Edgar Filing: MASSEY ENERGY CO

AMENDMENT NO. 1 TO FORM 10-K/A

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

Amendment No. 1

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2002

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 1-7775

MASSEY ENERGY COMPANY

(Exact name of registrant as specified in its charter)

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)

Registrant’s telephone number, including area code: (804) 788-1800

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Common stock, $0.625 par value

Name of each exchange on which registered

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:

None

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 registrant’s voting stock held by non-affiliates was $698,064,369.80 on February 28, 2003 based upon the volume weighted average sales price of the registrant’s Common Stock.

Common Stock, $0.625 par value, outstanding as of February 28, 2003—75,322,095 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2003 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, 2002.

Explanatory Note

This Amendment No.1 to the Annual Report on Form 10-K of Massey Energy Company for the fiscal year ended December 31, 2002, is being filed to add language regarding the restatement of the Company’s financial statements for the years ended October 31, 2001 and prior. Due to the concurrent filing on March 31, 2003 of both the Form 10-K/A for the fiscal year ended October 31, 2001, and the Form 10-K for the fiscal year ended December 31, 2002, the Company has determined it appropriate to include disclosure language about the restatements made in the Form 10-K/A for fiscal year ended October 31, 2001 in its Form 10-K for the fiscal year ended December 31, 2002.

Information included in the original report on Form 10-K has not been amended by this Form 10-K/A to reflect any information or events subsequent to the filing of the original Annual Report on Form 10-K.

* * * * *

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 Company growth, the adequacy of funds to service debt and the Company’s opinions about trends and factors which may impact future operating results. These forward-looking statements could also involve, among other things, statements regarding the Company’s intent, belief or expectation with respect to (i) the Company’s results of operations and financial condition, (ii) the consummation of acquisition, disposition or financing transactions and the effect thereof on the Company’s business, and (iii) the Company’s plans and objectives for future operations and expansion or consolidation.

Any forward-looking statements are subject to the risks and uncertainties that could cause actual 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 soon as reasonably practicable after it is electronically filed with, or furnished to, the Securities and Exchange Commission. You may also request copies of our filings, 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.

Part I

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 29 underground mines (four of which employ both room and pillar and longwall mining) and 14 surface mines (with seven highwall miners in operation) in West Virginia, Kentucky and Virginia. The number of mines that Massey’s 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 ranking of coal companies by 2002 revenue, Massey is the fourth largest coal company in the United States, 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 2001 and 2000 annual periods 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 for the two months ended December 31, 2001 (audited) compared with the two-months ended December 31, 2000 (unaudited). The comparative audited consolidated balance sheets are as of December 31, 2002 and October 31, 2001.

Industry Overview

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

The United States is the second largest coal producer in the world, exceeded only by China. Other leading coal producers include India, South Africa, and Australia. The United States is the largest holder of coal reserves in the world, with over 250 years 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 Energy Ventures Analysis. Total coal reserves are estimated by comparing the total probable heat value (British thermal units (“Btus”) per pound) of the demonstrated coal reserve tonnage reported by the Department of Energy to the heat value of other fossil fuel energy resources reported by the Department of Energy.

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

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

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

Total	1,144	100	%

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

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

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

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

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

Total	100	%

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

The United States ranks fifth among worldwide exporters of coal. Australia is the largest exporter, with other major exporters including South Africa, Indonesia, Canada, China, Russia and Colombia. U.S. exports have decreased by over 46% since 1991 as a result of increased international competition and the U.S. dollar’s strength in comparison to foreign currencies. According to DOE, the usage breakdown for 2000 U.S. exports of 59 million tons was 44% for electricity generation and 56% for steel making. U.S. coal exports were shipped to more than 40 countries. The largest purchaser of exported steam coal was Canada, which took 15 million tons or 58% of total steam coal exports. The largest purchaser of exported metallurgical coal was Europe, which represented 20 million tons or 61% of total metallurgical coal exports.

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

Industrial users of coal typically purchase high Btu products with the same type of quality focus as utility coal buyers. The primary goal is to maximize heat content, with other specifications like ash content, sulfur content, and size varying considerably among different customers. Because most industrial coal consumers use considerably less tonnage than electric generating stations, they typically prefer to purchase coal that is screened and sized to specifications that streamline coal handling processes. Due to the more stringent size and quality specifications, industrial customers often pay a 10% to 15% premium above utility coal pricing (on comparable quality). The largest regional supplier to the industrial market sector has historically been Central Appalachia, which supplied approximately 35% of all U.S. industrial coal demand in 2002.

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

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

Mining Methods

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, a shearer (cutting head) moves back and forth across a panel of coal typically about 1000 feet in width, cutting a slice 3.5 feet deep. The cut coal falls onto a flexible conveyor for removal. Longwall

mining is performed under hydraulic roof supports (shields) that are advanced as the seam is cut. The roof in the mined out areas falls as the shields advance.

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

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

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

Production from underground longwall mining operations constituted about 16% of Massey’s 2002 production. Massey now operates four longwall units.

Surface mining represented approximately 35% of Massey’s 2002 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 10% of Massey’s 2002 coal production.

Mining Operations

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 91% of 2002 coal shipments.

The following table provides key operational information on all Massey mining complexes (Resource Groups) that were active in 2002.

Massey Resource Groups

Resource Group Name	Location	2002 Production(1)	2002 Shipments	Year Established or Acquired
		(000’s of Tons)	(000’s of Tons)
West Virginia Resource Groups
Black Castle	Boone County, WV	2,972	643	1987
Delbarton	Mingo County, WV	2,807	2,595	1999
Eagle Energy	Boone County, WV	—	192	1996
Elk Run	Boone County, WV	2,147	4,118	1978
Green Valley	Nicholas County, WV	829	803	1996
Independence	Boone County, WV	3,728	3,082	1994
Logan County	Logan County, WV	3,572	3,353	1998
Marfork	Raleigh County, WV	2,792	5,428	1993
Nicholas Energy	Nicholas County, WV	4,627	4,310	1997
Omar	Boone County, WV	—	1,020	1954
Performance	Raleigh County, WV	3,355	1,188	1994
Progress	Boone County, WV	4,330	2,464	1998
Rawl	Mingo County, WV	1,988	1,511	1974
Stirrat	Logan County, WV	—	342	1993

Kentucky Resource Groups
Long Fork	Pike County, KY	—	1,342	1991
Martin County	Martin County, KY	3,025	2,755	1969
New Ridge	Pike County, KY	—	1,288	1992
Sidney	Pike County, KY	7,269	4,982	1984

Virginia Resource Group
Knox Creek	Tazewell County, VA	492	509	1997
Other/Unassigned	N/A	N/A	196	N/A

TOTAL		43,933	42,121

(1)

For purposes of this table, coal production has been allocated to the Resource Group where the coal is mined, rather than the Resource Group where the coal is processed and shipped. Several Massey Resource Groups provide processing and rail shipping services for coal mined at other nearby Massey operations.

The following descriptions of the Company’s resource groups are current as of February 28, 2003.

West Virginia Resource Groups

Black Castle. The Black Castle mining complex includes a large surface mine, a highwall miner and an underground belt conveyor system that transports direct-ship coal (i.e., coal that is shipped without processing) to the Omar resource group for loading. The remaining surface mined coal and the highwall miner production is trucked to the Independence preparation plant for cleaning and loading. In years previous to 2002, production from Black Castle was shown in the Elk Run resource group production.

Delbarton. The Delbarton complex includes an underground room and pillar mine and a preparation plant. This mine was idled in February 2002 due to weak demand for steam coal but was re-activated in January 2003. Production from this mine is transported to the adjacent Delbarton preparation plant via overland conveyor. The

Delbarton preparation plant also processes coal from two surface mines of the Logan County resource group. 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.

During the third quarter of 2002, the Company decided that a section of the idled mine at Delbarton that crossed under a creek would not be utilized in future mining plans. Unamortized development costs related to this section of the mine of approximately $9.2 million were written off in the third quarter. For further discussion, please see Note 5 to the Consolidated Financial Statements, “Impairment of Long-Lived Assets.”

Eagle Energy. The Eagle Energy complex is currently inactive but has historically processed coal production from the adjacent underground longwall mine. The economically accessible 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 in Massey controlled properties adjacent to the preparation plant.

Elk Run. Elk Run produces coal from three underground room and pillar mines, which deliver coal to its preparation plant by belt and truck. The surface mine that was previously a part of the Elk Run resource group is now part of the Black Castle resource group. 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 to the preparation plant of the Performance resource group for processing. 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, three highwall miners, one underground room and pillar mine and the Aracoma longwall mine, plus the Bandmill preparation plant and the Feats loadout. 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 also deliver direct-ship coal to the Feats loadout by truck. A portion of the coal from two of the surface mines, North Surface and South, and the highwall miners is also delivered to the Delbarton preparation plant by truck. Another surface mine, Sheep Fork, transports its coal by truck to the Rawl plant for processing and shipment. The Bandmill preparation plant has a processing capacity of 1600 tons per hour. The rail loading facility services customers via the CSX rail system with unit train shipments of up to 150 cars.

Marfork. The Marfork complex includes four 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, an underground room and pillar mine and a preparation plant. Coal from the underground mine, 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 crushes and loads direct-ship coal at its preparation plant from the adjacent surface mining operation of the Black Castle resource group. Production is transported via underground conveyor system to the Omar direct-ship facility. The direct-ship facility can crush 800 tons per hour. The Omar preparation plant, which can process 800 tons per hour, is currently inactive. 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. Most of the production from Upper Big Branch is shipped via overland conveyor to the preparation plant at the Marfork resource group. The balance of the production from this mine is shipped via truck to the Goals preparation plant. This plant also processes the production, received by belt conveyor, of two adjacent underground mines of the Independence 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 four surface mines, including the Upper Big Branch and Twilight MTR surface mines, a highwall miner and a direct-ship railroad load out. All production from the highwall miner and two of the surface mines is processed through a coal handling system and transported via underground conveyor to the Elk Run resource group for processing and rail shipment. Another surface mine trucks direct-ship coal to the rail loadout, located on the CSX railroad and trucks the coal requiring processing to the Independence resource group.

Rawl. The Rawl complex includes two active underground room and pillar mines, one surface mine and the Sprouse Creek processing plant. The mines transport coal to the Sprouse Creek plant via truck. In addition, a contract mine and two purchased-coal sources ship 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 underground room and pillar mine and preparation plant were idled in January 2003. When in production, all coal from the underground mine is transported via belt line to the preparation plant. 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.

The Company decided to permanently abandon a previously idled mine at the Stirrat resource group during the third quarter of 2002. Unamortized development costs of approximately $2.3 million were written off in the third quarter as a result of the mine closure. For further discussion, please see Note 2 to the Consolidated Financial Statements, “Impairment of Long-Lived Assets.”

Kentucky Resource Groups

Long Fork. The Long Fork preparation plant processes coal produced by the adjacent Solid Energy underground room and pillar mine and 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 portion of the production from the surface mine and highwall miner is shipped to river docks via truck. The balance of the coal 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. 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, idled in April, 2002, has a throughput capacity of 800 tons per hour. 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.

During the third quarter of 2002, Sidney closed a mine and decided to forego mining the final section of reserves. Unamortized development costs of approximately $1.7 million were written off as a result of the mine closure. For further discussion, please see Note 5 to the Consolidated Financial Statements, “Impairment of Long-Lived Assets.”

Virginia Resource Group

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.

Resource Group	Surface Mine		Underground Mine		Total
Black Castle	1	(1 HW)	0		1
Delbarton	0		1		1
Elk Run	0		4		4
Green Valley	0		2		2
Independence	0		4	(1 LW)	4
Logan County	5	(3 HW)	2	(1 LW)	7
Marfork	0		4		4
Nicholas Energy	1	(1 HW)	1		2
Performance	0		1	(1 LW)	1
Progress	4	(1 HW)	0		4
Rawl	1		2		3
Martin County	1	(1 HW)	1		2
Sidney	1		6	(1 LW)	7
Knox Creek	0		1		1

Total	14		29		43

LW—longwall mine

HW—highwall miners operated in conjunction with surface mines

Other Related Operations

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: Marfork Coal Company, Inc., a subsidiary of the Company, manages the Appalachian Synfuel facility under an operating agreement. Marfork receives fees for the operation of the facility. The Appalachian Synfuel facility processes coal fines (waste coal or crushed coal comprised of particles, the majority of which, by size, are no larger than ³/8 inch) into a pelletized coal product. See Note 6 to the Consolidated Financial Statements for further information regarding Appalachian Synfuel, LLC.

Westvaco Coal Handling Facility: Massey subsidiaries own and operate the coal unloading, storage and conveying facilities at 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, a long term industrial coal customer. The Westvaco CHF operating agreement extends through 2007, and provides for Massey to be paid a per ton fee (annually adjusted) for coal handling services and allows Massey to supply 100% of the coal required by 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.

Other: Massey also engages in the sale of certain non-strategic assets such as timber, oil and gas rights, as well as the sale of non-strategic surface properties and reserves.

Marketing and Sales

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, 2002, Massey sold 42.1 million tons of produced coal for total produced coal revenue of $1.3 billion. The breakdown of produced tons sold by market served was 65% utility, 26% metallurgical and 9% industrial. Sales were concluded with over 125 customers. Export shipments (including Canada) represented approximately 14% of 2002 tonnage sold. Massey’s 2002 export shipments serviced customers in 7 countries across North America, South America and Europe. Almost all sales are made in U.S. dollars, which eliminates foreign currency risk.

The Company has established several contractual arrangements with customers wherein services other than coal supply are provided on an ongoing basis. Such other services include coal handling and coal consignment services. Examples of such arrangements, none of which is considered to be material, include:

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The Westvaco CHF and the Eastman CHS (described above). The Company derives less than 1% of its total revenue through the coal handling services it provides in connection with the Westvaco CHF arrangement. The Company receives a $/mmBtu price for providing all of the coal and the transportation and handling of the coal to the Westvaco CHF. The Company derives less than 1% of its total revenue through the Eastman CHS, which became operational in September 2002. The Company receives coal handling, facility maintenance and facility lease fees at the Eastman CHS.

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At three steel companies and numerous industrial plants, Massey subsidiaries coordinate shipment of coal to the customers’ stockpiles, maintain ownership of the coal inventory on site and sell tonnage to the customers as it is consumed, the point at which title to the coal is transferred to the purchasers.

Other services of the type described herein are provided periodically in response to the current needs of each individual customer.

Distribution

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 2002 shipments of 42.1 million tons were loaded from 19 mining complexes. Rail shipments constituted 91% of total shipments, with 33% loaded on Norfolk Southern trains and 58% loaded on CSX trains. The 9% balance was shipped from Massey mining complexes via truck.

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

Customers and Coal Contracts

Massey has coal supply commitments with a wide range of electric utilities, steel manufacturers, industrial customers and energy traders and brokers. 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 12% of Massey’s total fiscal year 2002 produced coal revenue. In addition, sales to Duke Energy Corporation and its affiliate, Duke Energy Merchants, a Massey customer for over thirty years with agreements in place to supply coal through June 2003, accounted for 11% of Massey’s total fiscal year 2002 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, the creditworthiness of the energy trading and brokering companies with which we do business declined, increasing the risk that we may not be able to collect payment for all coal sold and delivered to or on behalf of these energy trading and brokering companies. To mitigate credit-related risks in all customer classifications, Massey maintains a credit policy, which requires scheduled reviews of customer creditworthiness and continuous monitoring of customer news events which might have an impact on their financial condition. Negative credit performance or events may trigger the application of tighter terms of sale, requirements for collateral or, ultimately, a suspension of credit privileges.

As 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. 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. The United States government determined that some steel producers in some foreign countries were selling steel products in the United States at below cost and has imposed certain tariffs on products from various foreign countries. The imposition of the tariffs has led to a moderate increase in the price of some steel products in the United States. However, several large American producers filed for bankruptcy protection both before and after the tariffs were imposed, including two substantial customers of Massey: Wheeling-Pittsburgh Steel Corporation, which filed for bankruptcy protection in late 2000, accounted for approximately 3% of the Company’s produced coal revenue in 2002, and Bethlehem Steel Corporation, which filed for bankruptcy protection in mid-2001, accounted for approximately 2% of the Company’s produced coal revenue in 2002. In addition, Algoma Steel, Inc., a Canadian steel producer and a customer of Massey, filed for bankruptcy protection under Canadian law. Sales to Algoma

accounted for approximately 2% of the Company’s produced coal revenue for 2002. We continue to sell to these financially stressed customers on very restrictive terms. Further deterioration in conditions in the steel industry could reduce the demand for Massey’s metallurgical coal and impact the collectibility of Massey’s accounts receivable from steel industry customers. Since Massey’s metallurgical grade coal can also be marketed as a high-Btu steam coal for use by utilities, a decline in the metallurgical market could result in coal being switched from the metallurgical market to the utility market.

As is customary in the coal industry, Massey continually enters into long-term contracts (exceeding one year 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, 2002, approximately 94% of our coal sales volume was pursuant to long-term contracts. The Company believes that in 2003, the percentage of sales pursuant to long-term arrangements will be comparable with the percentage of sales for 2002. 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.

By offering coal of both metallurgical and steam 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 terms of Massey’s long-term contracts are a result of extensive negotiations with the customer. 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. Most 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 mined.

For 2003, we expect to produce 40 to 45 million tons of 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 December 31, 2002, the Company had commitments to purchase 2.0 million tons during 2003 and 0.7 million tons in 2004 and 2005. The following table sets forth, as of February 28, 2003, the total tons of coal the Company is committed to deliver at prices that are determined under existing contracts during calendar years 2003 through 2007.

Tons of Coal to be Delivered

(in millions of tons)

2003

2004

2005

2006

2007

Volume under existing contracts

38.0

16.3

11.5

5.9

4.4

Competition

The coal industry in the United States is highly competitive. Massey competes with other large producers and many small coal producers. 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 and the availability and cost of alternative fuel sources.

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-a-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 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) costs than those of surface mining. In recent years, increased development of large surface mining operations, particularly in the western United States, and more efficient mining equipment and techniques, have contributed to excess coal production capacity in the United States. Competition resulting from excess capacity has encouraged producers to reduce prices and to pass productivity gains through to customers. The lower production cost in the western mines is offset somewhat by the higher quality of many eastern coals and higher transportation cost 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. Intraregional and interregional competition is keen as producers seek to position themselves as the low-cost producer and supplier of high-demand product to the electricity generating industry.

Transportation costs are another fundamental factor affecting coal industry competition. Coordination of the many eastern loadouts, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern United States inherently more expensive on a per-mile basis than shipments originating in the western United States. Historically, coal transportation rates from the western coal producing areas into Central Appalachian markets limited the use of western coal in those markets. More recently, however, lower rail rates from the western coal producing areas to markets served by eastern producers have created major competitive challenges for eastern producers. Barge transportation is the lowest cost method of transporting coal long distances in the eastern United States, and the large numbers of eastern producers with river access keep coal prices competitive. The Company believes that many utilities with plants located on the Ohio River system are well positioned for deregulation as competition for river shipments should remain high for Central Appalachian coal. 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 a deregulated environment. 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 and limit rail price premiums. River transport is an important transportation option not available to Powder River Basin producers between Wyoming and midwestern river terminals.

Although undergoing significant consolidation, the coal industry in the United States remains highly fragmented. There can be no assurance that the Company’s costs will permit it to compete effectively with other producers seeking to provide coal to a customer; however, it is the Company’s goal to reduce production costs, offer a variety of products and have access to multiple transportation systems that will enable it to compete effectively with other producers.

Employees and Labor Relations

As of December 31, 2002, Massey had 4,552 employees, including 171 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.

Environmental, Safety and Health Matters

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; 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 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. Additional disclosure regarding the Clean Air Act and the Clean Water Act is found under the “Business Risks” subsections entitled “The Clean Air Act affects Massey’s customers and could influence their purchasing decisions” and “Massey is subject to the Clean Water Act which imposes monitoring and reporting obligations”. Additional disclosure concerning black lung benefits is found under the “Business Risks” subsection entitled “Governmental regulations increase Massey’s costs and may discourage customers from buying Massey’s coal.”

SMCRA. The Surface Mining Control and Reclamation Act (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement, establishes mining, environmental protection and reclamation standards for all aspects of surface mining as well as many aspects of deep mining. 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 Surface Mining Control and Reclamation Act, 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 these reclamation obligations. Mine operators must receive permits and permit renewals for surface mining operations from the Office of Surface Mining Reclamation and Enforcement 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. It accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge as coal is mined, on a unit-of-production basis over the proven and probable reserves as defined in Securities and Exchange Commission Industry Guide 7.

