Edgar Filing: MASSEY ENERGY CO

Year Ended

December 31,

2004

December 31,

2003

Health care cost trend rate for next year

Ultimate trend rate

Year that the rate reaches ultimate trend rate

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2004

¨	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 Common Stock held by non-affiliates of the registrant on June 30, 2004, was approximately $2,140,756,247 based on the last sales price reported that date on the New York Stock Exchange of $28.21 per share. In determining this figure, the Registrant has assumed that all of its directors and executive officers are affiliates. Such assumptions should not be deemed to be conclusive for any other purpose.

Common Stock, $0.625 par value, outstanding as of February 28, 2005—76,754,725 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2005 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, 2004.

Forward Looking Statements

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

(i)

the Company’s cash flows, results of operation or financial condition;

(ii)

the consummation of acquisition, disposition or financing transactions and the effect thereof on the Company’s business;

(iii)

governmental policies and regulatory actions;

(iv)

legal and administrative proceedings, settlements, investigations and claims;

(v)

weather conditions or catastrophic weather-related damage;

(vi)

the Company’s production capabilities;

(vii)

availability of transportation for the Company’s produced coal;

(viii)

expansion of the Company’s mining capacity;

(ix)

the Company’s ability to manage production costs;

(x)

market demand for coal, electricity and steel;

(xi)

competition;

(xii)

the Company’s relationships with, and other conditions affecting, its customers;

(xiii)

employee workforce factors;

(xiv)

the Company’s assumptions concerning economically recoverable coal reserve estimates;

(xv)

future economic or capital market conditions;

(xvi)

the Company’s plans and objectives for future operations and expansion or consolidation; and

(xvii)

the adequacy and sufficiency of its internal controls.

Any forward-looking statements are subject to the risks and uncertainties that could cause actual cash flows, results of operations, financial condition, cost reductions, acquisitions, dispositions, financing transactions, operations, expansion, consolidation and other events to differ materially from those expressed or implied in such forward-looking statements. Any forward-looking statements are also subject to a number of assumptions regarding, among other things, future economic, competitive and market conditions generally. These assumptions would be based on facts and conditions as they exist at the time such statements are made as well as predictions as to future facts and conditions, the accurate prediction of which may be difficult and involve the assessment of events beyond the Company’s control.

The Company wishes to caution readers that forward-looking statements, including disclosures which use words such as the Company “believes,” “anticipates,” “expects,” “estimates” and similar statements, are subject to certain risks and uncertainties which could cause actual results to differ materially from expectations. Any forward-looking statements should be considered in context with the various disclosures made by the Company about its businesses, including without limitation the risk factors more specifically described below in Item 1. Business, under the heading “Business Risks.”

Available Information

Massey files its annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, proxy statements and other information with the Securities and Exchange Commission (“SEC”). Massey’s SEC filings are available to the public over the Internet at the SEC’s website at www.sec.gov. You may also read and copy any document Massey files at the SEC’s public reference room at 450 Fifth Street, NW, Washington D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. Massey makes available, free of charge through its Internet website, www.masseyenergyco.com, its annual report, quarterly reports, current reports, proxy statements, section 16 reports and other information and any amendments thereto as soon as practicable after filing or furnishing the material to the SEC in addition to the Company’s Corporate Governance Guidelines, codes of ethics and the charters of the Audit, Compensation, Governance and Nominating, Public and Environmental Policy and Executive Committees. Materials may be requested at no cost by telephone at (866) 814-6512 or by mail at: Massey Energy Company, Post Office Box 26765, Richmond, Virginia 23261, Attention: Investor Relations.

2004 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS


		Page
PART I

Item 1.	Business	3

Item 2.	Properties	23

Item 3.	Legal Proceedings	26

Item 4.	Submission of Matters to a Vote of Security Holders	27

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28

Item 6.	Selected Financial Data	29

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	44

Item 8.	Financial Statements and Supplementary Data	45

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80

Item 9A.	Controls and Procedures	81

Item 9B.	Other Information	82

PART III

Item 10.	Directors and Executive Officers of the Registrant	83

Item 11.	Executive Compensation	83

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	83

Item 13.	Certain Relationships and Related Transactions	83

Item 14.	Principal Accounting Fees and Services	83

PART IV

Item 15.	Exhibits and Financial Statement Schedules	84

SIGNATURES		88

Annual Shareholders Meeting

Massey’s 2005 Annual Meeting of Shareholders will be held at 9:00 a.m. EDT on Tuesday, May 24, 2005 at the Waldorf Astoria Hotel, 301 Park Avenue, New York, NY 10022.

Part I

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

Item 1.

Business

Massey produces, processes and sells bituminous coal of steam and metallurgical grades, primarily of a low sulfur content, through its 22 processing and shipping centers, called “resource groups,” many of which receive coal from multiple coal mines. Massey currently operates 34 underground mines (four of which employ both room and pillar and longwall mining) and 15 surface mines (with seven highwall miners in operation) in West Virginia, Kentucky and Virginia. The number of mines that Massey operates may vary from time to time depending on a number of factors, including the existing demand for and price of coal and exhaustion of economically recoverable reserves. Massey’s steam coal is primarily purchased by utilities and industrial clients as fuel for power plants. Its metallurgical coal is used primarily to make coke for use in the manufacture of steel. As measured by 2004 revenue, Energy Ventures Analysis, Inc. (“EVA”) ranks Massey as the fourth largest coal company in the United States (the “U.S.”), and the largest in the Central Appalachian region.

A.T. Massey was originally incorporated in Richmond, Virginia in 1920 as a coal brokering business. In the late 1940s, A.T. Massey expanded its business to include coal mining and processing. In 1974, St. Joe Minerals acquired a majority interest in A.T. Massey. In 1981, St. Joe Minerals was acquired by Fluor Corporation. 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.

During 2004, Massey’s produced coal revenues increased by 15% to $1.46 billion on produced coal sales of 40.4 million tons. Exports increased 34% to 6.7 million tons. Net income in 2004 totaled $13.9 million, or $0.18 per basic and diluted share.

In an effort to capitalize on historically high coal prices due to increased market demand, in 2004, Massey focused on building capacity, mainly by expanding its lower cost surface mine operations and purchasing additional equipment. Total capital spending for 2004 was $347.2 million, including approximately $17.0 million in operating lease buyouts. Massey started four major new surface mines during the year, including the Edwight, Glory, Republic Energy and Superior mines. The Company’s total workforce increased by 606 to 5,034 employees at the end of 2004.

On July 14, 2004, Massey announced that it had entered into a joint venture agreement with Penn Virginia Resource Partners to own and operate end user coal handling facilities. Penn Virginia purchased a 50% interest in the joint venture from Massey for approximately $28.5 million in cash and Massey realized a pre-tax gain of approximately $13 million, of which $1.7 million was recognized in 2004.

On October 1, 2004, the Company reported that it concluded a purchase of selected assets associated with two Horizon Natural Resources Company (“Horizon”) mining operations, Starfire, located in Knott and Perry Counties, Kentucky, and Cannelton, located in Kanawha County, West Virginia. The assets acquired include an estimated 20 million tons of low sulfur coal reserves, two preparation plants, a barge loading facility, related infrastructure and selected mining equipment. The Cannelton operation was subsequently renamed Mammoth Coal Company, and began limited operations in December 2004. The Starfire operation was subsequently renamed Big Elk Mining Company.

Industry Overview

A major contributor to the world energy supply, coal represents approximately 23.5% of the world’s primary energy consumption according to the World Coal Institute (“WCI”). The primary use for coal is to fuel electric power generation. In calendar year 2004, it is estimated that coal generated 51.8% of the electricity produced in the U.S. according to EVA.

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

U.S. coal production has more than doubled during the last 30 years. In 2004, total coal production as estimated by the EIA was 1.1 billion tons. The primary producing regions by tons were the Powder River Basin (39%), Central Appalachia (21%), Midwest (12%), Northern Appalachia (12%), West (other than the Powder River Basin) (13%) and other (3%). All of the Company’s coal production comes from the Central Appalachian region. The EVA estimates that approximately 67% of U.S. coal is produced by surface mining methods. The remaining 33% is produced by underground mining methods that include room and pillar mining and longwall mining (more fully described in Item 1, Business, under the heading “Mining Methods”).

Coal is used in the U.S. by utilities to generate electricity, by steel companies to make products with blast furnaces, and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. Significant quantities of coal are also exported from both East and West Coast terminals. The breakdown of 2003 U.S. coal consumption, as estimated by the EIA, is as follows:


End Use	Tons (millions)	% of Total
Electricity generation	1,004	88	%
Industrial users	62	6	%
Exports	43	4	%
Steel making	24	2	%
Residential & commercial	4	—

Total	1,137	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. Platts Analytics and Forecasting (“Platts”) estimated the average total production costs of electricity, using coal and competing generation alternatives in 2004 as follows:


Electricity Generation Source	Cost per million Kilowatt Hours
Oil	$	6.217
Natural Gas	$	6.161
Other (solar, wind, etc.)	$	4.725
Coal	$	1.898
Nuclear	$	1.703
Hydroelectric	$	0.548

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 2004, as estimated by Platts, is as follows:


Electricity Generation Source	% of Total Electricity Generation
Coal	52	%
Nuclear	22	%
Natural Gas	15	%
Hydroelectric	6	%
Oil	3	%
Other (solar, wind, etc.)	2	%

Total	100	%

Demand for electricity has historically been driven by U.S. economic growth. Because coal-fired generation is used in most cases to meet base load requirements, coal consumption has generally grown at the pace of electricity demand growth.

According to the WCI, the U.S. ranks seventh among worldwide exporters of coal. Australia is the largest exporter, with other major exporters including South America, Indonesia, Canada, China, Russia and Colombia. According to the EIA, U.S. exports, which had decreased by over 61% between 1992 and 2002 as a result of increased international competition and the U.S. dollar’s historic strength in comparison to foreign currencies, increased by 8.6% in 2003 as compared to 2002. The usage breakdown for 2003 U.S. exports of 43 million tons was 49% for electricity generation and 51% for steel making. In 2003, U.S. coal exports were shipped to more than 25 countries. The largest purchaser of U.S. exported utility coal was Canada, which took 17.2 million tons or 82% of total utility coal exports. The largest purchasers of U.S. exported metallurgical coal were Canada, which imported 3.6 million tons, or 16.3%, and Brazil, which imported 3.3 million tons, or 15%. Exports to Ontario, Canada, however, may be negatively impacted if the government’s stated goal to shut down Ontario’s five coal plants by 2007 is carried out. Those plants currently produce approximately 25% of the province’s electricity. Depending on the relative strength of the U.S. dollar versus currencies in other coal producing regions of the world, U.S. producers may export more or less coal into foreign countries as they compete on price with other foreign coal producing sources. Additionally, the domestic coal market may be impacted due to the relative strength of the U.S. dollar to other currencies, as foreign sources could be cost-advantaged based on a coal producing region’s relative currency position. In 2003,

according to the EIA, coal imported into the U.S. reached a record level of 25 million tons, while still representing only 3% of total U.S. coal consumption. Columbia continued to dominate as the source for coal imported into the U.S., accounting for 62% of imports, followed by Venezuela, Indonesia and Canada.

Since 2003, a significant demand/supply imbalance of coal has developed, resulting in record high prices for coal producers in the U.S. Increased demand has primarily been driven by worldwide economic expansion particularly throughout Asia. China projects a doubling of its electricity output by 2020. At the same time, infrastructure and regulatory limitations in China have contributed to a tightening of worldwide coal supply, affecting global prices of coal. China’s growth has caused an increase in worldwide demand for raw materials resulting in a sustained increase in freight rates and a disruption of expected coal exports to Japan, Korea, India and other countries. In addition, the weakness of the U.S. dollar has made U.S. coal increasingly competitive in foreign markets.

Metallurgical grade coal is distinguished by special quality characteristics that include high carbon content, volatile matter, low expansion pressure, low sulfur content, and various other chemical attributes. High vol met coal is also high in heat content (as measured in Btus), and therefore is desirable to utilities as fuel for electricity generation. Consequently, high vol met coal producers have the ongoing opportunity to select the market that provides maximum revenue. The premium price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content. The primary concentration of U.S. metallurgical coal reserves is located in the Central Appalachian region. Platts estimates that the Central Appalachian region supplied 87% of domestic metallurgical coal and 79% of U.S. exported metallurgical coal during 2003.

Industrial users of coal typically purchase high Btu products with the same type of quality focus as utility coal buyers. The primary goal is to maximize heat content, with other specifications like ash content, sulfur content, and size varying considerably among different customers. Because most industrial coal consumers use considerably less tonnage than electric generating stations, they typically prefer to purchase coal that is screened and sized to specifications that streamline coal handling processes. Due to the more stringent size and quality specifications, industrial customers often pay a 10% to 15% premium above utility coal pricing (on comparable quality). The largest regional supplier to the industrial market sector has historically been Central Appalachia, which supplied approximately 27% of all U.S. industrial coal demand in 2004.

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 (“NMA”), in 2003 approximately two-thirds of U.S. coal production was shipped via railroads. Final delivery to consumers often involves more than one transportation mode. A significant portion of U.S. production is delivered to customers via barges on the inland waterway system and ships loaded at Great Lakes ports.

Neither Massey nor any of its subsidiaries is affiliated with or has any investment in the EIA, EVA, Platts or WCI. Massey is a member of the NMA.

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 fall. When retreat mining is completed to the mouth of the panel, the mined panel is abandoned.

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

Surface mining is used when coal is found close to the surface. This method involves the removal of overburden (earth and rock covering the coal) with heavy earth moving equipment and explosives, loading of the coal, replacing the overburden and topsoil after the coal has been excavated, 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 portal. The cut is typically a rectangular, horizontal opening in the highwall (the unexcavated face of exposed overburden and coal in a surface mine) 11-feet wide and reaching depths of up to 1000 feet. Multiple, parallel openings are driven into the highwall, separated by narrow pillars that extend the full depth of the hole.

Use of continuous mining machines in the room and pillar method of underground mining represented approximately 38% of Massey’s 2004 coal production. Production from underground longwall mining operations constituted about 14% of Massey’s 2004 production. Surface mining represented approximately 41% of Massey’s 2004 coal production. Massey has established large-scale surface mines in Boone and Nicholas Counties, 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 7% of Massey’s 2004 coal production.

Mining Operations

Massey currently has 22 distinct resource groups or mining complexes, including 16 in West Virginia, five 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, trucks or barges, with rail shipments representing approximately 94% of 2004 coal shipments.

The following table provides key operational information on Massey’s mining complexes (Resource Groups) in 2004.


Resource Group Name	Location	2004 Production⁽¹⁾	2004 Shipments⁽²⁾	Year Established or Acquired
		(Thousands of Tons)
West Virginia Resource Groups
Black Castle	Boone County, WV	2,668	910	1987
Delbarton	Mingo County, WV	473	958	1999
Eagle Energy	Boone County, WV	—	—	1996
Elk Run	Boone County, WV	2,032	2,637	1978
Green Valley	Nicholas County, WV	825	809	1996
Independence	Boone County, WV	2,309	2,345	1994
Logan County	Logan County, WV	5,651	5,206	1998
Mammoth	Kanawha County, WV	23	—	2004
Marfork	Raleigh County, WV	2,255	5,019	1993
Nicholas Energy	Nicholas County, WV	4,280	3,956	1997
Omar	Boone County, WV	—	1,223	1954
Performance	Raleigh County, WV	2,781	1,039	1994
Progress	Boone County, WV	6,306	4,223	1998
Rawl	Mingo County, WV	1,654	643	1974
Republic Energy	Raleigh County, WV	96	44	2004
Stirrat	Logan County, WV	853	581	1993

Kentucky Resource Groups
Big Elk	Knott and Perry Counties, KY	—	—	2004
Long Fork	Pike County, KY	—	3,108	1991
Martin County	Martin County, KY	1,825	1,931	1969
New Ridge	Pike County, KY	—	1,940	1992
Sidney	Pike County, KY	7,424	3,376	1984

Virginia Resource Group
Knox Creek	Tazewell County, VA	550	489	1997

Total		42,005	40,437

⁽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. Production amounts above represent coal severed from the ground and a portion of tons not yet severed from the ground but for which production costs have been incurred in the overburden removal process (i.e. work in process inventory).

⁽²⁾	For purposes of this table, coal shipments have been allocated to the Resource Group from where the coal is processed and shipped, rather than the Resource Group where the coal is mined.

The following descriptions of the Company’s Resource Groups are current as of February 28, 2005.

West Virginia Resource Groups

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

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

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

Elk Run. The Elk Run complex produces coal from three underground room and pillar mines, which deliver coal to its preparation plant by belt and truck. Additionally, Elk Run processes coal for shipment that is produced by surface mines of the Progress resource group. Coal from these mines is transported via underground conveyor system. The Elk Run preparation plant has a processing capacity of 2,200 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 Revolution (formerly called Justice) longwall mine, four underground room and pillar mines and a preparation plant. Production from two of the underground mines is transported via underground conveyor system directly to the Independence preparation plant. One of the underground mines ships coal via belt conveyor for processing to the preparation plant of the Performance resource group. The remaining two underground mines truck their production to the Independence preparation plant for processing. 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. The Independence plant has a processing capacity of 2,200 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 four surface mines, two highwall miners, one underground room and pillar mine and the Aracoma longwall mine, plus the Bandmill preparation plant and the Feats loadout, all on the CSX rail system. Two surface mines and a highwall miner deliver coal to the Bandmill plant via truck and conveyor system, while both underground mines belt coal directly to this plant. Two surface mines and one highwall miner deliver direct-ship coal to the Feats loadout by truck and conveyor system. The Feats loadout services customers via the CSX rail system with unit train shipments of up to 80 cars. A portion of the coal from two of the surface mines and one highwall miner is also delivered by truck to the Delbarton preparation plant, which is on the Norfolk Southern rail system. In 2004, the Bandmill preparation plant increased its processing capacity from 1,600 tons to 1,800 tons per hour. The Bandmill rail loading facility services customers via the CSX rail system with unit train shipments of up to 150 cars.

Mammoth. The Mammoth complex, formerly Horizon’s Cannelton mining operation, which was acquired in September 2004, operates one underground room and pillar mine. The coal is transported by conveyor to the Mammoth preparation plant, which has a 1,200 tons per hour processing facility capacity with barge loading capabilities on the upper Kanawha River. The mine was acquired in September 2004 and began production in December 2004.

Marfork. The Marfork complex includes six underground room and pillar mines and a preparation plant. The largest production source for the Marfork preparation plant 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 haul roads. The Marfork preparation plant has a capacity of 2,400 tons per hour. Customers are served via the CSX rail system with unit trains of up to 150 railcars.

Nicholas Energy. The Nicholas Energy complex includes a large surface mine, a highwall miner and a preparation plant. Coal from the highwall miner and the portion of surface mined coal requiring processing is transported to the preparation plant via overland conveyor system. The plant has a processing capacity of 1,200 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 complex crushes and loads direct-ship coal from the adjacent surface and highwall mining operations of the Black Castle resource group. Production is transported via underground conveyor system or trucked to the Omar facility. Omar’s preparation plant was not utilized for processing coal in 2004. The direct-ship facility can crush 500 tons per hour and the preparation plant can process 800 tons per hour. Omar serves CSX rail system customers with unit train shipments of up to 110 railcars.

Performance. The Performance complex includes the Upper Big Branch longwall mine and the Goals preparation plant. All of the production from Upper Big Branch is shipped via overland conveyor to the preparation plant at the Marfork resource group. The Goals preparation plant processes the production received by belt conveyor of one adjacent underground mine and a surface mine of the Progress resource group. The Goals preparation plant can process 800 tons per hour. The rail loading facility serves CSX railway customers with unit trains of up to 100 railcars.

Progress. The Progress complex includes the large Twilight MTR surface mine and two smaller surface mines, two highwall miners and a direct-ship loadout. Production from the Twilight MTR surface mine is transported via underground conveyor to the Elk Run resource group for processing and rail shipment. Production from one surface mine is transported by overland conveyor to the Performance resource group’s Goals preparation plant for processing and loading, while the remaining surface mine trucks direct-ship coal to the railroad loadout via the CSX rail system with unit train shipments of up to 150 railcars.

Rawl. The Rawl complex includes three underground room and pillar mines, including one contract mine, one surface mine and the Sprouse Creek preparation plant. Production from the surface mine and two of the underground mines is transported to the Sprouse Creek plant via truck. Production from the remaining underground room and pillar mine is trucked to the Sidney resource group preparation plant. The Sprouse Creek plant has a throughput capacity of 1,450 tons per hour. Customers are served via the Norfolk Southern railway with unit trains of up to 150 railcars.

Republic Energy. The Republic Energy complex began surface mining operations in 2004. This start-up mining operation consists of one surface mine. Direct-ship coal is trucked to various Kanawha River docks for barge delivery to customers.

Stirrat. The Stirrat complex includes one surface mine, a preparation plant and the Superior loadout. The surface mine belts coal directly to a 12,500 ton silo at the Superior loadout. The Superior loadout serves CSX railway customers with unit trains of up to 100 railcars. The Stirrat preparation plant has been idled since January 2003. Plans to reactivate the plant in 2005 are currently under consideration and review using production from an active surface mine and an adjacent underground room and pillar mine of the Rawl resource group. The plant has a rated capacity of 600 tons per hour. Customers can be serviced via the CSX rail system with unit trains of up to 100 railcars.

Kentucky Resource Groups

Big Elk. The Big Elk complex, formerly Horizon’s Starfire mining operation, which was acquired in September 2004, includes a permitted idle surface mining operation and a preparation plant that has a capacity of 550 tons per hour. While this property is currently inactive, it has the ability to produce in excess of 1.5 million tons per year. Production can be trucked to a loadout facility and delivered to river loading facilities or on the CSX railway with unit trains of up to 90 railcars.

Long Fork. The Long Fork preparation plant processes coal produced by an underground room and pillar mine and the Rockhouse longwall mine of the Sidney resource group. All production is transported via conveyor system to the Long Fork preparation plant. The Long Fork plant has a rated capacity of 1,500 tons per hour. The rail loading facility services customers on the Norfolk Southern railway with unit trains of up to 150 railcars.

