetical 100 basis point increase in the specified swap interest rate index would increase annual interest expense by approximately $2.4 million. The projected present value of the swap instrument is partially determined by movements in interest rates, and Massey may be required to post cash deposits with the swap counterparty if the present value in favor of the counterparty exceeds certain threshold amounts based on Massey’s credit rating at the time.

If it should become necessary to borrow under the new asset-based revolving credit facility, those borrowings would be also made at a variable rate.

The Company manages its commodity price risk through the use of long-term coal supply agreements, which are contracts with a term of 12 months or greater, rather than through the use of derivative instruments. The Company believes that the percentage of its sales pursuant to these long-term contracts was approximately 96% for its fiscal year ended December 31, 2003. The Company anticipates that in 2004, the percentage of sales pursuant to long-term contracts will be comparable with the percentage of sales for 2003. 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, the Company has 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, the Company’s 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 the Company’s exposure to market-based pricing may be increased should customers elect to purchase fewer tons.

We have audited the accompanying consolidated balance sheets of Massey Energy Company as of December 31, 2003 and December 31, 2002, and the related consolidated statements of income, cash flows, and shareholders’ equity for the years ended December 31, 2003 and December 31, 2002, the two months ended December 31, 2001 and the year ended October 31, 2001. Our audit also included the financial statement schedule listed in Item 15(a). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Massey Energy Company at December 31, 2003 and December 31, 2002, and the consolidated results of its operations and its cash flows for the years ended December 31, 2003 and December 31, 2002, the two months ended December 31, 2001 and the year ended October 31, 2001, in conformity with accounting principles generally accepted in the United States. Also, in our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 3 to the consolidated financial statements, in 2003 the Company changed its method of accounting for reclamation liabilities.

The accompanying consolidated financial statements include the accounts of Massey Energy Company (“Massey” or the “Company”), its wholly owned and sole, direct operating subsidiary A.T. Massey Coal Company, Inc. (“A.T. Massey”) and A.T. Massey’s subsidiaries. Massey has no separate independent operations. A.T. Massey fully and unconditionally guarantees the Company’s obligations under the 6.95% senior notes due 2007 (the “6.95% Senior Notes”), the 6.625% senior notes due 2010 (the “6.625% Senior Notes”), and the 4.75% convertible senior notes due 2023 (the “4.75% Convertible Senior Notes”). See Note 8 for a more complete discussion of debt.

Until the spin-off transaction on November 30, 2000 (the “Spin-Off”) (See Note 14), A.T. Massey was 100% controlled by Fluor Corporation (“Fluor”). Therefore, the financial statements for the period ended October 31, 2001 may not necessarily be indicative of the cash flows, results of operation or financial condition of Massey in the future or had it operated as a separate independent company during all periods reported. All significant intercompany transactions and accounts have been eliminated.

The Company changed to a calendar-year basis of reporting financial results effective January 1, 2002. As a requirement of the change in fiscal year, the Company is reporting consolidated results of operations and cash flows for a special transition period, the two months ended December 31, 2001.

The preparation of the financial statements of the Company in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported amounts. These estimates are based on information available as of the date of the financial statements. Therefore, actual results could differ from those estimates. The most significant estimates used in the preparation of the consolidated financial statements are related to defined benefit pension plans, coal workers’ pneumoconiosis (black lung), workers’ compensation, other post employment benefits, reclamation and mine closure obligations, contingencies, income taxes and coal reserve values.

Cash and cash equivalents are stated at cost, which approximates fair value. Cash equivalents consist of highly liquid investments with maturities of 90 days or less at the date of purchase.

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains a valuation allowance based upon the expected collectibility of its accounts receivable. The allowance includes specific amounts for accounts that are likely to be uncollectible, such as customer bankruptcies and disputed amounts, and a general allowance for accounts that may become uncollectible. The allowance is estimated based on many factors such as industry trends, creditworthiness of customers and age of the receivables. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote.

Produced coal and supplies inventories generally are stated at the lower of average cost or net realizable value. Coal inventory costs include labor, supplies, equipment costs, operating overhead, and other related costs. Purchased coal inventories are stated at the lower of cost, computed on the first-in, first-out method, or net realizable value.

Deferred income taxes result from temporary differences between the tax bases of assets and liabilities and their financial reporting amounts.

The Company defers certain costs related to the development of longwall panels within a deep mine. These costs are amortized over the life of the panel once it is placed in service. Longwall panel lives range from approximately four to twelve months.

Property, plant and equipment is carried at cost. Expenditures that extend the useful lives of existing buildings and equipment are capitalized. Maintenance and repairs are expensed as incurred. Coal exploration costs are expensed as incurred. Development costs applicable to the opening of new coal mines and certain mine expansion projects are capitalized. When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposition is credited or charged to income.

The Company’s coal reserves are controlled either through direct ownership or through leasing arrangements. Mining properties owned in fee represent owned coal properties carried at cost. Leased mineral rights represent leased coal properties carried at the cost of acquiring those leases. The leases are generally long-term in nature (original term 5 to 50 years or until the mineable and merchantable coal reserves are exhausted), and substantially all of the leases contain provisions that allow for automatic extension of the lease term as long as mining continues.

Depreciation of buildings, plant and equipment is calculated on the straight-line method over their estimated useful lives, which generally range from 15 to 30 years for building and plant, and 3 to 20 years for equipment. Assets under capital leases are amortized using the straight-line method over their useful lives, which generally range from 2 to 8 years, as ownership transfers to the Company at the end of the lease term. Amortization of assets under capital leases is included within Depreciation, depletion and amortization.

Amortization of development costs is computed using the units-of-production method over the estimated proven and probable reserve tons.

Depletion of mining properties owned in fee and leased mineral rights is computed using the units-of-production method over the estimated proven and probable reserve tons. As of December 31, 2003, approximately $49.1 million of costs associated with mining properties owned in fee and leased mineral rights is not currently subject to depletion as mining has not begun or production has been temporarily idled on the associated coal reserves.

The Company capitalizes certain costs incurred in the development of internal-use software, including external direct material and service costs, and employee payroll and payroll-related costs in accordance with the

American Institute of Certified Public Accountants’ Statement of Position (“SOP”) 98-1, “Accounting for the Costs of Computer Software Developed for or Obtained for Internal Use.” All costs capitalized are amortized using the straight-line method over the estimate useful life not to exceed 7 years.

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to their estimated fair value, which is usually measured based on an estimate of future discounted cash flows. See Note 16 for a description of impairment charges that were recorded in the consolidated statements of income.

Coal leases, which require minimum annual or advance payments and are recoverable from future production are generally deferred and charged to expense as the coal is subsequently produced. At December 31, 2003 and 2002, advance mining royalties included in other noncurrent assets totaled $27.5 and $29.5 million, respectively.

The Federal Surface Mining Control and Reclamation Act (“SMCRA”) establishes operational, reclamation and closure standards for all aspects of surface mining as well as many aspects of deep mining. Estimates of the Company’s total reclamation and mine-closing liabilities are based upon permit requirements and the Company’s engineering expertise related to these requirements. Effective January 1, 2003, the Company changed its method of accounting for reclamation liabilities in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“Statement 143”). Statement 143 requires that asset 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 the period in which it is incurred. The estimate of ultimate reclamation liability and the expected period in which reclamation work will be performed is reviewed periodically by the Company’s management and engineers. In estimating future cash flows, the Company considers the estimated current cost of reclamation and applies 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 the Company. When the liability is initially recorded, the offset is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Accretion expense is included in cost of produced coal revenue. To settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, a gain or loss upon settlement is incurred. Additionally, the Company performs a certain amount of required reclamation of disturbed acreage as an integral part of its normal mining process. These costs are expensed as incurred.

Prior to the adoption of Statement 143, the Company accrued for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge, for each permit as coal was mined, on a unit-of-production basis over the proven and probable reserves as defined in the Security and Exchange Commission’s (“SEC”) Industry Guide 7.

The Company sponsors a noncontributory defined benefit pension plan covering substantially all administrative and non-union employees. The computation of benefits for this plan varies based on the date of entry in the plan, and is based either on years of service and employee compensation during the highest consecutive five years or benefits on a cash balance formula with contribution credits based on hours worked.

The Company’s policy is to annually fund the defined benefit pension plans at or above the minimum required by law. The Company accounts for its defined benefit pension plans in accordance with SFAS No. 87, “Employers’ Accounting for Pension” (“Statement 87”), which requires the cost to provide benefits be accrued over the employees’ remaining service.

The Company is liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in which it has operations. 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. The Company’s operations have workers’ compensation coverage through a combination of either a self-insurance program, as a participant in a state run program, or by an insurance policy. The Company accrues 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 the Company utilizes the services of third party administrators who derive claim reserves from historical experience. These third parties provide information to independent actuaries, who after review and consultation with the Company with regards to actuarial assumptions, including discount rate, prepare an evaluation of the self-insured program liabilities.

The Company is 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 employees and their dependents resulting from occurrences of coal worker’s pneumoconiosis disease (black lung). The Company provides for federal and state black lung claims principally through a self-insurance program. The Company uses the service cost method to account for its self-insured black lung obligation. The liability measured under the service cost method represents the discounted future estimated cost for former employees either receiving or projected to receive benefits, and the portion of the projected liability relative to prior service for active employees projected to receive benefits.

Expense for black lung under the service cost method represents the service cost, which is the portion of the present value of benefits allocated to the current year, interest on the accumulated benefit obligation, and amortization of unrecognized actuarial gains and losses. The Company amortizes unrecognized actuarial gains and losses over a five-year period.

Annual actuarial studies are prepared by independent actuaries using certain assumptions to determine the liability. The calculation is based on assumptions regarding disability incidence, medical costs, mortality, death benefits, dependents and interest rates. These assumptions are derived from actual Company experience and credible outside sources.

The Company sponsors defined benefit health care plans that provide postretirement medical benefits to eligible union and non-union members. To be eligible, retirees must meet certain age and service requirements. Depending on year of retirement, benefits may be subject to annual deductibles, coinsurance requirements, lifetime limits, and retiree contributions. The Company accounts for postretirement benefits other than pensions in accordance with SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (“Statement 106”), which requires the cost to provide benefits be accrued over the employees’ remaining service. These costs are accrued based on annual studies prepared by independent actuaries.

Under the Coal Industry Retiree Health Benefits Act of 1992 (the “Coal Act”), coal producers are required to fund medical and death benefits of certain retired union coal workers based on premiums assessed by the

United Mine Workers of America (“UMWA”) Benefit Funds. The Company treats its obligation under the Benefit Act as a participation in a multi-employer plan as permitted by Emerging Issues Task Force (“EITF”) No. 92-13, “Accounting for Estimated Payments in Connection with the Coal Industry Retiree Health Benefit Act of 1992,” and records the cost of the Company’s obligation as expense as payments are assessed.

Shareholders’ Equity for periods prior to the Spin-Off (see Note 14) reflects the outstanding shares of Massey immediately following the Spin-Off. The Company believes this presentation to be preferable to reporting earnings per share utilizing the distribution ratio at the time of the Spin-Off and the capital structure of the combined Fluor Corporation entity prior to the Spin-Off. Please refer to the “Earnings per Share” section below for further discussion of the impact of this presentation on earnings per share.

Coal sales are recognized when title passes to customers. For domestic sales, this generally occurs when coal is loaded at the mine or at off-site storage locations. For export sales, this generally occurs when coal is loaded onto marine vessels at terminal locations. In certain instances, the Company maintains ownership of the coal inventory on customers’ sites and sells tonnage to such customers as it is consumed. For these customers, revenue is recognized when title and risk of loss passes to the customers at the point of consumption.

Produced coal revenue represents revenue recognized from the sale of coal produced by the Company.

Freight and handling costs paid to third-party carriers and invoiced to coal customers are recorded as Freight and handling costs and Freight and handling revenue, respectively.