On March 29, 2002, the U.S. District Court for the District of Columbia issued a ruling that could restrict underground mining activities conducted in the vicinity of public roads, within a variety of federally protected lands, within national forests and within certain proximity to occupied dwellings. The lawsuit, Citizens Coal Council v. Norton, was filed in February 2000 to challenge regulations issued by the Department of Interior providing, among other things, that subsidence and underground activities that may lead to subsidence are not surface mining activities within the meaning of SMCRA. SMCRA generally contains restrictions and certain prohibitions on the locations where surface mining activities can be conducted. The District Court entered summary judgment upon the plaintiff’s claims that the Secretary of the Interior’s determination violated SMCRA. By order dated April 9, 2002, the court remanded the regulations to the Secretary of the Interior for reconsideration. The significance of this decision for the coal mining industry remains unclear because this ruling is subject to appellate review. The Department of Interior and the National Mining Association, a trade group that intervened in this action, sought a stay of the order pending appeal to the U.S. Court of Appeals for the District of Columbia Circuit and the stay was granted. If the District Court’s decision is not overturned, or if some legislative solution is not enacted, this ruling could have a material adverse effect on all coal mine operations that utilize underground mining techniques, including those of the Company. While it still may be possible to obtain permits for underground mining operations in these areas, the time and expense of that permitting process are likely to increase significantly.

Black Lung. The U.S. Department of Labor has issued a final rule amending the regulations implementing the federal black lung laws which, among other things, establish a presumption in favor of a claimant’s treating physician and limit a coal operator’s ability to introduce medical evidence regarding the claimant’s medical condition. The amendments could have an adverse impact on Massey, the extent of which cannot be accurately predicted. Further discussion is set forth below in Business Risks—Government regulations increase Massey’s costs and may discourage customers from buying Massey’s coal.

Clean Water Act. 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.

On May 8, 2002, the United States District Court for the Southern District of West Virginia issued an order in Kentuckians for the Commonwealth v. Rivenburgh enjoining the Huntington, West Virginia office of the U.S. Army Corps of Engineers from issuing permits under Section 404 of the Clean Water Act for the construction of valley fills for the disposal of overburden from mountaintop mining operations solely for the purpose of waste disposal. The court held that the filling of these waters solely for waste disposal is a violation of the Clean Water Act. The court’s injunction also prohibits the issuance of permits authorizing fill activities associated with types of mining activities other than mountaintop mining where the primary purpose or use of those fill activities is the disposal of waste. Such activities might include those associated with slurry impoundments and coal refuse disposal areas.

On January 29, 2003, the Fourth Circuit Federal Court of Appeals reversed the district court’s decision and lifted the injunction. The time for filing a possible appeal has not yet expired. If the decision of the Court of Appeals were reversed and the injunction reinstated, the effect would be to make mountaintop mining uneconomical in those areas subject to the injunction and call into question the ability of the Company to obtain permits with respect to other mining activities that use valley fills.

In January 2002, a number of environmental groups and individuals filed suit in the U.S. District Court for the Southern District of West Virginia to challenge the U.S. Environmental Protection Agency’s (“EPA’s”) approval of West Virginia’s antidegradation implementation policy. Under the federal Clean Water Act, state regulatory authorities must conduct an antidegradation review before approving permits for the discharge of pollutants to waters that have been designated as high quality by the state. Antidegradation review involves public and intergovernmental scrutiny of permits and requires permittees to demonstrate that the proposed activities are justified in order to accommodate significant economic or social development in the area where the waters are located. 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. If the plaintiffs are successful and if the Company discharges into waters that have been designated as high-quality by the state, the costs, time and difficulty associated with obtaining and complying with Clean Water Act permits for surface mining could increase.

Clean Air Act. The Clean Air Act and corresponding state laws extensively regulate emissions into the air of particulate matter and other substances, including sulfur dioxide, nitrogen oxides and mercury. Although these regulations apply directly to impose certain requirements for the permitting and operation of 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 ambient air standards. Significant additional emissions control expenditures will be needed in order to meet the current national ambient air standard for ozone. In particular, coal-fired power plants will be affected by state regulations designed to

achieve attainment of the ambient air quality standard for ozone. Ozone is produced by the combination of two precursor pollutants: volatile organic compounds and nitrogen oxides. Nitrogen oxides are a by-product of coal combustion. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers will continue to become more demanding in the years ahead. The EPA has imposed or attempted to impose tighter emission restrictions in a number of areas, some of which are currently subject to litigation. The general effect of such tighter restrictions could be to reduce demand for coal. In July 1997, the EPA adopted new, more stringent National Ambient Air Quality Standards for very fine particulate matter and ozone. The Court of Appeals for the District of Columbia issued an opinion in May 1999 limiting the manner in which the EPA can enforce these standards. After a request by the federal government for a rehearing by the Court of Appeals was denied, the Supreme Court agreed in January 2000 to review the case. On February 27, 2001, the Supreme Court found in favor of the EPA in material part and remanded the case to the Court of Appeals. On remand, the Court of Appeals for the D.C. Circuit affirmed the EPA’s adoption of these more stringent ambient air quality standards. As a result of the finalization of these standards, states that are not in attainment for these standards will have to revise their State Implementation Plans to include provisions for the control of ozone precursors and/or particulate matter. Revised State Implementation Plans could require electric power generators to further reduce nitrogen oxide and particulate matter emissions. The potential need to achieve such emissions reductions could result in reduced coal consumption by electric power generators. Thus, future regulations regarding ozone, particulate matter and other pollutants could restrict the market for coal and the development of new mines by the Company. This in turn may result in decreased production by the Company and a corresponding decrease in the Company’s revenue. Although the future scope of these ozone and particulate matter regulations cannot be predicted, future regulations regarding these and other ambient air standards could restrict the market for coal and the development of new mines.

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

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

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

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

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

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

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reducing electricity generating levels; or

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purchasing or trading emission credits.

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

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

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

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

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

Massey Operations—Permitting; Compliance. 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 National Pollutant Discharge Elimination System 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 United States. Valley fills and refuse impoundments are typically authorized under Nationwide Permits that are revised and renewed periodically by the U.S. Corps of Engineers. Additionally, certain surface mines and preparation plants have permits issued pursuant to the Clean Air Act and state counterpart clean air laws allowing and controlling the discharge of air pollutants. These permits are primarily permits allowing initial construction (not operation) and they do not have expiration dates.

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 Section 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 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 2002, Massey spent approximately $6.9 million to comply with environmental, health and safety laws and regulations, none of which expenditures were capitalized. Massey anticipates making $13.1 million and $12.3 in such non-capital expenditures in 2003 and 2004, respectively. Of these expenditures, $6.6 million, $11.6 million and $10.7 million for 2002, 2003 and 2004, respectively, were or 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 10 to Notes to 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.

Business Risks

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

Massey competes with coal producers in various regions of the United States for domestic sales and with both domestic and overseas producers for sales to international markets. Continued 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.

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 29 active underground mines, including four longwall mines, and 14 active surface mines.

Massey depends on continued demand from its customers

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.

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

At December 31, 2002, less than 5% of Massey’s total workforce was represented by the United Mine Workers of America. Seven of Massey’s coal processing plants and one of its smaller surface mines have a workforce that is represented by a union. In fiscal 2002, these seven processing 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 incur additional risk of work stoppages and higher labor costs.

Transportation disruptions could impair Massey’s ability to sell coal

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 has recently increased enforcement of weight limits on coal trucks on its public roads. Also, recently enacted legislation, which raised coal truck weight limits in West Virginia, includes

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.

Recently, certain of Massey’s subsidiaries, among others, 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 adverse effect on Massey’s ability to compete with other energy sources and on its business, financial condition and results of operations. On the other hand, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, coal mines in the western United States 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.

Coal mining is subject to inherent risks

Massey’s operations are subject to certain events and conditions which could disrupt operations, including fires and explosions from methane, accidental minewater discharges, natural disasters, equipment failures and maintenance problems, flooding, changes in geologic conditions, failure of reserve estimates to prove correct and inability to acquire mining rights or permits. Massey maintains business interruption insurance and property and general liability insurance policies that provide limited coverage for some, but not all, of these risks. Even where insurance coverage applies, there can be no assurance that these risks would be fully covered by Massey’s insurance policies.

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

Numerous governmental permits and approvals are required for coal mining operations. Massey may be required to prepare and present to federal, state and local authorities more extensive data describing the effect or impact that any proposed mining operations may have upon the environment. For example, the West Virginia Division of Environmental Protection is involved in litigation regarding its alleged failure to consider the hydrologic effects of mining operations in issuing mining permits. This suit could lead to additional requirements that Massey and other mining companies assess potential hydrologic risks. These and any other increased requirements may be costly and time-consuming and may delay commencement or continuation of mining operations.

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.

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 recent years, legislation on black lung reform has been introduced but not enacted in Congress. It is possible that this legislation will be reintroduced for consideration by Congress. If any of the proposals included in this or similar legislation is passed, the number of claimants who are awarded benefits could significantly increase. Any such changes in black lung legislation, if approved, could adversely affect Massey’s business, financial condition and results of operations.

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 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. The National Mining Association (“NMA”) challenged the amendments in the United States District Court for the District of Columbia. On August 9, 2001, the Court lifted a temporary injunction blocking the Labor Department’s processing of black lung benefit claims after dismissing the National Mining Association’s challenge to the amendments and upheld the new regulations. The NMA appealed this decision to the United States Court of Appeals for the District of Columbia Circuit. By opinion dated June 14, 2002, the Court found that the Department of Labor exceeded its authority by allowing judges to shift costs for expert witnesses from the claimant to the employer, even if the claimant was unsuccessful. The Court further found that certain provisions of the rule which applied to pending claims were impermissibly retroactive. However, the Court denied NMA’s appeal in all other material respects. NMA did not seek review of this decision by the United States Supreme Court.

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

The Clean Air Act affects Massey’s customers and could influence their purchasing decisions

The Clean Air Act and corresponding state laws extensively regulate emissions into the air of particulate matter and other substances, including sulfur dioxide, nitrogen oxides and mercury. See Item 1, Environmental, Safety and Health Matters, for further discussion on the Clean Air Act. In order to comply with limitations on emissions, Massey’s customers may switch to other fuels or coal from other regions.

The passage of legislation responsive to the Framework Convention on Global Climate Change could have an adverse effect on Massey’s business.

The United States has not implemented the 1992 Framework Convention on Global Climate Change (“Kyoto Protocol”) which is intended to limit emissions of greenhouse gases, such as carbon dioxide. See Item 1, Environmental, Safety and Health Matters, for further discussion on the Kyoto Protocol. However, continuing international and federal efforts to control greenhouse gas emissions could result in reduced use of coal if electric power generators switch to lower carbon sources of fuel.

Massey is subject to the Clean Water Act which imposes monitoring and reporting obligations

The federal Clean Water Act affects coal mining operations by imposing restrictions on discharge of pollutants into waters and dredging and filling of wetlands. See Item 1, Environmental, Safety and Health Matters, for further discussion on the Clean Water Act. Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of permits governing the discharge of pollutants into water.

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

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

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 adverse effect on us. That failure could result from a variety of factors including the following:

•

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

•

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

•

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

Severe weather may affect Massey’s ability to mine and deliver coal

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. The lack of skilled miners could have an adverse impact on Massey’s labor productivity and cost and its ability to expand production.

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 under 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 credit worthiness 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 the “Customers and Coal Contracts” section of Item 1, Business, for further discussion.

Item 2. Properties

Operations of Massey and its subsidiaries are conducted in both owned and leased properties totaling approximately 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.

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

Coal Reserves

Massey estimates that, as of December 31, 2002, it had total recoverable reserves of approximately 2.2 billion tons consisting of both proven and probable reserves. “Reserves” are defined by Securities and Exchange Commission 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 Securities and Exchange Commission 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 Securities and Exchange Commission 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 our producing properties (owned and leased) was approximately 4.2% of produced coal revenue for the year ended December 31, 2002.

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

Recoverable reserves

	Location	Total	Proven	Probable	Assigned(2)	Unassigned	Owned	Leased
	(in thousands of tons)(1)
Resource Groups:

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

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

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

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

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

Land Management Companies:(3)
Black King	Boone Co., WV	60,764	60,764		395	60,368	23,037	37,727
	Raleigh, WV
Boone East	Boone Co., WV	212,483	173,639	38,845	89,682	122,802	93,755	118,728
	Kanawha, 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, WV	12,397	10,142	2,255	—	12,397	—	12,397
Lauren Land	Mingo Co., WV	142,640	94,383	48,257	11,447	131,194	20,360	122,281
	Logan Co., WV
New Market	Wyoming, 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, WV

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

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

Notes:

(1)

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

(2)

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

(3)

Land management companies are Massey subsidiaries whose primary purposes are to acquire and hold Massey’s reserves.

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

Recoverable Reserves

	Recoverable Reserves	Sulfur content			Average BTU as received	Coal Type(3)
	Recoverable Reserves	+1%	-1%	Compliance(2)	Average BTU as received	Coal Type(3)
	(in thousands of tons except Average Btu as received)(1)
Resource Groups:

West Virginia
Delbarton	310,332	119,784	190,549	138,830	13,476	Low Sulfur Utility
						Low Sulfur Industrial
Black Castle	53,214	8,454	44,760	37,819	12,552	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Eagle Energy	—	—	—	—	—	N/A
Elk Run	78,148	16,526	61,622	51,704	13,210	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Green Valley	9,117	—	9,117	9,117	12,903	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Independence	58,994	7,455	51,539	8,801	13,011	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Logan County	89,457	18,492	70,965	51,240	12,889	Low Sulfur Utility
						Low Sulfur Industrial
Marfork	73,221	33,803	39,418	17,064	13,602	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Nicholas Energy	108,107	50,991	57,116	28,387	12,579	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Omar	35,946	16,045	19,901	444	12,937	Low Sulfur Utility
						Low Sulfur Industrial
Performance	38,192	5,188	33,004	19,792	13,752	High Vol Met
Progress	92,748	11,460	81,287	60,309	11,880	Low Sulfur Utility
						Low Sulfur Industrial
Rawl	113,460	36,870	76,589	53,876	12,784	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Stirrat	5,482	—	5,482	5,482	13,087	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial

Kentucky
Long Fork	5,616	3,728	1,888	—	12,809	Low Sulfur Utility
						Low Sulfur Industrial
Martin County	46,752	35,888	10,864	3,515	12,724	Low Sulfur Utility
						Low Sulfur Industrial
New Ridge	—	—	—	—	—	N/A
Sidney	162,703	63,165	99,538	63,639	13,170	Low Sulfur Utility
						Low Sulfur Industrial
						High Vol Met

Recoverable Reserves
	Recoverable Reserves	Sulfur content			Average BTU as received	Coal Type(3)
	Recoverable Reserves	+1%	-1%	Compliance(2)	Average BTU as received	Coal Type(3)
	(in thousands of tons except Average Btu as received)(1)
Virginia
Knox Creek	54,333	—	54,333	54,333	13,351	High Vol Met
						Low Sulfur Utility
						Low Sulfur Industrial
Other	91,683	27,433	64,249	58,000	12,999	Various

Subtotal	1,427,504	455,282	972,221	662,352

Land Management Companies:(4)

Black King	60,764	37,821	22,942	19,730	12,365	High Vol Met
						Low Sulfur Utility
Boone East	212,483	37,299	175,184	60,831	13,202	High Vol Met
						Low Sulfur Utility
						Low Vol Met
Boone West	258,397	137,300	121,097	81,277	13,047	High Vol Met
						Low Sulfur Utility
Ceres Land	12,397	3,807	8,589	8,589	13,730	High Vol Met
						Low Sulfur Utility
Lauren Land	142,640	45,123	97,517	79,772	13,137	High Vol Met
						Low Sulfur Utility
New Market Land	60,202	5,046	55,156	55,156	14,423	Low Vol Met
						High Vol Met
Raven Resources	31,890	18,483	13,407	4,069	13,683	High Vol Met

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

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

Notes:

(1)

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

(2)

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

(3)

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

(4)

Land management companies are Massey subsidiaries whose primary purposes are to acquire and hold Massey’s reserves.

The following map shows the locations of Massey’s properties:

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

Item 3. Legal Proceedings

Shareholder Derivative Suit

On August 5, 2002, a shareholder derivative complaint was filed in the Boone County, West Virginia, Circuit Court naming as defendants the Company, each of the Company’s directors (including Don L. Blankenship, Chairman, President and Chief Executive Officer), James L. Gardner, Executive Vice President and Chief Administrative Officer, Jeffrey M. Jarosinski, Vice President—Finance and Chief Financial Officer, Madeleine M. Curle, Vice President—Human Resources, and Bennett K. Hatfield, former Executive Vice President and Chief Operating Officer. The complaint 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 Don L. Blankenship, Jeffrey M. Jarosinski, Madeleine M. Curle and Bennett K. Hatfield. The plaintiff makes these allegations derivatively, and seeks to recover damages on behalf of the Company. The damages claimed by the plaintiff have not been quantified. The Company and the other defendants removed the case to Federal District Court in Charleston, West Virginia, but the case has now been remanded to the Boone County Circuit Court. The case is still in very early procedural stages. The Company intends to vigorously pursue defense of this case.

Force Majeure Litigation

The impoundment failure at Martin County on October 11, 2000 (See Martin County Impoundment Discharge below in this Item 3), caused the destruction of the raw coal beltline feeding the preparation plant and led to the immediate closure of the slurry impoundment by order of regulatory authorities. As a result, coal could not be processed through the Martin County preparation plant and the Company was unable to fully meet its coal

sales commitments. The preparation plant was closed for six (6) months until April 2001 when it partially resumed operation after limited alternate slurry disposal methods were approved by the regulatory agencies. The preparation plant was expected to process over one million shippable tons during the period it was shut down. Martin County was able to send some of its coal to Massey’s Rawl Sales & Processing Co. subsidiary’s Sprouse Creek preparation plant for processing.

In addition to the impoundment failure, Massey’s operations experienced various other force majeure events in 2000 and 2001, including:

•

Adverse geological conditions in several of the Company’s longwall mines, including severe roof falls that forced the closure of the Upper Cedar Grove mine of the Independence resource group, flooding conditions in the Marfork resource group’s Ellis Eagle mine, adverse sandstone intrusions in both the Ellis Eagle and Performance resource group’s Upper Big Branch longwall mines, and a significant roof fall on the mainline belt and other adverse conditions at the Nicholas Energy resource group’s Jerry Fork longwall;

•

Various weather related problems in May, June and July, 2001 which caused power outages and flooding at several Massey operations;

•

Various underground disruptions such as a roof fall that curtailed transportation of coal from the Independence resource group’s Hernshaw mine to the Elk Run resource group’s Chess Processing preparation plant for approximately six weeks, and subsidence at the Twilight surface mine of the Progress resource group that covered a highwall miner for more than three weeks; and

•

Labor shortages, especially in trained and qualified underground workers, particularly electricians.

As a result, Massey declared events of force majeure under a number of its contracts and sent reduced shipments to its affected customers. The Company was able to resolve most shortfalls with its customers without dispute. However, the following disputes occurred:

On April 16, 2002, Appalachian Power Company, a subsidiary of American Electric Power, filed suit against Massey’s subsidiaries Central West Virginia Energy Company, Massey Coal Sales Company, Inc. and A.T. Massey Coal Company, Inc. in the Franklin County, Ohio Court of Common Pleas. The suit alleges that we improperly claimed force majeure with respect to a tonnage shortfall under our agreements with Appalachian Power in 2000 and 2001, and seeks to recover the additional cost Appalachian Power incurred in purchasing substitute coal. The complaint further alleges that our claim of force majeure constitutes fraud, and seeks to recover profits made by us on sales to other customers of the coal Appalachian Power claims should have been delivered to it. By order entered July 25, 2002, the court dismissed the fraud claim, however, on December 20, 2002, the court granted Appalachian Power leave to file a second amended complaint to reassert the fraud claim. The trial for this matter is currently scheduled for April 28, 2003. Discovery is ongoing and Appalachian Power has indicated on a preliminary basis that it intends to seek approximately $20.3 million in damages for its cost of purchasing substitute coal. No other alleged damages have been quantified.

On December 14, 2001, Duke Energy made a demand for arbitration, disputing our claim that an event of force majeure had occurred and claiming $20.5 million in damages resulting from coal tonnage shortfalls. On January 23, 2003, the arbitrators awarded Duke Energy $10.6 million on its claim, which was recorded as a charge to cost of produced coal revenue in the fourth quarter of 2002.

Clean Water Act Proceeding

On August 30, 2002, charges were filed in the United States District Court for the Southern District of West Virginia alleging that Massey’s Independence and Omar subsidiary operations had negligently violated the Clean Water Act. On December 16, 2002, Independence and Omar each pled guilty to the charges and each agreed to pay a $200,000 fine and to a probation period of five years for the violations. Sentencing was completed accordingly on March 12, 2003.

Harman Case

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. In June 1998, Harman filed a breach of contract action against Wellmore in Buchanan County, Virginia, Circuit Court. Harman claimed that Wellmore breached the CSA by declaring a force majeure event and reducing the amount of coal to be purchased from Harman. On August 24, 2000, a jury found that Wellmore had breached its contract and awarded Harman $6 million in damages. After unsuccessfully pursuing an appeal, on November 12, 2002, Massey paid Harman $6.0 million plus post-judgment interest of approximately $1.2 million, in full satisfaction of the judgment.

On October 29, 1998, Harman and its sole shareholder, Hugh Caperton, filed a separate action against Massey and certain of its subsidiaries in Boone County, West Virginia, Circuit Court, 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 in the case awarded the plaintiffs $50 million in compensatory and punitive damages. Massey is vigorously pursuing post-judgment remedies, and various motions filed in the trial court have been fully briefed and argued. Massey will appeal to the West Virginia Supreme Court of Appeals, if necessary. The Company accrued a liability with respect to these cases of $31.0 million, excluding interest, which the Company believes is a fair estimate of the eventual total payout relating to both the Virginia and West Virginia actions. After the payment of the Virginia verdict, the remaining accrual is $25.0 million as of December 31, 2002, which is included in “Other current liabilities.”