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

New Ridge. The New Ridge complex loads clean coal that is transported via truck from the Big Creek preparation plant of Massey’s Sidney resource group. The New Ridge preparation plant has a capacity of 800 tons per hour. The preparation plant currently processes coal from an underground mine of the Sidney resource group. 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 six underground room and pillar mines, including one contract mine, the Rockhouse longwall mine, two surface mines, a highwall miner, the Big Creek preparation plant and the Sandlick direct-ship loadout facility. The Sandlick loadout facility services customers on the Norfolk Southern system with unit trains of up to 110 railcars. 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 capacity of 1,500 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.

Virginia Resource Group

Knox Creek. The Knox Creek complex includes one 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.

Active Mines

The following chart lists the active mines, by type, at the Company’s resource groups as of February 28, 2005.


Resource Group	Surface Mine		Underground Mine		Total
Black Castle	1	(1 HW)¹	—		1
Delbarton	—		2		2
Elk Run	—		3		3
Green Valley	—		2		2
Independence	—		5	(1 LW)²	5
Knox Creek	—		1		1
Logan County	4	(2 HW)	2	(1 LW)	6
Mammoth	—		1		1
Marfork	—		6		6
Martin County	1		1		2
Nicholas Energy	1	(1 HW)			1
Performance	—		1	(1 LW)	1
Progress	3	(2 HW)	—		3
Rawl³	1		3		4
Republic Energy	1		—		1
Sidney³	2	(1 HW)	7	(1 LW)	9
Stirrat	1		—		1

Total	15	(7 HW)	34	(4 LW)	49

^1.	HW—highwall miners operated in conjunction with surface mines

^2.	LW—longwall mine

^3.	Includes one underground room and pillar contract mine.

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: One of Massey’s subsidiaries, Marfork Coal Company, manages a synthetic fuel manufacturing facility located adjacent to the Marfork complex in Boone County, West Virginia. This facility converts coal products to synthetic fuel. Appalachian Synfuel, LLC (“Appalachian Synfuel”), the entity that owns the facility, became a wholly owned subsidiary of the Company in connection with the Spin-Off. Appalachian Synfuel has obtained a private letter ruling from the Internal Revenue Service (“IRS”) that provides that production from this synfuel facility qualifies the owner for tax credits pursuant to Section 29 of the Internal Revenue Code of 1986, as amended (“IRC”). These tax credits are scheduled to expire December 31, 2007.

The ownership interest in Appalachian Synfuel is divided into three tranches, Series A, Series B and Series C. In 2001 and 2002, the Company sold a total of 99% of its Series A and Series B interests, respectively, contingent upon favorable IRS rulings that were obtained. The Company received cash of $7.2 million, a recourse promissory note for $34.6 million that is being paid in quarterly installments of $1.9 million including interest, and a contingent promissory note that is paid on a cents per Section 29 credit dollar earned based on synfuel tonnage shipped. Deferred gains of $14.3 million and $19.1 million as of December 31, 2004 and December 31, 2003, respectively, are included in Other noncurrent liabilities to be recognized ratably through 2007. See Note 16 to the Consolidated Financial Statements for further information regarding Appalachian Synfuel.

Penn Virginia: In July 2004, Massey sold a 50% interest in a joint venture to Penn Virginia Resource Partners, L.P. for approximately $28.5 million in cash to own and operate end user coal handling facilities. The joint venture currently owns coal handling facilities that stockpile and manage coal for Mead/Westvaco Corporation, Eastman Chemical Company and Carmeuse Lime and Stone, Inc. The sale resulted in a pre-tax gain of approximately $13 million, of which $1.7 million was recognized in 2004 with the balance being recognized in future periods. Massey subsidiaries currently operate the coal handling facilities for the joint venture.

Gas Operations: The Company holds interests in operations that produce, gather and market natural gas from shallow reservoirs in the Appalachian Basin. In the eastern U.S., conventional natural gas reservoirs are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. The depths of the reservoirs drilled and operated by Massey range from 2,500 to 5,600 feet.

Nearly all of the Company’s gas production is from operations in southern West Virginia. In this region, the Company owns and operates approximately 156 wells, 184 miles of gathering line, and various small compression facilities. The Company’s southern West Virginia operations control approximately 27,000 acres of drilling rights. In addition, it owns a majority working interest in 46 wells operated by others, and minority working interests in approximately 30 wells operated by others. The December 2004 average daily production, from the 202 wells owned or controlled, was 2.0 million cubic feet per day. The Company does not consider its current gas production level to be material to the Company’s cash flows, results of operations or financial condition.

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

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, 2004, Massey sold 40.4 million tons of produced coal for total produced coal revenue of $1.5 billion. The breakdown of produced tons sold by market served was 63% utility, 26% metallurgical and 11% industrial. Sales were concluded with over 125 customers. Export shipments (including Canada) represented approximately 17% of 2004 tonnage sold. Massey’s 2004 export shipments serviced customers in 13 countries across the globe. Almost all sales are made in U.S. dollars, which eliminates foreign currency risk.

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 each customer’s needs.

Massey’s 2004 shipments of 40.4 million tons were loaded from 19 mining complexes. Rail shipments constituted 94% of total shipments, with 33% loaded on Norfolk Southern trains and 61% loaded on CSX trains. The 6% balance was shipped from Massey mining complexes via truck.

Approximately 17% of Massey’s production was ultimately delivered via the inland waterway system. Coal is transported by rail or truck to docks on the Ohio, Big Sandy and Kanawha Rivers and then ultimately transported by barge to electric utilities, integrated steel producers and industrial consumers served by the inland waterway system. Massey also moved approximately 8% of its production to Great Lakes Ports for transport 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. By offering coal of both steam and metallurgical grades, Massey is able to serve a diverse customer base. This market diversity allows Massey to adjust to changing market conditions and sustain high sales volumes. The majority of Massey’s customers purchase coal for terms of one year or longer, but Massey also supplies coal on a spot basis for some of its customers. Massey’s two biggest customers, affiliates of DTE Energy Corporation and affiliates of American Electric Power Company, Inc., accounted for 12.9% and 10.4%, respectively, of Massey’s total fiscal year 2004 produced coal revenue.

In an effort to mitigate credit-related risks in all customer classifications, Massey maintains a credit policy, which requires scheduled reviews of customer creditworthiness and continuous monitoring of customer news events that might have an impact on their financial condition. Negative credit performance or events may trigger the application of tighter terms of sale, requirements for collateral or, ultimately, a suspension of credit privileges.

As is customary in the coal industry, Massey enters into long-term contracts (one year or more in duration) with many of its customers. These arrangements allow customers to secure a supply for their future needs and provide Massey with greater predictability of sales volume and sales prices. The terms of Massey’s long-term contracts are a result of extensive negotiations with customers. As a result, the terms of these contracts vary with respect to price adjustment mechanisms, pricing terms, permitted sources of supply, force majeure provisions, quality adjustments and other parameters. Some of the contracts contain price adjustment mechanisms that allow for changes to prices based on statistics from the U.S. Department of Labor. Many of these contracts also specify the approved locations from which the coal is to be sourced. Coal quality specifications may be especially stringent for steel customers. Failure to meet agreed upon coal contract requirements may result in price reductions or contract termination by the customer. In some instances, contracted tonnage delivery for a given year may also vary at the election of the customer who may alter, within specified limits, the timing of delivery, or the actual volume itself.

For the year ended December 31, 2004, approximately 93% of Massey’s coal sales volume was pursuant to long-term contracts. The Company believes that in 2005, its coal sales volume percentage pursuant to long-term arrangements will be comparable to 2004. As of February 28, 2005, the Company had contractual sales commitments of approximately 126 million tons, including commitments subject to price reopener and/or optional tonnage provisions. Remaining contractual terms range from one to 15 years with an average volume-weighted remaining term of approximately 2.7 years. Eighty-two percent of the contracted sales tons are currently priced. For 2005, the Company has fully committed all of its expected production. In addition, the Company purchases coal from third-party coal producers from time to time to supplement production and resells this coal to its customers. As of February 28, 2005, the Company had commitments to purchase 0.9, 0.9 and 0.2 million tons of coal during 2005, 2006 and 2007, respectively.

Competition

The coal industry in the U.S. and overseas is highly competitive. Massey competes with both domestic and foreign producers for sales to both domestic and international markets. It was estimated that in 2003 there were approximately 25 coal companies in the U.S. with annual production in excess of 5 million tons, which accounts for approximately 85% of U.S. production. According to EVA, Massey was the sixth largest coal company in terms of tons produced in 2004, exceeded by Peabody Energy Corporation (“Peabody”), Kennecott Energy Company, Arch Coal, Inc. (“Arch”), Foundation Coal Holdings Inc. (“Foundation”) and CONSOL Energy Inc. (“CONSOL”). However, Massey was the fourth largest U.S. coal company in terms of revenue in 2004, exceeded by Peabody, CONSOL and Arch. In addition, Massey competes with a wide variety of coal producers located outside of the United States, notably companies in Australia, Canada, Columbia, Venezuela and Russia.

Massey is the largest producer in Central Appalachia according to EVA, with an estimated 18% of the region’s production in 2004. Many small producers still compete in the region, but other significant producers in Central Appalachia include Arch, CONSOL, Foundation, James River Coal Company, Peabody, Alpha Natural Resources and International Coal Group.

Massey competes with other producers primarily on the basis of price, coal quality, transportation cost and reliability of supply. Continued demand for coal is also dependent on factors outside Massey’s control, including demand for electricity, environmental and governmental regulations, weather, technological developments, the availability and cost of alternative fuel sources and general economic conditions.

A significant demand/supply imbalance of coal has developed since 2003, resulting in record high prices for coal producers in the U.S. Increased demand has primarily been driven by worldwide economic expansion particularly throughout Asia. China projects a doubling of its electricity output by 2020. At the same time, infrastructure and regulatory limitations in China have contributed to a tightening of worldwide coal supply, affecting global prices of coal. China’s growth has caused an increase in worldwide demand for raw materials resulting in a sustained increase in freight rates and a disruption of expected coal exports to Japan, Korea, India and other countries. In addition, the weakness of the U.S. dollar has made U.S. coal increasingly competitive in foreign markets.

Increased demand and prices encourage coal producers around the world to attempt to expand supplies of coal and eventually result in increased competition and/or reduced prices in future years. Currently, a number of coal producers in Canada and Australia have announced plans to increase production of metallurgical grade coal between now and the end of the decade; however, port and rail infrastructure limitations make it unclear how rapidly these production increases can impact the world markets and coal prices.

The Company sells coal under long-term contracts and on the spot market. See the “Customers and Coal Contracts” section above. Generally, the relative competitiveness of coal vis-à-vis other fuels or other coals is evaluated on a delivered cost per heating value unit basis. In addition to the price of alternative sources of fuels, coal quality, the marginal cost of producing coal in various regions of the country and transportation costs are major determinants of the price for which the Company’s production can be sold.

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

Transportation costs are another fundamental factor affecting coal industry competition. Coordination of the many eastern coal loadouts, the large number of small shipments, terrain and labor issues all combine to make shipments originating in the eastern U.S. inherently more expensive on a per-mile basis than shipments originating in the western U.S. However, the total cost and availability of coal transportation from the western coal producing areas into Central Appalachian markets has historically limited the use of western coal in those markets. Barge transportation is the lowest cost method of transporting coal long distances in the eastern U.S., and the large numbers of eastern producers with river access help keep coal prices competitive. The ability of utilities to blend western and eastern coal has created a new, dynamic fuel procurement environment that will place eastern and western coals in even greater competition.

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

Historically, increased demand for coal attracted new investors to the coal industry, spurred the development of new mines and resulted in additional production capacity throughout the industry, all of which can lead to increased competition and lower coal prices. Increases in coal prices continue to encourage the development of expanded capacity by new or existing coal producers, which could reduce coal prices and therefore decrease the Company’s revenues. However, in recent years, capacity expansion has been limited by the increased costs of mining, high capital requirements, coal seam degradation, labor shortages, transportation issues related to rail, barge and truck shipments, higher costs related to compliance with new regulations and the difficulty of obtaining permits and bonding.

Employees and Labor Relations

As of December 31, 2004, Massey had 5,034 employees, including 166 employees affiliated with the United Mine Workers of America (“UMWA”). Relations with employees are generally good, and there have been no material work stoppages in the past ten years.

Executive Officers of the Company

The current executive officers of Massey are:

Don L. Blankenship, Age 55

Mr. Blankenship has been a Director since 1996 and the Chairman, Chief Executive Officer and President of Massey since 1992. He was formerly the President and Chief Operating Officer of the Company from 1990 and President of the Company’s subsidiary, Massey Coal Services, Inc., from 1989. He joined the Company’s subsidiary, Rawl Sales & Processing Co., in 1982. He is a director of the National Mining Association and the U.S. Chamber of Commerce.

Baxter F. Phillips, Jr., Age 58

Mr. Phillips has been Executive Vice President and Chief Administrative Officer of Massey since November 20, 2004. Mr. Phillips previously served as Senior Vice President and Chief Financial Officer since September 1, 2003, and as Vice President and Treasurer since November 30, 2000. Mr. Phillips joined the Company in 1981 and has served in the roles of Corporate Treasurer, Manager of Export Sales and Corporate Human Resources Manager, among others. Prior to joining Massey, Mr. Phillips’ background included banking and investments.

J. Christopher Adkins, Age 41

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

H. Drexel Short, Jr., Age 48

Mr. Short has been Senior Vice President, Group Operations of 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 the Company in 1981 and has served in a variety of capacities.

Thomas J. Dostart, Age 49

Mr. Dostart has been Vice President, General Counsel & Secretary of Massey since May 5, 2003. He served from 1997 to 2003 as General Counsel & Assistant Secretary for Alliance Coal, LLC. Mr. Dostart previously served as Vice President, General Counsel & Secretary for National Auto Credit, Inc., and as an attorney with Amoco Corporation, Diamond Shamrock, Inc., and the law firms of Jones, Day, Reavis & Pogue and Arter & Hadden.

Jeffrey M. Jarosinski, Age 45

Mr. Jarosinski has been Vice President, Finance of Massey since September 1998 and Chief Compliance Officer of Massey since December 9, 2002. From September 1998 through December 9, 2002, Mr. Jarosinski was Chief Financial Officer of Massey. Mr. Jarosinski was formerly Vice President, Taxation of Massey from 1997 to August 1998 and Assistant Vice President, Taxation of the Company from 1993 to 1997. Mr. Jarosinski joined the Company in 1988. Prior to joining Massey, Mr. Jarosinski held various positions in public accounting.

John M. Poma, Age 40

Mr. Poma has been Vice President, Human Resources of Massey since April 1, 2003. Mr. Poma served as Corporate Counsel of the Company from 1996 until March 2000 and as Senior Corporate Counsel from March 2000 through March 2003. Prior to joining Massey in 1996, Mr. Poma practiced law with Midkiff & Hiner in Richmond, Virginia and Jenkins, Fenstermaker, Krieger, Kayes & Farrell in Huntington, West Virginia.

Eric B. Tolbert, Age 37

Mr. Tolbert has been Vice President and Chief Financial Officer of Massey since November 20, 2004. Mr. Tolbert previously served as Corporate Controller since 1999. He joined the Company in 1992 as a financial analyst and subsequently served as Director of Financial Reporting. Prior to joining Massey, Mr. Tolbert held various positions in public accounting.

David W. Owings, Age 31

Mr. Owings has been Corporate Controller and Massey’s principal accounting officer since November 20, 2004. Mr. Owings previously served as Manager of Financial Reporting since joining Massey in 2001. Prior to joining Massey, Mr. Owings worked at Ernst & Young LLP, serving as a senior auditor in the Assurance and Advisory Business Services group from October 1998 through January 2001 and as a manager in the Assurance and Advisory Business Services group from January 2001 through September 2001.

Environmental, Safety and Health Laws and Regulations

Massey and its customers are subject to federal, state and local laws and regulations that are revised and amended from time to time relating to environmental protection and plant and mine safety and health, including, but not limited to, the Federal Surface Mining Control and Reclamation Act of 1977 (the “SMCRA”); Occupational Safety and Health Act of 1970; Mine Safety and Health Act of 1977; Water Pollution Control Act of 1972 (commonly known as the Clean Water Act); Clean Air Act of 1963; Black Lung Benefits Revenue Act of 1977; and Black Lung Benefits Reform Act of 1977. Massey is rarely subject to permitting or enforcement under the Federal Resource Conservation and Recovery Act or Comprehensive Environmental Response, Compensation, and Liability Act and does not consider the effects of those statutes on its operations to be material for purposes of disclosure.

SMCRA

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

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 under the Clean Water Act. 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 that 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. See Note 19 to the Notes to the Consolidated Financial Statements for a further discussion of certain Clean Water Act litigation matters.

Clean Air Act

Coal contains impurities, including sulfur, mercury, chlorine, nitrogen oxide and other elements or compounds, many of which are released into the air when coal is burned. The Clean Air Act and corresponding state laws extensively regulate emissions into the air of particulate matter and other substances, including sulfur dioxide, nitrogen oxide and mercury. Although these regulations apply directly to impose certain requirements for the permitting and operation of Massey’s mining facilities, by far their greatest impact on Massey and the coal industry generally is the effect of emission limitations on utilities and other customers. Owners of coal-fired power plants and industrial boilers have been required to expend considerable resources in an effort to comply with these air pollution standards. 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. This in turn may result in decreased production by the Company and a corresponding decrease in the Company’s revenue and profits.

National Ambient Air Quality Standards. In July 1997, the EPA adopted more stringent National Ambient Air Quality Standards (“NAAQS”) for very fine particulate matter and ozone. Ozone is produced by a combination of two precursor pollutants: volatile organic compounds and nitrogen oxide, a by-product of coal combustion. States that are not in compliance with these more stringent standards will have until 2007 to revise their State Implementation Plans (“SIPs”) to include provisions for the control of ozone precursors and/or particulate matter. Revised SIPs could require electric power generators to further reduce nitrogen oxide and sulfur dioxide emissions.

Acid Rain Control Provisions. The acid rain control provisions of Title IV of the Clean Air Act require a reduction of sulfur dioxide emissions from power plants. Because sulfur is a natural component of coal, required sulfur dioxide reductions can have an adverse affect on coal mining operations. All power plants of greater than 25 megawatt capacity must reduce sulfur dioxide emissions by: (i) burning lower sulfur coal, either exclusively or mixed with higher sulfur coal; (ii) installing pollution control devices such as scrubbers, which reduce the emissions from high sulfur coal; (iii) switching to fuels other than coal; (iv) reducing electricity generating levels; or (v) 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.

Nitrogen Oxide Emissions Reduction. In October 1998, the EPA finalized a rule requiring 22 states in the eastern U.S. that have or contribute to ambient air quality problems to make substantial reductions in nitrogen oxide emissions by June 1, 2004. The installation of additional control measures to achieve these reductions makes it more costly to operate coal-fired power plants and could make coal a less attractive fuel. In addition, reductions in nitrogen oxide emissions can be achieved at a low capital cost through a combination of low nitrogen oxide burners and coal produced in western U.S. coal mines. As a result, changes in current emissions standards could also impact the economic incentives for eastern U.S. coal-fired power plants to consider using more coal produced in western U.S. coal mines.

Regional Haze Program. Along with regulations addressing ambient air quality, the EPA has initiated a regional haze program designed to protect and to improve visibility at and around National Parks, National Wilderness Areas and International Parks. This program restricts the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. Moreover, this program may require certain existing coal-fired power plants to install additional control measures designed to limit haze-causing emissions, such as sulfur dioxide, nitrogen oxide and particulate matter. EPA’s final rule concerning best available retrofit technology is currently on remand to the EPA from the U.S. Court of Appeals for the D.C. Circuit. By imposing limitations upon the placement and construction of new coal-fired power plants, the EPA’s regional haze program could affect the future market for coal. States will be given until 2007 to submit revised SIPs to address regional haze.

New Source Review Program. Under the Clean Air Act, new and modified sources of air pollution must meet certain new source standards (the “New Source Review Program”). In the late 1990s the EPA filed lawsuits against many coal-fired plants in the eastern United States alleging that the owners performed non-routine maintenance, causing increased emissions that should have triggered the application of these new source standards. In December 2002 and August 2003, the EPA promulgated rules designed to clarify the New Source Review Program and add flexibility to it. These rules have been challenged by various parties and it appears unlikely that the new rules will substantially impact the resolution of the outstanding EPA litigation, which the EPA continues to pursue even though the litigation is being prosecuted under the old New Source Review Program rules. These lawsuits, and the uncertainty around the New Source Review Program rules, could require utilities to pay penalties and install pollution control equipment or undertake other emission reduction measures which could adversely impact their demand for coal.

Multi-Pollutant Strategies. On January 30, 2004, the EPA proposed two closely related rules designed to significantly reduce levels of sulfur dioxide, nitrogen oxide and mercury: the Clean Air Interstate Rule (initially called the Interstate Air Quality Rule) and the Clean Air Mercury Rule (initially called the Utility Mercury Reduction Rule). The Clean Air Interstate Rule would set a cap-and-trade program in 28 states and the District of Columbia to establish emissions limits for sulfur dioxide and nitrogen oxide, by allowing utilities to buy and sell credits at a rate that would cut sulfur dioxide emissions over 70% and nitrogen oxide emissions over 60% by 2015, to assist in achieving compliance with the NAAQS for 8-hour ozone and fine particulates. The Clean Air Mercury Rule would cut mercury emissions nearly 70% by 2018 through one of two possible methods. One option would involve cutting emissions through a cap-and-trade program and the other by installing maximum achievable control technology. Environmentalists have criticized the proposed cap-and-trade program, arguing that it falls short of the standards mandated by the Clean Air Act. Nevertheless, these proposals would directly affect coal producers, suppliers and utilities in the eastern and western regions of the U.S. and require revisions to the SIPs in many eastern states. The new mercury proposal would set emissions limits based on coal rank, potentially giving the users of western sub-bituminous coal a significant competitive advantage over eastern bituminous coal users.

In January 2005, “Clear Skies” proposed legislation, supported by the Bush Administration, was re-introduced to Congress. This legislation would reduce emissions of sulfur dioxide, nitrogen oxide and mercury from power plants through a cap-and-trade program that would supplant the need for the proposed Clean Air Interstate Rule and Clean Air Mercury Rule. Environmentalists criticized the proposed Clear Skies legislation in much the same way they criticized the Clean Air Interstate and Clean Air Mercury Rules for allegedly falling short of standards mandated by the Clean Air Act, as well as for failing to address greenhouse gas emissions, such as carbon dioxide. In March 2005, the Clear Skies legislation failed to advance from committee to the Senate floor for consideration. Consequently, the EPA issued the Clean Air Interstate Rule on March 10, 2005 and the cap-and-trade program of the Clean Air Mercury Rule on March 15, 2005.