Purchased coal revenue represents revenue recognized from the sale of coal purchased from external production sources. In these instances, the Company takes title to the coal that is purchased from external production sources, which is then sold to the Company’s customer. Tons of purchased coal shipped were 3.1 million, 3.3 million, and 1.3 million tons for the years ended December 31, 2003 and 2002 and October 31, 2001, respectively.

Other revenue generally consists of royalties, rentals, contract buyout payments, coal handling services, gas well revenue, miscellaneous income and gains on the sale of non-strategic assets.

During the third quarter of 2003, the Company received $21.0 million for the settlement of a property and business interruption claim related to the Martin County impoundment discharge (see Note 20), which, after adjusting for a previously booked receivable and claim settlement expenses, resulted in a gain of $17.7 million (pre-tax) and is reflected in Insurance settlement for the year ended December 31, 2003.

The Company accounts for stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. Accordingly, compensation cost for stock options granted to employees is measured as the excess, if any, of the quoted market price of the stock at the date of grant over the amount an employee must pay to acquire the stock. Compensation cost for stock appreciation rights and performance equity units is recorded based on the quoted market price of the Company’s stock at the end of the period. Stock-based compensation other than stock options is recorded to expense on a straight-line basis. The Company has implemented the disclosure-only provisions of SFAS No. 123 “Accounting for Stock-Based Compensation” (“Statement 123”). The Company has recognized no stock-based compensation expense related to stock options in any period as all options granted had an exercise price equal to market value of the underlying common stock on the date of the grant.

If the Company had followed the fair value method under Statement 123 to account for stock based compensation cost for stock options, the amount of stock based compensation cost for stock options, net of related tax, which would have been recognized for each period and pro-forma net income for each period would have been as follows:

The estimated fair value as of the date of grant for options granted to Massey employees during the years ended December 31, 2003 and 2002 and October 31, 2001 was determined using the Black-Scholes option-pricing model based on the following weighted average assumptions:

The weighted average fair value of options granted by the Company during the years ended December 31, 2003 and 2002 and October 31, 2001 using the Black-Scholes option-pricing model was $5.55, $2.23 and $7.22, respectively.

The number of shares used to calculate basic loss per share is based on the weighted average number of outstanding shares of Massey during the period. The number of shares used to calculate diluted loss per share is based on the number of shares used to calculate basic loss per share plus the dilutive effect of stock options and other stock-based instruments held by Massey employees each period. In accordance with accounting principles generally accepted in the United States, the effect of dilutive securities, excluding the impact of the redemption features of the 4.75% Convertible Senior Notes discussed below, in the amount of 0.4 million, 0.1 million and 0.3 million for the years ended December 31, 2003 and 2002 and October 31, 2001, respectively, was excluded from the calculation of the diluted loss per common share for all periods as such inclusion would result in antidilution.

The computations for basic and diluted loss per share are based on the following per share information:

The Company’s 4.75% Convertible Senior Notes are convertible by holders into shares of Massey’s common stock during certain periods under certain circumstances. None of the 4.75% Convertible Senior Notes were eligible for conversion at December 31, 2003. If all of the notes outstanding at December 31, 2003 had been eligible and were converted, the Company would have needed to issue 6,807,636 shares. See Note 8 for further discussion of conversion features of the 4.75% Convertible Senior Notes.

In addition, holders of the Company’s 4.75% Convertible Senior Notes may require Massey to purchase all or a portion of their 4.75% Convertible Senior Notes on May 15, 2009, May 15, 2013, and May 15, 2018. For purchases on May 15, 2013 or May 15, 2018, the Company may, at its option, choose to pay the purchase price in cash or in shares of Massey’s common stock or any combination thereof. As of December 31, 2003, assuming full redemption of the 4.75% Convertible Senior Notes, the dilutive shares would have increased by 6.3 million shares. See Note 8 for further discussion of the redemption features of the 4.75% Convertible Senior Notes.

The Company accounts for derivative instruments in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“Statement 133”) as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Hedging Activities,” and SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (“Statement 149”). The statements require that the Company recognize all derivatives as either assets or liabilities in the consolidated balance sheet at fair value. Changes in the fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in the fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in other comprehensive income. Any ineffective portions of hedges would be recognized in earnings. Currently, the Company has no cash flow hedges.

The Company’s use of derivative instruments is currently limited to an interest rate swap agreement used to modify the interest characteristics for a portion of its outstanding debt in order to manage its interest rate risk. See Note 8, Debt, Fair Value Hedge, for additional information. This interest rate swap is designated as a fair value hedge and is structured so that there is no ineffectiveness. The Company assesses on an ongoing basis whether the swap is highly effective in offsetting changes in the fair value of the hedged item. If it is determined that the swap has ceased to be a highly effective hedge, the Company will discontinue hedge accounting prospectively. If the interest rate swap is terminated, no gain or loss is recognized since the swap is recorded at fair value. However, the change in fair value of the hedged item attributable to hedged risk would be amortized to interest expense over the remaining life of the hedged item. If the hedge is terminated prior to maturity, the interest rate swap, if not terminated at the same time would become an undesignated derivative and its subsequent changes in fair value recognized in income.

In January 2003, the Financial Accounting Standards Board (the “FASB”) issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (“FIN 46”) and subsequently revised FIN 46 in December 2003. As revised, for periods ending after December 15, 2003, FIN 46’s consolidation provisions apply to interests in

variable interest entities (“VIEs”) that are specifically defined as special-purpose entities. For all other VIEs, FIN 46’s consolidation provisions apply for periods ending after March 15, 2004. The Company does not have any interests in special-purpose entities. The Company did not apply any of the FIN 46 consolidation provisions in 2003. The Company is continuing to evaluate the effect of FIN 46 but does not expect that it will have a material impact.

In December 2003, the FASB issued SFAS No. 132 (revised 2003), “Employers Disclosures about Pensions and Other Postretirement Benefits” (“Statement 132R”), which is effective for fiscal years and quarters ending after December 15, 2003. The revised standard requires that companies provide more details about their plan assets, benefit obligations, cash flows, benefit costs and other relevant information. Companies are required to provide an allocation of plan assets by investment category, a description of investment policies, projections of future benefit payments and an estimate of contributions to be made in the next year to fund pension and other postretirement benefit plans. The Company has included the expanded disclosures required by Statement 132R in Note 10 and Note 13.

Certain prior year amounts in the Consolidated Financial Statements have been reclassified to conform to current year presentation.

Effective January 1, 2003, the Company changed its method of accounting for reclamation liabilities in accordance with Statement 143. As a result of adoption of Statement 143, the Company recognized a decrease in total reclamation liability of $13.1 million. The Company 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, the Company recognized a decrease in mining properties owned in fee and leased 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 liabilities. The Company also recognized a decrease in net deferred tax liability of $5.0 million as a result of adoption of Statement 143.

The cumulative effect of the change on prior years resulted in a charge to income of $7.9 million, net of income taxes of $5.0 million ($0.11 per share). The pro forma effects of the application of Statement 143 as if Statement 143 had been applied retroactively are presented below:

The following table describes all changes to the Company’s reclamation liability:

The pro forma reclamation liability balances as if Statement 143 had been applied retroactively are as follows:

Prior to the adoption of Statement 143, the Company accrued for the costs of current mine disturbance and final mine closure, as coal was mined, on a unit-of-production basis over the proven and probable reserves as defined in Industry Guide 7. For the years ended December 31, 2002 and October 31, 2001, and the two-months ended December 31, 2001, the Company accrued approximately $9.8 million, $6.4 million, and $1.6 million, respectively, towards final mine closure reclamation, excluding re-costing adjustments. When changes in cost estimates or regulatory requirements caused the Company’s accrued liability for a permit to exceed its total estimated reclamation liability, the difference was credited to income. These “re-costing” adjustments were recorded as a decrease in Cost of produced coal revenue and totaled $1.7 million, $6.6 million, and $0.2 million for the years ended December 31, 2002 and October 31, 2001, and the two-months ended December 31, 2001, respectively.

Saleable coal represents coal ready for sale, including inventories designated for customer facilities under consignment arrangements of $44.8 million and $43.0 million at December 31, 2003 and 2002, respectively. Raw coal represents coal that generally requires further processing prior to shipment to the customer. Work in process consists of the costs incurred to remove overburden above an unmined coal seam as part of the surface mining process.

Deposits consist primarily of funds placed in restricted accounts with financial institutions to collateralize letters of credit that support workers’ compensation requirements, insurance and other obligations. Deposits also include collateral held from customers as credit enhancement, with a corresponding liability recorded within Other current liabilities. Deposits at December 31, 2003 and 2002 include $141.6 million and $31.5 million, respectively, of funds pledged as collateral to support outstanding letters of credit (see Note 8 for further discussion).

Land, buildings and equipment includes gross assets under capital lease of $16.3 million at December 31, 2003 and none at December 31, 2002.

In addition to the impact of the adoption of Statement 143 discussed in Note 3, during the fourth quarter of 2003, Massey’s subsidiaries, A. T. Massey and Alex Energy, Inc., acquired certain assets, including assets of Horizon Natural Resources Company (“Horizon”), which was in Chapter 11 bankruptcy. This acquisition provided the Company with an additional 28.0 million tons (unaudited) of leased coal reserves in Kanawha, Boone and Fayette counties, West Virginia. The purchase price for the assets was approximately $19.0 million, including funds to buy out a secured debt position and production payments. A portion of this consideration (approximately $5.0 million) is in the form of a deferred payment. The United States Bankruptcy Court for the Eastern District of Kentucky approved the purchase of the Horizon assets.

During the third quarter of 2002, the Company purchased the Holston mining assets from Pittston Coal Company. These assets, valued at approximately $11.0 million, included the Holston room and pillar mine and the preparation plant, among other assets. Total consideration paid by the Company was $6.2 million in cash, plus assumed liabilities of approximately $4.8 million.

Leased mineral rights represent leased coal properties carried at the cost of acquiring those leases. Depletion of leased mineral rights is computed using the units-of-production method and the rights are assumed to have no

residual value. The leases are generally long-term in nature (original terms of 5 to 50 years or until all mineable and merchantable coal reserves are exhausted), and substantially all of the leases contain provisions that allow for automatic extension of the lease term as long as mining continues. Accumulated depletion for mineral lease rights was $160.8 million and $149.0 million at December 31, 2003 and 2002, respectively.

Depletion expense related to mineral lease rights was $12.1 million, $15.3 million, and $12.6 million at December 31, 2003 and 2002 and October 31, 2001, respectively, and $2.1 million for the two months ended December 31, 2001.

Estimated depletion expense of leased mineral rights during the next five years is as follows:

The Company has historically classified mineral lease rights in the same manner as the coal it owns in fee, which is consistent with common practice in extractive industries. The Company and others in extractive industries have historically taken the position that rights under such long-term mineral leases are the functional equivalent of fee ownership of the underlying coal because the lessee has the exclusive right to extract the coal during the term of the lease and because the lessee owns the extracted coal in fee. SFAS No. 141, “Business Combinations” (“Statement 141”), provides leased mineral rights as an example of a contract-based intangible asset that should be considered for separate classification as the result of a business combination. Due to the potential for inconsistencies in applying the provisions of Statement 141 (and SFAS No. 142, “Goodwill and Other Intangible Assets”) in the extractive industries as they relate to mineral interests controlled by other than fee ownership, the EITF of the Financial Accounting Standards Board has established a Mining Industry Working Group that is currently considering this issue. The classification of our leased mineral rights in our consolidated balance sheet may be revised depending upon the conclusions reached by the Mining Industry Working Group and the EITF.

Income tax (benefit) expense included in the consolidated statement of earnings is as follows:

For the tax year ended October 31, 2001, Massey’s consolidated federal income tax return includes the operations of A.T. Massey and Fluor until the date of the Spin-Off.