Water Claims Litigation

Two cases were filed in the Mingo County, West Virginia Circuit Court alleging that Massey’s Delbarton subsidiary’s mining activities destroyed nearby resident plaintiffs’ water supplies. One case was filed on behalf of 54 plaintiffs on July 26, 2002, and the other was filed on behalf of 134 plaintiffs on July 1, 2002. The plaintiffs seek to recover compensatory and punitive damages, but their alleged damages have not been quantified. Delbarton has already provided many of the plaintiffs with a replacement water source. These cases are in early procedural stages and the trial is scheduled for October 2003.

Elk Run Dust Case

On February 2, 2001, approximately 160 residents of the Town of Sylvester, West Virginia, filed suit in the Circuit Court of Boone County, West Virginia against the Company and its subsidiary, Elk Run Coal Company, Inc., alleging that Elk Run’s operations create noise, light and dust constituting a nuisance and causing damage to the community and seeking to recover compensatory and punitive damages. On February 7, 2003, a jury awarded approximately $475,000 in compensatory damages to the plaintiffs but rejected the plaintiffs’ request for punitive damages. The plaintiffs’ claim for attorneys’ fees is pending. Upon entry of a final order, either party has four months to appeal the case to the West Virginia Supreme Court of Appeals. At December 31, 2002, the Company had recorded reserves for the verdict and the Company’s best estimate of the plaintiffs’ claim for attorneys’ fees.

West Virginia Flooding Cases

West Virginia in July of 2001. The plaintiffs have sued coal, timber, railroad and land companies under the theory that mining, construction of haul roads and removal of timber caused natural surface waters to be diverted and interrupted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that these cases, including several 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 in West Virginia to be handled by a panel consisting of three circuit court judges. The panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts. While the plaintiffs’ alleged damages have not been quantified and the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our cash flows, financial condition or results of operations.

Sidney Spill

On April 9, 2002, the rupture of a pipe at Massey’s Sidney Coal Company, Inc. subsidiary caused the discharge of approximately 135,000 gallons of coal slurry into a tributary stream of the Big Sandy River in eastern Kentucky. On April 23, 2002, the WVDEP filed a civil action against the Company and its subsidiary, Massey Coal Services, Inc., in connection with the coal slurry discharge. The lawsuit seeks unspecified damages to compensate for the alleged destruction of natural resources and the state’s costs in responding to the spill, civil penalties and punitive damages. None of the alleged damages or penalties have been quantified. We are defending this action vigorously.

Preparation Plant Employees Litigation

Several subsidiaries of the Company, along with several other coal companies and several chemical companies, are defendants in an action styled Denver Pettry, et al. v. Peabody Holding Company, et al., filed April 17, 2002 in the Circuit Court of Boone County, West Virginia, in which the plaintiffs allege that they were excessively exposed to chemicals used in the coal preparation plants of the defendant coal companies, which were manufactured by the defendant chemical companies. The plaintiffs are attempting to attain class action status, and seek to recover unquantified compensatory and punitive damages. The Company believes it has significant defenses to the claims, and is defending the case vigorously. The case is in early stages of discovery.

On July 25, 2002, one of the Company’s insurer’s filed a declaratory judgment action in the U.S. District Court for the Eastern District of Virginia, seeking a declaration that it has no duty to defend or indemnify the Massey companies in the Pettry action. On October 2, 2002, the Massey companies filed suit seeking a declaratory judgment in the Circuit Court of Boone County, West Virginia against that insurer and others that provided policies to the Massey companies that may cover the Pettry claims, and filed a motion to dismiss the action filed in Virginia. On February 25, 2003, the U.S. District Court for the Eastern District of Virginia entered an order dismissing the Virginia case. The West Virginia insurance litigation is also in early stages of discovery.

Dotco Energy Company

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

Environmental Show Cause Orders

Regulatory authorities implementing SMCRA may order surface mining permit holders to “show cause” why their permits should not be suspended or revoked because of alleged patterns of violations. A pattern of violations can be found when there are two or more violations of a same or similar type within a 12-month period. Under these “show cause orders,” if a pattern of violations is found and determined to have been caused by 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. However, the Company denies that the violations cited in the orders were willful or unwarranted and feels that the alleged violations were promptly remedied or abated. The Company’s affected subsidiaries are vigorously defending these enforcement actions. The Company does not expect that these actions, either individually or collectively, will have a material impact on its results of operations, financial position or cash flows. These proceedings are disclosed solely because they may result in monetary sanctions of more than $100,000. The particular proceedings affecting Massey subsidiaries are listed below:

On June 27, 2000, the WVDEP issued an administrative order to Massey’s Elk Run Coal Company subsidiary requiring Elk Run either to suspend operations for three days beginning July 17, 2000 or expend $100,000 on local community improvement projects. The order was based on alleged violations of the surface mining laws relating to dust, and Elk Run appealed the order to the West Virginia Surface Mining Board. On October 25, 2000 the West Virginia Surface Mining Board upheld the order. Elk Run has appealed the Surface Mining Board’s order to the Kanawha Circuit Court, Charleston, West Virginia. Elk Run believes that it has good defenses to the alleged violations.

On January 2, 2002, the West Virginia Division of Environmental Protection (“WVDEP”) entered an order finding that two violations relating to water quality constituted a pattern and suspended an idled Green Valley Coal Company refuse area permit for three days. Green Valley obtained a stay of the order and appealed to the West Virginia Surface Mine Board (the “Surface Mine Board”), where the order was overturned on June 7, 2002.

On January 14, 2002, WVDEP entered an order finding that seven violations relating to water quality constituted a pattern and suspended operations on Marfork Coal Company, Inc.’s refuse impoundment permit for 14 days. Marfork obtained a stay of enforcement of the order pending appeal to the Surface Mine Board, which heard the appeal, and on June 27, 2002, reduced the suspension to nine days. Marfork appealed the Surface Mine Board decision to the Circuit Court of Raleigh County, which stayed the suspension pending appeal. Subsequently, on December 23, 2002, the circuit court reversed the order on the grounds that Marfork was not given an unbiased hearing by the WVDEP and remanded the matter to WVDEP for a new hearing. WVDEP has not yet set a new hearing or appealed the circuit court order.

On February 19, 2002, WVDEP issued an order to Omar Mining Company to show cause why its permit for a refuse area and preparation plant should not be suspended or revoked due to an alleged pattern of four notices of violation and two cessation orders relating to drainage control and effluent limits. Omar had a hearing to show cause on January 13 and 14, 2003, but WVDEP has not yet issued its decision.

On April 22, 2002, WVDEP entered an order to Independence Coal Company finding that: three notices of violation and three cessation orders relating to sediment control constituted a pattern at Independence’s preparation plant permit; two notices of violation and one cessation order relating to effluent limits, refuse placement and sediment control constituted a pattern at Independence’s Jake Gore coal refuse impoundment; and three notices of violation and one cessation order relating to drainage control on its Justice mine permit constituted a pattern at Independence’s Justice longwall mine. WVDEP ordered a suspension at the preparation plant for 16 days, the Jake Gore coal refuse impoundment for 12 days and the Justice longwall mine for seven days. The suspensions were appealed to the Surface Mine Board. On September 13, 2002, the Surface Mine Board reduced the preparation plant permit suspension to 12 days and overturned the suspensions related to the

Jake Gore coal refuse impoundment and the Justice longwall permits. Independence appealed the suspension of the preparation plant permit to the Circuit Court of Boone County, West Virginia, and the suspension has been temporarily stayed pending the circuit court’s decision. In its appeal, Independence has raised the same due process arguments that were successful in the Marfork appeal.

On August 7, 2002, WVDEP issued an order to Massey’s Green Valley Coal Company subsidiary to show cause why its permit for an active refuse disposal area should not be suspended or revoked due to alleged pattern of three violations relating to sediment control. Green Valley has requested a hearing to show cause, but a hearing has not yet been scheduled.

On September 24, 2002, WVDEP issued an order to Massey’s Bandmill Coal Corporation subsidiary to show cause why its permit for an inactive surface mine should not be suspended or revoked due to an alleged pattern of four violations and one cessation order relating to sediment control, effluent limits, and hydrologic impacts. Bandmill has requested a hearing to show cause, but a hearing has not yet been scheduled.

On October 29, 2002 WVDEP issued an order to Massey’s Bandmill Coal Company subsidiary to show cause why its permit for its refuse area should not be suspended or revoked due to an alleged pattern relating to one cessation order and three violations issued with respect to impacts to hydrologic balance, effluent limits, disturbances to hydrologic balance, slurry injection and refuse placement. Bandmill has requested a hearing to show cause, but none has been scheduled.

On October 29, 2002 WVDEP issued an order to Massey’s Alex Energy, Inc. subsidiary to show cause why its permit for a surface mine that has completed mining and is undergoing reclamation should not be suspended or revoked due to an alleged pattern of three violations and one cessation order for effluent limits and hydrologic balance requirements. Alex Energy has requested a hearing to show cause, but none has been scheduled.

On October 29, 2002 WVDEP issued an order to Massey’s Independence Coal Company subsidiary to show cause why its permit for its Twilight Surface Mine should not be suspended or revoked due to an alleged pattern of ten violations relating to off-site impacts, drainage control, disturbed acreage limitations, soil handling, groundwater protection plans and general permit conditions. Independence has requested a hearing to show cause, but none has been scheduled.

On November 14, 2002, WVDEP issued an order to Alex Energy’s active South Surface Mine alleging a pattern with respect to four violations and one cessation order relating to impacts from mud and downslope placement of material. Alex Energy has requested a hearing, but none has been scheduled.

On November 14, 2002, WVDEP issued an order to Alex Energy’s active South Surface Mine alleging a pattern with respect to seven violations concerning sediment control, an unpermitted borehole and a leaking oil tank. Alex Energy has requested a hearing, but none has been scheduled.

On January 27, 2003, the Kentucky Natural Resources and Environmental Protection Cabinet issued a show cause order to an inactive mine site currently undergoing reclamation at Martin County Coal Corporation. The order alleged a pattern of violations and lists 27 violations that “contributed to” the pattern, including eight violations for sediment control, eight violations for off-permit disturbances, three violations relating to steep slopes standards, two violations of backfilling/grading standards, two violations for diversions and one violation each for contemporaneous reclamation, signs/markers, excess spoil disposal and water quality/effluent limitations standards. The Cabinet states in its order that it considers the sediment control, diversion, excess spoil and water quality effluent limitation to be “related” because of impacts or potential impacts to state waters. The violations were issued from January 19, 1999 through July 24, 2002 and it is unclear what one year time period the pattern encompasses. The order states that the Cabinet recommends revoking the permit and forfeiting the bond; however, based on conversations with Cabinet officials, it appears that the Cabinet does not necessarily intend that the show cause order impact the ability of MCCC or affiliated companies to obtain permits in the future.

On February 18, 2003, WVDEP issued an order to Alex Energy’s active North Surface Mine alleging a pattern with respect to two citations and one cessation order concerning sediment control and impacts to the hydrologic balance. Alex Energy has requested a hearing, but none has been scheduled.

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

If a company has its permit revoked and its 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 company may also be deemed ineligible to receive new permits. An inability 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.

Efforts to improve the Company’s environmental performance include creating the Public and Environmental Policy Committee of the Company’s Board of Directors on July 17, 2001. Subsequently, at the Committee’s direction, the Company has initiated environmental audits which are regularly reviewed with the Public and Environmental Policy Committee, hired an impoundment compliance officer and implemented an improved environmental management system.

Martin County Impoundment Discharge

On October 11, 2000, a partial failure of Massey’s Martin County Coal Corporation subsidiary’s coal refuse impoundment 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. As of December 31, 2002, Massey incurred a total of approximately $58.3 million of cleanup costs in connection with the spill, $52.2 million of which have been paid directly or reimbursed by insurance companies. Massey continues to seek insurance reimbursement of any and all covered costs, the majority of which are recorded as a receivable in the Company’s financial statements. Most of the claims, fines, penalties and lawsuits from the impoundment failure have been satisfied or settled. The remaining issues (none of which is considered material) are:

(1)

there are two remaining suits with 8 plaintiffs (one seeking class certification) alleging property damage claims and seeking unquantified compensatory and punitive damages allegedly resulting from the October 11, 2000 incident.

(2)

On June 26, 2001, the WVDEP filed a civil action against Martin County Coal in the Wayne County, West Virginia, Circuit Court alleging natural resources damages in West Virginia and alleged violations of law resulting from the impoundment discharge. The WVDEP’s alleged damages have not been quantified. The court ruled that WVDEP cannot collect statutory penalties, but has not yet ruled whether WVDEP can continue to assert its claims for punitive damages. Massey is continuing to defend this action vigorously and believes that it has numerous valid defenses to the claims.

(3)

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

(4)

On October 11, 2002, the Town of Fort Gay, West Virginia filed suit against the Company and Martin County Coal Corporation, alleging that it’s water treatment and distribution plant was damaged when water, allegedly damaged by the discharge from the Martin County impoundment, was pumped into the facility. The plaintiff seeks unquantified compensatory and punitive damages. Massey denies the allegations and is defending the action vigorously.

The Company believes 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 our carriers has stated that it believes its policy does not provide coverage for governmental penalties or punitive damages.

MSHA Proceedings

In September 2002, MSHA petitioned the Federal Mine Safety and Health Commission to assess Massey’s Independence Coal Company subsidiary $275,000 for alleged violations relating to a roof fall fatality at Independence’s Cedar Grove Mine. Independence has challenged the petition before the Commission.

In October 2002, the MSHA petitioned the Federal Mine Safety and Health Commission to assess Massey’s Independence Coal Company subsidiary $165,000 for alleged violations relating to a roof fall fatality at Independence’s Justice No. 1 Mine. Independence has challenged the petition before the Commission.

Trucking Litigation

On January 7, 2003, Coal River Mountain Watch, an advocacy group representing local residents in the Counties of Boone, Raleigh and Kanawha, West Virginia, and other plaintiffs, filed suit in the Circuit Court of Kanawha County, West Virginia against various coal and transportation companies (including various Massey subsidiaries) alleging that the defendants illegally transport coal in overloaded trucks causing damage to state roads and interfering with the plaintiffs’ use and enjoyment of their properties and their right to use the public roads, and seeking injunctive relief and unquantified compensatory and punitive damages.

Other Legal Proceedings

In addition, 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 adverse effect upon the consolidated financial position, cash flows or results of operations of Massey. The Company also is party to numerous lawsuits and other legal proceedings related to the non-coal businesses previously conducted by the 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.

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

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, 2002.

The current executive officers of Massey are:

Don L. Blankenship, Age 52

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 Coal Company, Inc.(1) since 1992. He was formerly the President and Chief Operating Officer of A.T. Massey from 1990 and President of Massey Coal Services, Inc.(2) from 1989. He joined Rawl Sales & Processing Co.(3) in 1982. He is also Director of the National Mining Association and the Governor’s Mission West Virginia and a member of the Norfolk Southern Advisory Board.

James L. Gardner, Age 51

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.

H. Drexel Short, Age 46

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.

Kenneth J. Stockel, Age 56

Mr. Stockel has been Senior Vice President and Chief Financial Officer since December 9, 2002. Prior to joining Massey, he served as Vice President—Finance & Administration at Sequent Energy Management in Houston, Texas, the non-regulated asset management affiliate of AGL Resources Inc. Prior to joining AGL Resources in 2000, Mr. Stockel was Chief Financial Officer at British Borneo USA, also in Houston, beginning in April 1998. Previously, he held positions of increasing responsibility in accounting and finance at Basis Petroleum and Philipp Brothers, affiliates of Salomon Inc. in New York. He began his career in the natural resources attestation group at Arthur Andersen in New York City.

R. Eberley Davis, Age 46

Mr. Davis has been Vice President, Secretary and General Counsel since July 15, 2002. Prior to joining Massey, Mr. Davis served as General Counsel for Lodestar Energy in Lexington, Kentucky. Prior to joining Lodestar in 1993 as Director of Legal Affairs, Mr. Davis was in private practice in Sturgis, Kentucky. He began his legal career in 1982 with the Morganfield, Kentucky law firm of Ruark, Hulette, Arnette & Davis.

Jeffrey M. Jarosinski, Age 43

Mr. Jarosinski has been Chief Compliance Officer of Massey since December 9, 2002, and Vice President, Finance of Massey since November 30, 2000. 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 9, 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 accounting, most recently as Manager at Womack, Burke & Associates, CPAs in Richmond, Virginia.

Baxter F. Phillips, Jr., Age 56

Mr. Phillips has been 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 has served as Vice President of A.T. Massey from January 1992 and, as Vice President, his responsibilities have encompassed purchasing, risk management, benefits and administration. Mr. Phillips joined A.T. Massey in 1981 and, prior to his election as Vice President in 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.

(1)

A.T. Massey Coal Company, Inc., or A.T. Massey, is a wholly-owned subsidiary of Massey Energy Company.

(2)

Massey Coal Services, Inc. is a wholly-owned subsidiary of Massey Coal Sales Company, Inc., a wholly-owned subsidiary of A.T. Massey.

(3)

Rawl Sales & Processing Co. is a wholly-owned subsidiary of A.T. Massey.

Part II

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 28, 2003, there were 75,322,095 shares outstanding and approximately 9,783 shareholders of record of Massey’s common stock.

The dividends paid and the stock prices of Massey stock for the past two fiscal years and the two-month transition period ended December 31, 2001, 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.

	High		Low		Dividends
Fiscal Year 2001
Quarter ended January 31, 2001(1)	$	18.10	$	9.94	$	0.08
Quarter ended April 30, 2001	$	28.23	$	17.20	$	0.04
Quarter ended July 31, 2001	$	22.95	$	15.66	$	0.04
Quarter ended October 31, 2001	$	20.56	$	12.25	$	0.04

	High		Low		Dividends
Fiscal Year 2002(2)
Transition Period ended December 31, 2001	$	20.73	$	15.53	$	0.00
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

(1)

Due to the timing of the Spin-Off transaction, in December 2000, the Company declared a first quarter dividend of $0.04 per share, payable in January 2001. Additionally, in January 2001, the Company declared a second quarter dividend of $0.04 per share, payable in April 2001.

(2)

On January 1, 2002, Massey changed its fiscal year end from October 31 to December 31. No dividend was declared during the transition period from October 31, 2001 to December 31, 2001.

The Company’s current dividend policy anticipates the payment of quarterly dividends in the future. The Company is restricted by its credit facilities from declaring and paying cash dividends in excess of $0.16 per share in any fiscal year, which dividends shall not exceed $13,000,000 in such fiscal year. 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.

Transfer Agent and Registrar

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

Equity Compensation Plan Information

(c) 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		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	2,314,515	$	12.86	4,878,326	(1)
Equity compensation plans not approved by security holders	—		—	—

Total	2,314,515	$	12.86	4,878,326

(1)

The following plans have securities available for future issuance (refer to column (c)): 1997 Restricted Stock Plan for Non-Employee Directors (156,576 shares remain available for annual grants of restricted stock to non-employee directors); 1995 Non-Employee Director Stock Program (63,636 shares remain available for initial grants of restricted stock to new non-employee directors); 1996 Executive Stock Plan (2,728,945 shares remain available for grants of either restricted stock or options to employees); and 1999 Executive Performance Incentive Plan (1,929,169 shares remain available for grants of either restricted stock or options to employees).

Item 6. Selected Financial Data.

SELECTED FINANCIAL DATA (1)

As described in the explanatory note immediately before Part I the Company is amending its Annual Report on Form 10-K for the fiscal year ended December 31, 2002, to include disclosure language about restatements made in the Company’s Form 10-K/A for the fiscal year ended October 31, 2001. See Note 2 to the Consolidated Financial Statements for further information regarding the restatements.