Notably, alternative bills have been introduced in the past that would place tighter caps on coal-fired emissions, including mandatory limits on carbon dioxide emissions, and shorter implementation time frames. While the details of these proposed initiatives vary, there is 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.

1992 Framework Convention on Global Climate Change

The U.S. has not implemented the 1992 Framework Convention on Global Climate Change (the “Kyoto Protocol”), which became effective for many countries on February 16, 2005. The Kyoto Protocol is intended to limit or reduce emissions of greenhouse gases, such as carbon dioxide. Under the terms of the Kyoto Protocol, with specific emission targets that vary from country to country, the U.S. would be required to reduce emissions to 93% of 1990 levels over a five-year period from 2008 through 2012. Although the U.S. has not ratified the emission targets and no comprehensive regulations focusing on greenhouse gas emissions are in place, these restrictions, whether through ratification of the emission targets or other efforts to stabilize or reduce greenhouse gas emissions, could adversely affect the price and demand for coal. If the U.S. were to enact comprehensive legislation focused on the mandatory reduction of greenhouse gas emissions, it could force a large reduction in coal-fired electricity generation, as technologies for carbon dioxide sequestration are not yet commercially available.

Massey Permitting and 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 NPDES permits pursuant to the Clean Water Act and state counterpart water pollution control laws for the discharge of pollutants to waters. These permits are issued for terms of five years and also are renewed in conjunction with the surface mining permit renewals. Additionally, the Clean Water Act requires permits for operations that fill waters of the U.S. Valley fills and refuse impoundments are typically authorized under Nationwide Permits that are revised and renewed periodically by the U.S. Army 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, Clean Water Act and Clean Air Act and corresponding state laws. Massey believes that it is in compliance in all material respects with such permits, and routinely corrects in a timely fashion violations of which it receives notice in the normal course of operations. See Item 3, Legal Proceedings, for a discussion of orders issued to the Company’s subsidiaries to show cause why certain permits should not be revoked or suspended for alleged violations of surface mining laws. The expiration dates of the permits are largely immaterial as the law provides for a right of successive renewal. The cost of obtaining surface mining, clean water and air permits can vary widely depending on the scientific and technical demonstrations that must be made to obtain the permits. However, the cost of obtaining a permit is rarely more than $500,000 and the cost of obtaining a renewal is rarely more than $5,000. It is impossible to predict the full impact of future judicial, legislative or regulatory developments on Massey’s operations because the standards to be met, as well as the technology and length of time available to meet those standards, continue to develop and change.

In 2004, Massey spent approximately $18.0 million to comply with environmental laws and regulations, of which $7.4 million was for surface reclamation. None of these expenditures was capitalized. Massey anticipates spending $28.4 million and $28.3 million in such non-capital expenditures in 2005 and 2006, respectively. Of these expenditures, $17.9 million and $17.5 million for 2005 and 2006, respectively, are anticipated to be for surface reclamation.

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

Mine Safety and Health

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

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

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

Black Lung. Under federal black lung benefits legislation, each coal mine operator is required to make payments of black lung benefits or contributions to: (i) current and former coal miners totally disabled from black lung disease; and (ii) certain survivors of a miner who dies from black lung disease. The Black Lung Disability Trust Fund, to which the Company must make certain tax payments based on tonnage sold, provides for the payment of medical expenses to claimants whose last mine employment was before January 1, 1970 and to claimants employed after such date, where no responsible coal mine operator has been identified for claims or where the responsible coal mine operator has defaulted on the payment of such benefits. In addition to federal acts, the Company is also liable under various state statutes for black lung claims. Federal benefits are offset by any state benefits paid.

In Kentucky, most coal miners’ black lung claims are being placed in abeyance pending a recent decision by the Kentucky Supreme Court in the case Bartrum v. Hunter Excavating. The Kentucky Supreme Court is currently reviewing the Kentucky Court of Appeals decision in Bartrum in which the Court of Appeals held the 2002 statute covering coal workers’ black lung claims unconstitutional because it limited the evidence that could be submitted in a claim in violation of due process rights. The Company does not anticipate that the Court’s ruling will result in any significant change in the number of Kentucky miner black lung claims granted or denied on their merits.

Workers’ Compensation. The Company is liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in which it has operations. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. In June 2003, the West Virginia Legislature passed a workers’ compensation bill that was sponsored by the employer community to address growing issues surrounding the solvency of the state workers’ compensation program. The legislation, which became effective on July 1, 2003, is designed to improve practices within the workers’ compensation system by restructuring the Workers’ Compensation Division and limiting and tightening benefit payments. The legislation also authorizes additional funding to address solvency concerns. On February 16, 2005, the Governor of West Virginia signed into law an increase in the coal severance tax on West Virginia coal production of $0.56 per clean ton beginning November 30, 2005. This additional tax provides funding, in addition to direct workers’ compensation premiums, to retire the estimated $3 billion deficit in the West Virginia Workers’ Compensation Fund. That legislation also converts West Virginia’s monopolistic state fund into an employer owned mutual insurance company beginning in January 2006. On July 1, 2008, West Virginia employers will be allowed to purchase workers’ compensation insurance coverage from qualified private carriers. It is difficult to predict the impact the legislation will have on either future costs or premiums.

Coal Industry Retiree Health Benefit Act of 1992. The Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”) provides for the funding of health benefits for certain UMWA retirees. The Coal Act established the Combined Fund into which “signatory operators” and “related persons” are obligated to pay annual premiums for covered beneficiaries. In 1995, in a case filed by the predecessor to the NMA on behalf of its members, the U.S. District Court for the Northern District of Alabama ordered the Social Security Administration (“SSA”) to recalculate the per-beneficiary premium that the Combined Fund charges assigned operators. The SSA applied the recalculated, lower premium to all assigned operators, including subsidiaries of the Company. In 1996, the Combined Fund sued the SSA in the U.S. District Court for the District of Columbia seeking a declaration that the SSA’s original premium calculation was proper. On February 25, 2000, that Court ruled that the original, higher per beneficiary premium was proper. The SSA then retroactively applied the original, higher premium to various coal operators, including subsidiaries of the Company, for all plan years prior to October 1, 2003. However, the NMA and certain other coal operators, including subsidiaries of the Company, and the Combined Fund filed separate lawsuits in the U.S. District Courts for the Northern District of Alabama and the District of Columbia, respectively, seeking a determination regarding the SSA’s 2003 premium recalculation. Those lawsuits were transferred to the U.S. District Court for the District of Maryland. The Company does not believe this matter will have a material impact on its cash flows, results of operations or financial condition. See Note 13 to the Notes to the Consolidated Financial Statements for further information.

Business Risks

In addition to the business risks described herein in Item 1, Business, under the headings “Customers and Coal Contracts,” “Competition,” “Environmental, Safety and Health Laws and Regulations” and in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) under “Critical Accounting Estimates and Assumptions,” “Certain Trends and Uncertainties” and elsewhere in MD&A, Massey is subject to certain risks, including, but not limited to, those set forth below.

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

Massey competes with coal producers in various regions of the U.S. and overseas for domestic and international sales. Continued domestic demand for Massey’s coal and the prices that it will be able to obtain primarily will depend upon coal consumption patterns of the domestic electric utility industry and the domestic steel industry. Consumption by the domestic utility industry is affected by the demand for electricity, environmental and other governmental regulations, technological developments and the price of competing coal and alternative fuel supplies including nuclear, natural gas, oil and renewable energy sources, including hydroelectric power. Consumption by the domestic steel industry is primarily affected by economic growth and the demand for steel used in construction as well as appliances and automobiles. Recently, the competitive environment for coal has been impacted by worldwide economic recovery and sustained growth in a number of the largest markets in the world, including the U.S., China, Japan and India, where demand for both electricity and steel have supported higher pricing for steam and metallurgical coal. The cost of ocean transportation and the valuation of the U.S. dollar in relation to foreign currencies significantly impact the relative attractiveness of Massey’s coal as it competes on price with other foreign coal producing sources. See Item 1, Business, under the heading “Competition”, for further discussion.

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

Coal prices are influenced by a number of factors and may vary dramatically by region. The two principal components of the price of coal are the price of coal at the mine, which is influenced by mine operating costs and coal quality, and the cost of transporting coal from the mine to the point of use. The cost of mining the coal is influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. Underground mining is generally more expensive than surface mining as a result of high capital costs, including costs for modern mining equipment and construction of extensive ventilation systems and higher labor costs due to lower productivity. The Company presently operates 34 active underground mines, including 4 longwall mines, and 15 active surface mines, with 7 highwall miners. See Item 1, Business, under the headings “Mining Methods” and “Mining Operations” for further discussion.

Massey depends on continued demand from its customers

Reduced demand from or the loss of Massey’s largest customers could have an adverse impact on Massey’s ability to achieve its projected revenue. Decreases in demand may result from, among other things, a reduction in consumption by the electric generation industry and/or the steel industry, the availability of other sources of fuel at cheaper costs and a general slow-down in the economy. 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. In the event that a large customer account is lost or a long-term contract is not renewed profits could suffer if alternative buyers are not willing to purchase the Company’s coal on comparable terms. See Item 1, Business, under the heading “Customers and Coal Contracts” for further discussion.

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

At December 31, 2004, Massey had $920.5 million of total indebtedness outstanding, which represented 54.2% of its total book capitalization. The Company has significant debt, lease and royalty obligations. The Company’s ability to satisfy debt service, lease and royalty obligations and to effect any refinancing of its indebtedness will depend upon future operating performance, which will be affected by prevailing economic conditions in the markets that the Company serves as well as financial, business and other factors, many of which are beyond the Company’s control. The Company may be unable to generate sufficient cash flow from operations and future borrowings, or other financings may be unavailable in an amount sufficient to enable it to fund its debt service, lease and royalty payment obligations or its other liquidity needs.

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

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

Massey’s asset based loan credit facility and the indentures governing its senior notes contain a number of significant restrictions and covenants that may limit the Company’s ability and its subsidiaries’ ability to, among other things: (i) incur liens and debt or provide guarantees in respect of obligations of any other person; (ii) increase common stock dividends above specified levels; (iii) make loans and investments; (iv) prepay, redeem or repurchase debt; (v) engage in mergers, consolidations and asset dispositions; (vi) engage in affiliate transactions; (vii) create any lien or security interest in any real property or equipment; (viii) engage in sale and leaseback transactions; and (ix) restrict distributions from subsidiaries.

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

Massey depends on its ability to continue acquiring and developing coal reserves

A key component to the future success of Massey is its ability to continue acquiring coal reserves for development that have the geological characteristics that allow them to be economically mined. Replacement reserves may not be available or, if available, may not be capable of being mined at costs comparable to those characteristics of the depleting mines. An inability to continue acquiring economically recoverable coal reserves could have a material impact on the Company’s cash flows, results of operations or financial condition.

Massey faces numerous uncertainties in estimating its economically recoverable coal reserves, and inaccuracies in its estimates could result in lower than expected revenues, higher than expected costs and decreased profitability

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond Massey’s control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about the Company’s reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by the Company’s staff. Some of the factors and assumptions that impact economically recoverable reserve estimates include: (i) geological conditions; (ii) historical production from the area compared with production from other producing areas; (iii) the assumed effects of regulations and taxes by governmental agencies; (iv) assumptions governing future prices; and (v) future operating costs.

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

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

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

Corporate governance regulatory requirements may divert attention and resources away from more pressing business concerns; however, failing to meet such requirements may result in other negative consequences

The Sarbanes-Oxley Act of 2002 and the New York Stock Exchange (“NYSE”) corporate governance rules have created new demands and requirements upon public companies. A significant amount of the Company’s time, attention and resources has been diverted from other matters in order to meet such requirements and may continue to be diverted in future years. In addition, failing to meet any of the additional regulatory requirements, such as having to report a material weakness under the internal control over financial reporting standards of the Sarbanes-Oxley Act, may have an adverse affect on the Company, including limiting its ability to access the capital markets.

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, which may negatively impact on the Company’s cash flows, results of operations or financial condition.

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

At December 31, 2004, less than 4% of Massey’s total workforce was represented by the UMWA. Six of Massey’s coal preparation plants and one of its smaller surface mines have a workforce that is represented by a union. In fiscal 2004, these six preparation plants handled approximately 22% of Massey’s coal production. There may be an increased risk of strikes and other related work actions, in addition to higher labor costs, associated with these operations. Massey has experienced some union organizing campaigns at some of its open shop facilities within the past five years. If some or all of Massey’s current open shop operations were to become union represented, Massey could be subject to additional risk of work stoppages and higher labor costs, which could adversely affect the stability of production and reduce its net income.

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

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

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

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

GLOSSARY OF SELECTED TERMS

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

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

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

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

Coal seam. Coal deposits occur in layers. Each layer is called a “seam.”

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

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

Direct-ship coal. Coal that is shipped without first being processed.

Deep mine. An underground coal mine.

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

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

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

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

Long-term contracts. Contracts with terms of one year or longer.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Item 2.

Properties

Operations of Massey and its subsidiaries are conducted on both owned and leased properties totaling more than 967,000 acres in West Virginia, Kentucky, Virginia, Pennsylvania 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
Chapmanville, West Virginia	Leased	Massey Coal Services Field Office

For a description of Massey’s mining properties see “Mining Operations” in Item 1 of this Annual Report on Form 10-K.

Coal Reserves

Massey estimates that, as of December 31, 2004, it had total recoverable reserves of approximately 2.3 billion tons consisting of both proven and probable reserves. “Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves means coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. Approximately 1.5 billion tons of Massey’s reserves are classified as proven reserves. “Proven (Measured) Reserves” are defined by the SEC Industry Guide 7 as reserves for which (a) quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes; grade and/or quality are computed from the results of detailed sampling and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. The remaining 0.8 billion tons of Massey’s reserves are classified as probable reserves. “Probable reserves” are defined by the SEC Industry Guide 7 as reserves for which quantity and grade and/or quality are computed from information similar to that used for proven (measured) reserves, but the sites for inspection, sampling, and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven (measured) reserves, is high enough to assume continuity between points of observation.

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

As with most coal-producing companies in Central Appalachia, the majority of Massey’s coal reserves are controlled pursuant to leases from third party landowners. These leases convey mining rights to the coal producer in exchange for a per ton or percentage of gross sales price royalty payment to the lessor. However, approximately 19% of Massey’s reserve holdings are owned and require no royalty or per ton payment to other parties. The average royalties for coal reserves from the Company’s producing properties (owned and leased) was approximately 4.3% of produced coal revenue for the year ended December 31, 2004.

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, 2004:

Recoverable Reserves⁽¹⁾


	Location⁽²⁾	Total	Proven	Probable	Assigned⁽³⁾	Unassigned⁽³⁾	Owned	Leased
	(In Thousands of Tons)
Resource Groups:

West Virginia
Black Castle	Boone County	76,284	61,228	15,056	49,902	26,382	—	76,284
Delbarton	Mingo County	291,203	122,324	168,879	144,307	146,896	79	291,124
Eagle Energy	Boone County	—	—	—	—	—	—	—
Elk Run	Boone County	136,809	104,540	32,269	64,558	72,251	4,701	132,108
Green Valley	Nicholas County	6,974	6,974	—	6,974	—	—	6,974
Independence	Boone County	60,527	59,215	1,312	55,869	4,658	16,300	44,227
Logan County	Logan County	88,209	88,209	—	38,034	50,175	—	88,209
Mammoth Coal	Kanawha County	38,430	29,126	9,304	24,985	13,445	38,430	—
Marfork	Raleigh County	64,628	57,707	6,921	41,676	22,952	684	63,944
Nicholas Energy	Nicholas County	113,946	97,365	16,581	64,099	49,847	58,749	55,197
Omar	Boone County	18,757	7,491	11,266	—	18,757	523	18,234
Performance	Raleigh County	30,976	30,946	30	26,120	4,856	—	30,976
Progress	Boone County	83,667	76,625	7,042	83,667	—	29,655	54,012
Rawl	Mingo County	108,316	77,976	30,340	60,533	47,783	1,400	106,916
Republic Energy⁽⁴⁾	Raleigh County	40,119	36,108	4,011	40,119	—	—	40,119
Stirrat	Logan County	5,404	3,545	1,859	416	4,988	—	5,404

Kentucky
Big Elk	Perry County	12,829	6,415	6,414	—	12,829	8,981	3,848
Long Fork	Pike County	5,537	3,227	2,310	602	4,935	—	5,537
Martin County	Martin County	46,326	19,809	26,517	8,222	38,104	1,402	44,924
New Ridge	Pike County	—	—	—	—	—	—	—
Sidney	Pike County	145,854	88,695	57,159	119,019	26,835	8,211	137,643

Virginia
Knox Creek	Tazewell County	49,566	36,826	12,740	33,047	16,519	—	49,566

Subtotal		1,424,361	1,014,351	410,010	862,149	562,212	169,115	1,255,246
Land Management Companies⁽⁵⁾:
Black King	Boone Co., WV	59,219	56,728	2,491	—	59,219	16,398	42,821
	Raleigh Co., WV
Boone East	Boone Co., WV	142,145	112,174	29,971	56,368	85,777	65,906	76,239
	Kanawha Co., WV
Boone West	Boone Co., WV	254,757	99,502	155,255	10,445	244,312	66,183	188,574
	Logan Co., WV
Ceres Land	Raleigh Co., WV	12,222	9,999	2,223	—	12,222	—	12,222
Lauren Land	Mingo Co., WV	152,842	106,383	46,459	11,285	141,557	18,324	134,518
	Pike Co., KY
Mine Maintenance	Fayette Co., PA	66,360	31,087	35,273	—	66,360	66,360	—
	Westmoreland Co., PA
New Market	Wyoming Co., WV	59,354	23,374	35,980	—	59,354	5,945	53,409
Raven Resources	Boone Co., WV	31,441	21,585	9,856	—	31,441	—	31,441
	Raleigh Co., WV

Subtotal		778,340	460,832	317,508	78,098	700,242	239,116	539,224
Other	N/A	90,391	44,513	45,878	11,970	78,421	25,539	64,852

Total		2,293,092	1,519,696	773,396	952,217	1,340,875	433,770	1,859,322

Notes:

⁽¹⁾	All of the recoverable reserves listed are in Central Appalachia, except for Mine Maintenance reserves, which are located in Northern Appalachia.

⁽²⁾

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 in the Company’s delivered coal.

⁽³⁾	Assigned Reserves represent recoverable reserves that are dedicated to a specific permitted mine. Otherwise, the reserves are considered Unassigned. For Land Management Companies, Assigned Reserves have been leased to a Resource Group and are dedicated to a specific permitted mine of the lessee.

⁽⁴⁾	Formerly presented as a land management company known as Hannah Land Company.

⁽⁵⁾	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⁽¹⁾


	Recoverable Reserves	Sulfur content			Average BTU as received⁽⁴⁾	Coal Type⁽⁵⁾
	Recoverable Reserves	+1%⁽²⁾	-1%⁽²⁾	Compliance⁽³⁾	Average BTU as received⁽⁴⁾	Coal Type⁽⁵⁾
(In Thousands of Tons Except Average Btu as Received)
Resource Groups:

West Virginia
Black Castle	76,284	27,568	48,716	26,648	12,493	Utility and Industrial
Delbarton	291,203	115,948	175,255	128,565	13,743	High Vol Met, Utility and Industrial
Eagle Energy	—	—	—	—	—	N/A
Elk Run	136,809	57,230	79,579	71,488	13,636	High Vol Met, Utility and Industrial
Green Valley	6,974	—	6,974	6,974	13,110	High Vol Met, Utility and Industrial
Independence	60,527	11,967	48,560	8,471	13,249	High Vol Met, Utility and Industrial
Logan County	88,209	19,027	69,182	44,174	12,615	High Vol Met, Utility and Industrial
Mammoth	38,430	2,229	36,201	12,729	12,931	Utility and Industrial
Marfork	64,628	28,391	36,237	23,187	13,537	High Vol Met, Utility, Industrial
Nicholas Energy	113,946	46,970	66,976	29,338	12,821	Utility and Industrial
Omar	18,757	7,107	11,650	438	13,061	Utility and Industrial
Performance	30,976	2,209	28,767	16,698	13,997	High Vol Met
Progress	83,667	10,463	73,204	54,471	12,034	High Vol Met, Utility and Industrial
Rawl	108,316	33,826	74,490	52,097	12,981	High Vol Met, Utility and Industrial
Republic Energy⁽⁶⁾	40,119	6,264	33,855	22,968	12,617	High Vol Met and Utility
Stirrat	5,404	—	5,404	5,404	13,297	High Vol Met, Utility and Industrial

Kentucky
Big Elk	12,829	11,162	1,667	—	11,588	Utility and Industrial
Long Fork	5,537	3,675	1,862	—	12,983	Utility and Industrial
Martin County	46,326	34,638	11,688	3,683	12,914	Utility and Industrial
New Ridge	—	—	—	—	—	N/A
Sidney	145,854	58,737	87,117	62,437	13,139	High Vol Met, Utility and Industrial
Virginia
Knox Creek	49,566	—	49,566	49,566	13,297	High Vol Met, Utility and Industrial

Subtotal	1,424,361	477,411	946,950	619,336

Land Management Companies:⁽⁷⁾

Black King	59,219	30,449	28,770	22,708	13,735	High Vol Met and Utility
Boone East	142,145	24,635	117,510	48,909	13,480	High Vol Met, Utility and Low Vol Met
Boone West	254,757	135,366	119,391	80,132	13,256	High Vol Met and Utility
Ceres Land	12,222	3,754	8,468	8,468	13,951	High Vol Met and Utility
Lauren Land	152,842	56,137	96,705	75,875	13,279	High Vol Met and Utility
Mine Maintenance	66,360	66,360	—	—	13,894	High Vol Met, Utility and Industrial
New Market Land	59,354	4,975	54,379	54,380	14,655	High Vol Met and Low Vol Met
Raven Resources	31,441	18,223	13,218	4,012	13,902	High Vol Met and Utility

Subtotal	778,340	339,899	438,441	294,484
Other	90,391	27,047	63,344	56,966	12,945	Various

Total	2,293,092	844,357	1,448,735	970,786

Notes:

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

⁽²⁾	+1% or -1% refers to sulfur content as a percentage in coal by weight. Compliance coal is less than 1% sulfur content by weight and, therefore, is included in the -1% column.