A reconciliation of income tax (benefit) expense calculated at the federal statutory rate of 35% to the Company’s income tax (benefit) expense on (loss) earnings is as follows:

Deferred taxes reflect the tax effects of differences between the amounts recorded as assets and liabilities for financial reporting purposes and the amounts recorded for income tax purposes. The tax effects of significant temporary differences giving rise to deferred tax assets and liabilities are as follows:

The Company’s deferred tax assets include alternative minimum tax (“AMT”) credits of $90.6 and $80.9 million at December 31, 2003 and 2002, respectively. The AMT credits have no expiration date. State net operating loss carryforwards begin to expire in 2016.

tax depletion expense, etc.), tax credits and interest expense applied to temporary difference adjustments. The tax reserves are analyzed periodically (at least annually) and adjustments are made as events occur to warrant adjustment to the reserve. For example, if the statutory period for assessing tax on a given tax return or period lapses, the reserve associated with that period will be reduced. In addition, the adjustment to the reserve will reflect additional exposure based on current calculations. Similarly, if tax authorities provide administrative guidance or a decision is rendered in the courts, appropriate adjustments will be made to the tax reserve. The tax reserve was unchanged for the year ending December 31, 2003 and was lowered in the year ending December 31, 2002 by $4.1 million, reflecting the reduction in exposure due to the lapsing of the statutory period for assessing tax on the tax period ending in 1998, partially offset by additional exposures identified for tax years that remained open. In addition, payments were applied against the reserve for federal taxes and state taxes of $172,000, $821,000, and $470,000 as a result of audits conducted during the years ended October 31, 2001 and December 31, 2002 and 2003, respectively.

The Company’s federal income tax returns have been examined by the Internal Revenue Service (the “IRS”), or statutes of limitations have expired through 1998. The Company is currently under audit from the IRS for the fiscal years ended October 31, 1999 and October 31, 2001. Management believes that the Company has adequately provided for any income taxes and interest that may ultimately be paid with respect to all open tax years.

The weighted average effective interest rate of the outstanding borrowings was 5.4% at December 31, 2003, after giving effect to the interest rate swap (discussed in this Note under Fair Value Hedge), and 3.92% at December 31, 2002. At December 31, 2003, the Company’s available liquidity was $149.4 million, including cash and cash equivalents of $88.8 million and $60.6 million availability on its previously outstanding accounts receivable program.

On July 2, 2003, the Company refinanced its prior revolving credit facilities. The Company executed a $355 million secured financing package consisting of a $105 million revolving credit facility and a $250 million secured term loan secured by substantially all of the Company’s assets except accounts receivable. The refinanced revolving credit facility included a $55 million sublimit for the issuance of letters of credit. The Company and A.T. Massey’s direct and indirect subsidiaries guaranteed these credit facilities. The revolving credit facility was scheduled to expire on January 1, 2007 and the secured term loan was scheduled to expire on July 2, 2008.

A portion of the proceeds from the secured term loan was used to repay all outstanding amounts under the prior revolving credit facilities and under the accounts receivable financing program. Of the remaining proceeds, $100 million was placed in restricted, interest bearing accounts to collateralize current and future letters of credit

issued outside of the refinanced credit facility. These credit facilities were subsequently repaid and canceled on November 10, 2003 in connection with the issuance of the 6.625% Senior Notes.

On November 10, 2003, the Company issued $360 million of 6.625% unsecured senior notes due November 15, 2010 in a private placement. The Company subsequently filed a Registration Statement on Form S-4 with the SEC to register these notes. The 6.625% Senior Notes are unsecured obligations ranking equally with all other unsecured senior indebtedness of the Company. Interest on the 6.625% Senior Notes is payable on May 15 and November 15 of each year, beginning on May 15, 2004. The Company may call the 6.625% Senior Notes at any time after November 15, 2007. The 6.625% Senior Notes are guaranteed by A.T. Massey and substantially all of the Company’s indirect operating subsidiaries (the “Guarantors”). The guarantees are full and unconditional obligations of the Guarantors and are joint and several among the Guarantors. The subsidiaries not providing a guarantee of the 6.625% Senior Notes are minor (as defined under SEC Rule 3-10(h)(6) of Regulation S-X).

Part of the proceeds of this issuance was used to permanently repay the $249.4 million outstanding under the Company’s $250 million secured term loan. The Company also canceled its $105 million revolving credit facility, effectively terminating its $355 million secured credit facility. The Company recognized a charge of $6.3 million (pre-tax) for the write-off of unamortized financing fees related to this facility. The charge is included within Interest expense for the year ended December 31, 2003. The remaining proceeds of this issuance were used for general corporate purposes, including the collateralization of the $34.3 million of letters of credit then outstanding under the Company’s revolving credit facility letter of credit sublimit.

The 6.625% Senior Notes contain a number of significant restrictions and covenants that limit the Company’s ability and its subsidiaries’ ability to, among other things:

The 6.95% Senior Notes due March 1, 2007, are general unsecured obligations of the Company and rank equally with all other unsecured senior indebtedness of the Company. Interest is payable semiannually on March 1 and September 1 of each year. The 6.95% Senior Notes are redeemable in whole or in part, at the option of the Company at any time at a redemption price equal to the greater of (i) 100 percent of the principal amount of the Notes or (ii) as determined by a Quotation Agent as defined in the offering prospectus.

During the first quarter of 2003 and the fourth quarter of 2002, the Company made several open-market purchases, retiring a total principal amount of $3.0 million and $14.0 million, respectively, of the 6.95% Senior Notes at a cost of $2.4 million and $10.7 million plus accrued interest, respectively. A gain of $0.6 million and $3.3 million was recognized in the first quarter of 2003 and the fourth quarter of 2002, respectively, and is shown in the Consolidated Financial Statements of Income in Senior notes repurchase income.

On May 29, 2003, the Company issued $132.0 million of 4.75% convertible senior notes due May 15, 2023, in a private placement. The proceeds of this transaction were used to pay down outstanding borrowings under the $400 million aggregate revolving credit facilities in effect at that time. The Company subsequently filed a Registration Statement on Form S-3 with the SEC to register the Convertible Notes. The 4.75% Convertible Senior Notes are unsecured obligations ranking equally with all other unsecured senior indebtedness of the Company. Interest on the 4.75% Convertible Senior Notes is payable on May 15 and November 15 of each year, beginning on November 15, 2003. The Convertible Notes will mature on May 15, 2023, however Massey may redeem some or all of the 4.75% Convertible Senior Notes at any time on or after May 20, 2009.

Holders of the 4.75% Convertible Senior Notes may require Massey to purchase all or a portion of their Convertible Notes on May 15, 2009, May 15, 2013 and May 15, 2018. The Company must pay cash for all 4.75% Convertible Senior Notes so purchased on May 15, 2009. For purchases on May 15, 2013 or May 15, 2018, the Company may, at its option, choose to pay the purchase price for such 4.75% Convertible Senior Notes in cash or in shares of Massey’s common stock or any combination thereof.

The 4.75% Convertible Senior Notes are convertible during certain periods by holders into shares of Massey’s common stock initially at a conversion rate of 51.573 shares of common stock per $1,000 principal amount of 4.75% Convertible Senior Notes (subject to adjustment in certain events) under the following circumstances: (1) if the price of Massey’s common stock reaches specified thresholds; (2) if the 4.75% Convertible Senior Notes are redeemed by the Company; (3) upon the occurrence of certain specified corporate transactions; or (4) if the credit ratings assigned to the 4.75% Convertible Senior Notes decline below specified levels. Regarding the thresholds in (1) above, holders may convert each of their notes into shares of the Company’s common stock during any calendar quarter (and only during such calendar quarter) if the last reported sale price of Massey’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% of the conversion price per share of Massey’s common stock. The conversion price is $19.39 per share.

On November 10, 2003, the Company entered into a fixed interest rate to floating interest rate swap agreement with a highly rated financial institution covering a notional amount of debt of $240 million. The Company designated this swap as a fair value hedge of a portion of its 6.625% Senior Notes. Under the swap, the Company will receive interest payments at a fixed rate of 6.625% and will pay a variable rate that is based on six-month LIBOR plus 216 basis points. The payments received or disbursed in connection with the interest rate swap are included in Interest expense, net. The initial term of this swap agreement expires on November 15, 2010, however, the counterparty to the swap agreement has an option to terminate the swap, in whole or in part, after November 15, 2007 upon payment of an early termination fee equal to the early redemption premium on the 6.625% Senior Notes. The terms of the swap agreement mirror the terms of the hedged portion of the 6.625% Senior Notes.

The Company is exposed to certain losses in the event of nonperformance by the counterparty to the swap agreement. However, the Company’s exposure is not material and, since the counterparty is an investment grade financial institution, nonperformance is not anticipated.

On January 31, 2003, the Company entered into a borrowing program secured by its accounts receivable. The amount available to be borrowed under the program was up to $80 million, depending on the level of eligible receivables and restrictions on concentrations of receivables. At December 31, 2003, there were no borrowings outstanding under the program. The program was set to expire in July 2004, however, it was canceled by the Company in January 2004 in connection with the closing of a new asset-based credit facility. See Note 22 for further discussion. The total cost of the program is included in Interest expense for the year ended December 31, 2003.

The aggregate amounts of long-term debt maturities subsequent to December 31, 2003 are as follows:

Total interest paid for the year ended December 31, 2003 and 2002, and October 31, 2001, was $46.5 million, $35.4 million and $34.8 million, respectively.

In the normal course of business, the Company is 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 impacts on our cash flows, results of operation or financial condition to result from these off-balance sheet arrangements.

The Company uses surety bonds to secure reclamation, workers’ compensation, wage payments, and other miscellaneous obligations. As of December 31, 2003, the Company had $275 million of outstanding surety bonds with third parties. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $247 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, the Company would seek to secure obligations with letters of credit, cash deposits, or other suitable forms of collateral.

From time to time the Company uses bank letters of credit to secure its obligations for workers’ 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 December 31, 2003, the Company had $136.7 million of letters of credit outstanding, collateralized by $141.6 million of cash deposited in restricted, interest bearing accounts (classified in Other current assets), with no claims outstanding against those letters of credit. At December 31, 2002, the Company had $32.5 million of letters of credit outstanding, collateralized by $31.5 million of cash deposited in restricted, interest bearing accounts (classified in Other current assets), with no claims outstanding against those letters of credit.

The Company leases certain mining and other equipment under various lease agreements. Certain of these leases provide options for the purchase of the property at the end of the initial lease term, generally at its then fair market value, or to extend the terms at its then fair rental value. Rental expense for the years ended December 31, 2003 and 2002, and October 31, 2001, was $61.5 million, $53.4 million, and $54.3 million, respectively, and $8.5 million for the two-month period ended December 31, 2001.

In December 2003, the Company entered into several capital leases for certain mining equipment. The leases are for periods ranging from 1 to 7 years. The leases contain residual value guarantees at the end of the lease term, which are included within the table below.

In 2003, the Company sold and leased-back certain mining equipment. The Company received net proceeds of $16.7 million, resulting in a gain of $1.7 million, which was deferred. The gain is being recognized ratably over

the term of the leases, which range from 2 to 6 years. The leases contain renewal options at lease termination and purchase options at an amount approximating fair value at lease termination. The leases are being accounted for as operating leases. Future payments required under the leases are included within the table below.

In 2002, the Company entered into a sale-leaseback transaction involving certain mining equipment. The Company received proceeds of $17.0 million, with no resulting gain or loss on the transaction. The assets were leased back from the purchaser over a period of 4 years. The lease contains a renewal option at lease termination and a purchase option at an amount approximating fair value at lease termination. The lease is being accounted for as an operating lease. Future payments required under the lease are included within the table below.

The following presents future minimum rental payments, by year, required under leases with initial terms greater than one year, in effect at December 31, 2003:

Massey sponsors a qualified non-contributory defined benefit pension plan, which covers substantially all administrative and non-union employees. Based on a participant’s entrance date to the plan, the participant may accrue benefits based on one of four benefit formulas. Two of the formulas provide pension benefits based on the employee’s years of service and average annual compensation during the highest five consecutive years of service. The third formula credits certain eligible employees with flat dollar contributions based on years of service with the Company and years of service under the UMWA 1974 Pension Plan. The fourth formula provides benefits under a cash balance formula with contribution credits based on hours worked. For contributions prior to December 31, 2003, the cash balance formula guaranteed a set rate of return of 6.5% annually. This guaranteed rate of return on contributions was changed effective January 1, 2004 to 4% for all future contributions. Funding for the plan is generally at the minimum annual contribution level required by applicable regulations. No company contributions were necessary in 2003, 2002 or 2001 for this qualified plan.