	Year Ended December 31, 2002			Year Ended October 31,									Two Months Ended December 31, (5)
	Year Ended December 31, 2002			2001			2000		1999		1998		2001			2000
				(Restated)			(Restated)		(Restated)		(Restated)		(Restated)			(Restated) (Unaudited)
CONSOLIDATED STATEMENT OF EARNINGS DATA:
Produced coal revenue	$	1,318.9		$	1,203.3		$	1,081.0	$	1,076.1	$	1,121.1	$	204.8		$	168.8
Total revenue		1,630.1			1,431.9			1,312.7		1,263.0		1,292.4		246.4			200.8
(Loss) Earnings from operations		(26.7	)		9.5			96.5		137.9		170.1		(19.2	)		(9.4	)
Net (Loss) Earnings		(32.6	)		(5.4	)		78.5		102.5		128.3		(14.8	)		(6.7	)
(Loss) earnings per share (2)
Basic and diluted		(0.44	)		(0.07	)		1.07		1.40		1.75		(0.20	)		(0.09	)
Dividends declared per share		0.16			0.20			N/A		N/A		N/A		—			—

CONSOLIDATED BALANCE SHEET DATA:
Working capital (deficit)	$	(63.4	)	$	(84.7	)	$	164.8	$	72.5	$	33.7	$	(93.3	)		(45.7	)
Total assets		2,241.4			2,271.1			2,183.8		2,008.6		1,866.6		2,272.0			2,191.2
Long-term debt		286.0			300.0			N/A		N/A		N/A		300.0			300.0
Shareholders’ equity		808.2			860.6			1,372.5		1,275.6		1,181.2		849.5			857.5

OTHER DATA:
EBIT	$	(26.7	)	$	9.5		$	96.5	$	137.9	$	170.1		(19.2	)		(9.4	)
EBITDA (3)		181.0			190.8			267.8		305.5		320.6		12.0			19.4
Tons Sold		42.1			43.7			40.2		37.9		37.6		7.0			6.4
Tons Produced		43.9			45.1			41.5		38.4		38.0		7.0			6.3
Total costs and expenses per ton sold	$	39.33		$	32.52		$	30.22	$	29.71	$	29.85	$	38.10		$	32.86
Average cash cost per ton sold (4)		28.90			24.33			21.74		21.40		22.22		28.61			23.95
Produced coal revenue per ton sold		31.30			27.51			26.86		28.40		29.83		29.36			26.39
Capital expenditures		135.1			247.5			204.8		230.0		307.9		37.7			23.4
Number of employees		4,552			5,004			3,610		3,190		3,094		5,040			3,730

(1)

On November 30, 2000, 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, subsequently renamed Massey Energy Company, which retained the Company’s coal-related businesses. Further discussion of the Spin-Off may be found in the Notes to the Consolidated Financial Statements. As New Fluor is the accounting successor to Fluor Corporation, Massey’s equity structure was impacted as a result of the Spin-Off. Massey retained $300 million of 6.95 percent Senior Notes, $278.5 million of Fluor commercial paper, other equity contributions from Fluor, and assumed Fluor’s common stock equity structure. Therefore, the Selected

Financial Data for years prior to 2001 are not necessarily indicative of the results of operations, financial position and cash flows of Massey in the future or had it operated as a separate independent company during the periods prior to November 30, 2000.

(2)

Shares used to calculate basic earnings per share for the periods ended October 31, 2000 and prior is based on the number of shares outstanding immediately following the Spin-Off (73,468,707). Shares used to calculate diluted earnings per share for the periods ended October 31, 2000 and prior is based on the number of shares outstanding immediately following the Spin-Off and the dilutive effect of stock options and other stock-based instruments of Fluor Corporation, held by Massey employees, that were converted to equivalent instruments in Massey Energy Company in connection with the Spin-Off. In accordance with accounting principles generally accepted in the United States, the effect of dilutive securities was excluded from the calculation of the diluted loss per common share for the years ended December 31, 2002 and October 31, 2001, and for the two-month periods ended December 31, 2001 and 2000, as such inclusion would result in antidilution.

(3)

EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although EBITDA is not a measure of performance calculated in accordance with generally accepted accounting principles, management believes that it is useful to an investor in evaluating Massey because it is widely used in the coal industry as a measure to evaluate a company’s operating performance before debt expense and its cash flow. EBITDA does not purport to represent cash generated by operating activities and should not be considered in isolation or as a substitute for measures of performance in accordance with generally accepted accounting principles.

In addition, because EBITDA is not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. Management’s discretionary use of funds depicted by EBITDA may be limited by working capital, debt service and capital expenditure requirements and by restrictions related to legal requirements, commitments and uncertainties. (4) Average cash cost per ton is calculated as the sum of Cost of produced coal revenue and Selling, general and administrative expense (excluding Depreciation, depletion and amortization), divided by the number of tons sold. Although Average cash cost per ton is not a measure of performance calculated in accordance with generally acceptable accounting principles, management believes that it is useful to investors in evaluating Massey because it is widely used in the coal industry as a measure to evaluate a company’s control over its cash costs. Average cash cost per ton should not be considered in isolation or as a substitute for measures of performance in accordance with generally accepted accounting principles. In addition, because Average cash cost per ton is not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. The table below reconciles the generally acceptable accounting principal measure of Total costs and expenses per ton to Average cash cost per ton.

	Year ended December 31,				Year ended October 31,
	2002				2001				2000				1999				1998
	$		per ton		$		per ton		$		per ton		$		per ton		$		per ton
Total Costs and Expenses	$	1,656.8	$	39.33	$	1,422.3	$	32.52	$	1,216.2	$	30.22	$	1,125.1	$	29.71	$	1,122.3	$	29.85
Less: Freight and handling costs		112.0		2.66		129.9		2.97		131.3		3.26		106.2		2.80		130.7		3.48
Less: Cost of purchased coal revenue		119.6		2.84		47.0		1.08		38.9		0.97		41.2		1.09		5.5		0.15

Average Cash Cost	$	1,217.5	$	28.90	$	1,064.1	$	24.33	$	874.7	$	21.74	$	810.1	$	21.40	$	835.6	$	22.22

	Two Months ended December 31,
	2001				2000
	$		per ton		$		per ton
Total Costs and Expenses	$	265.7	$	38.10	$	210.2	$	32.86
Less: Freight and handling costs		18.9		2.71		21.9	$	3.41
Less: Cost of purchased coal revenue		16.1		2.31		6.3		0.99
Less: Depletion, Depreciation and Amortization		31.2		4.47		28.8		4.51

Average Cash Cost	$	199.5	$	28.61	$	153.2	$	23.95

(5)

The Company changed to a calendar-year basis of reporting financial results effective January 1, 2002. For comparative purposes, the selected financial data reported for 1998 through 2001 is for the twelve months and periods then ended, October 31. As a requirement of the change in fiscal year, the Company is reporting results of operations and cash flows for a special transition period for the two months ended December 31, 2001 compared with the two-months ended December 31, 2000. Additionally, other selected financial data is presented as of and for the two months ended December 31, 2001 and December 31, 2000.

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 and 2000 annual periods 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 (audited) compared with the two months ended December 31, 2000 (unaudited). The comparative audited balance sheets are as of December 31, 2002 and October 31, 2001.

Results of Operations

2002 Compared with 2001

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:

•

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

•

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

Realized prices for our produced tonnage sold in 2002 reflected the improvement seen in the market during 2001, as spot market prices of Central Appalachian coal increased to 20-year highs, and we were able to obtain sales commitments at relatively higher prices. However, during 2002 the soft economic environment, weak steel demand and the higher stockpiles built by the utilities due to the unusually mild weather that prevailed in the Eastern United States during the winter of 2001—2002 significantly reduced demand for all grades of coal.

Freight and handling revenue decreased 14 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 $1,177.4 million for 2002 from $1,032.4 million for 2001. Cost of produced coal revenue on a per ton of coal sold basis increased by 18 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 West Virginia Harman Mining Corporation lawsuit, as well as a fourth quarter charge of $10.6 million related to an arbitration award in a contract dispute. Additionally, the reduction in tons sold, poor productivity at our longwalls, as well as at some room and pillar and surface mining operations, and higher wage and benefit costs contributed to the increase. During 2001, in response to the market improvement, we increased staffing and benefits costs in order to increase production. However, due to the subsequent market weakness, we reduced total workforce during the first quarter of 2002 by approximately 7 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. Tons produced in 2002 were 43.9 million compared to 45.1 million in 2001.

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 (DD&A) 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.

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.

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 Virginia Harman Mining Corporation action after the dismissal of the appeal in the third quarter of 2002.

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

2001 Compared with 2000

Produced coal revenue increased 11% to $1,203.3 million in 2001 as compared to $1,081.0 million for the previous year. Two factors that impacted produced coal revenue for 2001 compared to 2002 were:

•

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

•

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

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

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

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

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

Cost of produced coal revenue increased 23 percent to $1,032.4 million for 2001 from $839.4 million in 2000. This was partially due to the increase in tons sold. Cost of produced coal revenue on a per ton sold basis increased by 14 percent to $23.65 for the fiscal year 2001 compared to $20.82 in fiscal 2000. This increase in cost was related to both the direct cost of labor and the decreases in productivity resulting from a greater percentage of inexperienced miners. This was due, in part, to the Company’s efforts to increase production. In addition, heavy rains in southern West Virginia in July increased employee absenteeism and disrupted loading operations and rail service, slowing coal shipping. Other operational problems impacted production and costs throughout the fiscal year. Operating difficulties and problematic geologic conditions were encountered at several longwall mines and during the expansion of Massey’s two large surface mines, where we experienced higher than expected overburden ratios in the first half of the year. The Ellis Eagle longwall mine experienced flooding that caused significant disruption to coal production during April and May. The flooding caused reduced shipments from both the Marfork and Goals preparation plants. Increases in operating costs related to the Martin County Coal slurry spill and the idling of the Martin County Coal preparation plant from October 11, 2000, to April 2, 2001, also negatively impacted cost of sales.

Cost of produced coal revenue for 2001 and 2000 includes credits of $9.5 million and $15.0 million, respectively, related to refunds of black lung excise taxes paid on coal export sales tonnage. Black lung excise

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

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

Costs of purchased coal revenue increased 21 percent to $47.0 million in 2001 from $38.9 million in 2000. This was due to the increase in spot prices for coal, as purchased tons sold were 1.3 million in 2001 and 2000. Massey purchases varying amounts of coal each year to supplement produced coal.

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

Selling, general and administrative expenses decreased 10 percent to $31.7 million for 2001 compared with $35.4 million for 2000. This was due in part to a $7.1 million bad debt expense in 2000 associated with the bankruptcy of a major steel industry customer as well as a reduction in accruals related to long-term executive compensation plans, partially offset by additions to the administrative workforce associated with running a stand-alone publicly traded company.

Interest income decreased to $8.7 million for 2001 compared to $25.7 million for 2000. This decrease was primarily due to the elimination of the Company’s loans with Fluor Corporation in connection with the Spin-Off transaction on November 30, 2000. Additionally, in the second quarter of 2001, $3.2 million was accrued for interest due on the black lung excise tax refund as noted above, while in the third fiscal quarter of 2000, $5.3 million was accrued for interest on the black lung excise tax refund.

Interest expense increased to $34.2 million for 2001. The increase was due to the addition of the 6.95 percent Senior Notes and commercial paper borrowings subsequent to the Spin-Off.

Income tax benefit was $10.5 million for 2001 compared to an income tax expense of $43.2 million for 2000. This primarily reflects the loss before taxes for 2001 compared to income before taxes for 2000, as well as a depletion accounting income tax benefit of $4.5 million in 2001.

Liquidity and Capital Resources

At December 31, 2002, the Company’s available liquidity was $134.5 million, including cash and cash equivalents of $2.7 million and $131.8 million availability under the Company’s revolving credit facilities. At December 31, 2002, Massey had $264.0 million outstanding under its credit facilities, which is included in short-term debt. In early May 2002, Moody’s and S&P downgraded our credit ratings. These ratings actions effectively prevented us from accessing the commercial paper market due to the restrictive investment policy credit guidelines of potential commercial paper investors and caused us to draw on the credit facilities for short-term financing needs. No commercial paper obligations were outstanding at December 31, 2002.

assets, now owned or at any time hereafter acquired by the Company, excluding among other things, all coal, oil and gas reserves and mining permits, certain properties (e.g., the Eastman Chemical Company Coal Handling System and Westvaco Coal Handling Facility, and the value of properties that might exceed the lien threshold established in the indenture related to the Senior Notes (discussed below)) and certain other assets associated with the Company’s accounts receivable securitization program discussed below. Both facilities have been renewed through November 25, 2003. The Company intends to replace these credit facilities prior to their expiration on November 25, 2003. Borrowings under these facilities bear interest based on (i) the London Interbank Offer Rate (LIBOR) or (ii) the Base Rate (as defined in the facility agreements) plus a margin, which is based on the Company’s senior secured debt credit rating as determined by Moody’s and Standard & Poor’s. At December 31, 2002, and currently, Massey’s senior secured debt ratings are Ba1 and BB+, respectively.

The revolving credit facilities contain financial covenants requiring the Company to maintain various financial ratios. Failure by the Company to comply with these covenants could result in an event of default, which if not cured or waived could have a material adverse effect on the Company. The financial covenants consist of a maximum leverage ratio, a minimum interest coverage ratio, and a minimum net worth test. The leverage ratio requires that the Company not permit the ratio of total indebtedness at the end of any quarter to adjusted EBITDA for the four quarters then ended to exceed a specific amount. The interest coverage ratio requires that the Company not permit the ratio of the Company’s adjusted EBITDA to interest expense for the four quarters then ended to be less than a specified amount. The net worth test requires that the Company not permit its net worth to be less than a specified amount. The Company was in compliance with all material covenants at December 31, 2002 and during other periods reflected except for the covenant related to the maximum leverage ratio, with which we were not in compliance at December 31, 2001. However, the participant banks granted a waiver of this financial covenant for the period ended December 31, 2001. In the event we violate any of the debt covenants and do not affect a timely cure or receive a waiver from the lenders in our credit facilities, the debt agreements provide that the Administrative Agent shall, if requested by at least four lenders holding at least 50% of the aggregate amount of the loans, declare the loans immediately due and payable.

In determining EBITDA as defined in the credit facility agreements for use in computing the leverage ratio, the Company has excluded certain items, including the $25.6 million reserve relative to the Harman litigation described in Note 15. The Company believes that the exclusion of such items is appropriate and has notified the lenders’ Administrative Agent of this exclusion. If the accrual for the Harman litigation were to be included in the EBITDA calculation and no further adjustments were made, the Company would still be in compliance with the covenant at December 31, 2002. For further detail on the financial covenants, see Section 5.02 of the Amended and Restated Credit Agreement, which is included as Exhibit 10.1 to this Form 10-K.

The Company had $286.0 million of long-term debt as of December 31, 2002, which consisted entirely of 6.95 percent Senior Notes (the “Notes”) due March 1, 2007. Initially, $300 million of the Notes were issued in March 1997 at a discount, for aggregate proceeds of $296.7 million. During the fourth quarter of 2002, the Company made several open-market purchases, retiring a total principal amount of $14.0 million Senior Notes at a cost of $10.7 million plus accrued interest. Interest is payable semiannually on March 1 and September 1 of each year, commencing September 1, 1997. The 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. On November 27, 2002, Moody’s and S&P reduced the credit ratings on the Senior Notes to Ba3 and B+, respectively, citing the structural subordination caused by the secured status of the amended bank credit facilities.

Additionally, the Company has available a $500 million debt shelf registration filed with the Securities and Exchange Commission (the “SEC”) in March 1999, all of which remains unused. Prior to the spin-off, Fluor Corporation filed this debt shelf registration. An updated filing with the SEC would be required to issue debt under this shelf registration.

In December 2002, the Company generated cash flow of $17 million from the sale and leaseback of mining equipment. In January 2003, the Company implemented an accounts receivable securitization program that will

allow it to generate cash of up to $80 million based on the amount of accounts receivable outstanding. The cash generated from both the sale leaseback and securitization programs will reduce capacity under the Company’s main credit facility by 25% of the proceeds.

The total debt-to-book capitalization ratio was 40.5 percent at December 31, 2002 compared to 38.8 percent at October 31, 2001. The cash flow provided by operating activities was $122.5 million in 2002 and $172.8 million for the fiscal year ended October 31, 2001. Cash provided by operating activities reflects net earnings adjusted for non-cash charges and changes in working capital requirements. Net cash utilized in investing activities was $122.0 million in 2002 and $212.6 million for the fiscal year ended October 31, 2001. The cash used in investing activities reflects capital expenditures in the amount of $135.1 million and $247.5 million in the years ended December 31, 2002 and October 31, 2001, respectively. These capital expenditures are for replacement of mining equipment, the expansion of mining capacity and projects to improve the efficiency of mining operations. Net cash utilized in financing activities was $3.3 million in 2002 compared to net cash provided by financing activities of $38.6 million in 2001. Financing activities in 2001 primarily reflect changes in amounts due from Fluor Corporation and other capital accounts associated with the Spin-Off transaction and being a publicly traded company. In addition, the net cash utilized in financing activities in 2002 also includes $17 million of proceeds from a sale-leaseback transaction, as well as $10.7 million utilized to repurchase a portion of our outstanding Senior Notes. In addition to the cash spent on capital expenditures during the year of 2001, the Company leased, through operating leases, $10.6 million and $109.0 million of mining equipment in 2002 and the fiscal year ended October 31, 2001, respectively.

The cash flow provided by operating activities was $172.8 million in 2001 and $153.7 million for the same period in 2000. Cash provided by operating activities reflects net earnings adjusted for non-cash charges and changes in working capital requirements. Net cash utilized in investing activities was $212.6 million in 2001, and $172.8 million in 2000. The cash used in investing activities reflects capital expenditures in the amount of $247.5 million and $204.8 million for the years ended October 31, 2001 and 2000, respectively. These capital expenditures are for replacement of mining equipment, the expansion of mining capacity and projects to improve the efficiency of mining operations. Financing activities primarily reflect changes in amounts due from Fluor Corporation and other capital accounts associated with the Spin-Off transaction and being a publicly traded company. In addition to the cash spent on capital expenditures during the year of 2001, the Company leased, through operating leases, $109.0 million and $69.0 million of mining equipment in 2001 and 2000, respectively.

Massey believes that 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 several 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 which Massey finds acceptable, or at all.

The following is a summary of our significant obligations as of December 31, 2002:

	Payments Due by Years
In thousands	Total		Within 1 Year		2-3 Years		4-5 Year		After 5 Years
Long-term debt	$	286,000	$	—	$	—	$	286,000	$	—
Short-term debt		264,045		264,045		—		—		—
Operating lease obligations		212,342		61,486		106,806		40,987		3,063

Total obligations	$	762,387	$	325,531	$	106,806	$	326,987	$	3,063

Additionally, we have liabilities relating to other post-employment benefits, work related injuries and illnesses, and mine reclamation and closure. As of December 31, 2002, payments related to these items are estimated to be:

Payments Due by Years (In thousands)

Within 1 Year

2 - 3

Years

4 - 5

Years

$32,903

$65,463

$59,031

Our determination of these noncurrent liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Moreover, in particular for periods after 2002, our estimates may change from the amounts included in the table, and may change significantly, if our assumptions change to reflect changing conditions. These assumptions are discussed in the notes to our 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.

Off-Balance sheet arrangements

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

The Company uses surety bonds to secure reclamation, workers’ compensation, wage payments, and other miscellaneous obligations. As of December 31, 2002, the Company had $261 million of outstanding surety bonds with third parties. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $217 million, workers’ compensation bonds of $10 million, wage payment and collection bonds of $9 million, and other miscellaneous obligation bonds of $25 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 worker’s compensation programs, various insurance contracts and other obligations. Issuing banks currently require that such letters of credit be secured by funds deposited into restricted accounts pledged to the banks under reimbursement agreements. At 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, and no claims were outstanding against those letters of credit.

Inflation

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

Recent Accounting Pronouncements

On August 15, 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). The standard requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred. 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. 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. This statement is effective for fiscal years beginning after June 15, 2002 and transition is by cumulative catch-up adjustment. The Company has adopted SFAS No. 143 on January 1, 2003 and the adoption will change the Company’s current accounting for reclamation. The Company is continuing to calculate its transition adjustment.

In April 2002, the FASB issued Statement of Financial Accounting Standards No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” (“SFAS No. 145”), which is effective for fiscal years beginning after May 2002. The standard requires that gains or losses on debt extinguishment, previously reported as extraordinary items, be presented as a component of results from continuing operations unless the extinguishment meets the criteria for classification as an extraordinary item in Accounting Principles Board Opinion No. 30. During the fourth quarter of 2002, the Company purchased in open market transactions, an aggregate of $14.0 million of its 6.95 percent Senior Notes at an aggregate purchase price of $10.7 million. The Company has chosen early adoption of SFAS No. 145, and accordingly, recorded a gain on the transactions in Senior notes repurchase income, a component of Total revenue.

In November 2002, the FASB issued FASB Interpretation No. 45, Guarantors’ Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN45”). This Interpretation describes the disclosure requirements of a guarantor’s issuance of certain guarantees, and clarifies that a guarantor is required to recognize a liability, at the date of issuance, for the fair value of the obligation assumed in issuing the guarantee. The disclosure requirements of FIN 45 are effective for the Company for the year ended December 31, 2002, and the initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. See Note 8 to the Consolidated Financial Statements.

Outlook

Cold winter weather, reductions in utility coal stockpiles and the rising costs of alternative energy sources, are expected to accelerate demand for coal in early 2003. Supply constraint and production declines by producers throughout Central Appalachia should also support coal prices. Nevertheless, the Company expects a loss in the first quarter of 2003 due to operational disruptions caused by moving four longwalls to new panels and weather-related production and shipping issues. The Company currently projects produced coal sales of 40 to 45 million tons in 2003.