⁽³⁾	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.

⁽⁴⁾	Represents the average Btu per pound present in the Company’s delivered coal.

⁽⁵⁾	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 utility coal for electricity generation.

⁽⁶⁾	Formerly presented as a land management company known as Hannah Land Company.

⁽⁷⁾	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:

LOGO

Massey Properties, February 2005

Note:

Other properties not shown on this map include Mine Maintenance, located in Fayette and Westmoreland Counties, Pennsylvania and Tennessee Consolidated Coal Company located near Chattanooga, Tennessee. See Item 1. Business, for additional information regarding the coal operations and properties of Massey.

Item 3.

Legal Proceedings

Environmental Show Cause Orders

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

As of March 1, 2005, the West Virginia Department of Environmental Protection (the “WVDEP”) had outstanding show cause orders with respect to active permits at the Company’s Alex Energy, Inc., Bandmill Coal Corporation, Elk Run Coal Company, Inc., Independence Coal Company, Inc. and Marfork Coal Company, Inc. subsidiaries. In addition, the Kentucky Natural Resources and Environmental Protection Cabinet (“KNREPC”) had two outstanding show cause orders with respect to an active permit at Sidney Coal Company. The WVDEP has also issued show cause orders with respect to idled permits at certain of the Company’s subsidiaries.

The potential impact on operations from a permit suspension in the show cause proceedings varies. For example, some of the operations are not currently mining or processing coal; therefore, a suspension at those operations would not impact earnings. At the active operations, suspensions could impact earnings to the extent that downtime cannot be offset by increases in production and/or coal sales at other times or at other operations. The impact of suspensions at these operations could also vary depending on when the suspensions are served. For example, suspensions served over weekends or during scheduled maintenance periods would have lesser impacts. The outcome of each of these actions remains uncertain, so the eventual cost to the Company, if any, cannot presently be reasonably estimated. Accordingly, the Company has not accrued any amounts for any WVDEP or KNREPC show cause orders mentioned herein. While the cost of these matters cannot be reasonably estimated, the Company does not expect these actions, or the cost of defending them, to have a material impact, either individually or collectively, on its cash flows, results of operations or financial condition.

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

The Company continues to carefully monitor its environmental performance. At the direction of the Public and Environmental Policy Committee of the Company’s Board of Directors, the Company periodically obtains a comprehensive environmental audit conducted by an independent environmental auditing firm and continues to conduct regular internal environmental audits that are reviewed with the Committee.

WVDEP Litigation

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

On April 1, 2004, the WVDEP brought suit against two Massey subsidiaries, Bandmill Coal Corporation and Independence Coal Company in the Circuit Courts of Logan County and Boone County, West Virginia, respectively. The suits allege various violations of waste and clean water laws for Bandmill (primarily in 2001 and 2002) and Independence (primarily in 2003 and 2004) and seek unspecified amounts in fines as well as injunctive relief to compel compliance. Bandmill and Independence believe that compliance has been achieved for these violations and are defending the suits vigorously.

Other Legal Proceedings

Certain information regarding other legal proceedings required by this Item 3 is contained in Note 19, “Contingencies and Commitments,” of the Consolidated Financial Statements in this Annual Report on Form 10-K and is incorporated herein by reference.

Massey and its subsidiaries, incident to their normal business activities, are parties to a number of other legal proceedings. While Massey cannot predict the outcome of these proceedings, it does not believe that any liability arising from these matters individually or in the aggregate should have a material impact upon the consolidated cash flows, results of operations or financial condition of Massey.

The Company also is party to lawsuits and other legal proceedings related to the non-coal businesses previously conducted by Fluor Corporation (renamed Massey Energy Company) but now conducted by New Fluor. Under the terms of the Distribution Agreement entered into by the Company and New Fluor as of November 30, 2000, in connection with the Spin-Off of New Fluor by the Company, New Fluor has agreed to indemnify the Company with respect to all such legal proceedings and has assumed their defense.

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, 2004.

Part II

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The Company’s stock is listed on the NYSE. The Company’s Common Stock trading symbol is MEE.

At February 28, 2005, there were 76,754,725 shares outstanding and approximately 8,401 shareholders of record of Massey’s common stock.

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


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

	High		Low		Dividends
Fiscal Year 2004
Quarter ended March 31, 2004	$	24.40	$	17.99	$	0.04
Quarter ended June 30, 2004	$	28.21	$	20.79	$	0.04
Quarter ended September 30, 2004	$	29.66	$	24.59	$	0.04
Quarter ended December 31, 2004	$	36.96	$	26.03	$	0.04

On February 22, 2005, the Company’s board of directors declared a dividend of $0.04 per share, payable on April 12, 2005, to shareholders of record on March 29, 2005.

The Company’s current dividend policy anticipates the payment of quarterly dividends in the future. The Company is restricted by its asset based revolving credit facility and its 6.625% senior notes to paying dividends not in excess of $25 million annually so long as no default exists under the facility or the 6.625% senior notes, as the case may be, or would result thereunder from paying such dividend. There are no other restrictions, other than those set forth under the corporate laws of the State of Delaware, 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

The transfer agent and registrar for the Massey Common Stock is Mellon Investor Services LLC, 85 Challenger Road, Ridgefield Park, New Jersey 07660, toll free (800) 813-2847.

Item 6.

Selected Financial Data

SELECTED FINANCIAL DATA⁽¹⁾


	Year Ended December 31,								Year Ended October 31,					Two Months Ended December 31, 2001⁽²⁾
	2004		2003			2002			2001			2000		Two Months Ended December 31, 2001⁽²⁾
	(In millions, except per share, per ton and number of employee amounts)
CONSOLIDATED STATEMENT OF INCOME DATA:
Produced coal revenue	$	1,456.7	$	1,262.1		$	1,318.9		$	1,203.3		$	1,081.0	$	204.8
Total revenue		1,766.6		1,571.4			1,630.1			1,431.9			1,312.7		246.4
Income (Loss) before interest and taxes		46.2		(17.5	)		(26.7	)		9.5			96.5		(19.2	)
Income (Loss) before cumulative effect of accounting change		13.9		(32.3	)		(32.6	)		(5.4	)		78.5		(14.8	)
Net income (loss)		13.9		(40.2	)		(32.6	)		(5.4	)		78.5		(14.8	)
Income (Loss) per share - Basic ⁽³⁾
Income (Loss) before cumulative effect of accounting change		0.18		(0.43	)		(0.44	)		(0.07	)		1.07		(0.20	)
Net income (loss)		0.18		(0.54	)		(0.44	)		(0.07	)		1.07		(0.20	)
Income (Loss) per share - Diluted ⁽³⁾
Income (Loss) before cumulative effect of accounting change		0.18		(0.43	)		(0.44	)		(0.07	)		1.07		(0.20	)
Net income (loss)		0.18		(0.54	)		(0.44	)		(0.07	)		1.07		(0.20	)
Dividends declared per share		0.16		0.16			0.16			0.20			N/A		—

CONSOLIDATED BALANCE SHEET DATA:
Working capital (deficit)	$	458.4	$	443.2		$	(59.7	)	$	(84.7	)	$	164.8	$	(93.3	)
Total assets		2,650.9		2,376.7			2,241.4			2,271.1			2,183.8		2,272.0
Long-term debt		900.2		784.3			286.0			300.0			N/A		300.0
Shareholders’ equity		776.9		759.0			808.2			860.6			1,372.5		849.5

OTHER DATA:
EBIT⁽⁴⁾	$	46.2	$	(17.5	)	$	(26.7	)	$	9.5		$	96.5	$	(19.2	)
EBITDA⁽⁵⁾		270.8		179.0			181.0			190.8			267.8		12.0
Average cash cost per ton sold⁽⁶⁾		30.50		28.23			28.64			24.15			21.60		28.33
Produced coal revenue per ton sold		36.02		30.79			31.30			27.51			26.86		29.36
Capital expenditures		347.2		164.4			135.1			247.5			204.8		37.7
Produced tons sold		40.4		41.0			42.1			43.7			40.2		7.0
Tons produced		42.0		41.0			43.9			45.1			41.5		7.0
Number of employees		5,034		4,428			4,552			5,004			3,610		5,040

⁽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 Corporation, subsequently renamed Massey Energy Company, which retained the Company’s coal-related businesses. 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% senior notes, $278.5 million of Fluor Corporation commercial paper, other equity contributions from Fluor Corporation, and assumed Fluor Corporation’s common stock equity structure. Therefore, the Selected Financial Data for years prior to 2001 are not necessarily indicative of the cash flows, results of operation and financial condition of Massey in the future or had it operated as a separate independent company during the periods prior to November 30, 2000.

⁽²⁾

The Company changed to a calendar-year basis of reporting financial results effective January 1, 2002. The selected financial data reported for 2000 through 2001 is as of and for the twelve month periods ended on 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.

⁽³⁾

Shares used to calculate basic earnings per share for the period ended October 31, 2000 are 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 period ended October 31, 2000 are 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 U.S., the effect of dilutive securities was excluded from the calculation of the diluted loss per common share for the years ended December 31, 2003 and 2002 and October 31, 2001, and for the two-month period ended December 31, 2001, as such inclusion would result in antidilution.

⁽⁴⁾	EBIT is defined as Income (Loss) before interest and taxes.

⁽⁵⁾

EBITDA is defined as EBIT before deducting 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. The table below reconciles the generally acceptable accounting principal measure of Net income (loss ) to EBITDA.


	Year Ended December 31,									Year Ended October 31,						Two Months Ended December 31, 2001
	2004			2003			2002			2001			2000			Two Months Ended December 31, 2001
	(In millions)
Net income (loss)	$	13.9		$	(40.2	)	$	(32.6	)	$	(5.4	)	$	78.5		$	(14.8	)
Cumulative effect of accounting change, net		—			7.9			—			—			—			—

Income (Loss) before cumulative effect of accounting change, net		13.9			(32.3	)		(32.6	)		(5.4	)		78.5			(14.8	)
Income tax (benefit) expense		(19.5	)		(28.3	)		(24.9	)		(10.5	)		43.2			(8.7	)
Interest expense (income), net		51.8			43.1			30.8			25.4			(25.2	)		4.3

Income (Loss) before interest and taxes		46.2			(17.5	)		(26.7	)		9.5			96.5			(19.2	)
Depreciation, depletion and amortization		224.6			196.5			207.7			181.3			171.3			31.2

EBITDA	$	270.8		$	179.0		$	181.0		$	190.8		$	267.8		$	12.0

⁽⁶⁾

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 produced 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 to Average cash cost per ton.


	Year Ended December 31,												Year Ended October 31,								Two Months Ended December 31, 2001
	2004				2003				2002				2001				2000				Two Months Ended December 31, 2001
	$		per ton		$		per ton		$		per ton		$		per ton		$		per ton		$		per ton
	(In millions, except per ton amounts)
Total costs and expenses	$	1,720.4			$	1,588.9			$	1,656.8			$	1,422.3			$	1,216.2			$	265.7
Less: Freight and handling costs		148.8				109.7				112.0				129.9				131.3				18.9
Less: Cost of purchased coal revenue		104.1				117.3				119.6				47.0				38.9				16.1
Less: Depletion, depreciation and amortization		224.6				196.5				207.7				181.3				171.3				31.2
Less: Other expense		9.5				9.8				11.2				7.7				5.5				1.9

Average cash cost	$	1,233.4	$	30.50	$	1,155.6	$	28.23	$	1,206.3	$	28.64	$	1,056.4	$	24.15	$	869.2	$	21.60	$	197.6	$	28.33

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

Massey operates coal mines and processing facilities in Central Appalachia, which generate revenues and cash flow through the mining, processing and selling of coal of steam and metallurgical grades, primarily of a low sulfur content. The Company also generates income and cash flow through other coal-related businesses, including the management of material handling facilities and a synfuel production plant. Other revenue is obtained from royalties, rentals, gas well revenues, gains on the sale of non-strategic assets, contract buyout payments and miscellaneous income. For the year ended December 31, 2004, approximately 64% of the Company’s produced coal sales were to U.S. electricity generators, 26% were to steel manufacturers in the U.S. and abroad, and 10% were to the U.S. industrial sector.

The Company reported net income for the year ended December 31, 2004 of $13.9 million, or $0.18 per basic and diluted share, compared to a net loss for 2003 of $40.2 million, or $0.54 per share. Included in the 2003 loss was an after-tax, non-cash charge of $7.9 million, or $0.11 per share, to record the cumulative effect of an accounting change, and a gain of $17.7 million pre-tax, or $0.15 per share, as a result of the recovery of an insurance claim.

Produced coal sales were 40.4 million tons in 2004, compared to 41.0 million tons in 2003. Shipments were negatively affected during the year by poor railroad service, the idling of a longwall at the Independence resource group due to a delay in the development of the next longwall panel, an extremely tight labor market, and other weather and production related issues. The Company produced 42.0 million tons during 2004, compared to 41.0 million tons produced in 2003. Exports increased to 6.7 million tons, including 1.9 million tons shipped to Canada, compared to 5.0 million tons exported in 2003, with 2.2 million tons shipped to Canada.

During 2004, Massey benefited from steady price increases approaching historic highs for both Central Appalachian steam and metallurgical coal due to a worldwide shortage of certain grades of coal. The Company’s average Produced coal revenue per ton sold in 2004 increased by 17% to $36.02 compared to $30.79 in 2003. Massey’s average Produced coal revenue per ton in 2004 for metallurgical tons sold increased by 32% in 2004 to $45.55 from $34.63 in 2003. Over the past five-year period, average Produced coal revenue per ton increased by 70% compared to $26.86 in 2000. The Company has been able to negotiate higher sales prices for contracted sales for the next three years. In reaction to the improved coal markets, the Company focused on building capacity during 2004, particularly by expanding its lower cost surface mine operations and purchasing new, more productive surface mine equipment. Total capital spending for 2004 was $347.2 million. Increased production from surface mines can free metallurgical grade coal to sell to the strengthened worldwide steel industry.

The Company experienced a significant increase in costs during the past 5-year period, with Average cash cost per ton sold increasing from $21.60 in fiscal 2000 to $30.50 in fiscal 2004 (a reconciliation of these non-GAAP figures is presented in footnote 6 of Item 6. Selected Financial Data). The increased cost level is mainly due to materially higher supply costs, including diesel fuel, steel and explosives, higher labor and benefit costs, and lower operating productivity. The Company’s management is focused on reducing costs and employing higher productivity mining methods, such as surface mining and highwall mining, and utilizing more high productivity mine equipment.

On January 20, 2004, the Company established an asset-based revolving credit facility that provides for borrowings of up to $130 million, depending on the level of eligible inventory and accounts receivable, and includes a $100 million sublimit for the issuance of letters of credit. This facility replaced an existing $80 million undrawn accounts receivable securitization facility that was set to expire in July 2004. On April 7, 2004, the Company issued $175 million in 2.25% convertible senior notes due April 1, 2024. The proceeds of this offering were partially utilized to reduce outstanding higher-cost debt.

On October 1, 2004, the Company reported that it concluded a purchase of selected assets associated with two Horizon mining operations, Starfire, located in Knott and Perry Counties, Kentucky, and Cannelton, located in Kanawha County, West Virginia. The assets acquired include an estimated 20 million tons of low sulfur coal reserves, two preparation plants, a barge loading facility, related infrastructure and selected mining equipment. The Cannelton operation was subsequently renamed Mammoth Coal Company, and began limited operations in December 2004. The Starfire operation was subsequently renamed Big Elk Mining Company.

Results of Operations

2004 Compared with 2003

Revenues

For the year ended December 31, 2004, produced coal revenue increased 15 percent to $1,456.7 million compared with $1,262.1 million for the year ended December 31, 2003. The following is a breakdown, by market served, of the changes in produced tons sold and average produced coal revenue per ton sold for 2004 compared to 2003:


	Year ended December 31,
(In Millions, Except Per Ton Amounts)	2004	2003	Increase (Decrease)		% Increase (Decrease)
Produced tons sold:
Utility	25.7	27.6	(1.9	)	(7	)%
Metallurgical	10.4	9.6	0.8		8	%
Industrial	4.3	3.8	0.5		13	%

Total	40.4	41.0	(0.6	)	(1	)%


	Year ended December 31,
	2004		2003		Increase (Decrease)		% Increase (Decrease)
Produced coal revenue per ton sold:
Utility	$	31.79	$	29.08	$	2.71	9	%
Metallurgical		45.55		34.63		10.92	32	%
Industrial		38.21		33.48		4.73	14	%
Weighted average		36.02		30.79		5.23	17	%

The improvement in Massey’s year-to-date average per ton sales prices is attributable to higher demand for all grades of coal in the U.S. and for metallurgical coal worldwide in 2004. A continuing global economic recovery and rapid economic expansion in China resulted in shortages of certain coals and led to increases in the market prices of these coals. The Company was able to take advantage of the market situation during 2004, even though the majority of its coal was committed to customers prior to the rise in coal prices, by shifting some production from the utility market to the higher-priced export metallurgical market, supplemented by purchases of steam coal for utility customers. The Company’s exports of metallurgical coal increased by 1.6 million tons, or 36 percent, to 6.1 million tons for 2004 from 4.5 million tons in 2003.

Freight and handling revenue increased $39.1 million, or 36 percent, to $148.8 million for 2004 compared with $109.7 million for 2003, due to increased export shipments and more shipments to customers where freight and handling are paid by the Company.

Purchased coal revenue decreased $10.3 million, or 9 percent, to $105.0 million for 2004 from $115.3 million for 2003, due to a decrease in purchased tons sold from 3.1 million in 2003 to 2.4 million in 2004. Massey purchases varying amounts of coal to supplement produced coal sales.

Other revenue, which consists of royalties, rentals, coal handling facility fees, gas well revenues, synfuel earnings, gains on the sale of non-strategic assets, contract buyout payments, and miscellaneous income, decreased to $56.2 million for 2004 from $66.6 million for 2003. The decrease was due to profits earned on several large customer contract buyouts that occurred in 2003, versus contract settlement losses experienced in 2004 related to the Company’s efforts to shift some production from the utility market to the export metallurgical market.

Insurance settlement revenue for the year ended December 31, 2003, consisted of $21.0 million of proceeds received for the settlement of a property and business interruption claim, which after adjusting for a previously booked receivable and claim settlement expenses, resulted in a gain of $17.7 million (pre-tax).

Costs

Cost of produced coal revenue increased approximately 5 percent to $1,175.9 million for 2004 from $1,115.9 million for 2003. This increase resulted from a variety of factors including heavy rains that caused flooding and power outages at a number of the Company’s mines in West Virginia during the summer months, higher labor and training costs due to an increasingly tight labor market for coal miners, increased supply costs, including diesel fuel, explosives and steel prices, and longwall productivity issues. Also negatively impacting cost of produced coal revenue were higher sales-related costs for production royalties and taxes associated with the increase in average realized prices. Generally, these sales-related costs are computed as a percentage of sales prices and will increase as coal revenues increase. Tons produced during the year ended December 31, 2004, were 42.0 million compared to 41.0 million during the year ended December 31, 2003. As production was greater than shipped tons, coal inventories (in various stages of production) increased during 2004.

Freight and handling costs increased $39.1 million, or 36 percent, to $148.8 million for 2004 compared with $109.7 million for 2003, due to increased export shipments and more shipments to customers where freight and handling are paid by the Company.

Cost of purchased coal revenue decreased $13.2 million, or 11 percent, to $104.1 million for 2004 from $117.3 million for 2003, due to a decrease in purchased tons sold from 3.1 million in 2003 to 2.4 million in 2004.

Depreciation, depletion and amortization increased by 14 percent to $224.6 million in 2004 compared to $196.5 million in 2003, due in part to a significant investment in new surface mining equipment during 2004 and the write-off of $6.1 million (pre-tax) of capitalized development costs at an idle mine and an active gas well during 2004.

Selling, general and administrative expenses were $57.5 million for the year ended December 31, 2004 compared to $39.7 million for the year ended December 31, 2003. The increase was primarily attributable to higher stock-based compensation accruals based on the appreciation and higher average market price of the Company’s common stock during 2004 compared to 2003 which was offset by a reduction in 2004 of the Company’s bad debt reserves of $4.3 million due to the re-evaluation of the total reserve, in light of improved market conditions for the steel industry and the Company’s tighter credit terms.

Other expense, which consists of costs associated with the generation of other revenue, such as costs to operate the coal handling facilities, gas wells, and other miscellaneous expenses, decreased slightly from $9.8 million in 2003 to $9.5 million in 2004.

Interest

Interest income of $8.8 million in 2004 was greater than the $5.2 million earned in 2003 as the Company had higher levels of cash reserves on hand during 2004 than in 2003 and $1.3 million recorded in 2004 related to black lung excise tax refund interest. Interest expense increased to $60.7 million for the year ended December 31, 2004 compared with $48.3 million for the year ended December 31, 2003. The higher interest expense was due in part to higher debt levels in 2004 compared to 2003 and to accruals for interest on the Harman lawsuit (see Note 19 to the Notes to Consolidated Financial Statements) of $6.8 million.

Income Taxes

Income tax benefit was $19.5 million for the year ended December 31, 2004 compared with $28.3 million for the year ended December 31, 2003. The tax rate in 2004 was favorably impacted by percentage depletion allowances, the closing of a prior period audit by the Internal Revenue Service, and the closing of a federal statutory period. In accordance with Company policy, a reserve was released for the closed statutory periods. Because of the tax benefit recognized as a result of the closing of the statutory periods and other factors, the tax rate for the twelve months ended December 31, 2004 should not be considered indicative of future tax rates.

Cumulative Effect of Accounting Change

Cumulative effect of accounting change was a charge of $7.9 million, net of tax of $5.0 million during 2003 related to the adoption of SFAS 143, as required, effective January 1, 2003. See Note 3 of the Notes to Consolidated Financial Statements for further information.