The plan assets for the qualified defined benefit pension plan are held by an independent trustee. The plan’s assets include cash and cash equivalents, corporate and government bonds, preferred and common stocks and an investment in a group annuity contract. The Company has an internal investment committee that sets investment policy, selects and monitors investment managers and monitors asset allocation.

The investment policy for the pension plan assets includes the objectives of providing growth of capital and income while achieving a target annual rate of return of 8.5% over a full market cycle, approximately 5 to 7 years. Diversification of assets is employed to reduce risk. The target asset allocation is 63% for equity securities (including 50% domestic and 13% international) and 37% for cash and interest bearing securities. The investment policy is based on the assumption that the overall portfolio volatility will be similar to that of the target allocation. Given the volatility of the capital markets, strategic adjustments in various asset classes may be required to rebalance asset allocation back to its target policy. Investment fund managers are not permitted to

invest in certain securities and transactions as outlined by the investment policy statements specific to each investment category without prior investment committee approval.

To develop the expected long-term rate of return on assets assumption, the Company considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension portfolio. This resulted in the selection of the 8.5% long-term rate of return on assets assumption for the year ended December 31, 2003.

The fair value of the major categories of qualified defined benefit pension plan assets includes the following:

In addition to the qualified defined benefit pension plan noted above, the Company sponsors a nonqualified supplemental benefit pension plan for certain salaried employees. Participants in this nonqualified supplemental benefit pension plan accrue benefits under the same formula as the qualified defined benefit pension plan, however, where the benefit is capped by IRS limitations, this nonqualified supplemental benefit pension plan compensates for benefits in excess of the IRS limit. This supplemental benefit plan is unfunded with benefit payments paid by the Company. Pension expense and obligations under this supplemental benefit plan are included in the information presented below. In the table below, Company contributions and the Amount included in noncurrent liabilities are solely related to this nonqualified supplemental benefit plan.

The following table sets forth the change in benefit obligation, plan assets and funded status of both the Company’s qualified defined benefit pension plan and nonqualified supplemental benefit pension plan:

The accumulated benefit obligation for the qualified defined benefit pension plan was $185.4 million and $154.4 million as of December 31, 2003 and 2002, respectively. The fair value of pension plan assets exceeded the projected benefit obligation and the accumulated benefit obligation as of December 31, 2003 and 2002. The accumulated benefit obligation for the nonqualified supplemental defined benefit pension plan was $4.3 million and $3.6 million as of December 31, 2003 and 2002, respectively.

The weighted average assumptions used in determining pension benefit obligations for both the Company’s qualified defined benefit pension plan and nonqualified supplemental benefit pension plan are as follows:

Net periodic pension expense (income) for both the Company’s qualified defined benefit pension plan and nonqualified supplemental benefit pension plan includes the following components:

The weighted average assumptions used in determining pension expenses for both the Company’s qualified defined benefit pension plan and nonqualified supplemental benefit pension plan are as follows:

No company contributions are expected in 2004 for the qualified defined benefit pension plan, however, the company expects to contribute, as benefit payments to participants, $0.03 million in 2004 for the nonqualified supplemental benefit pension plan.

The following benefit payments from both plans, which reflect expected future service, as appropriate, are expected to be paid:

Under labor contracts with the UMWA, certain operations make payments into two multi-employer defined benefit pension plan trusts established for the benefit of certain union employees. The contributions are based on tons of coal produced and hours worked. Such payments aggregated approximately $0.1 million each in the years ended December 31, 2003, December 31, 2002, and October 31, 2001. Payments into the two multi-employer plan trusts were less than $0.1 million during the two months ended December 31, 2001.

For the years ended December 31, 2003, December 31, 2002 and October 31, 2001, Company contributions to these three plans aggregated approximately $0.2 million, $0.2 million, and $7.5 million, respectively. Contributions to these plans during the two months ended December 31, 2001 were less than $0.1 million.

The Company also sponsors a salary deferral and profit sharing plan covering substantially all administrative and non-union employees. The maximum salary deferral rate is 15% of eligible compensation and the Company contributes a fixed match on the first 10% of employee deferrals. The Company may make additional discretionary contributions to the plan. Total Company contributions aggregated approximately $3.5 million, $4.6 million, and $2.5 million for the years ended December 31, 2003, December 31, 2002, and October 31, 2001, respectively, and approximately $0.6 million for the two-month period ended December 31, 2001.

Workers’ compensation and black lung benefit obligation consisted of the following:

The amount of workers’ compensation liability related to self-insurance was $38.2 million at December 31, 2003 and $31.1 million at December 31, 2002. Actuarial assumptions used in the determination of the self-insured portion of workers’ compensation liability included a discount rate of 6.25% at December 31, 2003 and 7.25% at December 31, 2002.

Expenses for black lung benefits and workers’ compensation related benefits include the following components:

Payments for benefits, premiums and other costs related to workers’ compensation and black lung liabilities were $34.2 million, $30.0 million, and $25.0 million for the years ended December 31, 2003, December 31, 2002, and October 31, 2001, respectively, and $2.6 million in the two months ended December 31, 2001.

The actuarial assumptions used in the determination of black lung benefits included a discount rate of 6.25% as of December 31, 2003 (6.75% as of December 31, 2002, and 7.25% as of October 31, 2001 and December 31, 2001).

The Company’s black lung obligation is calculated using assumptions regarding future medical cost increases and cost of living increases. Federal black lung benefits are subject to cost of living increases. State benefits increase only until disability, and then remain constant. The Company assumes a 6.5% annual medical cost increase and a 3.0% cost of living increase in determining its black lung obligation and the annual black lung expense. Assumed medical cost and cost of living increases significantly affect the amounts reported for the Company’s black lung expense and obligation. A one-percentage point change in each of assumed medical cost and cost of living trend rates would have the following effects:

The Company sponsors defined benefit health care plans that provide postretirement medical benefits to eligible union and non-union employees. To be eligible, retirees must meet certain age and service requirements. Depending on year of retirement, benefits may be subject to annual deductibles, coinsurance requirements, lifetime limits, and retiree contributions. Service costs are accrued currently based on an annual study prepared by independent actuaries.

Effective May 15, 2003, the Company amended its plan for postretirement benefits (also known as the “retiree medical program”). Non-union employees who were not previously grandfathered from prior plan changes and who will not be age and service eligible to retire on January 1, 2010 under the provisions of the retiree medical program prior to this amendment are affected. The changes for those employees affected include: the eligibility age for the retiree medical program is changed to correspond directly with the Medicare age eligibility requirement; at least 20 years of service is required; and a $600 annual cap on prescription drug benefits indexed to the Consumer Price Index. The accumulated postretirement benefit obligation decreased by $11.6 million as a result of this amendment.

The following table sets forth the change in benefit obligation of the Company’s postretirement benefit plans:

The discount rate used in determining the postretirement benefit obligation was 6.25% at December 31, 2003 and 6.75% at December 31, 2002.

The postretirement benefit obligation at December 31, 2003 was determined in accordance with the current terms of the Company’s health care plans, together with relevant actuarial assumptions and health care cost trend rates projected at an annual rate of 11.0% ranging down to 5.0% in 2010 (11.0% ranging down to 5.0% in 2009 at December 31, 2002) and remaining level thereafter. Assumed health care cost trend rates have a significant effect on the amounts reported for the medical plans. A one-percentage point change in assumed health care cost trend rates would have the following effects:

In December 2003, Medicare legislation was passed that creates a prescription drug benefit for eligible citizens. This legislation provides for a subsidy for corporate entities that offer their own retiree medical prescription drug benefit, or would allow corporations to make plan changes making Medicare the primary coverage on prescription drug coverage, thus potentially reducing corporations’ other postretirement benefit obligations. Due to the fact that the FASB has not yet determined the appropriate accounting treatment of this favorable development, the Company decided to defer recognition of any impact of this legislation until additional accounting guidance is available. Accordingly, the amounts recorded and disclosed in the Consolidated Financial Statements do not reflect any amounts related to the legislation. The Company does not believe the impact of this legislation on its obligation or its annual expense will be material.

Under the Coal Act, coal producers are required to fund medical and death benefits of certain retired union coal workers based on premiums assessed by the UMWA Benefit Funds. Based on available information at December 31, 2003, the Company’s obligation (discounted at 6.25%) under the Coal Act is estimated at approximately $61.2 million. The Company’s obligation at December 31, 2002 was $60.6 million. The Company treats its obligation under the Coal Act as a participation in a multi-employer plan and records the cost of the Company’s obligation as expense as payments are assessed. The Company expense related to this obligation for the years ended December 31, 2003, December 31, 2002 and October 31, 2001, totaled $4.7 million, $4.1 million, and $5.0 million, respectively. For the two-month period ended December 31, 2001 the Company expensed $0.7 million related to this obligation.

On November 30, 2000, Fluor Corporation (“Fluor”) completed a reverse spin-off, which divided it into two separate publicly-traded corporations. As a result of the reverse spin-off (the “Spin-Off”), Fluor separated into (i) the spun-off corporation, “new” Fluor Corporation (“New Fluor”), which owns all of Fluor’s then existing

businesses except for the coal-related business conducted by A.T. Massey Coal Company, Inc. (“A.T. Massey”), and (ii) Fluor Corporation, subsequently renamed Massey Energy Company, which owns the coal-related business. Further discussion of the Spin-Off may be found in Massey’s Annual Report on Form 10-K for the fiscal year ended October 31, 2000 as filed with the SEC.

Immediately after the Spin-Off, Massey had 73,468,707 shares of $0.625 par value common stock outstanding. In connection with the Spin-Off, A.T. Massey became the sole direct and wholly owned subsidiary of Massey.

Due to the relative significance of the businesses transferred to New Fluor following the Spin-Off, New Fluor has been treated as the “accounting successor” for financial reporting purposes, and the Company has been treated by New Fluor as a discontinued operation despite the legal form of separation resulting from the Spin-Off.

Massey’s equity structure was also impacted as a result of the Spin-Off. Massey assumed from Fluor $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.

Massey’s executive stock plans provide for grants of non-qualified stock options, incentive stock options, stock appreciation rights (“SARs”) and restricted stock awards. All executive stock plans are administered by the Compensation Committee of the Board of Directors (the “Compensation Committee”) comprised of independent outside directors. Option exercise prices, determined by the Committee, are equal to the average of the high and low of the quoted market price of the Company’s common stock on the date of grant. Options and SARs normally extend for 10 years and become exercisable over a vesting period determined by the Compensation Committee, which can include accelerated vesting for achievement of performance or stock price objectives. Additionally, two restricted stock plans exist for the purpose of providing non-employee directors with grants of restricted stock upon initial election or appointment to the Board of Directors and with annual grants of restricted stock. The restricted stock shares and compensation expense related to these shares are included in the “employee” totals discussed in this Note.

Stock based grants (restricted shares, stock options and SARs as discussed herein) awarded to employees of the Company prior to the Spin-Off, were generally converted to equivalent instruments in Massey following its separation from Fluor. In this regard, the outstanding number of grants were increased by multiplying the applicable amount by 4.056 (the “Conversion Ratio”), except for the grants held by Mr. Blankenship, as discussed below. Similarly, where applicable, the exercise price was reduced by dividing the exercise price prior to the Spin-Off by the Conversion Ratio. The Conversion Ratio applied to the outstanding awards held by Company employees was utilized to preserve the intrinsic value of such awards. It was determined by dividing the closing price of Fluor Corporation common stock on the date of the Spin-Off ($36.50) by the opening price for Massey Energy common stock the first trading day after the Spin-Off ($9.00). There were no accounting implications of having reduced the exercise price since the aggregate intrinsic value of the awards immediately after the change was not greater than the aggregate intrinsic value of the awards immediately before the change and the ratio of the exercise price per share to the market value per share was not reduced.