CRITICAL ACCOUNTING ESTIMATES AND ASSUMPTIONS

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported amounts. These estimates and assumptions are based on information available as of the date of the financial statements. The following critical accounting estimates and assumptions were used in the preparation of the financial statements:

Defined Benefit Pension

The Company has noncontributory defined benefit pension plans, which cover substantially all administrative and non-union employees of the Company. Benefits are generally based on the employee’s years of service and compensation, or under a cash balance formula with contribution credits based on hours worked. Funding for the plan is generally at the minimum annual contribution level required by applicable regulations. The Company accounts for its defined benefit plans in accordance with FAS 87, Employer’s Accounting for Pensions, which requires amounts recognized in the financial statements to be determined on an actuarial basis. The estimated cost and benefits of our non-contributory defined benefit pension plans are determined by independent actuaries, who, with our input, use various actuarial assumptions, including discount rate, future rate

of increase in compensation levels and expected long-term rate of return on pension plan assets. The discount rate is determined each year at the measurement date. In estimating the discount rate, we look to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. At December 31, 2002, the discount rate was determined to be 6.75% compared to the discount rate at October 31, 2001 of 7.25%. The rate of increase in compensation levels is determined based upon the Company’s long-term plans for such increases. The rate of increase in compensation levels was determined to be 4% at December 31, 2002, and October 31, 2001. Expected long-term rate of return on plan assets is based on long-term historical return information for the mix of investments that comprise plan assets and future estimates of long-term investment returns. The expected long-term rate of return on plan assets used to determine expense in each period was 9.0% and 9.5% for the years ended December 31, 2002 and October 31, 2001, respectively. The Company expects to adjust the expected long-term rate of return on plan assets to 8.5% for determination of 2003 expense. Significant changes to these rates introduce substantial volatility to our costs. The fair value of the defined benefit pension plan assets is an important factor in the determination of defined benefit pension expense. The fair value of plan assets at December 31, 2002 was $174 million compared to $196 million at October 31, 2001, a reduction of $22 million. As a result of the decrease in discount rate, the reduction in expected long-term rate of return on plan assets, and the decline in defined benefit pension plan assets during 2002, costs for the defined benefit pension plans are expected to increase in 2003 compared to 2002 related expense.

Coal Workers’ Pneumoconiosis

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

Workers’ Compensation

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

Other Post Employment Benefits

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

Reclamation and Mine Closure Obligations

The Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. We accrue for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge as coal is mined, on a unit-of-production basis over the proven and probable reserves as defined in Industry Guide 7. The estimate of ultimate reclamation liability is reviewed annually by our management and engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly. Accounting pronouncement, SFAS No. 143 requires that retirement obligations be recorded as a liability based on the present value of the estimated cash flows. Further discussion of the implementation of this new accounting pronouncement can be found in the previous section “New Accounting Pronouncements.”

Contingencies

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

Deferred Taxes

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

Coal Reserve Values

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

•

geological conditions;

•

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

•

the assumed effects of regulations and taxes by governmental agencies;

•

assumptions governing future prices; and

•

future operating costs.

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

Capitalized Development Costs

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

Item 7A. Quantitative and Qualitative Discussions about Market Risk

Our interest expense is sensitive to changes in the general level of interest rates in the United States. At December 31, 2002, we had outstanding $286.0 million aggregate principal amount of long-term debt under fixed-rate instruments; however, our primary exposure to market risk for changes in interest rates relates to our short-term financing. At December 31, 2002, we had $264.0 million outstanding under the revolving credit facilities. At December 31, 2002, the weighted average interest rate of borrowings under the credit facilities was 3.92 percent. Based on the short-term debt balance outstanding at December 31, 2002, a 100 basis point increase in the average interest rate for our borrowings would increase our annual interest expense by approximately $2.6 million.

Almost all of Massey’s transactions are denominated in U.S. dollars, and, as a result, it does not have material exposure to currency exchange-rate risks.

We manage our commodity price risk through the use of long-term coal supply agreements, which are contracts with a term of greater than 12 months, rather than through the use of derivative instruments. For our fiscal year ended December 31, 2002, approximately 94% of our coal sales volume was pursuant to long-term contracts. The Company anticipates that in 2003, the percentage of sales pursuant to long-term arrangements will be comparable with the percentage of sales for 2002. The prices for coal shipped under long-term contracts may be below the current market price for similar types of coal at any given time. As a consequence of the substantial volume of its sales which are subject to these long-term agreements, 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.

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT AUDITORS

To the Shareholders of Massey Energy Company

We have audited the accompanying consolidated balance sheets of Massey Energy Company as of December 31, 2002 and October 31, 2001, and the related consolidated statements of income, cash flows, and shareholders’ equity for the year ended December 31, 2002, the two months ended December 31, 2001, and each of the two years in the period 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, 2002 and October 31, 2001, and the consolidated results of its operations and its cash flows for the year ended December 31, 2002, the two months ended December 31, 2001, and each of the two years in the period 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 2 to the consolidated financial statements, the Company has restated its financial statements for the two-month period ended December 31, 2001 and each of the two years in the period ended October 31, 2001.

/S/ ERNST & YOUNG LLP

Richmond, Virginia

March 26, 2003

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Amounts)

	Year Ended									Two Months Ended
	December 31, 2002			October 31, 2001			October 31, 2000			December 31, 2001			December 31, 2000
				(Restated)			(Restated)			(Restated)			(Restated) (Unaudited)
Revenues
Produced coal revenue	$	1,318,935		$	1,203,285		$	1,081,027		$	204,753		$	168,809
Freight and handling revenue		112,017			129,894			131,334			18,912			21,893
Purchased coal revenue		117,049			49,485			39,585			16,999			6,301
Other revenue		78,804			49,197			60,752			5,779			3,774
Senior notes repurchase income		3,290			—			—			—			—

Total revenues		1,630,095			1,431,861			1,312,698			246,443			200,777

Costs and Expenses
Cost of produced coal revenue		1,177,363			1,032,420			839,359			191,957			147,283
Freight and handling costs		112,017			129,894			131,334			18,912			21,893
Cost of purchased coal revenue		119,562			47,030			38,853			16,081			6,301
Depreciation, depletion and amortization applicable to:
Cost of produced coal revenue		203,921			177,384			169,467			30,293			28,538
Selling, general and administrative		3,809			3,885			1,869			899			293
Selling, general and administrative		40,111			31,702			35,364			7,510			5,888

Total costs and expenses		1,656,783			1,422,315			1,216,246			265,652			210,196

(Loss) Income from operations		(26,688	)		9,546			96,452			(19,209	)		(9,419	)
Interest income		4,470			8,747			25,661			987			2,123
Interest expense		(35,302	)		(34,214	)		(347	)		(5,302	)		(3,719	)

(Loss) Income before taxes		(57,520	)		(15,921	)		121,766			(23,524	)		(11,015	)
Income tax (benefit) expense		(24,946	)		(10,501	)		43,235			(8,723	)		(4,296	)

Net (loss) income	$	(32,574	)	$	(5,420	)	$	78,531		$	(14,801	)	$	(6,719	)

(Loss) Income per share
Basic	$	(0.44	)	$	(0.07	)	$	1.07		$	(0.20	)	$	(0.09	)

Diluted	$	(0.44	)	$	(0.07	)	$	1.07		$	(0.20	)	$	(0.09	)

Shares used to calculate (loss) income per share
Basic		74,442			73,858			73,469			74,131			74,098

Diluted		74,442			73,858			73,472			74,131			74,098

See Notes to Consolidated Financial Statements.

MASSEY ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	December 31, 2002			October 31, 2001
				(Restated)
ASSETS
Current Assets
Cash and cash equivalents	$	2,725		$	5,664
Trade and other accounts receivable, less allowance of $8,775 and $9,848, respectively		175,795			198,885
Inventories		193,669			141,483
Deferred taxes		13,889			13,572
Income taxes receivable		6,437			1,880
Other current assets		117,326			96,034

Total current assets		509,841			457,518

Net Property, Plant and Equipment		1,534,488			1,613,133
Other Noncurrent Assets
Pension assets		77,356			80,400
Other		119,747			120,029

Total other noncurrent assets		197,103			200,429

Total assets	$	2,241,432		$	2,271,080

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable, principally trade and bank overdrafts	$	124,933		$	185,903
Short-term debt		264,045			248,231
Payroll and employee benefits		44,389			37,878
Other current liabilities		139,896			70,223

Total current liabilities		573,263			542,235

Noncurrent Liabilities
Long-term debt		286,000			300,000
Deferred taxes		244,676			250,444
Other		329,281			317,796

Total noncurrent liabilities		859,957			868,240

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 – 75,317,732 and 74,543,670 shares, respectively		47,074			46,590
Additional Capital		21,659			15,541
Unamortized executive stock plan expense		(6,407	)		(6,706	)
Retained earnings		745,886			805,180

Total shareholders’ equity		808,212			860,605

	$	2,241,432		$	2,271,080

See Notes to Consolidated Financial Statements.

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands of Dollars)

	Year Ended									Two Months Ended
	December 31, 2002			October 31, 2001			October 31, 2000			December 31, 2001			December 31, 2000
				(Restated)			(Restated)			(Restated)			(Restated) (Unaudited)
Cash Flows From Operating Activities
Net (loss) income	$	(32,574	)	$	(5,420	)	$	78,531		$	(14,801	)	$	(6,719	)
Adjustments to reconcile net (loss) income to cash provided by operating activities:
Depreciation, depletion and amortization		207,730			181,269			171,336			31,192			28,831
Deferred taxes		3,511			(4,260	)		28,053			(8,748	)		(4,296	)
Loss (Gain) on disposal of assets		803			517			(28,169	)		111			1,565
Gain on repurchase of senior notes		(3,290	)		—			—			—			—
Changes in operating assets and liabilities:
Decrease (Increase) in accounts receivable		2,068			4,603			(42,801	)		11,079			9,864
(Increase) Decrease in inventories		(37,876	)		(40,350	)		(12,349	)		(14,310	)		1,965
Increase in other current assets		(17,657	)		(25,461	)		(13,983	)		(3,579	)		(22,733	)
Decrease (Increase) in pension and other assets		4,961			25,237			(30,013	)		11,938			(6,698	)
(Decrease) Increase in accounts payable and bank overdrafts		(61,877	)		32,446			(6,729	)		907			(34,990	)
(Decrease) Increase in accrued income taxes		(4,557	)		(7,002	)		2,197			—			(2,427	)
Increase (Decrease) in other accrued liabilities		76,950			(2,004	)		(5,204	)		(906	)		(20,442	)
(Decrease) Increase in other non-current liabilities		(15,717	)		13,217			12,818			6,553			9,398

Cash provided (utilized) by operating activities		122,475			172,792			153,687			19,436			(46,682	)

Cash Flows From Investing Activities
Capital expenditures		(135,099	)		(247,517	)		(204,835	)		(37,698	)		(23,386	)
Proceeds from sale of assets		13,127			34,870			32,072			416			—

Cash utilized by investing activities		(121,972	)		(212,647	)		(172,763	)		(37,282	)		(23,386	)

Cash Flows From Financing Activities
Increase (Decrease) in short-term debt, net		944			(29,998	)		—			14,870			(3,568	)
Proceeds from sale and leaseback of equipment		16,955			—			—			—			—
Repurchase of senior notes		(10,710	)		—			—			—			—
Decrease in amount due from Fluor Corporation		—			67,554			1,352			—			67,554
Equity contributions from Fluor Corporation		—			2,476			17,069			—			2,476
Cash dividends paid		(11,919	)		(11,811	)		—			—			—
Stock options exercised		1,408			9,369			—			2,856			—
Other, net		—			1,000			(467	)		—			1,058

Cash (utilized) provided by financing activities		(3,322	)		38,590			17,954			17,726			67,520

Decrease in cash and cash equivalents		(2,819	)		(1,265	)		(1,122	)		(120	)		(2,548	)
Cash and cash equivalents at beginning of period		5,544			6,929			8,051			5,664			6,929

Cash and cash equivalents at end of period	$	2,725		$	5,664		$	6,929		$	5,544		$	4,381

Supplemental Cash Flow Information
Cash paid during the period for income taxes	$	1,156		$	1,656		$	12,834		$	46		$	107

See Notes to Consolidated Financial Statements.

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In Thousands of Dollars except share amounts)

	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
	(Restated)		(Restated)									(Restated)						(Restated)			(Restated)			(Restated)
Balance at October 31, 1999	73,469		$	45,918		$	—		$	—		$	1,510,789		$	(280,416	)	$	—		$	(716	)	$	1,275,575
Net income													78,531												78,531
Other comprehensive loss, net of deferred tax benefit of $30:
Unrealized loss on investment																						1,075			1,075
Reclassification of unrealized gain to net income																						(1,122	)		(1,122	)
Comprehensive income																									78,484

Capital contributions													17,069												17,069

Net change in amount due from Fluor Corporation																1,352									1,352

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

See Notes to Consolidated Financial Statements.

MASSEY ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation

The accompanying consolidated financial statements include the accounts of Massey Energy Company (“Massey” or the “Company”), its wholly owned subsidiary A.T. Massey Coal Company, Inc. (“A.T. Massey”) and its subsidiaries. A.T. Massey now represents the sole operating subsidiary of Massey, as Massey has no separate independent operations. Until the spin-off transaction on November 30, 2000 (the “Spin-Off”) (See Note 13), A.T. Massey was 100% controlled by Fluor Corporation (“Fluor”). Therefore, these financial statements for all periods prior to 2001 may not necessarily be indicative of the results of operations, financial position and cash flows 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.

Change in Fiscal Year-end

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 2001 and 2000 annual periods 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 (audited) compared with the two-months ended December 31, 2000 (unaudited). The comparative audited consolidated balance sheets are as of December 31, 2002 and October 31, 2001.

2. Restatement and Reclassification

The Company has recently resolved certain accounting and disclosure issues resulting from a review by the Securities and Exchange Commission (SEC) of its annual report on Form 10-K for the fiscal year ended October 31, 2001 and subsequently filed periodic reports on Forms 10-Q. The issues, which are explained more fully below involve corrections to (1) the timing of recognition of certain charges related to claims against the Company, (2) its presentation of shareholders’ equity and adjustments related to the Spin-Off and (3) its accounting method for black lung liabilities and related expense recognition. The Company has restated its 2002 quarterly financial information, the two-month transition period ended December 31, 2001, as well as its 2001 and prior year financial statements to reflect charges related to claims against the Company in the proper periods, properly present shareholders’ equity in periods prior to the Spin-Off and to account for black lung obligations under the service period approach as described in Statement of Financial Accounting Standards No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions” (SFAS No. 106)

The restatement adjustments are as follows:

The Consolidated Financial Statements for the two-month transition period ended December 31, 2001 are restated to record in the two-month transition period ended December 31, 2001, a reduction in the Company’s bad debt reserves of $3 million pre-tax with respect to Enron Corporation, previously recorded in the first quarter 2002.

The Consolidated Financial Statements for 2001 are restated to recognize a fourth quarter $6.9 million charge related to the settlement of claims for delinquent workers’ compensation premiums which was previously recognized in the two-month transition period ended December 31, 2001. As a result, at October 31, 2001, Other Current Liabilities increased by $2.4 million and Other Non-Current Liabilities increased by $4.5 million.

The Consolidated Financial Statements for 2001 are restated to recognize a fourth quarter $2.5 million charge in connection with a wrongful employee discharge lawsuit which was previously recognized in the transition period ended December 31, 2001. As a result, at October 31, 2001, Other Non-Current Liabilities increased by $2.5 million.

The Consolidated Financial Statements are restated to present assumed shares outstanding for all periods presented. As a result, at October 31, 2000 and 1999, there was an increase of $45.9 million in Common Stock and a decrease of $45.9 million in Net Investment by Fluor Corporation to reflect 73.5 million shares of common stock outstanding (the number of shares outstanding on the date of the Spin-off).

The Consolidated Financial Statements have also been restated to retroactively adopt and apply the service period approach described in SFAS No. 106 as allowed under SFAS No. 112 “Employers’ Accounting for Postemployment Benefits” to the Company’s obligations with respect to coal worker’s pneumoconiosis (black lung). Previously, the Company utilized a different actuarial approach. This change has been implemented effective November 1, 1994, the first date under which the Company was required to implement SFAS No. 112. Trust assets previously offset against the Company’s black lung liability ($2.4 million at October 31, 2001) have been reclassified to Other Current Assets and accounted for under SFAS No. 115 “Accounting for Certain Investments in Debt and Equity Securities.”

The service period approach that the Company retroactively adopted, differs from the previous actuarial method utilized primarily as follows:

•

The Company’s previous method accrued the difference between the estimated total black lung liability for past and future service and the actual amount recorded immediately for all shutdown locations and over a 15-year period for all active locations. The service cost method makes no distinction between active and shutdown operations.

^¡

Under the previous method, for active operations, the annual cost was calculated as the unreserved amount amortized over 15 years. The unreserved amount included gains and losses arising from assumptions changes and experience as well as the estimated liability for future service. The service cost method divides this into a service cost component that is spread over the future working lifetime of active employees and a gain/loss amortization component that is spread over a five-year period.

^¡

Under the previous method, for inactive operations, the unreserved amount was immediately recognized. Under the service cost method, this unreserved amount would fall solely into the gain/loss amortization component and be recognized over a five-year period.

•

The Company’s previous method included an interest cost calculated on the recorded liability while under the service cost approach interest is calculated on the total accumulated benefit obligation.

•

Under the previous method, special actuarial gains or losses resulting from new experience studies were amortized on an accelerated basis (over 5 years). Under the service cost method, no such distinction exists. All gains and losses are amortized over the same period.

Both methods use the same assumptions with respect to discount rate, inflation, and benefit cost trend.

The restatement (change in black lung expense net of realized gains on reclassified trust assets) changed net income in each year presented as follows: decrease of $0.3 million in fiscal 2000, and an increase of $1.4 million in fiscal 2001. The restatement of black lung expense and the related liability had no net impact on the Shareholders’ Equity at October 31, 2001 as adjustments to income and expense amounts offset. Balance sheet changes as of October 31, 2001 related to the restatement were an increase in Other Non-Current Liabilities of $2.4 million, and an increase in Prepaid Expenses and Other Current Assets of $2.4 million. The restatement reduced pre-tax income in each quarter of 2002 by $0.4 million and increased pre-tax income by $0.7 million, $0.7 million, $0.7 million, and $0.3 million in the three-months ended January 31, 2001, April 30, 2001, July 31, 2001 and October 31, 2001, respectively. The adjustment was not material for the two-month transition period ended December 31, 2001.

The Company has also reclassified all periods presented to present Freight and Handling Revenue and Costs and Purchased Coal Revenue and Costs on a gross rather than net basis. Previously, these items were presented “net” in other income. The net amount included in other income was $2.5 million in 2001 and $0.7 million in 2000. These changes have been made to conform to the requirements of Emerging Issues Task Force (EITF) Issue No. 00-10 “Accounting for Shipping and Handling Fees and Costs” and EITF Issue No. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent”.

Set forth below is a comparison of the previously reported and restated consolidated net income and per share amounts for the two-month transition period ended December 31, 2001 and the years ended October 31, 2001 and 2000.

	Two months ended December 31, 2001						October 31, 2001						October 31, 2000
	(In thousands except per share amounts)
	As Reported			As Restated			As Reported			As Restated			As Reported		As Restated
Net (loss) earnings	$	(22,391	)	$	(14,801	)	$	(1,050	)	$	(5,420	)	$	78,804	$	78,531
(Loss) Earnings per share
Basic	$	(0.30	)	$	(0.20	)	$	(0.01	)	$	(0.07	)	$	1.07	$	1.07
Diluted		(0.30	)		(0.20	)		(0.01	)		(0.07	)		1.07		1.07
Shares used to calculate (loss) earnings per share
Basic		74,131			74,131			73,858			73,858			73,469		73,469
Diluted		74,131			74,131			73,858			73,858			73,472		73,472

On January 30, 2003, the Company issued a press release reporting its operating results for the year ended December 31, 2002. That press release was filed with the SEC on Form 8-K on February 5, 2003. Subsequent to the filing of the 8-K and prior to the issuance of its 2002 financial statements the Company recorded adjustments to its 2002 results primarily to reflect the change in accounting for black lung discussed above, and a reduction in bad debt reserves as discussed above. In addition, total revenues increased $0.3 million primarily due to a customer billing adjustment.

Set forth below is a comparison of the Company’s consolidated net income and per share amounts for the year ended December 31, 2002, as reported in the Company’s press release filed on Form 8-K on February 5, 2003, and as reflected in the Company’s consolidated financial statements as of and for the year ended December 31, 2002, included herein.

	Year ended December 31, 2002
	(A)			(B)
Net loss	$	(30,019	)	$	(32,574	)
Loss per share
Basic	$	(0.40	)	$	(0.44	)
Diluted		(0.40	)		(0.44	)
Shares used to calculate loss per share
Basic		74,442			74,442
Diluted		74,442			74,442

(A)

As reported in the Company’s press release.

(B)

As reflected in the Company’s consolidated financial statements for the year ended December 31, 2002.

A comparison of the previously reported and restated consolidated net income and per share amounts for the quarterly periods for fiscal year ended December 31, 2002 and October 31, 2001, and the two-month transition period ended December 31, 2001, may be found in Note 17, “Quarterly Information”.

3. Significant Accounting Policies

Use of Estimates

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.

Cash and Cash Equivalents

Securities with maturities of 90 days or less at the date of purchase are classified as cash equivalents.

Inventories

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.