2003 Compared with 2002

Revenues

Produced coal revenue for the year ended December 31, 2003 decreased 4 percent to $1,262.1 million compared with $1,318.9 million for the year ended December 31, 2002. The following is a breakdown, by market served, of the changes in produced tons sold and average produced coal revenue per ton sold for 2003 compared to 2002:


	Year ended December 31,
(In Millions, Except Per Ton Amounts)	2003		2002		Increase (Decrease)			% Increase (Decrease)
Produced tons sold:
Utility		27.6		27.4		0.2		—
Metallurgical		9.6		10.9		(1.3	)	(12	)%
Industrial		3.8		3.8		—		—

Total		41.0		42.1		(1.1	)	(3	)%

Produced coal revenue per ton sold:
Utility	$	29.08	$	28.83	$	0.25		1	%
Metallurgical		34.63		35.77		(1.14	)	(3	)%
Industrial		33.48		36.42		(2.94	)	(8	)%
Weighted average		30.79		31.30		(0.51	)	(2	)%

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

Freight and handling revenue decreased $2.3 million, or 2 percent, to $109.7 million for 2003 compared with $112.0 million for 2002, due to a decrease in tons sold over the comparable periods and less shipments to customers where freight and handling costs are paid by the Company.

Purchased coal revenue decreased $1.7 million to $115.3 million for 2003 from $117.0 million for 2002, as the Company purchased and sold 3.1 million tons of coal in 2003 compared to 3.3 million tons in 2002. Massey purchases varying amounts of coal each year to supplement produced coal sales.

Other revenue, which consists of royalties, rentals, coal handling facility fees, gas well revenues, synfuel earnings, gains on the sale of non-strategic assets, contract buyout payments, and miscellaneous income, decreased to $66.6 million for 2003 from $82.1 million for 2002. The decrease was primarily due to a decrease in contract buyout payments from 2002, offset by increased earnings related to the operations of Appalachian Synfuel, in 2003.

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

Costs

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

Freight and handling costs decreased $2.3 million, or 2 percent, to $109.7 million for 2003 compared with $112.0 million for 2002, due to a decrease in tons sold over the comparable periods and fewer shipments to customers where freight and handling costs are paid by the Company.

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

Depreciation, depletion and amortization decreased by 5 percent to $196.5 million in 2003 compared to $207.7 million for 2002. The decrease was primarily due to a $13.2 million (pre-tax) write-off of mine development costs at certain idled mines in 2002. See Note 15 to the Notes to Consolidated Financial Statements for further discussion of impairment charges.

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

Other expense, which consists of costs associated with the generation of Other revenue, such as costs to operate the coal handling facilities, gas wells, and other miscellaneous expenses, decreased $1.4 million from $11.2 million for 2002 to $9.8 million for 2003.

Interest

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

Income Taxes

Income tax benefit was $28.3 million for 2003 compared with $24.9 million for 2002. The first quarter of 2002 included a refund for the settlement of a state tax dispute in the amount of $2.4 million, net of federal tax.

Cumulative Effect of Accounting Change

Cumulative effect of accounting change was a charge of $7.9 million, net of tax of $5.0 million for 2003 related to the required adoption of SFAS 143 effective January 1, 2003. As a result of adopting SFAS 143, the Company recognized a decrease in total reclamation liability of $13.1 million and a decrease in net deferred tax liability of $5.0 million. The Company capitalized asset retirement costs by increasing the carrying amount of the related long lived assets recorded in Property, plant and equipment, net of the associated accumulated depreciation, by $22.7 million. Additionally, the Company recognized a decrease in mining properties owned in fee and leased mineral rights, net of accumulated depletion, of $48.7 million related to amounts recorded in previous asset purchase transactions from assumption of pre-acquisition reclamation liabilities. See Note 3 to the Notes to Consolidated Financial Statements for further information.

Liquidity and Capital Resources

At December 31, 2004, the Company’s available liquidity was $185.6 million, which consisted of cash and cash equivalents of $122.5 million and $63.1 million availability under the Company’s asset-backed liquidity facility.

The Company’s debt was comprised of the following:


	December 31, 2004			December 31, 2003
	(In Thousands)
6.625% senior notes due 2010	$	335,000		$	360,000
6.95% senior notes due 2007		239,205			283,000
2.25% convertible senior notes due 2024		175,000			—
4.75% convertible senior notes due 2023		132,000			132,000
Capital lease obligations		40,809			16,254
Fair value hedge valuation		(1,486	)		(3,213	)

		920,528			788,041
Amounts due within one year		(20,333	)		(3,714	)

Total long term debt	$	900,195		$	784,327

Asset-Backed Credit Facility

On January 20, 2004, the Company established an asset-backed revolving credit facility, which replaced an existing $80 million accounts receivable-based financing program. The new credit facility provides for borrowings of up to $130 million, depending on the level of eligible inventory and accounts receivable. It includes a $100 million sublimit for the issuance of letters of credit. As of December 31, 2004, this facility supported $43.2 million of letters of credit. The facility is secured by the Company’s accounts receivable, eligible coal inventories located at its facilities and on consignment at customers’ facilities, and other intangibles. At December 31, 2004, total availability was $106.3 million based on qualifying inventory and accounts receivable. The credit facility has a five-year term ending in January 2009. This facility contains a number of significant restrictions and covenants that limit the Company’s ability to, among other things: (i) incur liens and debt or provide guarantees in respect of obligations of any other person; (ii) increase the Company’s common stock dividends above specified levels; (iii) make loans and investments; (iv) prepay, redeem or repurchase debt; (v) engage in mergers, consolidations and asset dispositions; (vi) engage in affiliate transactions; (vii) create any lien or security interest in any real property or equipment; (viii) engage in sale and leaseback transactions; and (ix) make distributions from subsidiaries.

2.25% Convertible Senior Note Issuance

On April 7, 2004, the Company closed a private placement sale under Rule 144A of the Securities Act of 1933, as amended, of $175 million of 2.25% convertible senior notes due April 1, 2024 (“2.25% Convertible Senior Notes”) resulting in net proceeds of approximately $170.3 million. The 2.25% Convertible Senior Notes are unsecured obligations ranking equally with all other unsecured senior indebtedness of the Company and are guaranteed by substantially all of Massey’s current and future subsidiaries. Interest on the 2.25% Convertible Senior Notes is payable on April 1 and October 1 of each year. Subsequently, the Company filed a registration statement on Form S-4 with the Securities and Exchange Commission, which was declared effective on June 28, 2004.

Holders of the 2.25% Convertible Senior Notes may require the Company to purchase all or a portion of their notes for cash on April 1, 2011, 2014, and 2019. In addition, the Company may redeem all or a portion of the 2.25% Convertible Senior Notes for cash at any time on or after April 6, 2011.

The 2.25% Convertible Senior Notes are convertible into shares of the Company’s common stock at a conversion rate of 29.7619 shares of common stock per $1,000 principal amount of 2.25% Convertible Senior Notes (subject to adjustment upon certain events) under the following circumstances: (i) if the price of the Company’s common stock issuable upon conversion reaches specified thresholds, (ii) if the Company calls the 2.25% Convertible Senior Notes for redemption, (iii) upon the occurrence of specified corporate transactions or (iv) if the credit ratings assigned to the 2.25% Convertible Senior Notes decline below certain specified levels. Regarding the thresholds in (i) above, holders may convert each of their notes into shares of the Company’s common stock during any calendar quarter (and only during such calendar quarter) if the last reported sale price of Massey’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% of the conversion price per share of Massey’s common stock. The conversion price is $33.60 per share. None of the 2.25% Convertible Senior Notes are currently eligible for conversion. If all of the notes currently outstanding were eligible and were converted, the Company would need to issue 5.2 million shares of common stock. The proceeds from the sale of the 2.25% Convertible Senior Notes were used for general corporate purposes, including the buyout of equipment lease obligations and repayment of outstanding indebtedness.

Debt Repurchases

During 2004, Massey made several open market purchases, retiring a total of $43.8 million of principal amount of 6.95% senior notes due March 1, 2007 (the “6.95% Senior Notes”) and $25.0 million of principal amount of 6.625% senior notes due November 15, 2010 (“6.625% Senior Notes”) at a cost of $45.1 million and $25.0 million respectively, plus accrued interest. At December 31, 2004, the Company had $239.2 million of 6.95% Senior Notes and $335.0 million of the 6.625% Senior Notes outstanding (see Note 8 to the Notes to the Consolidated Financial Statements for further discussion of the 6.95% and 6.625% Senior Notes).

Convertible Notes Threshold

The Company’s 4.75% convertible senior notes due May 15, 2023 (“4.75% Convertible Senior Notes”) are convertible by holders into shares of Massey’s common stock during certain periods under certain circumstances. As of December 31, 2004, the price of Massey’s common stock had reached the specified threshold for conversion. Consequently, the 4.75% Convertible Senior Notes are convertible until March 31, 2005, the last day of the Company’s first quarter. The 4.75% Convertible Senior Notes may be convertible beyond this date if the specified threshold for conversion is met in subsequent quarters. To date, no holder has requested that the 4.75% Convertible Senior Notes be converted to Massey’s common stock.

Debt Ratings

Moody’s Investors Service (“Moody’s”) and Standard & Poor’s (“S&P”) rate Massey’s long-term debt. As of February 28, 2005, Moody’s and S&P rated the 6.95% Senior Notes and the 4.75% Convertible Senior Notes, B1 and B+, respectively, and the 6.625% Senior Notes and the 2.25% Convertible Senior Notes, Ba3 and BB, respectively.

Cash Flow

Net cash provided by operating activities was $226.7 million for 2004 compared to $15.4 million for 2003. Cash provided by operating activities reflects Net income (loss) adjusted for non-cash charges and changes in working capital requirements. In 2004, $36.6 million of cash previously on deposit to collateralize letters of credit was released upon the closing of the new asset-based revolving credit facility. In 2003, $73.5 million was placed on deposit to collateralize letters of credit and other obligations. Additionally, in 2004, coal inventory increased by $53.2 million, mainly due to an increase of $37.9 million in Work in process surface mine inventory, as the Company started four new surface mines. (see Note 4 to the Notes to Consolidated Financial Statements for further discussion). Changes in deposits and inventory are included in Changes in operating assets and liabilities.

Net cash utilized by investing activities was $289.4 million and $144.0 million for 2004 and 2003, respectively. The cash used in investing activities reflects capital expenditures in the amount of $347.2 million and $164.4 million for 2004 and 2003, respectively. These capital expenditures are for replacement of mining equipment, the expansion of mining and shipping capacity, and projects to improve the efficiency of mining operations. In addition to the cash spent on capital expenditures, during 2004 and 2003 the Company leased $24.7 million and $6.4 million, respectively, of mining equipment through operating leases. Additionally, 2004 and 2003 included $57.7 million and $20.4 million, respectively, of proceeds provided by the sale of assets. Proceeds for the sale of assets for 2004 include approximately $28.5 million for the sale of a 50% interest in a joint venture to Penn Virginia to own and operate end user coal handling facilities (see Note 6 to the Notes to Consolidated Financial Statements for further discussion).

Financing activities primarily reflect changes in debt levels for 2004 and 2003, as well as the exercising of stock options and payments of dividends. Net cash provided by financing activities was $96.5 million and $214.6 million for 2004 and 2003, respectively. Net cash provided by financing activities for 2004 includes the proceeds from the issuance of the 2.25% Convertible Senior Notes of $170.3 million. Additionally, during 2004, the Company made several open-market debt repurchases, retiring a total principal amount of $43.8 million of the 6.95% Senior Notes and $25.0 million of the 6.625% Senior Notes at a cost of $45.1 million and $25.0 million, respectively. The Company generated $15.0 million from a sale-leaseback (capital lease) transaction of certain mining equipment in 2004, compared to $16.7 million of sale-leasebacks (operating leases) in 2003. During 2004, the Company also entered into an additional $27.3 million of capital leases for mining equipment.

Massey believes that cash on hand, cash generated from operations and its borrowing capacity will be sufficient to meet its working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments and anticipated dividend payments for at least the next few years. Nevertheless, the ability of Massey to satisfy its debt service obligations, to fund planned capital expenditures or pay dividends will depend upon its future operating performance, which will be affected by prevailing economic conditions in the coal industry and financial, business and other factors, some of which are beyond Massey’s control. Massey frequently evaluates potential acquisitions. In the past, Massey has funded acquisitions primarily with cash generated from operations, but Massey may consider a variety of other sources, depending on the size of any transaction, including debt or equity financing. There can be no assurance that such additional capital resources will be available to Massey on terms that Massey finds acceptable, or at all.

Contractual Obligations

The Company has various contractual obligations that are recorded as liabilities within the Consolidated Financial Statements. Other obligations, such as certain purchase commitments, operating lease agreements, and other executory contracts are not recognized as liabilities within the Consolidated Financial Statements but are required to be disclosed. The following table is a summary of the Company’s significant obligations as of December 31, 2004 and the future periods in which such obligations are expected to be settled in cash. The table does not include current liabilities accrued within the Company’s Consolidated Financial Statements, such as Accounts payable and Payroll and employee benefits.


	Payments Due by Period
In Thousands	Total		Within 1 Year		2-3 Years		4-5 Years		Beyond 5 Years
Long-term debt⁽¹⁾	$	1,238,124	$	47,319	$	323,897	$	61,847	$	805,061
Capital lease obligations⁽²⁾		44,445		19,118		17,475		3,464		4,388
Operating lease obligations⁽³⁾		97,024		43,805		42,621		10,598		—
Coal purchase obligations⁽⁴⁾		50,806		29,502		10,652		10,652		—
Coal lease obligations⁽⁵⁾		179,781		16,482		30,755		27,847		104,697
Other purchase obligations⁽⁶⁾		131,659		98,325		17,460		14,110		1,764

Total obligations	$	1,741,839	$	254,551	$	442,860	$	128,518	$	915,910

⁽¹⁾

Long-term debt obligations reflect the future interest and principal payments of the Company’s fixed rate senior unsecured notes outstanding as of December 31, 2004. These amounts also include the estimated net interest payments related to the interest rate swap covering a notional amount of debt of $240 million. Under the interest rate swap, the Company receives interest payments at a fixed rate of 6.625% and pays a variable rate that is based on six-month LIBOR plus 216 basis points. The Company has estimated the variable rate based on the LIBOR forward curve as of December 31, 2004. See Note 8 to the Notes to the Consolidated Financial Statements for additional information.

⁽²⁾	Capital lease obligations include the amount of imputed interest over the terms of the leases. See Note 9 to the Notes to the Consolidated Financial Statements for additional information.

⁽³⁾	See Note 9 to the Notes to the Consolidated Financial Statements for additional information.

⁽⁴⁾	Coal purchase obligations represent commitments to purchase coal from external production sources under firm contracts as of December 31, 2004.

⁽⁵⁾

Coal lease obligations includes minimum royalties paid on leased coal rights. Certain coal leases do not have set expiration dates but extend until completion of mining of all merchantable and mineable coal reserves. For purposes of this table, the Company has generally assumed that minimum royalties on such leases will be paid for a period of 20 years.

⁽⁶⁾

Other purchase obligations primarily include capital expenditure commitments for surface mining and other equipment as well as purchases of materials and supplies. The Company has purchase agreements with vendors for most types of operating expenses. However, the Company’s open purchase orders (which are not recognized as a liability until the purchased items are received) under these purchase agreements, combined with any other open purchase orders, are not material and are excluded from this table. Other purchase obligations also includes contractual commitments under transportation contracts. Since the actual tons to be shipped under these contracts are not set and will vary, the amount included in the table reflects the minimum payment obligations required by the contracts.

Additionally, the Company has liabilities relating to pension and other postretirement benefits, work related injuries and illnesses, and mine reclamation and closure. As of December 31, 2004, payments related to these items are estimated to be:


Payments Due by Years (In Thousands)
Within 1 Year	2 - 3 Years	4 - 5 Years
$51,823	$107,134	$103,555

The Company’s determination of these noncurrent liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if the Company’s assumptions are inaccurate, the Company could be required to expend greater amounts than anticipated. Moreover, in particular for periods after 2004, the Company’s estimates may change from the amounts included in the table, and may change significantly, if its assumptions change to reflect changing conditions. These assumptions are discussed in the Notes to the Consolidated Financial Statements and in the Critical Accounting Estimates and Assumptions of the Management’s Discussion and Analysis of Financial Condition and Results of Operation section.

Off-Balance Sheet Arrangements

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

The Company uses surety bonds to secure reclamation, workers’ compensation, wage payments, and other miscellaneous obligations. As of December 31, 2004, the Company had $311.0 million of outstanding surety bonds. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $281.5 million, workers’ compensation bonds of $10.0 million, wage payment and collection bonds of $8.7 million, and other miscellaneous obligation bonds of $10.8 million.

Generally, the availability and market terms of surety bonds continue to be challenging. If the Company is unable to meet certain financial tests, or to the extent that surety bonds otherwise become unavailable, the Company would need to replace the surety bonds or seek to secure them with letters of credit, cash deposits, or other suitable forms of collateral. As of December 31, 2004, the Company had secured $37.8 million of surety obligations with letters of credit.

From time to time the Company uses bank letters of credit to secure its obligations for worker’s compensation programs, various insurance contracts and other obligations. At December 31, 2004, the Company had $143.2 million of letters of credit outstanding (including the $37.8 million noted above that secure surety obligations), of which $100.0 million was collateralized by $105.0 million of cash deposited in restricted, interest bearing accounts pledged to issuing banks and $43.2 million was issued under the Company’s asset based lending arrangement. No claims were outstanding against those letters of credit as of December 31, 2004.

Certain Trends and Uncertainties

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

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

Shortages of skilled labor in the Central Appalachian coal industry may pose a risk to achieving high levels of productivity and competitive costs

Coal mining continues to be a labor-intensive industry. In 2004, the Company experienced a shortage of experienced mine workers when the demand and prices for all specifications of coal mined by the Company increased appreciably. The Company’s productivity and cash costs were negatively impacted by the hiring of these less experienced workers. A continued lack of skilled miners could continue to have an adverse impact on Massey’s labor productivity and cost and its ability to expand production to meet the increased demand for coal.

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.

Throughout 2004, the Company’s ability to ship coal was negatively impacted by a reduction in available and timely rail service. Lack of sufficient resources to meet the rapid increase in demand, a greater demand for transportation to export terminals and rail line congestion all seem to have contributed to the disruption and slowdowns in rail service. While the railroads have taken action to remedy these issues, including the purchase of new locomotives and railcars, as well as the hiring and training of additional crews, the Company expects weak rail service to continue to affect its operations through at least the first half of 2005 and could impact shipments in future years.

In 2004, more stringent coal truck weight limits and enforcement laws were adopted in the State of West Virginia. In addition, law enforcement officials in both the State of West Virginia and the Commonwealth of Kentucky stepped up enforcement of coal truck weight limits. Although Massey has historically avoided trucking coal on public roads, by transporting coal by rail, barge and conveyor systems whenever possible, such legislation and stepped up enforcement actions have resulted in reduced availability of trucks, shipment delays and increased costs.

Certain of Massey’s subsidiaries and other coal and transportation companies have been named as defendants in lawsuits in West Virginia. The suits allege that the defendants illegally transported 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 seek injunctive relief and damages. See Note 19 to the Notes to the Consolidated Financial Statements for further discussion of this litigation.

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

Massey incurs substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species laws, including regulations and governmental enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from the Company’s operations. The Company may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from its operations. See Item 1, Business, under the headings “Environmental, Safety and Health Laws and Regulations” for further discussion.

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

On February 16, 2005, the Governor of West Virginia signed into law an increase in the coal severance tax of $0.56 per clean ton on West Virginia coal production beginning November 30, 2005. The funds generated by this additional severance tax will be used to help the State of West Virginia resolve an estimated $3 billion shortfall in its workers’ compensation program. While Massey expects to be able to pass through a portion of this additional cost to its customers and expects some reduction in future workers’ compensation premiums, it does anticipate that the tax will add to its per ton cost beginning in late 2005.

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

Federal and state laws require bonds to secure the Company’s obligations to reclaim lands used for mining, to pay federal and state workers’ compensation, and to satisfy other miscellaneous obligations. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. The Company’s failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material impact on the Company. That failure could result from a variety of factors including the following: (i) lack of availability, higher expense or unfavorable market terms of new bonds; (ii) restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of the Company’s senior notes or revolving credit facilities; (iii) the inability of the Company to meet certain financial tests with respect to a portion of the post-mining reclamation bonds; and (iv) the exercise by third-party surety bond issuers of their right to refuse to renew the bonds.

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 North America, South America, Europe, Asia and Africa. 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.

High oil prices could lead to a phase-out of IRC Section 29 tax credits, reducing the Company’s earnings from a promissory note tied to Section 29 tax credits

Owners of facilities that produce synthetic fuels can qualify for tax credits under the provisions of IRC Section 29. In 2001 and 2002, the Company sold most its interest in a synfuel facility. As part of the compensation for the sale, the Company received a contingent promissory note that is paid on a cents per Section 29 credit dollar earned based on synfuel tonnage shipped through 2007. The payments to be received under the contingent promissory note may be reduced or eliminated if the price of oil remains above a certain threshold price set by the IRS (the “threshold price”). Once the threshold price is reached, the Section 29 credits will be phased out ratably over a $13.50 per barrel range above the threshold price. The threshold price for 2005 will be set by the IRS in April 2005 and is expected to be in the range of $50 to $60 per barrel. If the value of the Section 29 credits is eliminated or significantly reduced, the owner of the synfuel facility may elect to idle the facility, suspending the earnings the Company receives from the facility. During the year ending December 31, 2004, the Company recognized earnings of approximately $22 million related to the sale of the synfuel facility and activities related to the synfuel facility. Should the price of oil exceed the threshold price, the earnings the Company receives related to this synfuel facility will be reduced or eliminated and the Company may incur a loss.

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

Transportation costs represent a significant portion of the delivered cost of coal and, as a result, the cost of delivery is a critical factor in a customer’s purchasing decision. Increases in transportation costs could make coal a less competitive source of energy. Such increases could have a material impact on Massey’s ability to compete with other energy sources and on its cash flows, results of operations or financial condition. On the other hand, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country. For instance, coal mines in the western U.S. could become an attractive source of coal to consumers in the eastern part of the country if the costs of transporting coal from the west were significantly reduced.

Coal mining is subject to inherent risks

Massey’s operations are subject to certain events and conditions that could disrupt operations, including fires and explosions from methane, accidental minewater discharges, natural disasters, equipment failures, maintenance problems and flooding. Massey maintains insurance policies that provide limited coverage for some, but not all, of these risks. Even where insurance coverage applies, there can be no assurance that these risks would be fully covered by Massey’s insurance policies.