Stock based grants existing on the date of the Spin-Off specific to Mr. Blankenship were administered pursuant to an agreement between Mr. Blankenship, Massey, A.T. Massey and New Fluor. Mr. Blankenship’s restricted stock and SARS after the Spin-Off were converted on a basis of one share or unit of Massey for each share or unit of Fluor. Additionally, Mr. Blankenship’s outstanding stock options were converted at a predetermined rate of 3.4 Massey options for each Fluor option. Similarly, the exercise price of Mr. Blankenship’s outstanding stock options were reduced by the 3.4 ratio.

During the year ended December 31, 2003 the Company issued 534,881 non-qualified stock options with annual vesting of 25% and 161,500 non-qualified stock options that vest after four years, all of which expire ten years after the date of grant. During the year ended December 31, 2002 the Company issued 519,873 non-qualified stock options with annual vesting of 25% and 163,400 non-qualified stock options that vest after four years, all of which expire ten years after the date of grant. During the year ended October 31, 2001 the Company issued 875,961 non-qualified stock options with annual vesting of 25% and that expire ten years after the date of grant.

On November 1, 2001, 787,500 SARs were granted to Mr. Blankenship pursuant to the Amended and Restated Employment Agreement between Massey, A.T. Massey and Don L. Blankenship dated as of November 1, 2001 (amended and restated as of July 16, 2002). These SARs have an exercise price of $19.45 and vest as follows: 225,000 and 225,000 vested on October 31, 2003 and October 31, 2002, respectively, and 225,000 and 112,500 will vest on October 31, 2004, and April 30, 2005, respectively. These SARs expire ten years after the date of grant. The Company shall pay cash in an amount equal to the amount by which the fair market value on the date exercised exceeds the exercise price. The estimated fair value as of the date of grant of $6.77 per SAR was computed using the Black-Scholes option pricing model using the following assumptions: $19.45 exercise price, 3.87% risk free interest rate, 37.1% stock price volatility, and 0.796% dividend yield. No grants of SARs were made to Massey employees during the fiscal years ended December 31, 2003, and 2002 and during the fiscal year ended October 31, 2001.

Restricted stock awards issued under the plans provide that shares awarded may not be sold or otherwise transferred until restrictions have lapsed or performance objectives have been attained. Upon termination of employment, shares upon which restrictions have not lapsed must be returned to the Company. Restricted stock awards issued to employees under the plans totaled 192,024 shares, 477,987 shares and 266,411 shares for the years ended December 31, 2003, December 31, 2002 and October 31, 2001, respectively. The weighted average fair value of restricted stock awards as of the date of grant was $12.94, $5.62 and $17.13 per share for the years ended December 31, 2003, December 31, 2002 and October 31, 2001, respectively. Vested restricted stock is included in the weighted average shares outstanding calculation for basic earnings per share. Unvested restricted stock is included in the weighted average shares outstanding calculation for diluted earnings per share. See the Earnings Per Share section of Note 2 for further discussion.

As permitted by Statement 123, the Company has elected to continue following the guidance of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” for measurement and recognition of stock-based transactions with employees. Expenses related to the Company’s stock compensation plans include amortization of restricted stock value, and expense related to those instruments paid out in cash that derive their value based on the price of the Company’s stock (these include SARs, shadow stock, and incentive units intended to compensate for the tax payable on vesting restricted stock awards). For the years ended December 31, 2003, December 31, 2002 and October 31, 2001, expenses related to the Company’s various stock compensation plans (with the exception of stock options) totaled $14.8 million, $3.6 million and $5.8 million, respectively, and $1.9 million for the two months ended December 31, 2001. Under APB Opinion No. 25, no compensation cost is recognized for the Company’s stock option plans because vesting provisions are based only on the passage of time and because the Company granted the options at an exercise price equal to the average of the high and low of the quoted market price of the Company’s stock on the date of grant. See Note 2, “Significant Accounting Policies—Stock Plans” for the pro forma impact of options.

Characteristics of outstanding stock options at December 31, 2003 are as follows:

At December 31, 2003, there are 3,999,352 shares available for future grant under the Company’s stock plans. Available for grant includes shares, which may be granted as either stock options, or restricted stock, as determined by the Compensation Committee under the Company’s various stock plans.

During the third quarter of 2002, the Company recorded charges in the amount of $13.2 million (pre-tax) related to the write off of capitalized development costs at certain idled mines, which included the Pegs Branch mine, the Spring Branch mine, and the Ruby Energy mine. This charge is included in depreciation, depletion and amortization for the year ended December 31, 2002. Details of the charges are as follows:

During the third quarter of 2001, management decided to move a longwall at the Jerry Fork mine of the Nicholas Energy resource group to better mining conditions in another mining location. As a result, unamortized longwall panel development costs of $7.6 million were considered to be impaired and were written off. This charge is reflected in cost of produced coal revenue for the year ended October 31, 2001.

Appalachian Synfuel, LLC (the “LLC”) was formed in 1997 as a wholly owned subsidiary of Fluor to manufacture and market synthetic fuel. The LLC became a wholly owned subsidiary of Massey in November 2000 when the Spin-Off occurred. As a provider of synthetic fuel, the LLC generates tax credits for its owners; however, because of the Company’s tax position it is unable to utilize the tax credits generated by the LLC. In order to monitize the value of the Company’s investment, the Company sought to sell an interest in the LLC to an entity that could benefit currently from the tax credits generated. In order to facilitate such a transaction, the LLC agreement was amended to divide the ownership interest into three tranches, Series A, Series B and Series C.

Under the amended LLC 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 the LLC going forward at a specified indexed interest rate. As a result, the Series C owner will fund the daily operations of the LLC. The Series C owner also has the responsibility at the end of the term of the LLC agreement to wind up the affairs of the LLC, disposing of all assets and settling liabilities.

On March 15, 2001, and May 9, 2002, the Company, in a two-part transaction, sold 99% of its Series A and Series B interests, respectively, in the LLC, contingent upon favorable Internal Revenue Service rulings, which

were received in September 2001 and in June 2002, respectively. The Company received cash of $7.2 million, a recourse promissory note for $34.6 million that is being 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 $19.1 million and $23.8 million as of December 31, 2003 and 2002, respectively, are included in Other noncurrent liabilities to be recognized ratably though 2007. Massey’s subsidiary, Marfork Coal Company, Inc., manages the facility under an operating agreement.

The Company is engaged in the production of high-quality low sulfur steam coal for the electric generating industry, as well as industrial customers and metallurgical coal for the steel industry. Steam coal sales accounted for approximately 64%, 60% and 54% of produced coal revenue for the years ended December 31, 2003, 2002 and October 31, 2001, respectively. Metallurgical coal sales accounted for approximately 26%, 30% and 34% of produced coal revenue for the years ended December 31, 2003, 2002 and October 31, 2001, respectively. Industrial coal sales for the years ended December 31, 2003, 2002 and October 31, 2001, were 10%, 10% and 12% of produced coal revenue, respectively.

Massey’s mining operations are conducted in southern West Virginia, eastern Kentucky, and western Virginia and the coal is marketed primarily in the United States.

For the years ended December 31, 2003 and 2002, approximately 14% and 12%, respectively, of produced coal revenue was attributable to affiliates of DTE Energy Company. For the years ended December 31, 2002 and October 31, 2001, approximately 11% of produced coal revenue was attributable to Duke Energy Corporation and its affiliate, Duke Energy Merchants, LLC. At December 31, 2003, approximately 53%, 28% and 19% of consolidated trade receivables represent amounts due from utility customers, metallurgical customers and industrial customers, respectively, compared with 59%, 20% and 21%, respectively, as of December 31, 2002. Credit is extended based on an evaluation of the customer’s financial condition. To mitigate credit-related risks in all customer classifications, the Company maintains a credit policy that 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.

The Company’s trade accounts receivable are subject to potential default by customers. Specifically, the Company has exposure to the U.S. steel industry and energy trading and brokering companies which have faced economic difficulty in recent years. Certain of the Company’s customers have filed for bankruptcy resulting in bad debt charges to the Company. The Company establishes its doubtful account reserve to specifically consider customers in financial difficulty and other potential receivable losses. In establishing its reserve, the Company considers the financial condition of its individual customers, and probability of recovery in the event of default. The Company charges off uncollectible trade receivables once legal potential for recovery is exhausted.

The following methods and assumptions were used by the Company in estimating its fair value disclosures for financial instruments as of December 31, 2003 and 2002:

Cash and cash equivalents: The carrying value approximates the fair value due to the short maturity of these instruments.

Short-term debt: The fair value estimate of the Company’s capital lease obligations at December 31, 2003 is based on estimated borrowing rates used to discount the cash flows to their present value. The carrying value of the Company’s capital lease obligations approximates their fair value as the leases were entered into in December 2003. At December 31, 2002, the fair value estimate of the Company’s prior revolving credit facility outstanding approximated its carrying value.

Long-term debt: At December 31, 2003, the fair value estimate of the Company’s 6.625% Senior Notes, 6.95% Senior Notes, and 4.75% Convertible Senior Notes outstanding was $836.9 million based on available market information at that date. At December 31, 2002, the fair value of the 6.95% Senior Notes was $270.9 million based on available market information at that date. As discussed above, the carrying value of the Company’s capital lease obligations approximates its fair value as the leases were entered into in December 2003.

Interest rate swap: The fair value estimate is based on the cost that would be incurred to terminate the contract. The Company would have paid $3.2 million to terminate the interest rate swap contract in place as of December 31, 2003. The fair value of the swap is recorded in Other noncurrent liabilities.

On July 31, 1997, the Company acquired United Coal Company and its subsidiary, Wellmore Coal Corporation (“Wellmore”). Wellmore was party to a coal supply agreement (the “CSA”) with Harman Mining Corporation and certain of its affiliates (“Harman”), pursuant to which Harman sold coal to Wellmore. In December 1997, Wellmore declared force majeure under the CSA 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 CSA was forced to close its Pittsburgh, Pennsylvania coke plant due to regulatory action. The Company 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 Massey and certain of its subsidiaries in the Circuit Court of Boone County, West Virginia, alleging that Massey and its 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 awarded the plaintiffs $50 million in compensatory and punitive damages. On July 17, 2003, the Company was ordered to file a $55 million letter of credit with the trial court to secure the jury verdict, plus one year’s interest, which it filed on August 13, 2003. The Company is pursuing post-judgment remedies. Various motions filed in the trial court have been fully briefed and argued. Massey will appeal to the Supreme Court of Appeals of West Virginia, if necessary. The Company has accrued a liability with respect to this case of $25 million, excluding interest, included in Other current liabilities in the Consolidated Financial Statements, which it believes is a fair estimate of the eventual total payout in this case.

On October 11, 2000, a partial failure of the coal refuse impoundment at Martin County Coal Corporation, one of the Company’s 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 with monitoring and reporting ongoing. Martin County Coal began processing coal again on April 2, 2001. The Company is 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 December 31, 2003, the Company had incurred a total of approximately $71.9 million of cleanup costs and other spill related costs, including claims, fines and other items, $66.0 million of which have been paid directly or reimbursed by insurance companies. The Company continues 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, including a lawsuit filed by the Town of Fort Gay, West Virginia alleging that its water treatment and distribution plant was damaged by the discharge from the impoundment, which was settled in January 2004 (totally with insurance proceeds). Remaining issues (none of which the Company considers material) include:

The Company believes, but cannot assure, that it has insurance coverage applicable to these items, at least with respect to costs other than governmental penalties, such as those assessed by MSHA, and punitive damages, if any. One of the Company’s carriers has stated that it believes its policy does not provide coverage for governmental penalties or punitive damages.