Inventories consisted of the following:

	At December 31, 2002		At October 31, 2001
	(in thousands)
Saleable coal	$	69,823	$	46,872
Raw coal		47,898		45,254
Work in process		52,817		25,789

Subtotal coal inventory	$	170,538	$	117,915
Supplies inventories		23,131		23,568

Total inventory	$	193,669	$	141,483

Saleable coal includes coal ready for sale. This category includes inventories located at customer facilities under consignment arrangements. Raw coal represents coal that may be further processed prior to shipment to customer or may be sold in current condition. Work in process consists of the costs incurred to remove overburden above an unmined coal seam as part of the surface mining process.

Income Taxes

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

Other Current Assets

Other current assets are comprised of the following:

	December 31,		October 31,
	2002		2001
			(Restated)
	(In thousands)
Longwall panel costs	$	39,155	$	51,971
Deposits		42,319		4,079
Other		35,852		39,984

Total other current assets	$	117,326	$	96,034

Longwall panel costs consist of deferred 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 eight to twelve months.

Deposits consist of funds placed in restricted accounts with financial institutions to collateralize letters of credit that support workers’ compensation requirements and other insurance obligations, as well as collateral required from customers as credit enhancement, with a corresponding liability recorded within Other current liabilities.

Property, Plant and Equipment

Property, plant and equipment is carried at cost and comprises:

	December 31, 2002			October 31, 2001
	(In thousands)
Land, buildings and equipment	$	1,692,587		$	1,652,017
Mining properties and mineral rights		602,303			596,280
Mine development		522,255			466,777

Total property, plant and equipment		2,817,145			2,715,074
Less accumulated depreciation, depletion and amortization		(1,282,657	)		(1,101,941	)

Net property, plant and equipment	$	1,534,488		$	1,613,133

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.

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.

Depletion of mining properties and mineral rights and amortization of mine development costs are computed using the units-of-production method over the estimated recoverable tons. As of December 31, 2002, approximately $53.0 million of costs associated with mining properties and mineral rights is not currently subject to amortization as mining has not begun or production has been temporarily idled on the associated coal reserves.

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.

Internal Use Software

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

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 5 for a description of impairment charges that were recorded in the consolidated statement of earnings.

Advance Mining Royalties

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, 2002 and October 31, 2001, advance mining royalties included in other noncurrent assets totaled $29.5 and $29.8 million, respectively.

Reclamation

The Federal Surface Mining Control and Reclamation Act establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Estimates of the Company’s total reclamation and mine-closing liabilities are based upon permit requirements and the Company’s engineering expertise related to these requirements. For each permit, the Company accrues for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge as coal is mined, on a unit-of-production basis over the proven and probable reserves as defined in Industry Guide 7. The Company’s reclamation costs estimates are regularly reviewed by the Company’s management and engineers and are revised for changes in future estimated costs and regulatory requirements. 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. As indicated in Accounting Pronouncements within this Note, SFAS No. 143, effective for the Company on January 1, 2003, will change the Company’s method of accounting for reclamation liabilities.

Shareholders’ Equity

The Statement of Shareholders’ Equity for periods prior to the Spin-Off (see Note 13) reflects the outstanding shares of Massey Energy Company 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.

Revenue Recognition

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 3.3 million tons for the year ended December 31, 2002 and 1.3 million tons for the years ended October 31, 2001 and 2000.

Other revenue generally consists of royalties, rentals, contract buyout payments, coal handling services, miscellaneous income and gains on the sale of non-strategic assets. For the years ended October 31, 2001 and

2000, the Company recorded gains on the sale of non-strategic reserves of $1.1 million, and $26.5 million, respectively. The gains and losses on reserve sales for the year ended December 31, 2002 were not material. Contract buyout payments were $23.5 million, including $5.1 million from one large customer, for the year ended December 31, 2002, and were not material for the years ended October 31, 2001 and 2000.

Earnings per Share

Shares used to calculate basic earnings per share for the period ended October 31, 2000 are the number of shares outstanding immediately following the Spin-Off (see Note 13). The calculation of historical earnings per share for the periods reported prior to the Spin-Off does not use a pro rata portion of the shares previously reported by Fluor Corporation prior to the Spin-Off. We have assumed no relation to Fluor’s previously existing capital structure in calculating earnings per share for these periods. This is considered preferable as the operations that comprise Massey Energy had no separate capital structure prior to the Spin-Off and New Fluor was treated for reporting purposes as the accounting successor to Fluor (see Note 13). A pro rata portion of Fluor’s historic shares would not have been a good representation of Massey Energy’s capital structure as Fluor had share transactions that were unrelated to the operations that became Massey Energy. The most significant such share transaction was the maturity and settlement by Fluor of a forward purchase contract on November 30, 2000 for 1,850,000 shares of Fluor Corporation common stock.

The number of shares used to calculate basic loss per share for periods subsequent to the Spin Off is based on the weighted number of average outstanding shares of Massey Energy during the period. Shares used to calculate diluted earnings per share for the period ended October 31, 2000 is based on the number of shares outstanding immediately following the Spin-Off and the dilutive effect of stock options and other stock-based instruments of Fluor Corporation, held by Massey employees, that were converted to equivalent instruments in Massey Energy Company in connection with the Spin-Off. In accordance with accounting principles generally accepted in the United States, the effect of dilutive securities was excluded from the calculation of the diluted loss per common share for the periods subsequent to the Spin Off as such inclusion would result in antidilution.

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

	Year Ended			Two months Ended
	December 31, 2002	October 31, 2001	October 31, 2000	December 31, 2001	December 31, 2000
	(In thousands)				(Unaudited)
Weighted number of average shares of common stock outstanding:
Basic	74,442	73,858	73,469	74,131	74,098
Effect of stock options/restricted stock	—	—	3	—	—

Diluted	74,442	73,858	73,472	74,131	74,098

Stock Plans

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. The Company has implemented the disclosure-only provisions of Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (SFAS No. 123). The Company has recognized no stock-based compensation expense related to stock options in the years ended October 31, 2000, October 31, 2001, December 31, 2002 and the two months ended December 31, 2001, as all options granted had an exercise price

equal to market value of the underlying common stock on the date of the grant. See Note 14 for additional information. If the Company had followed the fair value method under SFAS 123 to account for stock based compensation 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:

	Year ended									Two Months Ended December 31, 2001
	December 31, 2002			October 31, 2001			October 31, 2000			Two Months Ended December 31, 2001
				(Restated)			(Restated)			(Restated)
	(in thousands, except per share amounts)
Net (loss) income, as reported	$	(32,574	)	$	(5,420	)	$	78,531		$	(14,801	)
Deduct: Total stock-based employee compensation expense for stock options determined under Black-Scholes option pricing model	$	(2,135	)	$	(1,375	)	$	(1,600	)	$	(361	)

Pro forma net (loss) income	$	(34,709	)	$	(6,795	)	$	76,931		$	(15,162	)

Earnings (loss) per share:
Basic—as reported	$	(0.44	)	$	(0.07	)	$	1.07		$	(0.20	)

Basic—pro forma	$	(0.47	)	$	(0.09	)	$	1.05		$	(0.20	)

Diluted—as reported	$	(0.44	)	$	(0.07	)	$	1.07		$	(0.20	)

Diluted—pro forma	$	(0.47	)	$	(0.09	)	$	1.05		$	(0.20	)

Derivatives

Effective November 1, 2000, the Company adopted Statement of Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Hedging Activities.” The Statements require that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The adoption of these accounting standards and subsequent implementation guidance did not have a significant impact on the Company’s financial position, results of operations, or liquidity.

Accounting Pronouncements

Effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The provisions of this statement provide for a single accounting model for measuring impairment of long-lived assets. The adoption of SFAS No. 144 did not have a material effect on the Company’s financial condition or results of operations.

In April 2002, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” which is effective for fiscal years beginning after May 2002. The standard requires that gains or losses on debt extinguishment, previously reported as extraordinary items, be presented as a component of results from continuing operations unless the extinguishment meets the criteria for classification as an extraordinary item in Accounting Principles Board Opinion No. 30. During the fourth quarter of 2002, the Company purchased in open market transactions, an aggregate of $14.0 million of its 6.95 percent Senior Notes at an aggregate purchase price of $10.7 million. The Company has chosen early adoption of SFAS No. 145, and accordingly, recorded a gain of $3.3 million on the transactions in Senior notes repurchase income, a component of Total revenue.

On August 15, 2001, FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The standard requires the fair value of a liability for an asset retirement obligation to be recognized in the period in

which it is incurred. 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. 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. This statement is effective for the Company beginning January 1, 2003, and transition is by cumulative catch-up adjustment. The adoption changes the Company’s current accounting for reclamation. The Company is continuing to calculate its transition adjustment.

In November 2002, the FASB issued FASB Interpretation No. 45, Guarantors’ Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”). This Interpretation describes the disclosure requirements of a guarantor’s issuance of certain guarantees, and clarifies that a guarantor is required to recognize a liability, at the date of issuance, for the fair value of the obligation assumed in issuing the guarantee. The disclosure requirements of FIN 45 are effective for the Company for the year ended December 31, 2002, and the initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. This Interpretation is not expected to have a material effect on the Company’s financial position, results of operations, or liquidity.

4. Concentrations of Credit Risk and Major Customers

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 60%, 54%, and 50% of produced coal revenue for the years ended December 31, 2002, and October 31, 2001, and 2000, respectively. Metallurgical coal sales accounted for approximately 30%, 34%, and 40% of produced coal revenue for the years ended December 31, 2002, and October 31, 2001, and 2000, respectively. Industrial coal sales for the years ended December 31, 2002, and October 31, 2001, and 2000 were 10%, 12%, and 10% of produced coal revenue, respectively.

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

For the year ended December 31, 2002, approximately 11% and 12% of produced coal revenue was attributable to two utility customers, Duke Energy Corporation and its affiliate, Duke Energy Merchants, LLC, and affiliates of DTE Energy Company, respectively. For the years ended October 31, 2001 and 2000, approximately 11%, and 14%, respectively, of produced coal revenue was attributable to Duke Energy Corporation and its affiliate, Duke Energy Merchants, LLC. At December 31, 2002, approximately 20%, 59% and 21% of consolidated trade receivables represent amounts due from metallurgical customers, utility customers and industrial customers, respectively, compared with 25%, 63% and 12%, respectively, as of October 31, 2001. 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 consider specifically 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.

5. Impairment of Long-Lived Assets

The following impairment charges were recorded in the consolidated statement of earnings:

During the third quarter of 2002, the Company recorded a charge 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.

During the third quarter of 2002, the Pegs Branch mine of the Sidney resource group was closed. Based on operating conditions experienced in the Pegs Branch mine a decision was made to forego mining the final section of reserves. The mining equipment was moved to another mine location with more favorable coal reserve conditions. Unamortized development costs of approximately $1.7 million were written off during the third quarter of 2002 as a result of the Pegs Branch mine closure.

The Spring Branch mine of the Stirrat resource group temporarily ceased mining in January of 2001 due in part to a lack of experienced mine personnel. As part of the budget process for 2003, the mine, its coal reserves and its mining conditions were reassessed for future operating potential. Management made the decision to permanently abandon this mine during the third quarter of 2002. Unamortized development costs of approximately $2.3 million were written off in the third quarter as a result of the Spring Branch mine closure.

The Ruby Energy mine of the Delbarton resource group temporarily ceased operations in February of 2002 in reaction to market demand for steam coal by utilities. During the third quarter of 2002, as part of the 2003 budget process, Company management decided that a section of the mine that crossed under a creek would not be utilized in future mining plans. Unamortized development costs related to this section of the mine of approximately $9.2 million were written off in the third quarter related to the Ruby Energy mine closure. Other areas of the mine are expected to be mined in accordance with the mine plans as approved by management.

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.

During the fourth quarter of 2000, due to significant rock falls and continual poor and unsafe mining conditions at the Upper Cedar Grove mine of the Independence resource group, the Company abandoned certain longwall mining equipment and wrote off related longwall panel development costs. This write-off of approximately $9 million is included in cost of produced coal revenue for the year ended October 31, 2000.

6. Appalachian Synfuel, LLC

Appalachian Synfuel, LLC (the “LLC”) was formed in 1997 as a wholly owned subsidiary of Fluor Corporation 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 traunches, 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 will be paid in quarterly installments of $1.9 million including interest, and a contingent promissory note that is paid on a cents per Section 29 credit dollar earned based on synfuel tonnage shipped. Deferred gains of $23.8 million and $11.9 million as of December 31, 2002 and October 31, 2001, respectively, are included in other noncurrent liabilities to be recognized ratably though 2007. Massey’s subsidiary, Marfork Coal Company, Inc., will continue to manage the facility under an operating agreement.

7. Income Taxes

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

	Year Ended								Two Months Ended
	December 31, 2002			October 31, 2001			October 31, 2000		December 31, 2001			December 31, 2000
				(Restated)			(Restated)		(Restated)			(Restated)
												(Unaudited)
	(In thousands)
Current:
Federal	$	(24,694	)	$	(6,389	)	$	13,735	$	—		$	—
State and local		(3,763	)		148			1,447		25			—

Total current		(28,457	)		(6,241	)		15,182		25			—
Deferred:
Federal		1,050			(3,639	)		24,562		(8,707	)		(3,855	)
State and local		2,461			(621	)		3,491		(41	)		(441	)

Total deferred		3,511			(4,260	)		28,053		(8,748	)		(4,296	)

Total income tax (benefit) expense	$	(24,946	)	$	(10,501	)	$	43,235	$	(8,723	)	$	(4,296	)

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:

	Year Ended									Two Months Ended
	December 31, 2002			October 31, 2001			October 31, 2000			December 31, 2001			December 31, 2000
				(Restated)			(Restated)			(Restated)			(Restated)
													(Unaudited)
	(In thousands)
U.S. statutory federal tax expense	$	(20,132	)	$	(5,572	)	$	42,618		$	(8,233	)	$	(3,855	)
Increase (Decrease) resulting from:
State taxes		(4,558	)		(170	)		3,781			(25	)		(441	)
Items without tax effect		1,526			700			5,235			86			—
Depletion		(7,350	)		(4,496	)		(7,657	)		(551	)		—
FSC exempt income		(1,050	)		(963	)		(952	)		—			—
Other, net		6,618			—			210			—			—

Total income tax (benefit) expense	$	(24,946	)	$	(10,501	)	$	43,235		$	(8,723	)	$	(4,296	)

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:

	December 31, 2002			October 31, 2001
				(Restated)
	(In thousands)
Deferred tax assets:
Postretirement benefit obligations	$	28,608		$	28,428
Worker’s compensation		14,648			15,975
Reclamation and mine closure		41,167			32,416
Alternative minimum tax credit carryforwards		80,948			59,549
State NOL		14,204			6,959
Other		42,791			28,287

		222,366			171,614
Valuation allowance for deferred tax assets		(85,889	)		(66,508	)

Deferred tax assets, net		136,477			105,106

Deferred tax liabilities:
Plant, equipment and mine development		(231,782	)		(187,136	)
Mining property and mineral rights		(107,648	)		(110,748	)
Other		(27,834	)		(44,094	)

Total deferred tax liabilities		(367,264	)		(341,978	)

Net deferred tax liabilities	$	(230,787	)	$	(236,872	)

The Company’s deferred tax assets include alternative minimum tax (“AMT”) credits of $80.9 and $59.5 million each at December 31, 2002 and October 31, 2001. The AMT credits have no expiration date. Subsequent to the Spin-Off, the Company completed an assessment of its deferred tax balances and the likelihood of realizing AMT credit carryforwards as a stand-alone company. Management determined, more likely than not, that these credits will not be realized. State net operating loss carryforwards begin to expire in 2016.

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. 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 lowered in the years ending December 31, 2002, and October 31, 2001, by $4.1 million and $0.6 million, respectively, reflecting the reduction in exposure due to the lapsing of the statutory periods for assessing tax on tax periods ending in 1998 and 1997, partially offset by additional exposures identified for tax years that remained open. The tax reserve was increased in the fiscal year ending October 31, 2000 by $0.7 million for increased state and federal tax exposure in open years, partially offset by the lapsing of the statutory period for assessing tax on the tax period ending in 1996. In addition, payments were applied against the reserve for federal taxes and state taxes $1,045,000, $172,000, and $821,000 as a result of audits conducted during the years ended October 31, 2000 and 2001, and December 31, 2002, respectively.

Massey’s federal income tax returns have been examined by the Internal Revenue Service, or Statutes of Limitations have expired through 1998. 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.

8. Debt

The Company’s short-term debt at December 31, 2002, consists of $264.0 million of borrowings outstanding under its credit facilities. The weighted average effective interest rate of the outstanding borrowings was 3.92 percent at December 31, 2002 and 3.03 percent at October 31, 2001. In early May 2002, Moody’s and S&P downgraded the Company’s credit ratings. These ratings actions effectively prevented the Company from accessing the commercial paper market due to the restrictive investment policy credit guidelines of potential commercial paper investors and caused the Company to draw on the credit facilities for short-term financing needs. The Company had no commercial paper obligations outstanding at December 31, 2002, and $240.4 million at October 31, 2001. At October 31, 2001, the Company also had outstanding a note payable in the amount of $7.8 million, which was due and paid on November 1, 2001. At December 31, 2002, the Company’s available liquidity was $134.5 million, including cash and cash equivalents of $2.7 million and $131.8 million remaining on the Company’s revolving credit facilities.

On November 26, 2002, Massey and its lenders concluded the extension and amendment of the $150 million 364-day and $250 million multi-year revolving credit facilities, which have been guaranteed by A.T. Massey, that serve as the primary source of the Company’s short-term liquidity. The credit facilities now provide the lenders with selected assets as collateral for borrowings under the facilities. The selected assets that are collateral for the credit facilities include all capital stock of the Company’s subsidiaries and substantially all of the Company’s assets, now owned or at any time hereafter acquired by the Company, excluding among other things, all coal, oil and gas reserves and mining permits, certain properties (e.g., the Eastman Chemical Company Coal Handling System and Westvaco Coal Handling Facility, and the value of properties that might exceed the lien threshold established in the indenture related to the Senior Notes (discussed below)) and certain other assets associated with the Company’s accounts receivable securitization program discussed below. Both facilities have been renewed through November 25, 2003. The Company intends to replace these credit facilities prior to their expiration on November 25, 2003. Borrowings under these facilities bear interest based on (i) the London Interbank Offer Rate (LIBOR) or (ii) the Base Rate (as defined in the facility agreements) plus a margin, which is based on the Company’s senior secured debt credit rating as determined by Moody’s and Standard & Poor’s. At December 31, 2002, and currently, Massey’s senior secured debt ratings are Ba1 and BB+, respectively.

In determining EBITDA as defined in the credit facility agreements for use in computing the leverage ratio, the Company has excluded certain items, including the $25.6 million charge relative to the Harman litigation described in Note 16. The Company believes that the exclusion of such items is appropriate and has notified the lenders’ Administrative Agent of this exclusion. If the accrual for the Harman litigation were to be included in the EBITDA calculation and no further adjustments were made, the Company would still be in compliance with the covenant at December 31, 2002.

The Company had $286.0 million of long-term debt as of December 31, 2002, which consisted entirely of 6.95 percent Senior Notes (the “Notes”) due March 1, 2007. Initially, $300 million of the Notes were issued in March 1997 at a discount, for aggregate proceeds of $296.7 million. During the fourth quarter of 2002, the Company made several open-market purchases, retiring a total principal amount of $14.0 million of the Notes at a cost of $10.7 million plus accrued interest. A gain of $3.3 million was recognized in the fourth quarter of 2002 and is shown in the Consolidated Financial Statements of Income in Senior notes repurchase income. Interest is payable semiannually on March 1 and September 1 of each year, commencing September 1, 1997. The 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. On November 27, 2002, Moody’s and S&P reduced the credit ratings on the Senior Notes to Ba3 and B+, respectively, citing the structural subordination caused by the secured status of the amended bank credit facilities.

Additionally, the Company has available a $500 million debt shelf registration filed with the Securities and Exchange Commission (the “SEC”) in March 1999, all of which remains unused. Prior to the Spin-Off, Fluor Corporation filed this debt shelf registration. An updated filing with the SEC would be required to issue debt under this shelf registration.

Total interest paid for the year ended December 31, 2002 and October 31, 2001, was $35.4 million and $34.8 million, respectively, and was not material for the year ended October 31, 2000.

Off-Balance sheet arrangements

9. Fair Value of Financial Instruments

Certain Company subsidiaries prior to 2002 provided loans to West Virginia businesses at prevailing interest rates as part of an economic development program that provides tax credits as incentives. Outstanding loans at December 31, 2002 and October 31, 2001 amounted to $4.8 million and $10.5 million, respectively, of which $1.9 million and $2.4 million, respectively, are unsecured. These loans are estimated to be at fair value, after recording an allowance for loan losses of $1.4 million at December 31, 2002 and $2.1 million at October 31,

2001, based on future cash flows and related credit risk. The current portion of these notes is included in trade and other accounts receivable. The noncurrent portion is included in other noncurrent assets.

Prior to the Spin-Off (see Note 13), the Company loaned funds in excess of its operating and capital needs to Fluor and received interest on the average daily balance at 130% of the federal short-term rate determined in accordance with the Internal Revenue Code of 1986. Fluor repaid these loans to the Company as the need arose. The Company believed these financial practices to be a fair arrangement with its prior parent and concluded that any further assessment to determine fair market value of amounts due from Fluor would not be cost beneficial. Interest income for 2001 and 2000 related to these loans amounted to $1.5 million and $16.6 million, respectively. These loans were classified as a reduction to shareholders’ equity prior to the Spin-Off and were settled as part of the Spin-Off transaction.