Critical Accounting Estimates and Assumptions

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires management to make estimates and assumptions that affect reported amounts. These estimates and assumptions are based on information available as of the date of the financial statements. Significant changes to the estimates and assumptions used in determining certain liabilities described below introduce substantial volatility to the Company’s costs. The following critical accounting estimates and assumptions were used in the preparation of the financial statements:

Defined Benefit Pension

The estimated cost and benefits of the Company’s non-contributory defined benefit pension plans are determined by independent actuaries, who, with the Company’s review and approval, use various actuarial assumptions, including discount rate, future rate of increase in compensation levels and expected long-term rate of return on pension plan assets. The discount rate is an estimate of the current interest rate at which the applicable liabilities could be effectively settled as of the measurement date. In estimating the discount rate, the Company looks to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. At December 31, 2004, the discount rate used to determine defined benefit pension liability was 5.75% compared to 6.25% at December 31, 2003. A decrease in the assumed discount rate increases the Company’s defined benefit pension obligation. Such increases in the obligation are included in actuarial gains and losses and recognized in the determination of the defined benefit pension expense over the remaining service lives of plan participants. The rate of increase in compensation levels is determined based upon the Company’s long-term plans for such increases. The rate of increase in compensation levels used was 4.0% for the years ended December 31, 2004 and 2003. The expected long-term rate of return on pension plan assets is based on long-term historical return information and future estimates of long-term investment returns for the target asset allocation of investments that comprise plan assets. The expected long-term rate of return on plan assets used to determine expense in each period was 8.5%, 8.5% and 9.0% for the years ended December 31, 2004, 2003 and 2002, respectively. A decrease in the expected rate of return assumption increases the defined benefit pension expense.

Coal Workers’ Pneumoconiosis

The Company is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, and various states’ statutes, for the payment of medical and disability benefits to eligible recipients resulting from occurrences of coal workers’ pneumoconiosis disease (black lung). An annual evaluation is prepared by the Company’s independent actuaries, who, after review and approval by the Company, use various assumptions regarding disability incidence, medical costs trend, cost of living trend, mortality, death benefits, dependents and interest rates. The Company records expense related to this obligation using the service cost method. At December 31, 2004, the discount rate used to determine the black lung liability was 5.75% compared to 6.25% at December 31, 2003. A decrease in the assumed discount rate increases the Company’s black lung liability. Such increases in the liability are included in actuarial gains and losses and recognized in the determination of the black lung expense over a five-year period. Included in Note 12 to the Notes to the Consolidated Financial Statements is a medical cost trend and cost of the Company’s living trend sensitivity analysis.

Workers’ Compensation

The Company’s operations have workers’ compensation coverage through a combination of either self-insurance, participation in a state run program, or commercial insurance. The Company accrues for the self-insured liability by recognizing cost when it is probable that the liability has been incurred and the cost can be reasonably estimated. To assist in the determination of this estimated liability the Company utilizes the services of third party administrators who derive claim reserves from historical experience. These third parties provide information to independent actuaries, who after review and consultation with the Company with regards to actuarial assumptions, including discount rate, prepare an evaluation of the self-insured liabilities. At December 31, 2004, the discount rate used to determine the self-insured workers’ compensation liability obligation was 5.75% compared to 6.25% at December 31, 2003. A decrease in the assumed discount rate increases the workers’ compensation self-insured liability and related expense. Actual experience in settling these liabilities could differ from these estimates, which could increase the Company’s costs.

Other Postretirement Benefits

The Company’s sponsored health care plans provide retiree health benefits to eligible union and non-union retirees who have met certain age and service requirements. Depending on year of retirement, benefits may be subject to annual deductibles, coinsurance requirements, lifetime limits, and retiree contributions. These plans are not funded. Costs are paid by the Company as incurred by participants. The estimated cost and benefits of the Company’s retiree health care plans are determined by independent actuaries, who, after review and approval by the Company, use various actuarial assumptions, including discount rate, expected trend in health care costs and per capita costs. At December 31, 2004, the discount rate used to determine the other postretirement benefit liability was 5.75% compared to 6.25% at December 31, 2003. A decrease in the assumed discount rate increases the Company’s retiree medical liability. Such increases in the liability are included in actuarial gains and losses and recognized in the determination of the retiree medical expense over the remaining service lives of plan participants. At December 31, 2004 the Company’s assumptions of the company health care plans’ cost trend were projected at an annual rate of 10.0% ranging down to 5.0% by 2010 (11.0% ranging down to 5.0% by 2010 at December 31, 2003), and remaining level thereafter. Included in Note 13 to the Notes to the Consolidated Financial Statements is a sensitivity analysis on the health care trend rate assumption.

Reclamation and Mine Closure Obligations

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

Contingencies

The Company is the subject of, or a party to, various suits and pending or threatened litigation involving governmental agencies or private interests. The Company has accrued the probable and reasonably estimable costs for the resolution of these claims based upon management’s best estimate of potential results, assuming a combination of litigation and settlement strategies. Unless otherwise noted, management does not believe that the outcome or timing of current legal or environmental matters will have a material impact on its cash flows, results of operations or financial condition. See Item 3, Legal Proceeding’s and Note 19 to the Notes to the Consolidated Financial Statements for further discussion on the Company’s contingencies.

Income Taxes

The Company accounts for income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”), which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, the Company takes into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in the evaluation of the Company’s valuation allowance, the Company records a change in valuation allowance through income tax expense in the period such determination is made.

Coal Reserve Values

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves. Many of these uncertainties are beyond the Company’s control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about the Company’s reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by its staff. Some of the factors and assumptions that impact economically recoverable reserve estimates include: (i) geological conditions; (ii) historical production from similar areas with similar conditions; (iii) the assumed effects of regulations and taxes by governmental agencies; (iv) assumptions governing future prices; and (v) 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.

Recent Accounting Pronouncements

On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”) which requires all share-based payments to employees, including grants of employee stock options, be recognized in the income statement based on their grant date fair values for interim or annual periods beginning after June 15, 2005. Pro forma disclosure of stock option expense will no longer be permitted. The cost will be recognized over the requisite service period that an employee must provide to earn the award (i.e. usually the vesting period). The Company expects to adopt SFAS 123R on July 1, 2005 using the “modified prospective” method and expects a pre-tax charge to income of approximately $1.9 million for the expensing of unvested stock options for the period July 1, 2005 through December 31, 2005. SFAS 123R also requires the benefits of tax deductions in excess of recognized compensation cost be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement will reduce net operating cash flows and increase net financing cash flows in periods after adoption.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs: An Amendment of ARB 43, Chapter 4” (“SFAS 151”). SFAS 151 amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). Paragraph 5 of ARB 43, Chapter 4 previously stated that “under some circumstances, items such as idle facility expense, excess spoilage, double freight, and re-handling costs may be so abnormal as to require treatment as current period charges.” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, SFAS 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The provisions of SFAS 151 are effective for inventory cost incurred during fiscal years beginning after June 15, 2005. The Company does not expect the adoption of this statement to have a material impact on its financial statements.

In the second quarter of 2004, in response to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Medicare Modernization Act”) enacted on December 8, 2003, the FASB issued Staff Position No. FAS 106-2 “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). The Medicare Modernization Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company included the effects of the Medicare Modernization Act in its financial statements as of July 1, 2004 in accordance with FSP 106-2. Incorporation of the provisions of the Medicare Modernization Act resulted in a reduction in the Company’s postretirement benefit obligation as of July 1, 2004 of $27.2 million. The impact of the Medicare Modernization Act resulted in a reduction in the net periodic postretirement benefit cost of $2.1 million for the second half of 2004. Certain definitions and interpretations, yet to be issued by the federal government, could require the Company to adjust future estimates.

At its September 2004 meeting, the Emerging Issues Task Force (“EITF”) reached a final consensus on EITF Issue No. 04-8, “The Effect of Contingently Convertible Debt on Diluted Earnings Per Share,” concerning the accounting for contingently convertible debt instruments, commonly referred to as Co-Cos, which was ratified by the FASB on October 13, 2004. Under previous interpretations of FASB SFAS No. 128, “Earnings per Share,” issuers of Co-Cos excluded the potential common shares underlying the Co-Co from the calculation of diluted earnings per share until the market price or other contingency was met. When the contingency was met, generally the if-converted method was used to calculate the dilutive impact of the instrument. Under the if-converted method, the instrument is considered converted, with the resulting number of shares included in the denominator of the diluted earnings per share calculation and the interest expense, net of tax, added back to the numerator of the diluted earnings per share. The EITF concluded that the contingently issuable shares guidance in SFAS 128 does not apply to convertible debt. Therefore, the EITF determined that issuers of Co-Cos should include the dilutive effect in the calculation of diluted earnings per share immediately upon issuance of the instrument, generally using the if-converted method. The EITF concluded that application should be by retroactive restatement of earnings per share. The implementation date was for reporting periods ending after December 15, 2004, or the fourth quarter of 2004 for the Company. See Note 2 to the Notes to Consolidated Financial Statements in the Earnings Per Share section for a discussion of the Company’s convertible notes and the impact on earnings per share.

In March 2004, the FASB issued EITF Issue No. 04-2, “Whether Mineral Rights Are Tangible or Intangible Assets” (“EITF 04-2”). In this issue, the EITF reached the consensus that mineral rights are tangible assets. This consensus differed from the requirements of SFAS No. 141 “Business Combinations” (“SFAS 141”) and SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) which characterize mineral rights as intangible assets. As a result, the FASB amended SFAS 141 and SFAS 142 to eliminate the inconsistency. Historically, the Company has treated mineral rights as a tangible asset included within Property, plant and equipment, therefore, EITF 04-2 had no effect on its financial statements.

Other Accounting Developments

The Company currently accounts for the costs of removing overburden and waste materials (stripping costs) incurred during the production phase of a mine as a component of surface mining inventory costs. As overburden is removed, the stripping costs are captured in inventory costs and attributed to the proved reserves benefited. It is generally accepted in practice in the mining industry that stripping costs prior to production phase of the mine are capitalized as part of the initial development of a surface mine. Those capitalized costs are typically amortized over the productive life of the mine using the units of production method. There is diversity in practice throughout the mining industry with no consistent application with regards to stripping costs during the production phase of the mine. The EITF has established a Mining Industry Working Group that is currently considering this issue (Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry”). The conclusions of the EITF with regards to the classification and recognition of production phase stripping costs may have a significant impact on the Company’s financial statements depending on the findings of the task force. See Note 2 in the Inventory section to the Notes to Consolidated Financial Statements for a discussion of the Company’s inventory costs.

Inflation

Generally, inflation in the U.S. has been relatively low in recent years. However, over the course of the last twelve months, the Company has been significantly impacted by price inflation in many of the components of its Cost of goods sold, such as fuel, steel, copper and labor. For instance, the prices of diesel fuel, steel and copper increased approximately 42%, 101% and 42%, respectively, over the twelve-month period ending December 31, 2004.

Item 7A.

Quantitative and Qualitative Discussions about Market Risk

Massey’s interest expense is sensitive to changes in the general level of short-term interest rates. At December 31, 2004, the outstanding $920.5 million aggregate principal amount of long-term debt was under fixed-rate instruments; however, the primary exposure to market risk for changes in interest rates relates to an interest rate swap entered into on November 10, 2003, covering a notional amount of debt of $240 million. Based on the notional amount outstanding of $240 million, a hypothetical 100 basis point increase in the specified swap interest rate index would increase annual interest expense by approximately $2.4 million. The projected present value of the swap instrument is partially determined by movements in interest rates, and Massey may be required to post cash deposits with the swap counterparty if the present value in favor of the counterparty exceeds certain threshold amounts based on Massey’s credit rating at the time. If it should become necessary to borrow under the new asset-based revolving credit facility, those borrowings would be also made at a variable rate.

The Company manages its market price risk for coal through the use of long-term coal supply agreements, which are contracts with a term of 12 months or greater, rather than through the use of derivative instruments. The Company believes that the percentage of its sales pursuant to these long-term contracts was approximately 93% for its fiscal year ended December 31, 2004. The Company anticipates that in 2005, the percentage of sales pursuant to long-term contracts will be comparable with the percentage of sales for 2004. 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 REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Massey Energy Company

We have audited the accompanying consolidated balance sheets of Massey Energy Company as of December 31, 2004 and 2003, and the related consolidated statements of income, cash flows, and shareholders’ equity for each of the three years in the period ended December 31, 2004. Our audits 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 the standards of the Public Company Accounting Oversight Board (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, 2004 and December 31, 2003, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

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

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Massey Energy Company’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 14, 2005 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Richmond, Virginia

March 14, 2005

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Amounts)


	Year Ended
	December 31, 2004			December 31, 2003			December 31, 2002
Revenues
Produced coal revenue	$	1,456,684		$	1,262,098		$	1,318,935
Freight and handling revenue		148,795			109,720			112,017
Purchased coal revenue		104,955			115,304			117,049
Other revenue		56,210			65,945			78,804
Insurance settlement		—			17,677			—
Senior notes repurchase income		—			615			3,290

Total revenues		1,766,644			1,571,359			1,630,095

Costs and Expenses
Cost of produced coal revenue		1,175,900			1,115,858			1,166,159
Freight and handling costs		148,795			109,720			112,017
Cost of purchased coal revenue		104,109			117,281			119,562
Depreciation, depletion and amortization applicable to:
Cost of produced coal revenue		220,135			191,994			203,921
Selling, general and administrative		4,482			4,501			3,809
Selling, general and administrative		57,525			39,715			40,111
Other expense		9,509			9,832			11,204

Total costs and expenses		1,720,455			1,588,901			1,656,783

Income (Loss) before interest and taxes		46,189			(17,542	)		(26,688	)
Interest income		8,828			5,150			4,470
Interest expense		(60,660	)		(48,259	)		(35,302	)

Loss before taxes		(5,643	)		(60,651	)		(57,520	)
Income tax benefit		19,495			28,318			24,946

Income (Loss) before cumulative effect of accounting change		13,852			(32,333	)		(32,574	)
Cumulative effect of accounting change, net of tax		—			(7,880	)		—

Net income (loss)	$	13,852		$	(40,213	)	$	(32,574	)

Income (Loss) per share - Basic
Income (Loss) before cumulative effect of accounting change	$	0.18		$	(0.43	)	$	(0.44	)
Cumulative effect of accounting change		—			(0.11	)		—

Net income (loss)	$	0.18		$	(0.54	)	$	(0.44	)

Income (Loss) per share - Diluted
Income (Loss) before cumulative effect of accounting change	$	0.18		$	(0.43	)	$	(0.44	)
Cumulative effect of accounting change		—			(0.11	)		—

Net income (loss)	$	0.18		$	(0.54	)	$	(0.44	)

Shares used to calculate income (loss) per share
Basic		75,262			74,592			74,442
Diluted		76,450			74,592			74,442

See Notes to Consolidated Financial Statements.

MASSEY ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)


	December 31, 2004			December 31, 2003
ASSETS
Current Assets
Cash and cash equivalents	$	122,531		$	88,753
Trade and other accounts receivable, less allowance of $4,240 and $8,350, respectively		168,873			152,607
Inventories		259,785			206,616
Deferred taxes		3,085			12,783
Income taxes receivable		36,876			15,715
Other current assets		199,548			226,048

Total current assets		790,698			702,522

Net Property, Plant and Equipment		1,640,203			1,480,187
Other Noncurrent Assets
Pension assets		68,952			64,748
Other		151,052			129,281

Total other noncurrent assets		220,004			194,029

Total assets	$	2,650,905		$	2,376,738

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable, principally trade and bank overdrafts	$	134,969		$	109,418
Short-term debt		20,333			3,714
Payroll and employee benefits		31,007			26,374
Other current liabilities		145,993			119,768

Total current liabilities		332,302			259,274

Noncurrent Liabilities
Long-term debt		900,195			784,327
Deferred taxes		216,460			227,105
Other		425,075			347,076

Total noncurrent liabilities		1,541,730			1,358,508

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 – 76,430,992 and 75,508,359, respectively		47,769			47,193
Additional capital		39,925			24,270
Unamortized executive stock plan expense		(6,162	)		(6,219	)
Retained earnings		695,492			693,712
Other comprehensive loss		(151	)		—

Total shareholders’ equity		776,873			758,956

Total liabilities and shareholders’ equity	$	2,650,905		$	2,376,738

See Notes to Consolidated Financial Statements.

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)


	Year Ended
	December 31, 2004			December 31, 2003			December 31, 2002
Cash Flows From Operating Activities
Net income (loss)	$	13,852		$	(40,213	)	$	(32,574	)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Cumulative effect of accounting change		—			7,880			—
Depreciation, depletion and amortization		224,617			196,495			207,730
Deferred taxes		1,181			(11,255	)		3,511
(Gain) Loss on disposal of assets		(22,789	)		(16,201	)		(12,567	)
Loss (Gain) on repurchase of senior notes		1,279			(615	)		(3,290	)
Writeoff of deferred financing costs		—			6,331			—
Changes in operating assets and liabilities:
(Increase) Decrease in accounts receivable		(19,465	)		20,298			13,266
Increase in inventories		(53,169	)		(12,947	)		(37,876	)
Decrease (Increase) in other current assets		26,582			(108,677	)		(17,657	)
(Increase) Decrease in pension and other assets		(17,714	)		9,428			2,365
Increase (Decrease) in accounts payable and bank overdrafts		25,551			(15,515	)		(61,877	)
Increase in income taxes receivable		(21,161	)		(9,278	)		(4,557	)
Increase (Decrease) in other accrued liabilities		35,271			(35,059	)		76,950
Increase (Decrease) in other non-current liabilities		32,625			24,736			(10,949	)

Cash provided by operating activities		226,660			15,408			122,475

Cash Flows From Investing Activities
Capital expenditures		(347,152	)		(164,372	)		(135,099	)
Proceeds from sale of assets		57,731			20,418			13,127

Cash utilized by investing activities		(289,421	)		(143,954	)		(121,972	)

Cash Flows From Financing Activities
(Decrease) Increase in short-term debt, net		—			(264,045	)		944
Repurchase of senior notes		(70,799	)		(2,385	)		(10,710	)
Repayment of capital lease obligations		(17,770	)		—			—
Proceeds from issuance of 6.625% senior notes		—			353,700			—
Proceeds from issuance of convertible senior notes		170,275			128,040			—
Proceeds from term loan issuance		—			244,142			—
Repayment of term loan borrowings		—			(250,455	)
Proceeds from sale and leaseback of equipment		15,000			16,710			16,955
Cash dividends paid		(12,024	)		(11,931	)		(11,919	)
Stock options exercised		11,857			798			1,408

Cash provided (utilized) by financing activities		96,539			214,574			(3,322	)

Increase (Decrease) in cash and cash equivalents		33,778			86,028			(2,819	)
Cash and cash equivalents at beginning of period		88,753			2,725			5,544

Cash and cash equivalents at end of period	$	122,531		$	88,753		$	2,725

Supplemental Cash Flow Information
Cash paid during the period for income taxes	$	572		$	516		$	1,156

See Notes to Consolidated Financial Statements.

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(In Thousands, Except Per Share Amounts)


	Common Stock			Additional Capital		Unamortized Executive Stock Plan Expense			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
	Shares	Amount		Additional Capital		Unamortized Executive Stock Plan Expense			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity
Balance at December 31, 2001	74,774	$	46,734	$	18,559	$	(6,133	)	$	790,379		$	—		$	849,539

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

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

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

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

Net income										13,852						13,852
Other comprehensive loss, net of deferred tax of $81:
Minimum pension liability adjustment													(151	)		(151	)

Comprehensive income																13,701

Dividends declared ($0.16 per share)										(12,072	)					(12,072	)
Exercise of stock options, net	890		557		11,300											11,857
Stock option tax benefit					2,046											2,046
Amortization of executive stock plan expense							2,385									2,385
Issuance of restricted stock, net	33		19		2,309		(2,328	)								—

Balance at December 31, 2004	76,431	$	47,769	$	39,925	$	(6,162	)	$	695,492		$	(151	)	$	776,873

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 and sole, direct operating subsidiary A.T. Massey Coal Company, Inc. (“A.T. Massey”) and A.T. Massey’s wholly owned subsidiaries. Massey is a non-operating holding company. Significant intercompany transactions and accounts are eliminated in consolidation. Massey does not have a controlling interest in any separate independent operations. Investments in business entities in which the Company does not have control, but has the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method.

A.T. Massey fully and unconditionally guarantees the Company’s obligations under the 6.95% senior notes due 2007 (the “6.95% Senior Notes”), the 6.625% senior notes due 2010 (the “6.625% Senior Notes”), the 4.75% convertible senior notes due 2023 (the “4.75% Convertible Senior Notes”) and the 2.25% convertible senior notes due 2024 (the “2.25% Convertible Senior Notes”). In addition, the 6.625% Senior Notes and the 2.25% Convertible Senior Notes are guaranteed by substantially all of the Company’s indirect operating subsidiaries. The subsidiaries not providing a guarantee of the 6.625% Senior Notes and the 2.25% Convertible Senior Notes are minor (as defined under SEC Rule 3-10(h)(6) of Regulation S-X). See Note 8 for a more complete discussion of debt.

2.	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. The most significant estimates used in the preparation of the consolidated financial statements are related to defined benefit pension plans, coal workers’ pneumoconiosis (black lung), workers’ compensation, other postretirement benefits, reclamation and mine closure obligations, contingencies, income taxes and coal reserve values.

Cash and Cash Equivalents

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

Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains a bad debt reserve based upon the expected collectibility of its accounts receivable. The reserve includes specific amounts for accounts that are likely to be uncollectible, as determined by such variables as customer creditworthiness, the age of the receivables, bankruptcies and disputed amounts. Account balances are charged off against the reserve after all means of collection have been exhausted and the potential for recovery is considered remote.

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.

The Company currently accounts for the costs of removing overburden and waste materials (stripping costs) incurred during the production phase of a mine as a component of surface mining inventory costs. As overburden is removed, the stripping costs are captured in inventory costs and attributed to the proven reserves benefited. It is generally accepted in practice in the mining industry that stripping costs prior to production phase of the mine are capitalized as part of the initial development of a surface mine. Those capitalized costs are typically amortized over the productive life of the mine using the units of production method. There is diversity in practice throughout the mining industry with no consistent application with regards to stripping costs during the production phase of the mine. The Emerging Issues Task Force (the “EITF”) of the Financial Accounting Standards Board (“FASB”) has established a Mining Industry Working Group that is currently considering this issue (Issue No. 04-6, “Accounting for Stripping Costs in the Mining Industry”). The conclusions of the EITF with regards to the classification and recognition of production phase stripping costs may change the classification of Work in process inventory and may have a significant impact on the Company’s financial statements depending on the findings of the task force.