Since July 2001, seven subsidiaries of the Company have been named, along with approximately 170 other companies, in 35 separate complaints filed in the Circuit Courts of Boone, Fayette, Kanawha, McDowell, Mercer, Raleigh and Wyoming Counties, West Virginia. These cases cover approximately 2,200 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 Supreme Court of Appeals of West Virginia has ruled that these cases, along with 23 additional flood damage cases not involving the Company’s subsidiaries, be handled pursuant to the Court’s mass litigation rules. As a result of this ruling, the cases have been transferred to the Circuit Court of Raleigh County, West Virginia to be handled by a panel consisting of three circuit court judges. On August 1, 2003, the panel certified nine questions to the Supreme Court of Appeals of West Virginia. While the plaintiffs’ alleged damages have not been quantified and the outcome of this litigation is subject to uncertainties, the Company believes this matter will be resolved without a material impact on its cash flows, results of operations or financial condition.

In July 2002, two cases were filed by approximately 230 plaintiffs in the Circuit Court of Mingo County, West Virginia alleging that Massey’s Delbarton Mining Company’s mining activities destroyed nearby resident plaintiffs’ water supplies. The plaintiffs seek to recover compensatory and punitive damages relating to alleged personal injuries and property damages, but their alleged damages have not been quantified. Delbarton has provided almost all of the plaintiffs with replacement water sources. The cases have been consolidated for trial scheduled to begin in May 2004.

On August 5, 2002, a shareholder derivative suit was filed in the Circuit Court of Boone County, West Virginia, naming the Company, each of its directors, and certain of its current and former officers. The suit alleges (i) breach of fiduciary duties against all of the defendants for refusing to cause the Company to comply with environmental, labor and securities laws, and (ii) improper insider trading by certain of the Company’s current and former officers. The plaintiff makes these allegations derivatively, and seeks to recover damages on behalf of the Company. The damages claimed by the plaintiff have not been quantified. The Company and the other defendants removed the case to the U.S. District Court for the Southern District of West Virginia, but the case was remanded to the Circuit Court of Boone County, West Virginia. Motions to dismiss have been argued before the court and discovery continues.

In January 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 16 suits in the Circuit Court of Kanawha County, West Virginia against the Company and 12 subsidiaries. Plaintiffs alleged that the defendants illegally transport coal in overloaded trucks causing damage to state roads, interfering with the plaintiffs’ use and enjoyment of their properties and their right to use the public roads, and seek injunctive relief and unquantified compensatory and punitive damages. The Supreme Court of Appeals of West Virginia consolidated this and 3 similar lawsuits against other coal and transportation companies in other counties not involving the Company’s subsidiaries, to be handled pursuant to the Court’s mass litigation rules.

The Company is involved in various other legal actions incident to the conduct of its businesses. Management does not expect a material impact to its results of cash flows, results of operations or financial condition by reason of these actions.

As of December 31, 2003, the Company had commitments to purchase from external production sources 2.2 million, 0.8 million, and 0.7 million tons of coal at a cost of $70.5 million, $25.4 million and $15.6 million in 2004, 2005, and 2006, respectively. In addition, as of December 31, 2003 the Company had commitments to purchase $87.9 million of capital assets, supplies and other services during 2004.

Set forth below is the Company’s quarterly financial information for the previous two fiscal years

On January 20, 2004, the Company entered into a new asset-based revolving credit facility, secured by its inventory and accounts receivable. This new facility will provide the Company with increased liquidity and letter of credit capacity. The facility provides for borrowings of up to $130 million, depending on the level of eligible inventory and accounts receivable. This facility replaced the Company’s prior undrawn $80 million accounts

receivable-based financing program and includes a $100 million sublimit for letters of credit. This facility currently supports $40 million of letters of credit, a portion of which were previously supported by cash collateral. The credit facility has a five-year term ending in January 2009. This facility contains a number of significant restrictions and covenants that limit the Company’s ability to, among other things:

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

There have been no changes in, or disagreements with, accountants on accounting and financial disclosure.

The Company has established disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation as of December 31, 2003, the principal executive officer and principal financial officer of Massey Energy Company have concluded that Massey Energy Company’s disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Massey Energy Company in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no significant changes in Massey Energy Company’s internal controls or in other factors that could significantly affect those controls subsequent to the date of their most recent evaluation.

The following information is incorporated by reference from the Company’s definitive proxy statement pursuant to Regulation 14A, which will be filed not later than 120 days after the close of Massey’s fiscal year ended December 31, 2003:

Information required by this item is included in the Compensation Committee Report on Executive Compensation and Executive Compensation and Other Information sections of the definitive proxy statement pursuant to Regulation 14A, involving the election of directors, which is incorporated herein by reference and will be filed not later than 120 days after the close of Massey’s fiscal year ended December 31, 2003.

Information required by this item is included in the Stock Ownership section of the Election of Directors portion of the definitive proxy statement pursuant to Regulation 14A, involving the election of directors, which is incorporated herein by reference and will be filed not later than 120 days after the close of Massey’s fiscal year ended December 31, 2003.

Information required by this item is included in the Other Matters section of the Election of Directors portion of the definitive proxy statement pursuant to Regulation 14A, involving the election of directors, which is incorporated herein by reference and will be filed not later than 120 days after the close of Massey’s fiscal year ended December 31, 2003.

Information concerning principal accounting fees and services contained under the heading The Audit Committee Report in the definitive proxy statement pursuant to Regulation 14A, which is incorporated by reference and will be filed not later than 120 days after the close of Massey’s fiscal year ended December 31, 2003.

Consolidated Statements of Earnings for the Fiscal Years Ended December 31, 2003, December 31, 2002, October 31, 2001, and the two month period ended December 31, 2001

Consolidated Statements of Cash Flows for the Fiscal Years Ended December 31, 2003, December 31, 2002, October 31, 2001, and the two month period ended December 31, 2001

Consolidated Statements of Shareholders’ Equity for the Fiscal Years Ended December 31, 2003, December 31, 2002, October 31, 2001, and the two month period ended December 31, 2001

Current Report on Form 8-K under Item 12 furnished with the Securities and Exchange Commission on October 24, 2003 (containing a press release announcing its third quarter 2003 earnings).

Current Report on Form 8-K under Item 5 furnished with the Securities and Exchange Commission on October 27, 2003 (containing a press release reporting the commencement by the Company of a proposed private offering of $360 million aggregate principal amount of 6.625% Senior Notes due 2010 and certain sections of the preliminary offering memorandum).

Current Report on Form 8-K under Item 5 filed with the Securities and Exchange Commission on November 6, 2003 (containing a press release reporting the pricing of its private offering of $360 million aggregate principal amount of 6.625% Senior Notes due November 15, 2010).

Current Report on Form 8-K under Item 5 filed with the Securities and Exchange Commission on November 12, 2003 (containing a press release reporting the closing of its private offering of $360 million principal amount of 6.625% Senior Notes due November 15, 2010, and containing the Indenture and Registration Rights Agreement associated therewith).

Current Report on Form 8-K under Item 5 filed with the Securities and Exchange Commission on January 30, 2004 (containing a press release reporting the closing of its $130 million asset based revolving credit facility).

Current Report on Form 8-K under Item 12 furnished with the Securities and Exchange Commission on January 30, 2004 (containing a press release announcing its fourth quarter and year end 2003 earnings).

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

By:

/s/ B.F. PHILLIPS

B. F. Phillips, Jr.,

Senior Vice President

and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

* Manually signed Powers of Attorney authorizing Thomas J. Dostart, Baxter F. Phillips, Jr. and Jeffrey M. Jarosinski, and each of them, to sign the annual report on Form 10-K for the fiscal year ended December 31, 2003 and any amendments thereto as attorneys-in-fact for certain directors and officers of the registrant are included herein as Exhibits 24.


Delaware		95-0740960
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

4 North 4th Street, Richmond, Virginia		23219
(Address of principal executive offices)		(Zip Code)


Electricity Generation Type	Cost per million Kilowatt Hours
Oil	$	5.133
Natural Gas	$	4.221
Coal	$	1.895
Nuclear	$	1.816
Other (solar, wind, etc.)	$	1.115
Hydroelectric	$	0.580


Resource Group Name	Location	2003 Production⁽¹⁾	2003 Shipments	Year Established or Acquired
		(Thousands of Tons)
West Virginia Resource Groups
Black Castle	Boone County, WV	2,868	1,052	1987
Delbarton	Mingo County, WV	483	1,307	1999
Eagle Energy	Boone County, WV	—	—	1996
Elk Run	Boone County, WV	2,227	2,672	1978
Green Valley	Nicholas County, WV	811	846	1996
Independence	Boone County, WV	2,719	2,712	1994
Logan County	Logan County, WV	6,527	5,714	1998
Marfork	Raleigh County, WV	2,060	5,537	1993
Nicholas Energy	Nicholas County, WV	4,723	4,244	1997
Omar	Boone County, WV	—	1,336	1954
Performance	Raleigh County, WV	3,271	565	1994
Progress	Boone County, WV	3,759	3,087	1998
Rawl	Mingo County, WV	1,503	1,265	1974
Stirrat	Logan County, WV	—	11	1993

Kentucky Resource Groups
Long Fork	Pike County, KY	—	2,800	1991
Martin County	Martin County, KY	2,577	2,367	1969
New Ridge	Pike County, KY	—	1,774	1992
Sidney	Pike County, KY	6,910	3,018	1984

Virginia Resource Group
Knox Creek	Tazewell County, VA	520	523	1997
Other/Unassigned	N/A	—	163	N/A

Total		40,958	40,993


	Tons of Coal to be Delivered (In Millions)
	2004	2005	2006	2007	2008
Volume under existing contracts	47.8	37.4	14.7	6.7	3.1


Administrative Offices:
Richmond, Virginia	Owned	Massey Corporate Headquarters
Charleston, West Virginia	Leased	Massey Coal Services Headquarters
Chapmanville, West Virginia	Leased	Massey Coal Services Field Office


		Page
PART I

Item 1.	Business	4

Item 2.	Properties	29

Item 3.	Legal Proceedings	34

Item 4.	Submission of Matters to a Vote of Security Holders	36

PART II

Item 5.	Market for Registrant’s Common Stock and Related Stockholder Matters	38

Item 6.	Selected Financial Data	40

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	56

Item 8.	Financial Statements and Supplementary Data	57

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	95

Item 9A.	Controls and Procedures	95

PART III

Item 10.	Directors and Executive Officers of the Registrant	96

Item 11.	Executive Compensation	96

Item 12.	Security Ownership of Certain Beneficial Owners and Management	96

Item 13.	Certain Relationships and Related Transactions	96

Item 14.	Principal Accounting Fees and Services	96

PART IV

Item 15.	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	97

SIGNATURES		102


End Use	Tons (millions)	% of Total
Electricity generation	982	88	%
Industrial users	63	6	%
Exports	40	4	%
Steel making	23	2	%
Residential & commercial	4	—

Total	1,112	100	%


Electricity Generation Source	% of Total Electricity Generation
Coal	50	%
Nuclear	21	%
Natural Gas	18	%
Hydro	7	%
Oil	2	%
Other	2	%

Total	100	%


Resource Group	Surface Mine		Underground Mine		Total
Black Castle	1	(1 HW)	—		1
Delbarton	—		1		1
Elk Run	—		4		4
Green Valley	—		2		2
Independence	—		4	(1 LW)	4
Logan County	5	(2 HW)	2	(1 LW)	7
Marfork	—		5		5
Nicholas Energy	1	(1 HW)	—		1
Performance	—		1	(1 LW)	1
Progress	3	(1 HW)	—		3
Rawl	1		3		4
Martin County	1	(1 HW)	1		2
Sidney	1	(1 HW)	6	(1 LW)	7
Knox Creek	—		1		1

Total	13	(7 HW)	30	(4 LW)	43


	Location	Total	Proven	Probable	Assigned⁽²⁾	Unassigned	Owned	Leased
	(In Thousands of Tons)
Resource Groups:

West Virginia
Black Castle	Boone County	53,724	44,180	9,544	53,724	—	—	53,724
Delbarton	Mingo County	295,864	124,568	171,296	146,870	148,994	80	295,784
Eagle Energy	Boone County	—	—	—	—	—	—	—
Elk Run	Boone County	139,484	106,754	32,730	66,201	73,283	6,233	133,251
Green Valley	Nicholas County	8,154	8,154	—	7,234	920	—	8,154
Independence	Boone County	56,681	55,350	1,331	51,771	4,910	6,323	50,358
Logan County	Logan County	86,468	86,468	—	43,000	43,468	—	86,468
Marfork	Raleigh County	67,924	60,905	7,019	43,794	24,130	748	67,176
Nicholas Energy	Nicholas County	126,112	108,645	17,467	73,331	52,781	67,474	58,638
Omar	Boone County	19,025	7,598	11,427	—	19,025	530	18,495
Performance	Raleigh County	30,371	30,359	12	29,140	1,231	—	30,371
Progress	Boone County	89,349	81,316	8,033	89,349	—	30,545	58,804
Rawl	Mingo County	111,995	81,222	30,773	63,529	48,466	1,420	110,575
Stirrat	Logan County	5,482	3,596	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	49,733	22,838	26,895	8,870	40,863	1,423	48,310
New Ridge	Pike County	—	—	—	—	—	—	—
Sidney	Pike County	156,396	97,987	58,409	129,103	27,293	8,726	147,670

Virginia
Knox Creek	Tazewell County	50,839	37,810	13,029	34,083	16,756	—	50,839

Other	N/A	91,683	45,149	46,534	25,187	66,496	25,904	65,779

Subtotal		1,444,900	1,006,172	438,728	866,218	578,682	149,406	1,295,494

Land Management Companies:⁽³⁾

Black King	Boone Co., WV	60,065	57,539	2,526	—	60,065	23,037	37,028
	Raleigh Co., WV
Boone East	Boone Co., WV	169,634	129,620	40,014	88,873	80,761	93,200	76,434
	Kanawha Co., WV
Boone West	Boone Co., WV	258,397	100,924	157,473	10,595	247,802	67,128	191,269
	Logan Co., WV
Ceres Land	Raleigh Co., WV	12,397	10,142	2,255	—	12,397	—	12,397
Hanna Land	Boone Co., WV	40,717	36,643	4,074	40,717	—	—	40,717
	Kanawha Co., WV
Lauren Land	Mingo Co., WV	139,409	92,607	46,802	11,447	127,962	20,185	119,224
	Pike Co., KY
New Market	Wyoming Co., WV	60,202	23,708	36,494	—	60,202	6,030	54,172
Raven Resources	Boone Co., WV	31,890	21,893	9,997	—	31,890	—	31,890
	Raleigh Co., WV

Subtotal		772,711	473,076	299,635	151,632	621,079	209,580	563,131

Total		2,217,611	1,479,248	738,363	1,017,850	1,199,761	358,986	1,858,625


	Recoverable Reserves	Sulfur content			Average BTU as received	Coal Type⁽⁴⁾
	Recoverable Reserves	+1%⁽²⁾	-1%⁽²⁾	Compliance⁽³⁾	Average BTU as received	Coal Type⁽⁴⁾
	(In Thousands of Tons Except Average Btu as Received)
Resource Groups:

West Virginia
Black Castle	53,724	12,162	41,562	34,126	12,246	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Delbarton	295,864	117,605	178,259	130,402	13,526	Low Sulfur Utility
						Low Sulfur Industrial
Eagle Energy	—	—	—	—	—	N/A
Elk Run	139,484	58,824	80,660	72,340	13,460	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Green Valley	8,154	—	8,154	8,154	12,903	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Independence	56,681	7,767	48,914	8,592	12,993	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Logan County	86,468	17,898	68,570	48,352	12,424	Low Sulfur Utility
						Low Sulfur Industrial
Marfork	67,924	29,229	38,695	26,757	13,576	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Nicholas Energy	126,112	50,806	75,306	31,371	12,606	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Omar	19,025	7,209	11,816	444	12,855	Low Sulfur Utility
						Low Sulfur Industrial
Performance	30,371	2,821	27,550	16,937	13,754	High Vol Met
Progress	89,349	10,993	78,356	58,382	11,879	Low Sulfur Utility
						Low Sulfur Industrial
Rawl	111,995	35,873	76,122	53,409	12,778	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	—	12,778	Low Sulfur Utility
						Low Sulfur Industrial
Martin County	49,733	34,534	15,199	6,594	12,685	Low Sulfur Utility
						Low Sulfur Industrial
New Ridge	—	—	—	—	—	N/A
Sidney	156,396	61,437	94,959	59,457	12,980	Low Sulfur Utility
						Low Sulfur Industrial
						High Vol Met


	High		Low		Dividends
Fiscal Year 2002
Quarter ended March 31, 2002	$	22.41	$	13.45	$	0.04
Quarter ended June 30, 2002	$	18.70	$	12.26	$	0.04
Quarter ended September 30, 2002	$	12.78	$	5.15	$	0.04
Quarter ended December 31, 2002	$	10.80	$	4.55	$	0.04

	High		Low		Dividends
Fiscal Year 2003
Quarter ended March 31, 2003	$	10.85	$	7.30	$	0.04
Quarter ended June 30, 2003	$	15.05	$	9.15	$	0.04
Quarter ended September 30, 2003	$	14.20	$	10.80	$	0.04
Quarter ended December 31, 2003	$	21.60	$	13.25	$	0.04


Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights	(b) Weighted- average exercise price of outstanding options, warrants and rights		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	2,748,625	$	13.23	3,999,352	⁽¹⁾
Equity compensation plans not approved by security holders	—		—	—

Total	2,748,625	$	13.23	3,999,352


	Year Ended December 31,						Year Ended October 31,							Two Months Ended December 31, 2001⁽²⁾
	2003			2002			2001			2000		1999		Two Months Ended December 31, 2001⁽²⁾
CONSOLIDATED STATEMENT OF INCOME DATA:
Produced coal revenue	$	1,262.1		$	1,318.9		$	1,203.3		$	1,081.0	$	1,076.1	$	204.8
Total revenue		1,553.4			1,630.1			1,431.9			1,312.7		1,263.0		246.4
(Loss) Income from operations		(17.5	)		(26.7	)		9.5			96.5		137.9		(19.2	)
(Loss) Income before cumulative effect of accounting change		(32.3	)		(32.6	)		(5.4	)		78.5		102.5		(14.8	)
Net (loss) income		(40.2	)		(32.6	)		(5.4	)		78.5		102.5		(14.8	)
(Loss) Income per share (Basic and Diluted)⁽³⁾
(Loss) Income before cumulative effect of accounting change		(0.43	)		(0.44	)		(0.07	)		1.07		1.40		(0.20	)
Net (loss) income		(0.54	)		(0.44	)		(0.07	)		1.07		1.40		(0.20	)
Dividends declared per share		0.16			0.16			0.20			N/A		N/A		—

CONSOLIDATED BALANCE SHEET DATA:
Working capital (deficit)	$	443.2		$	(59.7	)	$	(84.7	)	$	164.8	$	72.5	$	(93.3	)
Total assets		2,376.7			2,241.4			2,271.1			2,183.8		2,008.6		2,272.0
Long-term debt		784.3			286.0			300.0			N/A		N/A		300.0
Shareholders’ equity		759.0			808.2			860.6			1,372.5		1,275.6		849.5

OTHER DATA:
EBIT⁽⁴⁾	$	(17.5	)	$	(26.7	)	$	9.5		$	96.5	$	137.9	$	(19.2	)
EBITDA⁽⁵⁾		179.0			181.0			190.8			267.8		305.5		12.0
Total costs and expenses per ton sold		38.38			39.33			32.52			30.22		29.71		38.10
Average cash cost per ton sold⁽⁶⁾		28.23			28.64			24.15			21.60		21.28		28.33
Produced coal revenue per ton sold		30.79			31.30			27.51			26.86		28.40		29.36
Capital expenditures		164.4			135.1			247.5			204.8		230.0		37.7

Tons sold		41.0			42.1			43.7			40.2		37.9		7.0
Tons produced		41.0			43.9			45.1			41.5		38.4		7.0
Number of employees		4,428			4,552			5,004			3,610		3,190		5,040


	Year Ended December 31,						Year Ended October 31,									Two Months Ended December 31, 2001
	2003			2002			2001			2000			1999			Two Months Ended December 31, 2001
Net (loss) income	$	(40.2	)	$	(32.6	)	$	(5.4	)	$	78.5		$	102.5		$	(14.8	)
Cumulative effect of accounting change, net		7.9			—			—			—			—			—

(Loss) Income before cumulative effect of accounting change, net		(32.3	)		(32.6	)		(5.4	)		78.5			102.5			(14.8	)
Income tax (benefit) expense		(28.3	)		(24.9	)		(10.5	)		43.2			49.0			(8.7	)
Interest expense (income), net		43.1			30.8			25.4			(25.2	)		(13.6	)		4.3

(Loss) Income from operations		(17.5	)		(26.7	)		9.5			96.5			137.9			(19.2	)
Depreciation, depletion and amortization		196.5			207.7			181.3			171.3			167.6			31.2

EBITDA	$	179.0		$	181.0		$	190.8		$	267.8		$	305.5		$	12.0


	December 31, 2003			December 31, 2002
	(In Thousands)
6.625% senior notes due 2010	$	360,000		$	—
6.95% senior notes due 2007		283,000			286,000
4.75% convertible senior notes due 2023		132,000			—
Capital lease obligations		16,254			—
Fair value hedge valuation		(3,213	)		—
Revolving credit facilities		—			264,045

		788,041			550,045
Amounts due within one year		(3,714	)		(264,045	)

Total long term debt	$	784,327		$	286,000


	Payments Due by Period
In Thousands	Total		Within 1 Year		2-3 Years		4-5 Years		Beyond 5 Years
Long-term debt⁽¹⁾	$	1,098,759	$	41,653	$	86,425	$	345,178	$	625,503
Capital lease obligations⁽²⁾		19,170		4,538		5,048		3,464		6,120
Operating lease obligations⁽³⁾		153,439		57,515		83,752		11,106		1,066
Coal purchase obligations⁽⁴⁾		111,546		70,496		41,050		—		—
Coal lease obligations⁽⁵⁾		157,017		13,857		24,245		21,667		97,248
Other purchase obligations⁽⁶⁾		117,551		87,894		18,728		6,110		4,819

Total obligations	$	1,657,482	$	275,953	$	259,248	$	387,525	$	734,756


Payments Due by Years (In Thousands)
Within 1 Year	2 - 3 Years	4 - 5 Years
$43,530	$86,506	$92,737


	Year Ended									Two Months Ended
	December 31, 2003			December 31, 2002			October 31, 2001			December 31, 2001
Revenues
Produced coal revenue	$	1,262,098		$	1,318,935		$	1,203,285		$	204,753
Freight and handling revenue		91,785			112,017			129,894			18,912
Purchased coal revenue		115,304			117,049			49,485			16,999
Other revenue		65,945			78,804			49,197			5,779
Insurance settlement		17,677			—			—			—
Senior notes repurchase income		615			3,290			—			—

Total revenues		1,553,424			1,630,095			1,431,861			246,443

Costs and Expenses
Cost of produced coal revenue		1,115,858			1,166,159			1,024,713			190,046
Freight and handling costs		91,785			112,017			129,894			18,912
Cost of purchased coal revenue		117,281			119,562			47,030			16,081
Depreciation, depletion and amortization applicable to:
Cost of produced coal revenue		191,994			203,921			177,384			30,293
Selling, general and administrative		4,501			3,809			3,885			899
Selling, general and administrative		39,715			40,111			31,702			7,510
Other expense		9,832			11,204			7,707			1,911

Total costs and expenses		1,570,966			1,656,783			1,422,315			265,652

(Loss) Income from operations		(17,542	)		(26,688	)		9,546			(19,209	)
Interest income		5,150			4,470			8,747			987
Interest expense		(48,259	)		(35,302	)		(34,214	)		(5,302	)

Loss before taxes		(60,651	)		(57,520	)		(15,921	)		(23,524	)
Income tax benefit		(28,318	)		(24,946	)		(10,501	)		(8,723	)