In addition, the Company had outstanding $264.0 million and $248.2 million of short-term debt at December 31, 2002 and October 31, 2001, respectively (see Note 8). The carrying amount of this debt approximates its fair value.

The Company’s long-term debt consists entirely of 6.95 percent Senior Notes due March 1, 2007 (see Note 8). The fair value of the Senior Notes at December 31, 2002, based on currently available market information, was $270.9 million. The Senior Notes are not traded frequently and there were no trades reported as a benchmark.

10. Pension Plans

Defined Benefit Pension

Prior to October 1, 2001, Massey sponsored two non-contributory defined benefit pension plans which covered substantially all administrative and non-union employees hired prior to September 1, 1994. As of October 1, 2001, these plans were merged together with each participant group retaining its benefit formula. These formulas provide pension benefits based on the employee’s years of service and average annual compensation during the highest five consecutive years of service. In addition, the new merged plan covers substantially all administrative and non-union employees of the Company who were previously covered under a non-contributory defined contributory pension plan. These participants will accrue benefits under a cash balance formula with contribution credits based on hours worked. Funding for the plan is generally at the minimum annual contribution level required by applicable regulations.

The plan assets are held by an independent trustee and, in certain circumstances, by insurance carriers. The plans assets include cash and cash equivalents, corporate and government bonds, preferred and common stocks, investments in mutual funds and annuity contracts. The fair market value of the plans assets was $174 million at December 31, 2002.

Net periodic pension expense (income) for the defined benefit pension plan includes the following components:

	Year Ended						Two Months Ended
	December 31, 2002			October 31, 2001			October 31, 2000			December 31, 2001
	(In thousands)
Service cost	$	10,649		$	2,657		$	2,509		$	1,769
Interest cost		10,256			9,498			9,114			1,693
Expected return on plan assets		(18,069	)		(22,245	)		(20,732	)		(2,886	)
Amortization of unrecognized net liability/(asset)		—			(1,800	)		(2,116	)		74
Amortization of prior service cost		133			57			56			10

Net periodic pension expense/(income)	$	2,969		$	(11,833	)	$	(11,169	)	$	660

The weighted average assumptions used in determining pension benefit obligations are as follows:

	December 31, 2002		October 31, 2001		December 31, 2001
Discount rates	6.75	%	7.25	%	7.25	%
Rates of increase in compensation levels	4.00	%	4.00	%	4.00	%
Expected long-term rate of return on plan assets used in determining expense in each of the periods	9.00	%	9.50	%	9.00	%

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

	Year Ended December 31, 2002			Year Ended October 31, 2001			Two Months Ended December 31, 2001
	(In thousands)
Change in benefit obligation
Benefit obligation at the beginning of the period	$	147,724		$	126,687		$	140,194
Service cost		10,649			2,657			1,769
Interest cost		10,256			9,498			1,693
Actuarial loss		6,103			7,626			5,120
Plan amendment		859			—			—
Benefits paid		(6,880	)		(6,274	)		(1,052	)

Benefit obligation at end of period	$	168,711		$	140,194		$	147,724

Change in plan assets
Fair value at the beginning of the period	$	204,473		$	237,551		$	196,131
Actual (loss) return on assets		(23,626	)		(35,156	)		9,390
Company contributions		29			10			4
Benefits paid		(6,880	)		(6,274	)		(1,052	)

Fair value at end of period	$	173,996		$	196,131		$	204,473

Funded status	$	5,285		$	55,937		$	56,749
Unrecognized net actuarial loss		67,153			20,743			19,423
Unrecognized prior service cost		1,187			461			451

Pension assets		73,625			77,141			76,623
Amount included in current liabilities		3,731			3,259			3,124

Noncurrent asset	$	77,356		$	80,400		$	79,747

Multi-Employer Pension

Under labor contracts with the United Mine Workers of America, 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, 2002, October 31, 2001 and October 31, 2000. Payments into the two multi-employer plan trusts were less than $0.1 million during the two months ended December 31, 2001.

Defined Contribution and Salary Deferral Pension

Certain union employees are covered by a non-contributory defined contribution pension plan. Contributions to the defined contribution retirement plan are based on hours worked.

Prior to October 1, 2001, the Company sponsored a separate non-contributory defined contribution pension plan for substantially all administrative and non-union employees. On September 30, 2001, the plan was frozen and assets were merged into an existing salary deferral and profit sharing plan. Employees covered under the frozen plan now participate in the defined benefit pension plan under the cash balance formula discussed in the first paragraph of this Note.

For certain eligible employees, the Company sponsors a contributory defined contribution pension plan with Company contributions based on hours worked. Effective October 1, 2001, the maximum salary deferral rate was increased from 10% to 15% of eligible compensation and the Company matches 30% on the first 10% of employee deferrals. The Company may make additional discretionary contributions to the plan.

For the years ended December 31, 2002 and October 31, 2001 and 2000, Company contributions to these three plans aggregated approximately $0.2 million, $7.5 million, and $5.6 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. Effective October 1, 2001, the maximum salary deferral rate was increased from 10% to 15% of eligible compensation and the Company matches 30% on the first 10% of employee deferrals. The Company may make additional discretionary contributions to the plan. Total Company contributions aggregated approximately $4.6 million, $2.5 million, and $2.2 million for the years ended December 31, 2002, October 31, 2001 and October 31, 2000, respectively, and approximately $0.6 million for the two-month period ended December 31, 2001.

11. Other Noncurrent Liabilities

Other noncurrent liabilities comprise the following:

	December 31, 2002		October 31, 2001
			(Restated)
	(In thousands)
Reclamation	$	104,895	$	107,448
Other post-employment benefits (Note 11)		79,578		72,061
Workers’ compensation and black lung		78,322		75,810
Other		66,486		62,477

Total other noncurrent liabilities	$	329,281	$	317,796

Reclamation

The Company accrues for the costs of current mine disturbance and final mine closure, as coal is 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, October 31, 2001 and 2000, and the two-months ended December 31, 2001, the Company accrued approximately $9.8 million, $6.4 million, $6.5 million and $1.6 million, respectively, towards final mine closure reclamation, excluding re-costing adjustments identified below. The Company regularly reviews its estimated and accrued liabilities on a permit-by-permit basis and makes necessary adjustments, including permit changes and revisions to costs and productivities to reflect current experience. When changes in cost estimates or regulatory requirements cause the Company’s accrued liability for a permit to exceed its total estimated reclamation liability, the difference is credited to income. These “re-costing” adjustments are recorded as a decrease in cost of produced coal revenue and totaled $1.7 million, $6.6 million, $7.2 million and $0.2 million for the years ended December 31, 2002, October 31, 2001 and 2000, and the two-months ended December 31, 2001, respectively. The Company’s management believes it is making adequate provision for all expected future reclamation costs. Final reclamation costs for all operations as of December 31, 2002 are

estimated to be approximately $163 million. As indicated in Note 3, SFAS No. 143, effective for the Company on January 1, 2003, will change the Company’s method of accounting for reclamation liabilities.

Workers’ Compensation and Black Lung

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). In addition, the Company is liable for workers’ compensation benefits for traumatic injuries under the workers’ compensation laws in the states in which it has operations.

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 terminated employees either receiving or are projected to receive benefits, and the portion of the projected liability relative to prior service for active employees who are projected to receive benefits. An annual actuarial study is 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 uses a combination of three methods for coverage of traumatic injury liability pursuant to workers’ compensation laws including self-insurance programs, insurance coverage of claims, and participation in state workers’ compensation fund. The Company accrues for traumatic injury claims as incurred under its self-insurance program. Additionally, for self-insured claims, a provision for incurred but not reported claims is recorded.

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. If the remaining service period of active participants were less than five years, the amortization period would be reduced to the remaining service period.

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

	December 31, 2002			October 31, 2001			Year Ended October 31, 2000			Two Months Ended December 31, 2001
				(Restated)			(Restated)			(Restated)
	(In thousands)
Self-insured black lung benefits
Service cost	$	3,461		$	1,792		$	1,558		$	598
Interest cost		3,478			3,054			3,418			626
Amortization of actuarial gain		(2,068	)		(4,080	)		(3,174	)		(192	)

	$	4,871		$	766		$	1,802		$	1,032
Other workers’ compensation benefits		31,727			27,106			16,383			4,308

	$	36,598		$	27,872		$	18,185		$	5,340

The actuarial assumptions used in the determination of black lung benefits included a discount rate of 6.75% as of December 31, 2002, (7.25% as of October 31, 2001 and December 31, 2001, and 7.75% as of October 31, 2000) and a black lung benefit cost escalation rate of 3% in each year. Payments for benefits, premiums and

other costs related to workers’ compensation and black lung liabilities were $30.0 million, $25.0 million, and $20.8 million in 2002, 2001, and 2000, respectively, and $2.6 million in the two months ended December 31, 2001.

Workers’ compensation and black lung consisted of the following:

	At December 31, 2002		At October 31, 2001
			(Restated)
	(In thousands)
Accrued self-insured black lung obligation	$	62,886	$	59,578
Workers’ compensation (traumatic injury)		37,432		31,535

Total accrued workers’ compensation and black lung	$	100,318	$	91,113
Less amount included in other current liabilities		21,996		15,303

Workers’ compensation & black lung in other noncurrent liabilities	$	78,322	$	75,810

The reconciliation of changes in the benefit obligation of the black lung obligation is as follows:

	At December 31, 2002			At October 31, 2001			At December 31, 2001
				(Restated)			(Restated)
	(In thousands)
Beginning of year accumulated black lung obligation	$	49,238		$	40,414		$	48,502
Service cost		3,461			1,792			598
Interest cost		3,478			3,054			626
Actuarial loss (gain)		2,749			5,768			—
Benefit payments		(2,107	)		(2,526	)		(488	)

End of year accumulated black lung obligation	$	56,819		$	48,502		$	49,238
Unamortized net gain		6,067			11,076			10,884

Accrued self-insured black lung obligation	$	62,886		$	59,578		$	60,122

12. Post-Employment Benefits

The Company also sponsors defined benefit health care plans that provide post-retirement 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. Service costs are accrued currently. The postretirement benefit obligation at December 31, 2002 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 rates of 11.0% ranging down to 5.0% in 2009 (8.0% ranging down to 5.0% in 2007 at October 31, 2001) 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:

	1-Percentage		1-Percentage
	Point Increase		Point Decrease
	(In thousands)
Effect on total of service and interest costs components	$	1,887	$	(1,534	)
Effect on accumulated postretirement benefit obligation	$	18,976	$	(15,570	)

Net periodic postretirement benefit cost includes the following components:

	Year Ended						Two Months Ended December 31, 2001
	December 31, 2002		October 31, 2001		October 31, 2000		Two Months Ended December 31, 2001
	(In thousands)
Service cost	$	4,636	$	3,426	$	3,543	$	749
Interest cost		6,062		5,333		4,611		1,064
Recognized loss		—		—		—		45
Amortization of prior service cost		140		140		140		23

Net periodic postretirement benefit cost	$	10,838	$	8,899	$	8,294	$	1,881

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

	Year Ended December 31, 2002			Year Ended October 31, 2001			Two Months Ended December 31, 2001
	(In thousands)
Change in benefit obligation
Benefit obligation at the beginning of the period	$	90,780		$	66,355		$	89,566
Service cost		4,616			3,426			749
Interest cost		6,062			5,333			1,064
Actuarial loss		23,483			16,857			—
Benefits paid		(3,830	)		(2,405	)		(599	)

Benefit obligation at end of period	$	121,111		$	89,566		$	90,780

Funded status	$	(121,111	)	$	(89,566	)	$	(90,780	)
Unrecognized net actuarial loss		36,382			12,965			12,920
Unrecognized prior service cost		1,333			1,496			1,473

Accrued postretirement benefit obligation		(83,396	)		(75,105	)		(76,387	)
Amount included in current liabilities		3,818			3,044			3,044

Noncurrent liability	$	(79,578	)	$	(72,061	)	$	(73,343	)

The discount rate used in determining the postretirement benefit obligation was 6.75 percent at December 31, 2002 and 7.25 percent at October 31, 2001 and at December 31, 2001.

Multi-Employer Benefits

Under the Coal Industry Retiree Health Benefits Act of 1992, 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 Benefit Funds. Based on available information at December 31, 2002, the Company’s obligation (discounted at 6.75%) under the Act is estimated at approximately $60.6 million. The Company’s obligation at October 31, 2001 was $52.3 million. The $8.3 million increase in obligation is primarily a result of a change in discount rate from 7.25% at October 31, 2001 to 6.75% at December 31, 2002, and an increase in per beneficiary premiums as determined by the funds. The Company treats its obligation under the Benefit 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, 2002 and October 31, 2001 and 2000, totaled $4.1 million, $5.0 million, and $3.6 million, respectively. For the two-month period ended December 31, 2001 the Company expensed $0.7 million related to this obligation.

13. Spin-Off Transaction

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 Securities and Exchange Commission.

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. As noted above, Massey assumed from Fluor $300 million of 6.95 percent Senior Notes, $278.5 million of Fluor commercial paper, other equity contributions from Fluor, and assumed Fluor’s common stock equity structure.

14. Equity Compensation Plans

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 “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 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, Fluor Corporation, A.T. Massey Coal Company, Inc. 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, 2002 the Company issued 519,873 non-qualified stock options with annual vesting of 25% and 163,400 non-qualified stock options that cliff vest after four years all of which expire in ten years. During the year ended October 31, 2001 the Company issued 875,961 non-qualified stock options with annual vesting of 25% and that expire in ten years. During the year ended October 31, 2000, prior to the Spin-Off, 290,080 options (in Fluor stock), were awarded to Massey employees. The 2000 awards cliff vest after four years and expire in ten years, with accelerated vesting provisions based on the price of Massey’s stock. The accelerated vesting provisions were achieved during the first quarter of 2001.

On November 1, 2001, 787,500 SARS were granted to Mr. Blankenship pursuant to the Amended and Restated Employment Agreement between Massey Energy Company, A.T. Massey Coal Company, Inc. 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 vested on October 31, 2002, while 225,000, 225,000 and 112,500 will vest on October 31, 2003, October 31, 2004, and April 30, 2005, respectively. These SARS expire in ten years. No grants of SARS were made to Massey employees during the fiscal years ended October 31, 2001 and 2000.

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 477,987 shares and 266,411 shares for the years ended December 31, 2002 and October 31, 2001, respectively. Prior to the Spin-Off, Fluor Corporation restricted stock issued to Massey employees totaled 31,390 shares for the year ended October 31, 2000 (117,618 shares when applying the Spin-Off conversion ratios at date of grant). 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 3 for further discussion.

As permitted by Statement of Financial Accounting Standards No. 123 “Accounting for Stock-Based Compensation” (“SFAS No. 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. For the years ended December 31, 2002, and October 31, 2001, and 2000, expenses related to Massey’s various stock compensation plans (with the exception of stock options) totaled $2.7 million, $5.8 million, and $3.8 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. Had the Company recorded compensation expense using the accounting method recommended by SFAS No. 123, net earnings and diluted earnings per share would have been reduced to the pro forma amounts as follows:

	Year ended								Two Months Ended December 31, 2001
	December 31, 2002			October 31, 2001			October 31, 2000		Two Months Ended December 31, 2001
				(Restated)			(Restated)		(Restated)
	(in thousands, except per share amounts)
Net (loss) earnings
As reported	$	(32,574	)	$	(5,420	)	$	78,531	$	(14,801	)
Pro forma	$	(34,709	)	$	(6,795	)	$	76,931	$	(15,162	)
Diluted net (loss) earnings per share
As reported	$	(0.44	)	$	(0.07	)	$	1.07	$	(0.20	)
Pro forma	$	(0.47	)	$	(0.09	)	$	1.05	$	(0.20	)

The estimated fair value as of the date of grant for options granted to Massey employees during the years ended December 31, 2002, and October 31, 2001 and 2000 was determined using the Black-Scholes option-pricing model based on the following weighted average assumptions (assumptions applied in 2000 were determined by Fluor):

	2002		2001		2000
Expected option lives (years)	5		5		6
Risk-free interest rates	3.08	%	4.29	%	6.03	%
Expected dividend yield	2.84	%	0.81	%	1.74	%
Expected volatility	49.4	%	37.1	%	39.8	%

The weighted average fair value of options granted by the Company during the years ended December 31, 2002 and October 31, 2001 using the Black-Scholes option-pricing model was $2.23 and $7.22, respectively. The weighted average fair value of options granted by Fluor to Massey employees during 2000 determined using the Black-Scholes option-pricing model was $18.00 (prior to conversion at the time of the Spin-Off).

The following table summarizes stock option activity:

	Weighted Average
	Stock Options		Exercise Price Per Share
Outstanding at October 31, 1999	441,746		$	47.51

Granted	290,080		$	44.31
Expired or Cancelled	(52,010	)	$	48.61
Exercised	(6,755	)	$	35.09

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

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

Characteristics of outstanding stock options at December 31, 2002 are as follows:

	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	679,473	9.8	$	5.78	—		—
$10.57 – 10.93	528,721	6.7	$	10.84	528,721	$	10.84
$12.50 – 13.03	156,285	4.9	$	12.79	142,464	$	12.76
$14.56 – 18.86	208,812	3.1	$	16.51	208,812	$	16.51
$19.42 – 20.11	741,224	8.7	$	19.78	195,766	$	19.78

$ 5.21 – 20.11	2,314,515	7.8	$	12.86	1,075,763	$	13.82

At December 31, 2002, there are 4,878,326 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 Committee under the Company’s various stock plans.

15. Future Minimum Obligations

Certain mining and other equipment is leased under operating leases. 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, 2002, and October 31, 2001 and 2000, was $53.4 million, $54.3 million and $28.4 million, respectively, and $8.5 million for the two-month period ended December 31, 2001.

In December 2002, the Company entered into a sale-leaseback transaction involving certain mining equipment. The Company received proceeds of $17 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 operating leases with initial terms greater than one year, in effect at December 31, 2002:

Year	Minimum Rentals
	(In thousands)
2003	$	61,486
2004		55,671
2005		51,135
2006		32,947
2007		8,040
Thereafter		3,063

	$	212,342

16. Contingencies and Commitments

Force Majeure Litigation

Massey’s operations experienced various events of force majeure in 2000 and 2001, including:

The impoundment failure at Martin County on October 11, 2000 causing the destruction of the raw coal beltline feeding the preparation plant and leading to the immediate closure of the slurry impoundment by order of regulatory authorities. As a result, over 1 million shippable tons of coal could not be processed through the Martin County preparation plant for the six months that it was shut down as a result of the spill;

Various weather related problems in May, June and July, 2001 which caused power outages and flooding at several Massey operations;

Labor shortages, especially in trained and qualified underground workers, particularly electricians.

As a result, Massey declared events of force majeure under a number of its contracts and sent reduced shipments to affected customers. The Company was able to resolve most shortfalls with its customers without dispute. However, the following dispute occurred and is not yet resolved:

On April 16, 2002, Appalachian Power Company, a subsidiary of American Electric Power, filed suit against Massey’s subsidiaries Central West Virginia Energy Company, Massey Coal Sales Company, Inc. and A.T. Massey Coal Company, Inc. in the Franklin County, Ohio Court of Common Pleas. The suit alleges that the Company improperly claimed force majeure with respect to a tonnage shortfall under its agreements with Appalachian Power in 2000 and 2001, and seeks to recover the additional cost Appalachian Power incurred in purchasing substitute coal. The complaint further alleges that the Company’s claim of force majeure constitutes fraud, and seeks to recover profits made by it on sales to other customers of the coal Appalachian Power claims should have been delivered to it. By order entered July 25, 2002, the court dismissed the fraud claim, however, on December 20, 2002, the court granted Appalachian Power leave to file a second amended complaint to reassert the fraud claim. The trial for this matter is currently scheduled for April 28, 2003. Discovery is ongoing and Appalachian Power has indicated on a preliminary basis that it intends to seek approximately $20.3 million in damages for its cost of purchasing substitute coal. No other alleged damages have been quantified.

Shareholder Derivative Suit

(ii) improper insider trading by Don L. Blankenship, Jeffrey M. Jarosinski, Madeleine M. Curle and Bennett K. Hatfield. The Company and the other defendants removed the case to Federal District Court in Charleston, West Virginia, but the case has now been remanded to the Boone County Circuit Court. The case is still in very early procedural stages. The Company intends to vigorously pursue defense of this case.

Harman Case

On October 29, 1998, Harman and its sole shareholder, Hugh Caperton, filed a separate action against Massey and certain of its subsidiaries in Boone County, West Virginia, Circuit Court, 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 in the case awarded the plaintiffs $50 million in compensatory and punitive damages. Massey is vigorously pursuing post-judgment remedies, and various motions filed in the trial court have been fully briefed and argued. Massey will appeal to the West Virginia Supreme Court of Appeals, if necessary. The Company accrued a liability with respect to these cases of $31.0 million, excluding interest, which the Company believes is a fair estimate of the eventual total payout relating to both the Virginia and West Virginia actions. After the payment of the Virginia verdict, the remaining accrual is $25.0 million. as of December 31, 2002, which is included in Other current liabilities.