Income Taxes

The Company accounts for income taxes in accordance with FASB Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes” (“SFAS 109”), which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. SFAS 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, the Company takes into account various factors, including the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in the evaluation of the Company’s valuation allowance, the Company records a change in valuation allowance through income tax expense in the period such determination is made.

Longwall Panel Costs

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

Property, Plant and Equipment

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

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

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

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

Depletion of mining properties owned in fee and leased mineral rights is computed using the units-of-production method over the estimated proven and probable reserve tons. As of December 31, 2004, approximately $54.2 million of costs associated with mining properties owned in fee and leased mineral rights is not currently subject to depletion as mining has not begun or production has been temporarily idled on the associated coal reserves.

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 estimated 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 15 for a description of impairment charges that were recorded in the Consolidated Statements of Income.

Advance Mining Royalties

Coal leases, which require minimum annual or advance payments and are recoverable from future production are generally deferred and charged to expense as the coal is subsequently produced. At December 31, 2004 and 2003, advance mining royalties included in Other noncurrent assets totaled $31.2 and $27.5 million, net of an allowance of $13.5 and $11.6 million, respectively.

Reclamation

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

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

Pension Plans

The Company sponsors a noncontributory defined benefit pension plan covering substantially all administrative and non-union employees. The computation of benefits for this plan varies based on the date of entry in the plan, and is based either on years of service and employee compensation during the highest consecutive five years or benefits on a cash balance formula with contribution credits based on hours worked. The Company’s policy is to annually fund the defined benefit pension plans at or above the minimum required by law. The Company accounts for its defined benefit pension plans in accordance with SFAS No. 87, “Employers’ Accounting for Pension” (“SFAS 87”), which requires the cost to provide benefits be accrued over the employees’ estimated remaining service life.

Workers’ Compensation

The Company is liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in which it has operations. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee that is injured in the course of employment. The Company’s operations have workers’ compensation coverage through a combination of either a self-insurance program, as a participant in a state run program, or by an insurance policy. The Company accrues for the self-insured liability by recognizing cost when it is probable that the liability has been incurred and the cost can be reasonably estimated. To assist in the determination of this estimated liability the Company utilizes the services of third party administrators who derive claim reserves from historical experience. These third parties provide information to independent actuaries, who after review and consultation with the Company with regards to actuarial assumptions, including discount rate, prepare an evaluation of the self-insured program liabilities.

Black Lung Benefits

The Company is responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, and various states’ statutes for the payment of medical and disability benefits to employees and their dependents resulting from occurrences of coal worker’s pneumoconiosis disease (black lung). The Company provides for federal and state black lung claims principally through a self-insurance program. The Company uses the service cost method to account for its self-insured black lung obligation. The liability measured under the service cost method represents the discounted future estimated cost for former employees either receiving or projected to receive benefits, and the portion of the projected liability relative to prior service for active employees projected to receive benefits.

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

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

Postretirement Benefits Other than Pension

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

Under the Coal Industry Retiree Health Benefits Act of 1992 (the “Coal Act”), coal producers are required to fund medical and death benefits of certain retired union coal workers based on premiums assessed by the United Mine Workers of America (“UMWA”) Benefit Funds. The Company treats its obligation under the Benefit Act as a participation in a multi-employer plan as permitted by EITF No. 92-13, “Accounting for Estimated Payments in Connection with the Coal Industry Retiree Health Benefit Act of 1992,” and records the cost of the Company’s obligation as expense as payments are assessed.

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 2.4 million, 3.1 million, and 3.3 million tons for the years ended December 31, 2004, 2003, and 2002, respectively.

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

During the third quarter of 2003, the Company received $21.0 million for the settlement of a property and business interruption claim related to the Martin County impoundment discharge (see Note 19), which, after adjusting for a previously booked receivable and claim settlement expenses, resulted in a gain of $17.7 million (pre-tax) and is reflected in Insurance settlement for the year ended December 31, 2003.

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. Stock-based compensation other than stock options is recorded to expense on a straight-line basis. The Company has implemented the disclosure-only provisions of SFAS No. 123 “Accounting for Stock-Based Compensation” (“SFAS 123”). The Company has recognized no stock-based compensation expense related to stock options in any period as all options granted had an exercise price equal to market value of the underlying common stock on the date of the grant.

If the Company had followed the fair value method under SFAS 123 to account for stock based compensation cost for stock options using a straight-line basis, 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
	December 31, 2004			December 31, 2003			December 31, 2002
	(In Thousands, Except Per Share Amounts)
Net income (loss), as reported	$	13,852		$	(40,213	)	$	(32,574	)
Deduct: Total stock-based employee compensation expense for stock options determined under Black-Scholes option pricing model (net of tax)		(2,138	)		(2,082	)		(2,135	)

Pro forma net income (loss)	$	11,714		$	(42,295	)	$	(34,709	)

Income (Loss) per share:
Basic – as reported	$	0.18		$	(0.54	)	$	(0.44	)

Basic – pro forma	$	0.16		$	(0.57	)	$	(0.47	)

Diluted – as reported	$	0.18		$	(0.54	)	$	(0.44	)

Diluted – pro forma	$	0.15		$	(0.57	)	$	(0.47	)

The estimated fair value as of the date of grant for options granted to Massey employees during the years ended December 31, 2004, 2003 and 2002 was determined using the Black-Scholes option-pricing model based on the following weighted average assumptions:


	Year Ended
	December 31, 2004		December 31, 2003		December 31, 2002
Expected option lives (years)	4.3		5.0		5.0
Risk-free interest rates	3.56	%	3.25	%	3.08	%
Expected dividend yield	0.53	%	1.20	%	2.84	%
Expected volatility	55.1	%	48.4	%	49.4	%

The weighted average fair value of options granted by the Company during the years ended December 31, 2004, 2003 and 2002 using the Black-Scholes option-pricing model was $13.67, $5.55 and $2.23, respectively.

Earnings Per Share

The number of shares used to calculate basic earnings (loss) per share is based on the weighted average number of outstanding shares of Massey during the respective periods. The number of shares used to calculate diluted earnings (loss) per share is based on the number of shares used to calculate basic earnings (loss) per share plus the dilutive effect of stock options and other stock-based instruments held by Massey employees and directors during each period and debt securities currently convertible into common stock during each period. In accordance with accounting principles generally accepted in the United States, the effect of dilutive securities in the amount of 10.3 million, 4.4 million and 0.1 million shares for the years ended December 31, 2004, 2003 and 2002, respectively, was excluded from the calculation of the diluted loss per common share for all periods as such inclusion would result in antidilution.

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


	Year Ended
	December 31, 2004		December 31, 2003			December 31, 2002
	(In Thousands, Except Per Share Amounts)
Numerator:
Income (loss) before cumulative effect of accounting change	$	13,852	$	(32,333	)	$	(32,574	)
Cumulative effect of accounting change		—		(7,880	)		—

Net income (loss) – numerator for basic and diluted	$	13,852	$	(40,213	)	$	(32,574	)

Denominator:
Weighted average shares – denominator for basic		75,262		74,592			74,442
Effect of stock options/restricted stock		1,188		—			—

Adjusted weighted average shares – denominator for diluted		76,450		74,592			74,442

Income (loss) per share:
Basic:
Before cumulative effect of accounting change	$	0.18	$	(0.43	)	$	(0.44	)
Cumulative effect of accounting change		—		(0.11	)		—

Net income (loss)	$	0.18	$	(0.54	)	$	(0.44	)

Diluted:
Before cumulative effect of accounting change	$	0.18	$	(0.43	)	$	(0.44	)
Cumulative effect of accounting change		—		(0.11	)		—

Net income (loss)	$	0.18	$	(0.54	)	$	(0.44	)

The Company’s 4.75% Convertible Senior Notes are convertible by holders into shares of Massey’s common stock during certain periods under certain circumstances. As of December 31, 2004, the price of Massey’s common stock had reached the specified threshold for conversion. Consequently, the 4.75% Convertible Senior Notes are convertible until March 31, 2005, the last day of the Company’s first quarter. The 4.75% Convertible Senior Notes may be convertible beyond this date if the specified threshold for conversion is met in subsequent quarters. To date, no holder has requested that the 4.75% Convertible Senior Notes be converted to Massey’s common stock. If all of the notes outstanding at December 31, 2004 had been converted, the Company would have needed to issue 6,807,636 shares. In addition, holders of the Company’s 4.75% Convertible Senior Notes may require Massey to purchase all or a portion of their 4.75% Convertible Senior Notes on May 15, 2009, May 15, 2013, and May 15, 2018. For purchases on May 15, 2013 or May 15, 2018, the Company may, at its option, choose to pay the purchase price in cash or in shares of Massey’s common stock or any combination thereof. See Note 8 for further discussion of the conversion and redemption features of the 4.75% Convertible Senior Notes.

The Company’s 2.25% Convertible Senior Notes are convertible by holders into shares of Massey’s common stock during certain periods under certain circumstances. None of the 2.25% Convertible Senior Notes were eligible for conversion at December 31, 2004. If all of the notes outstanding at December 31, 2004 had been eligible and were converted, the Company would have needed to issue 5,208,333 shares. See Note 8 for further discussion of conversion features of the 2.25% Convertible Senior Notes.

Derivatives

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

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

Accounting Pronouncements

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs: An Amendment of ARB 43, Chapter 4” (SFAS 151). This statement amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). Paragraph 5 of ARB 43, Chapter 4 previously stated that “under some circumstances, items such as idle facility expense, excess spoilage, double freight, and re-handling costs may be so abnormal as to require treatment as current period charges.” SFAS 151 requires that those items be recognized as current-period charges regardless of whether they meet the criterion of “so abnormal.” In addition, this statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The provisions of this statement are effective for inventory cost incurred during fiscal years beginning after June 15, 2005. The Company does not expect the adoption of the statement to have a material impact on its financial statements.

In the second quarter of 2004, in response to the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“the Medicare Modernization Act”) enacted on December 8, 2003, the FASB issued Staff Position No. 106-2 “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (“FSP 106-2”). The Medicare Modernization Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company included the effects of the Medicare Modernization Act in its financial statements as of July 1, 2004 in accordance with FSP 106-2. Incorporation of the provisions of the Medicare Modernization Act resulted in a reduction to the Company’s postretirement benefit obligation as of July 1, 2004 of $27.2 million. The impact of the Medicare Modernization Act resulted in a reduction in the net periodic postretirement benefit cost of $2.1 million for the second half of 2004. Certain definitions and interpretations, yet to be issued by the federal government, could require the Company to adjust future estimates.

At its September 2004 meeting, the EITF reached a final consensus on EITF Issue No. 04-8, “The Effect of Contingently Convertible Debt on Diluted Earnings Per Share,” concerning the accounting for contingently convertible debt instruments, commonly referred to as Co-Cos, which was ratified by the FASB on October 13, 2004. Under previous interpretations of SFAS No. 128, “Earnings per Share” (“SFAS 128”), issuers of Co-Cos excluded the potential common shares underlying the Co-Co from the calculation of diluted earnings per share until the market price or other contingency was met. When the contingency was met, generally the if-converted method was used to calculate the dilutive impact of the instrument. Under the if-converted method, the instrument is considered converted, with the resulting number of shares included in the denominator of the diluted earnings per share calculation and the interest expense, net of tax, added back to the numerator of the diluted earnings per share. The EITF concluded that the contingently issuable shares guidance in SFAS 128 does not apply to convertible debt. Therefore, the EITF determined that issuers of Co-Cos should include the dilutive effect in the calculation of diluted earnings per share immediately upon issuance of the instrument, generally using the if-converted method. The EITF concluded that application should be by retroactive restatement of earnings per share. The implementation date was for reporting periods ending after December 15, 2004, or the fourth quarter of 2004 for the Company. See Earnings Per Share section above for a discussion of the Company’s convertible notes and the impact on earnings per share.

In March 2004, the FASB issued EITF Issue No. 04-2, “Whether Mineral Rights Are Tangible or Intangible Assets” (“EITF 04-2”). In this issue, the EITF reached the consensus that mineral rights are tangible assets. This consensus differed from the requirements of SFAS No. 141 “Business Combinations” (“SFAS 141”) and SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”), which characterize mineral rights as intangible assets. As a result, the FASB amended SFAS 141 and SFAS 142 to eliminate the inconsistency. Historically, the Company has treated mineral rights as a tangible asset included within Property, plant and equipment, therefore, EITF 04-2, had no effect on its financial statements.

Reclassifications

Certain prior year amounts in the Consolidated Financial Statements have been reclassified to conform to current year presentation. The Company reclassified $17.9 million to Freight and handling revenue and costs for the year ended December 31, 2003. Previously, these amounts were presented “net” within Freight and handling costs.

3.	Cumulative Effect of Accounting Change for Reclamation Liabilities

Effective January 1, 2003, the Company changed its method of accounting for reclamation liabilities in accordance with SFAS 143. As a result of adoption of SFAS 143, the Company recognized a decrease in total reclamation liability of $13.1 million. The Company capitalized asset retirement costs by increasing the carrying amount of the related long lived assets recorded in Property, plant and equipment, net of the associated accumulated depreciation, by $22.7 million. Additionally, the Company recognized a decrease in mining properties owned in fee and leased mineral rights, net of accumulated depletion, of $48.7 million related to amounts recorded in previous asset purchase transactions from assumption of pre-acquisition reclamation liabilities. The Company also recognized a decrease in net deferred tax liability of $5.0 million as a result of adoption of SFAS 143.

The cumulative effect of the change on prior years resulted in a charge to income in 2003 of $7.9 million ($0.11 per share), net of income taxes of $5.0 million. The pro forma effects of the application of SFAS 143 as if the statement had been applied retroactively are presented below:


	Year Ended
	December 31, 2003			December 31, 2002
	(In Thousands, Except Per Share Amounts)
Net loss, as reported	$	(40,213	)	$	(32,574	)
Pro forma net loss	$	(32,333	)	$	(33,631	)
Loss per share:
Basic—as reported	$	(0.54	)	$	(0.44	)
Basic—pro forma	$	(0.43	)	$	(0.45	)
Diluted—as reported	$	(0.54	)	$	(0.44	)
Diluted—pro forma	$	(0.43	)	$	(0.45	)

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


	Year Ended
	December 31, 2004			December 31, 2003
	(In Thousands)
Reclamation liability at beginning of period	$	105,759		$	115,038
Cumulative effect		—			(13,124	)
Accretion expense		8,743			7,832
Liability incurred		32,649			2,935
Revisions in estimated cash flows		11,606			6,536
Payments		(6,090	)		(13,458	)

Reclamation liability at end of period		152,667			105,759
Less amount included in Other current liabilities		16,596			12,184

Total noncurrent liability	$	136,071		$	93,575

Liability incurred for the year ended December 31, 2004, includes approximately $25 million of reclamation associated with an acquisition made in the third quarter of 2004 (see Note 6 for further discussion).

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

4.	Inventories

Inventories consisted of the following:


	December 31, 2004		December 31, 2003
	(In Thousands)
Saleable coal	$	62,893	$	65,844
Raw coal		59,190		47,691
Work in process		100,937		63,073

Subtotal coal inventory	$	223,020	$	176,608
Supplies inventories		36,765		30,008

Total inventory	$	259,785	$	206,616

Saleable coal represents coal ready for sale, including inventories designated for customer facilities under consignment arrangements of $38.1 million and $44.8 million at December 31, 2004 and 2003, respectively. Raw coal represents coal that generally requires further processing prior to shipment to the customer. Work in process consists of the costs incurred to remove overburden above an unmined coal seam as part of the surface mining process.

5.	Other Current Assets

Other current assets are comprised of the following:


	December 31, 2004		December 31, 2003
	(In Thousands)
Longwall panel costs	$	53,687	$	44,174
Deposits		111,141		147,782
Other		34,720		34,092

Total other current assets	$	199,548	$	226,048

Deposits consist primarily of funds placed in restricted accounts with financial institutions to collateralize letters of credit that support workers’ compensation requirements, insurance and other obligations. Deposits also include collateral held from customers as credit enhancement, with a corresponding liability recorded within Other current liabilities. Deposits at December 31, 2004 and 2003 include $105.0 million and $141.6 million, respectively, of funds pledged as collateral to support outstanding letters of credit (see Note 8 for further discussion).

6.	Property, Plant and Equipment

Property, plant and equipment is comprised of the following:


	December 31, 2004			December 31, 2003
	(In Thousands)
Land, buildings and equipment	$	1,858,160		$	1,705,588
Mining properties owned in fee and leased mineral rights		630,419			598,222
Mine development		625,391			561,555

Total property, plant and equipment		3,113,970			2,865,365
Less accumulated depreciation, depletion and amortization		(1,473,767	)		(1,385,178	)

Net property, plant and equipment	$	1,640,203		$	1,480,187

Land, buildings and equipment includes gross assets under capital lease of $67.4 million and $16.3 million at December 31, 2004 and 2003, respectively.

During the third quarter of 2004, the Company purchased selected assets associated with two operations of Horizon Natural Resources Company (“Horizon”), which was in Chapter 11 bankruptcy, Starfire (subsequently renamed Big Elk Mining Company), located in Knott and Perry Counties, Kentucky, and Cannelton (subsequently renamed Mammoth Coal Company), located in Kanawha County, West Virginia. The Company paid $10 million in cash, plus the assumption of related property reclamation liabilities of approximately $25 million. The assets acquired include an estimated 15 to 20 million tons of low sulfur coal reserves, two preparation plants, a barge loading facility, related infrastructure and selected mining equipment. The United States Bankruptcy Court for the Eastern District of Kentucky approved the purchase of the Horizon assets.

During the third quarter of 2004, the Company entered into a joint venture agreement with Penn Virginia Resource Partners, L.P. to own and operate end user coal handling facilities. Penn Virginia purchased a 50% interest in the joint venture from Massey for approximately $28.5 million, from which Massey realized a pre-tax gain of approximately $13 million. Approximately $1.7 million of this gain was recognized in 2004. The remaining gain of $11 million (included in Other noncurrent liabilities) will be recognized over the terms of the related coal handling facility agreements. The Company accounts for its remaining 50% investment interest using the equity method and the balance is included in Other noncurrent assets.

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

7.	Income Taxes

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


	Year Ended
	December 31, 2004			December 31, 2003			December 31, 2002
	(In Thousands)
Current:
Federal	$	(20,691	)	$	(17,069	)	$	(24,694	)
State and local		15			57			(3,763	)

Total current		(20,676	)		(17,012	)		(28,457	)
Deferred:
Federal		518			(14,621	)		1,050
State and local		663			(1,671	)		2,461

Total deferred		1,181			(16,292	)		3,511

Total income tax benefit	$	(19,495	)	$	(33,304	)	$	(24,946	)

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


	Year Ended
	December 31, 2004			December 31, 2003			December 31, 2002
	(In Thousands)
U.S. statutory federal tax expense	$	(1,975	)	$	(25,731	)	$	(20,132	)
Increase (Decrease) resulting from:
State taxes		379			(1,740	)		(4,558	)
Items without tax effect		688			888			1,526
Depletion		(24,257	)		(8,050	)		(7,350	)
ETI/FSC income		(1,622	)		(1,050	)		(1,050	)
Alternative minimum tax adjustment		15,842			1,357			5,631
Reserve release		(7,300	)		—			(4,080	)
Other, net		(1,250	)		1,022			5,067

Total income tax benefit	$	(19,495	)	$	(33,304	)	$	(24,946	)

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, 2004			December 31, 2003
	(In Thousands)
Deferred tax assets:
Postretirement benefit obligations	$	43,582		$	35,027
Worker’s compensation		16,922			17,016
Reclamation and mine closure		45,666			47,246
Alternative minimum tax credit carryforwards		115,668			90,587
State net operating loss		14,204			14,204
Other		47,120			27,404

		283,162			231,484
Valuation allowance for deferred tax assets		(122,628	)		(97,547	)

Deferred tax assets, net		160,534			133,937

Deferred tax liabilities:
Plant, equipment and mine development		(246,522	)		(229,124	)
Mining property and mineral rights		(113,569	)		(105,517	)
Other		(13,818	)		(13,618	)

Total deferred tax liabilities		(373,909	)		(348,259	)

Net deferred tax liabilities	$	(213,375	)	$	(214,322	)

The Company’s deferred tax assets include alternative minimum tax (“AMT”) credits of $115.7 million and $90.6 million at December 31, 2004 and 2003, respectively. The AMT credits have no expiration date. State net operating loss carryforwards begin to expire in 2016. The Company has recorded a valuation allowance for a portion of its deferred tax assets that management believes, more likely than not, will not be realized. These deferred tax assets include AMT credits and state net operating losses that will likely not be realized at the maximum effective tax rate.

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. During 2004, the Company’s tax reserve was reduced by $7.3 million, reflecting the reduction in exposure due to the lapsing of the statutory period for assessing tax on the tax period ending in 2000 and the closing of a prior period audit on the tax period ending in 1999, partially offset by additional exposures identified for the current tax year. In addition, payments for federal taxes and state taxes of $526,000, and $470,000 were applied against the reserve during the years ended December 31, 2004 and 2003, respectively, as a result of audits of prior years.

The Company’s federal income tax returns have been examined by the Internal Revenue Service (the “IRS”), or statutes of limitations have expired through 2000. The Company is currently under audit from the IRS for the calendar year ended December 31, 2002 and the fiscal year ended October 31, 2001. Management believes that the Company has adequately provided for any income taxes and interest that may ultimately be paid with respect to all open tax years.

Debt

The Company’s debt is comprised of the following:


	December 31, 2004			December 31, 2003
	(In Thousands)
6.625% senior notes due 2010	$	335,000		$	360,000
6.95% senior notes due 2007		239,205			283,000
2.25% convertible senior notes due 2024		175,000			—
4.75% convertible senior notes due 2023		132,000			132,000
Capital lease obligations (see Note 9)		40,809			16,254
Fair value hedge valuation		(1,486	)		(3,213	)

		920,528			788,041
Amounts due within one year		(20,333	)		(3,714	)

Total long-term debt	$	900,195		$	784,327

The weighted average effective interest rate of the outstanding borrowings was 5.1% and 5.4% at December 31, 2004 and 2003, respectively, after giving effect to the interest rate swap (discussed in this Note under Fair Value Hedge). At December 31, 2004, the Company’s available liquidity was $185.6 million, including cash and cash equivalents of $122.5 million and $63.1 million availability on its asset-based revolving credit facility.