Loss before cumulative effect of accounting change		(32,333	)		(32,574	)		(5,420	)		(14,801	)
Cumulative effect of accounting change, net of tax		(7,880	)		—			—			—

Net loss	$	(40,213	)	$	(32,574	)	$	(5,420	)	$	(14,801	)

Loss per share (Basic and Diluted)
Loss before cumulative effect of accounting change	$	(0.43	)	$	(0.44	)	$	(0.07	)	$	(0.20	)
Cumulative effect of accounting change		(0.11	)		—			—			—

Net loss	$	(0.54	)	$	(0.44	)	$	(0.07	)	$	(0.20	)

Shares used to calculate loss per share
Basic and Diluted		74,592			74,442			73,858			74,131


	December 31, 2003			December 31, 2002
ASSETS
Current Assets
Cash and cash equivalents	$	88,753		$	2,725
Trade and other accounts receivable, less allowance of $8,350 and $8,775, respectively		152,607			175,795
Inventories		206,616			193,669
Deferred taxes		12,783			13,889
Income taxes receivable		15,715			6,437
Other current assets		226,048			117,326

Total current assets		702,522			509,841

Net Property, Plant and Equipment		1,480,187			1,534,488
Other Noncurrent Assets
Pension assets		64,748			77,356
Other		129,281			119,747

Total other noncurrent assets		194,029			197,103

Total assets	$	2,376,738		$	2,241,432


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable, principally trade and bank overdrafts	$	109,418		$	124,933
Short-term debt		3,714			264,045
Payroll and employee benefits		30,573			44,389
Other current liabilities		115,569			136,165

Total current liabilities		259,274			569,532

Noncurrent Liabilities
Long-term debt		784,327			286,000
Deferred taxes		227,105			244,676
Other		347,076			333,012

Total noncurrent liabilities		1,358,508			863,688

Shareholders’ Equity
Capital Stock
Preferred stock – authorized 20,000,000 shares; no par; none issued		—			—
Common stock – authorized 150,000,000 shares; $0.625 par; issued and outstanding – 75,508,359 and 75,317,732, respectively		47,193			47,074
Additional Capital		24,270			21,659
Unamortized executive stock plan expense		(6,219	)		(6,407	)
Retained earnings		693,712			745,886

Total shareholders’ equity		758,956			808,212

Total liabilities and shareholders’ equity	$	2,376,738		$	2,241,432


	Common Stock					Additional Capital			Unamortized Executive Stock Plan Expense			Net Investment by Fluor Corporation			Due From Fluor Corporation			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
	Shares		Amount			Additional Capital			Unamortized Executive Stock Plan Expense			Net Investment by Fluor Corporation			Due From Fluor Corporation			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
Balance at October 31, 2000	73,469		$	45,918		$	—		$	—		$	1,606,389		$	(279,064	)	$	—		$	(763	)	$	1,372,480
Net loss																			(5,420	)					(5,420	)
Other comprehensive income, net of deferred tax of $488:
Reclassification of unrealized gain to net income																						763			763

Comprehensive loss																									(4,657	)

Capital contributions													2,476												2,476
Net change in amount due from Fluor Corporation																67,554									67,554
Spin-Off transaction										(3,840	)		(1,608,865	)		211,510			825,373						(575,822	)
Dividends declared ($0.20 per share)																			(14,773	)					(14,773	)
Exercise of stock options, net	817			511			8,858																		9,369
Stock option tax benefit							2,611																		2,611
Amortization of executive stock plan expense										1,367															1,367
Issuance of restricted stock, net	258			161			4,072			(4,233	)														—

Balance at October 31, 2001	74,544		$	46,590		$	15,541		$	(6,706	)	$	—		$	—		$	805,180		$	—		$	860,605

Net loss																			(14,801	)					(14,801	)
Exercise of stock options, net	253			158			2,698																		2,856
Stock option tax benefit							640																		640
Amortization of executive stock plan expense										239															239
Issuance of restricted stock, net	(23	)		(14	)		(320	)		334															—

Balance at December 31, 2001	74,774		$	46,734		$	18,559		$	(6,133	)	$	—		$	—		$	790,379		$	—		$	849,539

Net loss																			(32,574	)					(32,574	)
Dividends declared ($0.16 per share)																			(11,919	)					(11,919	)
Exercise of stock options, net	126			78			1,330																		1,408
Stock option tax benefit							208																		208
Amortization of executive stock plan expense										1,550															1,550
Issuance of restricted stock, net	418			262			1,562			(1,824	)														—

Balance at December 31, 2002	75,318		$	47,074		$	21,659		$	(6,407	)	$	—		$	—		$	745,886		$	—		$	808,212

Net loss																			(40,213	)					(40,213	)
Dividends declared ($0.16 per share)																			(11,961	)					(11,961	)
Exercise of stock options, net	93			59			739																		798
Stock option tax benefit							172																		172
Amortization of executive stock plan expense										1,948															1,948
Issuance of restricted stock, net	97			60			1,700			(1,760	)														—

Balance at December 31, 2003	75,508		$	47,193		$	24,270		$	(6,219	)	$	—		$	—		$	693,712		$	—		$	758,956


$ In Thousands	Year Ended December 31, 2003
Reclamation liability at beginning of period	$	115,038
Cumulative effect		(13,124	)
Accretion expense		7,832
Liability incurred		2,935
Revisions in estimated cash flows		6,536
Payments		(13,458	)

Reclamation liability at end of period		105,759
Amount included in Other current liabilities		12,184

Total noncurrent liability	$	93,575


	Year Ended December 31, 2003		Year Ended December 31, 2002
	(In Thousands)
Pro forma amounts of reclamation liability at beginning of period	$	101,914	$	99,756
Pro forma amounts of reclamation liability at end of period	$	105,759	$	101,914


Year ended December 31,	(In Thousands)
2004	$	12,291
2005	$	12,440
2006	$	11,880
2007	$	11,709
2008	$	11,187


	Capital Leases		Operating Leases
	(In Thousands)
2004	$	4,538	$	57,515
2005		3,316		52,374
2006		1,732		31,378
2007		1,732		8,772
2008		1,732		2,334
Thereafter		6,120		1,066

Total minimum lease payments		19,170	$	153,439

Less imputed interest		2,916

Present value of minimum capital lease payments	$	16,254


	December 31, 2003				December 31, 2002
	(Dollars In Thousands)
Equity securities (domestic and international)	$	134,384	65.9	%	$	103,476	59.5	%
Debt securities		59,082	29.0	%		60,782	34.9	%
Other (includes cash, cash equivalents and a group annuity contract)		10,415	5.1	%		9,738	5.6	%

Total fair value of plan assets	$	203,881	100	%	$	173,996	100	%


	December 31, 2003	December 31, 2002
Discount rates	6.25%	6.75%
Rates of increase in compensation levels	4.00%	4.00%
Measurement date	December 31, 2003	December 31, 2002


	Year Ended									Two Months Ended December 31, 2001
	December 31, 2003			December 31, 2002			October 31, 2001			Two Months Ended December 31, 2001
	(In Thousands)
Service cost	$	11,471		$	10,649		$	2,657		$	1,769
Interest cost		11,282			10,256			9,498			1,693
Expected return on plan assets		(14,459	)		(18,069	)		(22,245	)		(2,886	)
Recognized loss		4,737			—			—			—
Amortization of unrecognized net liability/(asset)		—			—			(1,800	)		74
Amortization of prior service cost		133			133			57			10

Net periodic pension expense/(income)	$	13,164		$	2,969		$	(11,833	)	$	660


	Year Ended December 31, 2003	Year Ended December 31, 2002	Year Ended October 31, 2001
Discount rates	6.75%	7.25%	7.75%
Rates of increase in compensation levels	4.00%	4.50%	4.00%
Expected long-term rate of return on plan assets	8.50%	9.00%	9.50%
Measurement date	December 31, 2002	December 31, 2001	October 31, 2000


	Expected Pension Benefit Payments
	(In Thousands)
2004	$	7,765
2005		8,024
2006		8,309
2007		8,709
2008		9,323
Years 2009 to 2013		62,745


	1-Percentage Point Increase		1-Percentage Point Decrease
	(In Thousands)
Increase/decrease in medical cost trend rate:
Effect on total of service and interest costs components	$	195	$	(112	)
Effect on accumulated black lung obligation	$	1,837	$	(693	)

Increase/decrease in cost of living trend rate:
Effect on total of service and interest costs components	$	954	$	(717	)
Effect on accumulated black lung obligation	$	7,701	$	(5,400	)


	Weighted Average
	Stock Options		Exercise Price Per Share
Outstanding at October 31, 2000	673,061		$	47.16
Conversion adjustment to shares at Spin-Off	1,960,581
Granted	875,961		$	19.78
Expired or Cancelled	(375,486	)	$	12.12
Exercised	(817,110	)	$	11.47

Outstanding at October 31, 2001	2,317,007		$	14.89
Expired or Cancelled	(42,061	)	$	19.14
Exercised	(253,243	)	$	11.28

Outstanding at December 31, 2001	2,021,703		$	15.25
Granted	683,273		$	5.79
Expired or Cancelled	(264,772	)	$	13.64
Exercised	(125,689	)	$	11.17

Outstanding at December 31, 2002	2,314,515		$	12.86
Granted	696,381		$	13.39
Expired or Cancelled	(169,029	)	$	11.36
Exercised	(93,242	)	$	8.54

Outstanding at December 31, 2003	2,748,625		$	13.23


Exercisable at:
October 31, 2000 (pre-conversion shares)		257,850
October 31, 2001		1,243,903
December 31, 2001		1,083,704
December 31, 2002		1,075,763
December 31, 2003		1,243,111


	Outstanding Options				Exercisable Options
Range of Exercise Price	Number of Options	Weighted Average Remaining Contractual Life (years)	Weighted Average Exercise Price		Number of Options	Weighted Average Exercise Price
$ 5.21 – 7.63	583,471	8.8	$	5.85	85,093	$	5.21
$10.57 – 10.93	466,269	5.7	$	10.85	466,269	$	10.85
$12.28 – 13.60	795,140	9.1	$	13.43	126,467	$	12.78
$14.56 – 18.86	203,012	2.1	$	16.53	203,012	$	16.53
$19.42 – 20.11	700,733	7.7	$	19.78	362,270	$	19.79

$ 5.21 – 20.11	2,748,625	7.6	$	13.23	1,243,111	$	14.19


	Three Months Ended
	March 31, 2003			June 30, 2003			September 30, 2003⁽¹⁾			December 31, 2003⁽²⁾
	(In Thousands, Except Per Share Amounts)
Total revenue	$	374,567		$	393,403		$	390,815		$	394,639
(Loss) income from operations		(9,767	)		3,311			2,199			(13,285	)
Loss before taxes		(17,763	)		(5,586	)		(7,392	)		(29,910	)
Loss before cumulative effect of accounting change		(9,598	)		(2,197	)		(3,854	)		(16,684	)
Net loss		(17,478	)		(2,197	)		(3,854	)		(16,684	)
Loss per share (Basic and Diluted):
Loss before cumulative effect of accounting change	$	(0.13	)	$	(0.03	)	$	(0.05	)	$	(0.22	)
Net loss	$	(0.24	)	$	(0.03	)	$	(0.05	)	$	(0.22	)

	Three Months Ended
	March 31, 2002⁽³⁾			June 30, 2002⁽⁴⁾			September 30, 2002⁽⁵⁾			December 31, 2002⁽⁶⁾
	(In Thousands, Except Per Share Amounts)
Total revenue	$	392,551		$	402,507		$	424,441		$	410,596
(Loss) income from operations		(3,623	)		(17,398	)		6,642			(12,309	)
Loss before taxes		(10,441	)		(25,341	)		(2,049	)		(19,689	)
Net loss		(4,213	)		(16,456	)		(1,318	)		(10,587	)
Loss per share:
Basic and diluted	$	(0.06	)	$	(0.22	)	$	(0.02	)	$	(0.14	)