Elk Run Dust Case

West Virginia Flooding Cases

Five of the Company’s subsidiaries have been named, among others, in 17 separate complaints filed in Boone, Fayette, Kanawha, McDowell, Mercer, Raleigh and Wyoming Counties, West Virginia. These cases collectively include numerous plaintiffs who filed suit on behalf of themselves and others similarly situated, seeking damages for property damage and personal injuries arising out of flooding that occurred in southern West Virginia in July of 2001. The plaintiffs have sued coal, timber, railroad and land companies under the theory that mining, construction of haul roads and removal of timber caused natural surface waters to be diverted

and interrupted in an unnatural way, thereby causing damage to the plaintiffs. The West Virginia Supreme Court has ruled that these cases, including several 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 in West Virginia to be handled by a panel consisting of three circuit court judges. The panel will, among other things, determine whether the individual cases should be consolidated or returned to their original circuit courts. While the outcome of this litigation is subject to uncertainties, based on our preliminary evaluation of the issues and the potential impact on us, we believe this matter will be resolved without a material adverse effect on our cash flows, financial condition or results of operations.

Water Claims Litigation

Two cases were filed in the Mingo County, West Virginia Circuit Court alleging that Massey’s Delbarton Mining Company subsidiary’s mining activities destroyed nearby resident plaintiffs’ water supplies. One case was filed on behalf of 54 plaintiffs on July 26, 2002, and the other was filed on behalf of 134 plaintiffs on July 1, 2002. Delbarton has already provided many of the plaintiffs with a replacement water source. The case is in the very early procedural stages and the trial is scheduled for October 2003.

Trucking Litigation

Martin County Impoundment Discharge

On October 11, 2000, a partial failure of Massey’s Martin County Coal Corporation subsidiary’s coal refuse impoundment 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. As of December 31, 2002, Massey incurred to date a total of approximately $58.3 million of cleanup costs in connection with the spill, $52.2 million of which have been paid directly or reimbursed by insurance companies. In the consolidated balance sheet as of December 31, 2002 and October 31, 2001, the accruals related to this matter of $9.9 million and $11.5 million, respectively, are included in Other current liabilities, and probable insurance recoveries of $15.1 million and $20.5 million, respectively, are included in Trade and other accounts receivable. Massey 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. The remaining issues (none of which is considered material) are:

(1) there

are two remaining suits with 8 plaintiffs (one seeking class certification) seeking various unquantified damages allegedly resulting from the October 11, 2000 incident.

(2)

On June 26, 2001, the WVDEP filed a civil action against Martin County Coal in the Wayne County, West Virginia, Circuit Court alleging natural resources damages in West Virginia and alleged violations of law resulting from the impoundment discharge. The court ruled that WVDEP cannot collect statutory penalties, but has not yet ruled whether WVDEP can continue to assert its claims for punitive damages. Massey is continuing to defend this action vigorously and believes that it has numerous valid defenses to the claims.

(3) The

Federal Mine Safety and Health Administration (“MSHA”) issued various citations following the impoundment discharge, and assessed penalties totaling approximately $110,000. The Company has contested the violations and penalty amount.

(4) On

October 11, 2002, the Town of Fort Gay, West Virginia filed suit against the Company and Martin County Coal Corporation, alleging that it’s water treatment and distribution plant was damaged when water, allegedly damaged by the discharge from the Martin County impoundment, was pumped into the facility. Massey denies the allegations and is defending the action vigorously.

Valley Fill Litigation

* * * * * * * *

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 operations, financial position or cash flows by reason of these actions.

Coal Purchase Commitments

As of December 31, 2002, the Company had commitments to purchase from external production sources 2.0 million, 0.7 million, and 0.7 million tons of coal in 2003, 2004, and 2005, respectively.

17. Quarterly Information (Unaudited)

As described more fully in Note 2, the Company recently resolved certain accounting and disclosure issues resulting from a review by the Securities and Exchange Commission (“SEC”) of its October 31, 2001 Annual Report on Form 10-K and subsequently filed periodic reports on Forms 10-Q. The quarterly financial information for 2002, 2001 and the two-month transition period ended December 31, 2001 is, by means of this filing, being restated, except for the fourth quarter of 2002, to reflect these adjustments.

Set forth below is the Company’s quarterly financial information for the previous two fiscal years and two-month transition period ended December 31, 2001. Included below are the previously reported as well as restated amounts for each of the following periods: three-months ended September 30, 2002, June 30, 2002 and March 31, 2002; and two-month transition period ended December 31, 2001.

	Three months ended
	March 31, 2002(1)						June 30, 2002(2)						September 30, 2002(3)						December 31, 2002(4)
	Previously Reported			Restated			Previously Reported			Restated			Previously Reported			Restated			Previously Reported(9)			Restated
	(In thousands except per share amounts)
Total revenue	$	341,833		$	392,551		$	347,732		$	402,507		$	363,039		$	424,441		$	410,192		$	410,596
Income (loss) from operations		(229	)		(3,623	)		(17,047	)		(17,398	)		6,993			6,642			(12,217	)		(12,309	)
Loss before taxes		(7,047	)		(10,441	)		(24,990	)		(25,341	)		(1,698	)		(2,049	)		(19,597	)		(19,689	)
Net loss		(2,143	)		(4,213	)		(16,242	)		(16,456	)		(1,103	)		(1,317	)		(10,531	)		(10,587	)
Loss per share:
Basic and diluted	$	(0.03	)	$	(0.06	)	$	(0.22	)	$	(0.22	)	$	(0.01	)	$	(0.02	)	$	(0.14	)	$	(0.14	)

	Two months ended December 31, 2001(8)
	Previously Reported			Restated
	(In thousands, except per share amounts)
Total revenue	$	211,422		$	246,443
Loss from operations		(31,652	)		(19,209	)
Loss before taxes		(35,967	)		(23,524	)
Net loss		(22,391	)		(14,801	)
Loss per share:
Basic and diluted	$	(0.30	)	$	(0.20	)

	Three months ended
	January 31, 2001						April 30, 2001(5)				July 31, 2001(6)						October 31, 2001(7)
	Previously Reported			Restated			Previously Reported		Restated		Previously Reported			Restated			Previously Reported		Restated
Total revenue	$	280,329		$	324,728		$	317,788	$	359,644	$	311,536		$	354,990		$	344,103	$	392,499
Income (loss) from operations		3,590			4,248			8,367		9,025		(5,738	)		(5,081	)		10,491		1,354
Earnings (loss) before taxes		(2,216	)		(1,558	)		3,249		3,907		(13,622	)		(12,965	)		3,832		(5,305	)
Net earnings (loss)		(1,352	)		(951	)		2,081		2,482		(9,394	)		(8,993	)		7,615		2,042
Earnings (loss) per share:
Basic and diluted	$	(0.02	)	$	(0.01	)	$	0.03	$	0.03	$	(0.13	)	$	(0.12	)	$	0.10	$	0.03

(1)

Loss for the first quarter 2002 includes income in the amount of $5.1 million pre-tax received from one large customer for a contract buyout; a reduction in the Company’s bad debt reserves of $2.5 million pre-tax for a receivable from a large bankrupt customer, Wheeling-Pittsburgh Steel Corporation, due to a long-term repayment agreement; and a tax refund for the settlement of a state tax dispute in the amount of $2.4 million, net of federal tax.

(2)

Loss for the second quarter 2002 includes a charge of $25.6 million pre-tax related to an adverse jury verdict in the West Virginia Harman Mining Corporation action. See Note 16 for further information. Additionally, in June 2002, the Company sold an additional interest in its synfuel-producing subsidiary, Appalachian Synfuel, LLC. See Note 6 for further information.

(3)

Loss for the third quarter of 2002 includes a charge in the amount of $13.2 million pre-tax related to the write off of capitalized development costs at certain idled mines. See Note 5 for further information.

(4)

Earnings for the fourth quarter of 2002 include a charge in the amount of $10.6 million pre-tax related to an arbitration award in a contract dispute. See Note 18 for further information.

(5)

On March 15, 2001, the Company sold a substantial interest in its synfuel producing subsidiary, Appalachian Synfuel, LLC. See Note 6 for further information. Additionally, earnings for the second quarter 2001 include a reduction in cost of produced coal revenue of $6.5 million pre-tax and interest income of $3.2 million pre-tax related to the refund of black lung excise taxes.

(6)

Loss for the third quarter 2001 includes a $7.5 million pre-tax adjustment related to the write-off of unamortized longwall panel development costs. The Company decided in the third quarter to move the longwall unit to another mine to take advantage of better mining conditions. Additionally, the loss includes a reduction of cost of produced coal revenue of $3.0 million pre-tax related to the refund of black lung excise taxes.

(7)

Earnings for the fourth quarter 2001 include a charge of $6.9 million pre-tax related to the settlement with the State of West Virginia regarding Worker’s Compensation liabilities incurred by independent contractors, and $2.5 million pre-tax related to an increase in reserves for a wrongful employee discharge suit.

(8)

Earnings for the two-month transition period ended December 31, 2001 include a charge of $3.9 million pre-tax related to the bankruptcy of a substantial customer, Enron Corporation.

(9)

As reported within the Company’s Press Release filed on Form 8-K on February 5, 2003.

18. Subsequent Events

Receivables Securitization

On January 31, 2003, the Company entered into a borrowing program, secured by its accounts receivable. The amount eligible to be borrowed under the program is up to $80 million depending on the level of eligible receivables and restrictions on concentrations of receivables. At February 28, 2003, the borrowings outstanding under the program totaled $54.0 million. The program expires in July 2004. The receivables outstanding under these programs and the corresponding debt will be included as “Trade accounts receivables” and “Long-term debt,” respectively, on the Company’s consolidated balance sheets in subsequent accounting periods. As collections reduce previously pledged interests, new receivables will be pledged. A portion of the cost of the accounts receivable secured borrowing programs is based on the creditors’ level of investment and borrowing costs. The total cost of the programs will be included in interest expense on future statements of income.

Duke Arbitration

On December 14, 2001, Duke Energy made a demand for arbitration, disputing the Company’s claim that an event of force majeure had occurred and claiming $20.5 million in damages resulting from coal tonnage shortfalls. In December 2002, the dispute went to arbitration. On January 23, 2003, the arbitrators awarded Duke Energy $10.6 million on its claim, which Massey has paid. Charges for such payment were recorded in the fourth quarter of 2002.

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.

Part III

Item 10. Directors and Executive Officers of the Registrant.

Biographical information of Executive Officers is included in Item 4 of this Form 10-K. Other information required by this item is included in the Biographical 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 with the Securities and Exchange Commission (the “Commission”) not later than 120 days after the close of Massey’s fiscal year ended December 31, 2002.

Item 11. Executive Compensation.

Information required by this item is included in the Organization and 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, 2002.

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

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, 2002.

Item 13. Certain Relationships and Related Transactions.

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, 2002.

Item 14. Controls and Procedures.

We have 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 a date within 90 days of the filing date of this Annual Report on Form 10-K, 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.

Part IV

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

(a)

Documents filed as part of this report:

Financial Reports:

Consolidated Statements of Earnings for the Fiscal Years Ended December 31, 2002, October 31, 2001 and 2000, and the two month periods ended December 31, 2001 and 2000 (unaudited)

Consolidated Balance Sheets at December 31, 2002 and October 31, 2001

Consolidated Statements of Cash Flows for the Fiscal Years Ended December 31, 2002, October 31, 2001 and 2000, and the two month periods ended December 31, 2001 and 2000 (unaudited)

Consolidated Statements of Shareholders’ Equity for the Fiscal Years Ended December 31, 2002, October 31, 2001 and 2000, and the two month periods ended December 31, 2001 and 2000 (unaudited)

Notes to Consolidated Financial Statements

Financial Statement Schedules: Except as set forth below, all schedules have been omitted since the required information is not present or not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements and notes thereto.

Schedule II—Valuation and Qualifying Accounts

Exhibits:

Exhibit No.		Description

3.1		Restated Certificate of Incorporation of Massey, as amended [filed as Exhibit 3.1 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

3.2		Restated Bylaws (as amended effective August 1, 2002) of Massey Energy Company [filed as Exhibit 3.1 to Massey’s quarterly report on Form 10-Q for the period ended June 30, 2002 and incorporated by reference]

4.1		Fluor Corporation Dividend Reinvestment Plan (as amended and restated June 30, 1995) [filed as Exhibit 4.2 to Fluor’s annual report on Form 10-K for the fiscal year ended October 31, 1995 and incorporated by reference]

4.2		Indenture dated as of February 18, 1997 between Fluor Corporation and Banker’s Trust Company, trustee [filed as Exhibit 4.1 to Form 8-K filed March 7, 1997 and incorporated by this reference]

4.3		First Supplemental Indenture, dated as of the 9th day of February, 2001, between Massey Energy Company (successor by name change to Fluor Corporation) and Bankers Trust Company, supplementing that certain Indenture dated as of February 18, 1997 [filed as Exhibit 10.2 to Massey’s quarterly report on Form 10-Q for the period ended March 31, 2002 and incorporated by reference]

10.1		Amended and Restated Credit Agreement dated as of November 26, 2002, among Massey Energy Company, as Borrower, each domestic Subsidiary of Massey, as Guarantors, CitiCorp USA, Inc., as Administrative Agent and Collateral Agent, PNC Bank, National Association, as Syndication Agent, Wachovia Bank, National Association, as Documentation Agent, and the lenders party thereto, for a maximum principal amount at any one time outstanding not to exceed $250,000,000 [filed as Exhibit 10.1 to Massey’s annual report on Form 10-K for the period ended Decmeber 31, 2002 and incorporated by reference]

Exhibit No.		Description

10.2		First Amendment to Amended and Restated Credit Agreement dated as of January 30, 2003, among Massey Energy Company, as Borrower, each domestic Subsidiary of Massey, as Guarantors, CitiCorp USA, Inc., as Administrative Agent and Collateral Agent, PNC Bank, National Association, as Syndication Agent, Wachovia Bank, National Association, as Documentation Agent, and the lenders party thereto, for a maximum principal amount at any one time outstanding not to exceed $250,000,000 [filed as Exhibit 10.2 to Massey’s annual report on Form 10-K for the period ended December 31, 2002 and incorporated by reference]

10.3		Credit and Security Agreement dated as of January 31, 2003, among Massey Receivables Corporation, as Borrower, A.T. Massey Coal Company, Inc., as Servicer, Blue Ridge Asset Funding Corporation, the Liquidity Banks from time to time party hereto and Wachovia Bank, National Association, as Agent [filed as Exhibit 10.3 to Massey’s annual report on Form 10-K for the period ended December 31, 2002 and incorporated by reference]

10.4		Massey Energy Company 1999 Executive Performance Incentive Plan (as amended and restated effective November 30, 2000) [filed as Exhibit 10.1 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.5		Massey Executive Deferred Compensation Program (as amended and restated effective November 30, 2000) [filed as Exhibit 10.2 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.6		Massey Energy Company Executive Physical Program [filed as Exhibit 10.3 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.7		Massey Energy Company Directors’ Life Insurance Summary [filed as Exhibit 10.4 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.8		Massey Energy Split Dollar Life Insurance Program Summary [filed as Exhibit 10.5 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.9		Massey Energy Company 1988 Executive Stock Plan (as amended and restated effective November 30, 2000) [filed as Exhibit 10.6 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.10		Massey Energy Company Change of Control Compensation Plan (as amended and restated effective November 30, 2000) [filed as Exhibit 10.7 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.11		Massey Energy Company 1982 Shadow Stock Plan [filed as Exhibit 10.8 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.12		Massey Energy Company 1997 Stock Appreciation Rights Plan [filed as Exhibit 10.9 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.13		A.T. Massey Coal Company, Inc. Supplemental Benefit Plan [filed as Exhibit 10.10 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.14		A.T. Massey Coal Company, Inc. Executive Deferred Compensation Plan [filed as Exhibit 10.11 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

Exhibit No.		Description

10.15		Massey Energy Company 1997 Restricted Stock Plan for Non-Employee Directors (as amended and restated effective November 30, 2000) [filed as Exhibit 10.12 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.16		Massey Energy Company 1996 Executive Stock Plan (as amended and restated effective November 30, 2000) [filed as Exhibit 10.13 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.17		Massey Energy Company Stock Plan for Non-Employee Directors (as amended and restated effective November 30, 2000) [filed as Exhibit 10.14 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.18		Massey Energy Company Deferred Directors’ Fees Program [filed as Exhibit 10.15 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

10.19		Amended and Restated Employment Agreement between Massey Energy Company, A.T. Massey Coal Company, Inc. and Don L. Blankenship dated as of November 1, 2001(amending and restating on July 16, 2002, the Employment Agreement between Massey Energy Company, A.T. Massey Coal Company, Inc. and Don L. Blankenship dated as of November 1, 2001) [filed as Exhibit 3.1 to Massey’s quarterly report on Form 10-Q for the period ended June 30, 2002 and incorporated by reference]

10.20		Special Successor and Development Retention Program between Fluor Corporation and Don L. Blankenship dated as of September 1998 [filed as Exhibit 10.21 to Fluor’s annual report on Form 10-K for the fiscal year ended October 31, 1998 and incorporated by this reference]

10.21		Distribution Agreement between Fluor Corporation and Massey Energy Company dated as of November 30, 2000 [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed December 15, 2000 and incorporated by this reference]

10.22		Tax Sharing Agreement between Fluor Corporation, Massey Energy Company and A.T. Massey Coal Company, Inc. dated as of November 30, 2000 [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed December 15, 2000 and incorporated by this reference]

10.23		First Amendment to the A.T. Massey Coal Company, Inc. Executive Deferred Compensation Plan [filed as Exhibit 10.23 to Massey’s annual report on Form 10-K for the fiscal year ended October 31, 2000 and incorporated by reference]

21		Massey Energy Company Subsidiaries [filed as Exhibit 21 to Massey’s annual report on Form 10-K for the fiscal year ended December 31, 2002 and incorporated by reference]

23		Consent of Independent Auditors

24		Manually signed Powers of Attorney executed by Massey directors [filed as Exhibit 24 to Massey’s annual report on Form 10-K for the fiscal year ended December 31, 2002 and incorporated by reference]

99.1		Certification of Chief Executive Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.2		Certification of Chief Financial Officer pursuant to 18 U.S.C., Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(b)

Reports on Form 8-K:

Current Report on Form 8-K filed February 5, 2003 announcing Massey’s financial results for the fiscal year ended December 31, 2002.

SIGNATURES

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.

MASSEY ENERGY COMPANY

April 7, 2003

By:

/S/ K. J. STOCKEL

K. J. Stockel,

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.

Signature	Title	Date
Principal Executive Officer and Director:

/S/ D. L. BLANKENSHIP D. L. Blankenship	Chairman, Chief Executive Officer and President	April 7, 2003

Principal Financial Officer:

/S/ K. J. STOCKEL K. J. Stockel	Senior Vice President and Chief Financial Officer	April 7, 2003

Principal Accounting Officer:

/S/ E. B. TOLBERT E. B. Tolbert	Controller	April 7, 2003

Other Directors:

* E. G. Gee	Director	April 7, 2003

* W. R. Grant	Director	April 7, 2003

* J. H. Harless	Director	April 7, 2003

* B. R. Inman	Director	April 7, 2003

* D. R. Moore	Director	April 7, 2003

* M. R. Seger	Director	April 7, 2003

By:/s/ R. E. DAVIS R. E. Davis Attorney-in-fact		April 7, 2003

* Manually signed Powers of Attorney authorizing R. Eberley Davis, James L. Gardner and Kenneth J. Stockel, and each of them, to sign the annual report on Form 10-K for the fiscal year ended December 31, 2002 and any amendments thereto as attorneys-in-fact for certain directors and officers of the registrant are included herein as Exhibits 24.

CERTIFICATIONS

I, Kenneth J. Stockel, certify that:

I have reviewed this annual report on Form 10-K/A of Massey Energy Company;

Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

The registrant’s other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: April 7, 2003

/S/ K. J. STOCKEL

K. J. Stockel

Senior Vice President and Chief

Financial Officer

CERTIFICATIONS

I, Don L. Blankenship, certify that:

I have reviewed this annual report on Form 10-K/A of Massey Energy Company;

evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: April 7, 2003

/S/ D. L. BLANKENSHIP

D. L. Blankenship

President, Chairman and Chief

Executive Officer

MASSEY ENERGY COMPANY

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

Description	Balance at Beginning of Period		Amounts Charged to Costs and Expenses			Deductions(1)			Other(2)			Balance at End of Period
	(In Thousands of Dollars)
YEAR ENDED DECEMBER 31, 2002
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable	$	11,281	$	(2,706	)	$	—		$	200		$	8,775

TWO MONTHS ENDED DECEMBER 31, 2001
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable		9,848		1,433			—			—			11,281

YEAR ENDED OCTOBER 31, 2001
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable		12,899		(1,527	)		(24	)		(1,500	)		9,848

YEAR ENDED OCTOBER 31, 2000
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable		6,587		6,333			—			(21	)		12,899

(1)

Reserves utilized, unless otherwise indicated.

(2)

Reclassifications, unless otherwise indicated.