6.625% Senior Notes

The 6.625% Senior Notes due 2010 are unsecured obligations of the Company and rank equally with all other unsecured senior indebtedness of the Company. Interest is payable semiannually on May 15 and November 15 of each year. The Company may redeem the 6.625% Senior Notes, in whole or in part, at any time on or after November 15, 2007 at a redemption price equal to 100% of the principal amount plus a premium declining ratably to par, plus accrued and unpaid interest. At any time on or before November 15, 2006, the Company may redeem up to 35% of the aggregate principal amount of the notes with the proceeds of qualified equity offerings at a redemption price of 106.625% of the principal amount, plus accrued and unpaid interest. The 6.625% Senior Notes are guaranteed by A.T. Massey and substantially all of the Company’s current and future operating subsidiaries (the “Guarantors”). The guarantees are full and unconditional obligations of the Guarantors and are joint and several among the Guarantors. The subsidiaries not providing a guarantee of the 6.625% Senior Notes are minor (as defined under SEC Rule 3-10(h)(6) of Regulation S-X).

Part of the proceeds of the issuance of the 6.625% Senior Notes in November of 2003 was used to permanently repay the $249.4 million outstanding under the Company’s $250 million senior secured term loan. The Company recognized a charge of $6.3 million (pre-tax) for the write-off of unamortized financing fees related to the term loan. The charge is included within Interest expense for the year ended December 31, 2003.

The 6.625% Senior Notes contain a number of significant restrictions and covenants that limit the Company’s ability and its subsidiaries’ ability to, among other things: (i) incur liens and debt or provide guarantees in respect of obligations of any other person; (ii) increase the Company’s common stock dividends above specified levels; (iii) make loans and investments; (iv) prepay, redeem or repurchase debt; (v) engage in mergers, consolidations and asset dispositions; (vi) engage in affiliate transactions; (vii) create any lien or security interest in any real property or equipment; (viii) engage in sale and leaseback transactions; and (ix) restrict distributions from subsidiaries.

During 2004, the Company made several open-market purchases, retiring a total principal amount of $25.0 million of the 6.625% Senior Notes at a cost of $25.0 million, including accrued interest.

6.95% Senior Notes

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

During 2004, 2003 and 2002, the Company made several open-market purchases, retiring a total principal amount of $43.8 million, $3.0 million and $14.0 million, respectively, of the 6.95% Senior Notes at a cost of $45.1 million, $2.4 million and $10.7 million, respectively. A net loss of $1.3 million related to the repurchases was recognized in 2004 and is shown in the Consolidated Statements of Income in Other expense. Gains of $0.6 million and $3.3 million were recognized in 2003 and 2002, respectively, and are shown in the Consolidated Statements of Income in Senior notes repurchase income.

2.25% Convertible Senior Note Issuance

On April 7, 2004, the Company issued $175 million of the 2.25% Convertible Senior Notes due 2024, resulting in net proceeds of approximately $170.3 million. The 2.25% Convertible Senior Notes are unsecured obligations of the Company, rank equally with all other unsecured senior indebtedness of the Company and are guaranteed by substantially all of Massey’s current and future operating subsidiaries. Interest is payable semiannually on April 1 and October 1 of each year. The Company registered the 2.25% Convertible Senior Notes with the Securities and Exchange Commission for resale.

Holders of the 2.25% Convertible Senior Notes may require the Company to purchase all or a portion of their notes for cash on April 1, 2011, 2014, and 2019, at a purchase price equal to 100% of the principal amount of the notes to be redeemed, plus any accrued and unpaid interest. In addition, if the Company experiences certain specified types of fundamental changes on or before April 1, 2011, the holders may require the Company to purchase the notes for cash. The Company may redeem all or a portion of the 2.25% Convertible Senior Notes for cash at any time on or after April 6, 2011, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus any accrued and unpaid interest.

The 2.25% Convertible Senior Notes are convertible during certain periods by holders into shares of the Company’s common stock initially at a conversion rate of 29.7619 shares of common stock per $1,000 principal amount of 2.25% Convertible Senior Notes (subject to adjustment upon certain events) under the following circumstances: (i) if the price of the Company’s common stock issuable upon conversion reaches specified thresholds; (ii) if the 2.25% Convertible Senior Notes are redeemed by the Company; (iii) upon the occurrence of certain specified corporate transactions; or (iv) if the credit ratings assigned to the 2.25% Convertible Senior Notes decline below certain specified levels. Regarding the thresholds in (i) above, holders may convert each of their notes into shares of the Company’s common stock during any calendar quarter (and only during such calendar quarter) if the last reported sale price of Massey’s common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% of the conversion price per share of Massey’s common stock. The conversion price is $33.60 per share. None of the 2.25% Convertible Senior Notes are currently eligible for conversion. As of December 31, 2004, if all of the notes outstanding were eligible and were converted, the Company would need to issue 5.2 million shares of common stock.

The proceeds from the private placement sale of the 2.25% Convertible Senior Notes were used for general corporate purposes, including the buyout of equipment lease obligations and repayment of outstanding indebtedness.

4.75% Convertible Senior Notes

The 4.75% Convertible Senior Notes due 2023 are unsecured obligations of the Company and rank equally with all other unsecured senior indebtedness of the Company and is guaranteed by the Company’s wholly owned subsidiary, A.T. Massey, which together with its subsidiaries accounts for substantially all of the Company’s assets and all of its revenues. Interest is payable semiannually on May 15 and November 15 of each year. The Company registered the 4.75% Convertible Senior Notes with the SEC for resale.

Holders of the 4.75% Convertible Senior Notes may require Massey to purchase all or a portion of their notes on May 15, 2009, 2013, and 2018. On May 15, 2009, the Company must pay cash for all 4.75% Convertible Senior Notes so purchased. For purchases on May 15, 2013 or 2018, the Company may, at its option, choose to pay the purchase price for such 4.75% Convertible Senior Notes in cash or in shares of Massey’s common stock or any combination thereof. The Company may redeem some or all of the 4.75% Convertible Senior Notes at any time on or after May 20, 2009, at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus any accrued and unpaid interest.

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

As of December 31, 2004, the price of Massey’s common stock had reached the specified threshold for conversion. Consequently, the 4.75% Convertible Senior Notes are convertible until March 31, 2005, the last day of the Company’s first quarter. The 4.75% Convertible Senior Notes may be convertible beyond this date if the specified threshold for conversion is met in subsequent quarters. To date, no holder has requested that the 4.75% Convertible Senior Notes be converted to Massey’s common stock.

Fair Value Hedge

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

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

Asset-Based Lending Arrangement

On January 20, 2004, the Company entered into a new asset-based revolving credit facility, secured by its inventory, accounts receivable, and other intangibles. The facility provides for borrowings of up to $130 million, depending on the level of eligible inventory and accounts receivables and includes a $100 million sublimit for letters of credit. This facility replaced the Company’s prior undrawn $80 million accounts receivable-based financing program. As of December 31, 2004, this facility supported $43.2 million of letters of credit. The credit facility has a five-year term ending in January 2009. This facility contains a number of significant restrictions and covenants that limit the Company’s ability to, among other things: (i) incur liens and debt or provide guarantees in respect of obligations of any other person; (ii) increase the Company’s common stock dividends above specified levels; (iii) make loans and investments; (iv) prepay, redeem or repurchase debt; (v) engage in mergers, consolidations and asset dispositions; (vi) engage in affiliate transactions; (vii) create any lien or security interest in any real property or equipment; (viii) engage in sale and leaseback transactions; and (ix) make distributions from subsidiaries.

$355 Million Secured Credit Facility

On July 2, 2003, the Company refinanced its prior revolving credit facilities. The Company executed a $355 million secured financing package consisting of a $105 million revolving credit facility and a $250 million secured term loan secured by substantially all of the Company’s assets except accounts receivable. The revolving credit facility was scheduled to expire on January 1, 2007 and the secured term loan was scheduled to expire on July 2, 2008. These credit facilities were subsequently repaid and canceled on November 10, 2003 in connection with the issuance of the 6.625% Senior Notes.

Debt Maturity

The aggregate amounts of scheduled long-term debt maturities, including capital lease obligations, subsequent to December 31, 2004 are as follows:


	(In Thousands)
2005	$	20,333
2006		9,713
2007		242,870
2008		1,407
2009		1,480
Beyond 2009^*		644,725

Total	$	920,528

The 4.75% Convertible Senior Notes in the amount of $132 million included herein may be redeemed by the holders in 2009.

Total interest paid for the years ended December 31, 2004, 2003 and 2002, was $54.0 million, $46.5 million and $35.4 million, respectively.

Off-Balance Sheet Arrangements

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

The Company uses surety bonds to secure reclamation, workers’ compensation, wage payments, and other miscellaneous obligations. As of December 31, 2004, the Company had $311.0 million of outstanding surety bonds. Those bonds were in place to secure obligations as follows: post-mining reclamation bonds of $281.5 million, workers’ compensation bonds of $10.0 million, wage payment and collection bonds of $8.7 million, and other miscellaneous obligation bonds of $10.8 million.

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 or be issued under the Company’s asset-based revolving credit facility. At December 31, 2004, the Company had $143.2 million of letters of credit outstanding, of which $100.0 million was collateralized by $105.0 million of cash deposited in restricted, interest bearing accounts pledged to issuing banks, and $43.2 million was issued under the Company’s asset-based lending arrangement. No claims were outstanding against those letters of credit as of December 31, 2004.

9.	Lease Obligations

The Company leases two office buildings and certain mining and other equipment under various lease agreements. Certain of these leases provide options for the purchase of the property at the end of the initial lease term, generally at its then fair market value, or to extend the terms at its then fair rental value. Certain of these leases contain financial covenants that may require an accelerated buyout of the lease if the covenants are violated. Rental expense for the years ended December 31, 2004, 2003, and 2002, was $44.2 million, $61.5 million, and $53.4 million, respectively.

During 2004, the Company generated $15.0 million of cash from a sale-leaseback (capital lease) transaction of certain mining equipment with no resulting gain or loss on the transaction. The Company also entered into an additional $27.3 million of capital leases for mining equipment. The leases are for periods ranging from approximately 2 to 3 years with no residual value guarantee.

In December 2003, the Company entered into $16.3 million of capital leases for certain mining equipment. The leases are for periods ranging from 1 to 7 years. The leases contain residual value guarantees at the end of the lease term, which are included within the table below.

In 2003, the Company sold and leased-back certain mining equipment. The Company received net proceeds of $16.7 million, resulting in a gain of $1.7 million, which was deferred. The gain is being recognized ratably over the term of the leases, which range from 2 to 6 years. The leases contain renewal options at lease termination and purchase options at an amount approximating fair value at lease termination. The leases are being accounted for as operating leases. Future payments required under the leases are included within the table below.

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

The following presents future minimum rental payments, by year, required under leases with initial terms greater than one year, in effect at December 31, 2004:


	Capital Leases		Operating Leases
	(In Thousands)
2005	$	19,118	$	43,805
2006		13,386		31,295
2007		4,089		11,326
2008		1,732		5,783
2009		1,732		4,815
Beyond 2009		4,388		—

Total minimum lease payments		44,445	$	97,024

Less imputed interest		3,636

Present value of minimum capital lease payments	$	40,809

10.

Pension Plans

Defined Benefit Pension Plans

Massey sponsors a qualified non-contributory defined benefit pension plan, which covers substantially all administrative and non-union employees. Based on a participant’s entrance date to the plan, the participant may accrue benefits based on one of four benefit formulas. Two of the formulas provide pension benefits based on the employee’s years of service and average annual compensation during the highest five consecutive years of service. The third formula credits certain eligible employees with flat dollar contributions based on years of service with the Company and years of service under the UMWA 1974 Pension Plan. The fourth formula provides benefits under a cash balance formula with contribution credits based on hours worked. For contributions prior to January 1, 2004, the cash balance formula guaranteed a set rate of return of 6.5% annually. This guaranteed rate of return on contributions was changed effective January 1, 2004 to 4% for all future contributions. Funding for the plan is generally at the minimum annual contribution level required by applicable regulations. A voluntary contribution of $10 million was made to the qualified plan during the fourth quarter of 2004. No company contributions were made in 2003 or 2002 for this qualified plan.

The plan assets for the qualified defined benefit pension plan are held by an independent trustee. The plan’s assets include cash and cash equivalents, corporate and government bonds, preferred and common stocks and an investment in a group annuity contract. There were no investments in Massey Energy Company common stock held by the plan at December 31, 2004 or 2003. The Company has an internal investment committee that sets investment policy, selects and monitors investment managers and monitors asset allocation. Diversification of assets is employed to reduce risk. The target asset allocation is 63% for equity securities (including 50% domestic and 13% international) and 37% for cash and interest bearing securities. The investment policy is based on the assumption that the overall portfolio volatility will be similar to that of the target allocation. Given the volatility of the capital markets, strategic adjustments in various asset classes may be required to rebalance asset allocation back to its target policy. Investment fund managers are not permitted to invest in certain securities and transactions as outlined by the investment policy statements specific to each investment category without prior investment committee approval.

To develop the expected long-term rate of return on assets assumption, the Company considered the historical returns and the future expectations for returns for each asset class, as well as the target asset allocation of the pension portfolio. This resulted in the selection of the 8.5% long-term rate of return on assets assumption for the year ended December 31, 2004.

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


	December 31, 2004				December 31, 2003
	(Dollars In Thousands)
Equity securities (domestic and international)	$	144,429	63.8	%	$	134,384	65.9	%
Debt securities		59,727	26.4	%		59,082	29.0	%
Other (includes cash, cash equivalents and a group annuity contract)		22,272	9.8	%		10,415	5.1	%

Total fair value of plan assets	$	226,428	100	%	$	203,881	100	%

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

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


	Year Ended
	December 31, 2004			December 31, 2003
	(In Thousands)
Change in benefit obligation:
Benefit obligation at the beginning of the period	$	200,453		$	168,711
Service cost		8,032			11,471
Interest cost		12,121			11,282
Actuarial loss		14,800			16,198
Plan amendment		(797	)		—
Benefits paid		(7,932	)		(7,209	)

Benefit obligation at end of period	$	226,677		$	200,453


Change in plan assets:
Fair value at the beginning of the period	$	203,881		$	173,996
Actual return on assets		20,451			37,067
Company contributions		10,028			27
Benefits paid		(7,932	)		(7,209	)

Fair value of plan assets at end of period	$	226,428		$	203,881

Funded status	$	(249	)	$	3,428
Unrecognized net actuarial loss		64,494			56,066
Unrecognized prior service cost		217			1,055

Accrued pension assets recognized (net)		64,462			60,549


Amounts recognized in the consolidated balance sheets:
Net pension prepaid asset	$	68,952		$	64,748
Accrued benefit liability, included in noncurrent liabilities		(4,983	)		(4,460	)
Intangible asset		261			261
Additional minimum pension liability, included in accumulated other comprehensive loss		232			—

Net amount recognized	$	64,462		$	60,549


	Year Ended
	December 31, 2004		December 31, 2003
	(In Thousands)
Qualified Defined Benefit Pension Plan:
Projected benefit obligation	$	221,671	$	195,391
Accumulated benefit obligation	$	213,701	$	185,367
Fair value of plan assets	$	226,428	$	203,881

Nonqualified Supplemental Benefit Pension Plan:
Projected benefit obligation	$	5,006	$	5,062
Accumulated benefit obligation	$	4,983	$	4,308
Fair value of plan assets	$	—	$	—

The provisions of SFAS 87 require the recognition of an additional minimum liability and related intangible asset for plans with an accumulated benefit obligation (“ABO”) in excess of plan assets. No minimum pension liability was required at December 31, 2004 or 2003 for the qualified defined benefit pension plan as the fair value of the plan assets exceeded the ABO. The nonqualified supplemental benefit pension plan is an unfunded plan and required an increase in minimum liability of $232,000, which is included in accumulated Other comprehensive loss, net of $81,000 deferred tax.

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


	December 31, 2004		December 31, 2003
Discount rates	5.75	%	6.25	%
Rates of increase in compensation levels	4.00	%	4.00	%
Measurement date	12/31/2004		12/31/2003

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


	Year Ended
	December 31, 2004			December 31, 2003			December 31, 2002
	(In Thousands)
Service cost	$	8,032		$	11,471		$	10,649
Interest cost		12,121			11,282			10,256
Expected return on plan assets		(16,966	)		(14,459	)		(18,069	)
Recognized loss		3,148			4,737			—
Amortization of prior service cost		39			133			133

Net periodic pension expense	$	6,374		$	13,164		$	2,969

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


	Year Ended
	December 31, 2004		December 31, 2003		December 31, 2002
Discount rates	6.25	%	6.75	%	7.25	%
Rates of increase in compensation levels	4.00	%	4.00	%	4.50	%
Expected long-term rate of return on plan assets	8.50	%	8.50	%	9.00	%
Measurement date	1/1/2004		1/1/2003		1/1/2002

No Company contributions are expected to be required in 2005 for the qualified defined benefit pension plan, however, the Company expects to contribute, as benefit payments to participants, $45,000 in 2005 for the nonqualified supplemental benefit pension plan.

The following benefit payments from both the qualified defined benefit pension plan and the nonqualified supplemental benefit pension plan, which reflect expected future service, as appropriate, are expected to be paid from the plans:


	Expected Pension Benefit Payments
	(In Thousands)
2005	$	8,458
2006		8,679
2007		8,983
2008		9,538
2009		10,280
Years 2010 to 2014		67,551

Multi-Employer Pension

Under labor contracts with the UMWA, certain operations make payments into two multi-employer defined benefit pension plan trusts established for the benefit of certain union employees. The contributions are based on tons of coal produced and hours worked. Such payments aggregated less than $0.1 million in each of the years ended December 31, 2004, 2003, and 2002.

Defined Contribution Plans

The Company currently sponsors defined contribution pension plans as follows:

•

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

•

Prior to October 1, 2003, the Company sponsored a separate contributory defined contribution pension plan with Company contributions based on hours worked for certain eligible employees. On September 30, 2003, the plan was frozen and all 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.

Company contributions to these plans aggregated approximately $0.1 million for the year ended December 31, 2004 and $0.2 million each for the years ended December 31, 2003 and 2002.

Salary Deferral and Profit Sharing Plan

The Company also sponsors a salary deferral and profit sharing plan covering substantially all administrative and non-union employees. The maximum salary deferral rate was 15% of eligible compensation (effective January 1, 2005, the maximum salary deferral rate is 75%) and the Company contributes a fixed match on the first 10% of pre-tax eligible contributions employees made to the salary deferral and profit sharing plan. The Company may make additional discretionary contributions to the plan. Total Company contributions aggregated approximately $2.9 million, $3.5 million, and $4.6 million for the years ended December 31, 2004, 2003, and 2002, respectively.

11.

Other Noncurrent Liabilities

Other noncurrent liabilities comprise the following:


	December 31, 2004		December 31, 2003
	(In Thousands)
Reclamation (Note 3)	$	136,071	$	93,575
Workers’ compensation and black lung (Note 12)		95,891		90,620
Other postretirement benefits (Note 13)		96,705		88,886
Other		96,408		73,995

Total other noncurrent liabilities	$	425,075	$	347,076

12.

Workers’ Compensation and Black Lung Benefits

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


	December 31, 2004		December 31, 2003
	(In Thousands)
Accrued self-insured black lung obligation	$	71,469	$	65,902
Workers’ compensation (traumatic injury)		48,444		43,329

Total accrued workers’ compensation and black lung	$	119,913	$	109,231
Less amount included in other current liabilities		24,022		18,611

Workers’ compensation & black lung in other noncurrent liabilities	$	95,891	$	90,620

The amount of workers’ compensation liability related to self-insurance was $42.1 million at December 31, 2004 and $38.2 million at December 31, 2003. Weighted average actuarial assumptions used in the determination of the self-insured portion of workers’ compensation liability and the accumulated black lung obligation included a discount rate of 5.75% at December 31, 2004 and 6.25% at December 31, 2003.

A reconciliation of changes in the self-insured black lung obligation is as follows:


	Year Ended
	December 31, 2004			December 31, 2003
	(In Thousands)
Beginning of year accumulated black lung obligation	$	62,344		$	56,819
Service cost		3,333			2,982
Interest cost		3,886			3,617
Actuarial loss		3,284			909
Benefit payments		(1,191	)		(1,983	)

End of year accumulated black lung obligation	$	71,656		$	62,344
Unamortized net (loss) /gain		(187	)		3,558

Accrued self-insured black lung obligation	$	71,469		$	65,902

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


	Year Ended
	December 31, 2004			December 31, 2003			December 31, 2002
	(In Thousands)
Self-insured black lung benefits:
Service cost	$	3,333		$	2,982		$	3,461
Interest cost		3,886			3,617			3,478
Amortization of actuarial gain		(461	)		(1,601	)		(2,068	)

	$	6,758		$	4,998		$	4,871
Other workers’ compensation benefits		40,111			38,084			31,727

	$	46,869		$	43,082		$	36,598

Payments for benefits, premiums and other costs related to black lung and workers’ compensation liabilities were $36.2 million, $34.2 million, and $30.0 million for the years ended December 31, 2004, 2003, and 2002, respectively.

The weighted average actuarial assumptions used in the determination of self-insured black lung benefits expense included discount rates of 6.25%, 6.75%, and 7.25% for the years ended December 31, 2004, 2003, and 2002, respectively.

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


	1-Percentage Point Increase		1-Percentage Point Decrease
	(In Thousands)
Increase/decrease in medical cost trend rate:
Effect on total of service and interest costs components	$	208	$	(165	)
Effect on accumulated black lung obligation	$	1,500	$	(1,220	)

Increase/decrease in cost of living trend rate:
Effect on total of service and interest costs components	$	1,121	$	(885	)
Effect on accumulated black lung obligation	$	8,692	$	(7,033	)

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid related to the self-insured black lung obligation:


	Expected Benefit Payments
	(In Thousands)
2005	$	4,179
2006		4,305
2007		4,441
2008		4,605
2009		4,779
Years 2010 to 2014		25,484

13.

Other Postretirement Benefits

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

Net periodic postretirement benefit cost includes the following components:


	Year Ended
	December 31, 2004			December 31, 2003			December 31, 2002
	(In Thousands)
Service cost	$	4,474		$	4,964		$	4,636
Interest cost		7,650			7,626			6,062
Amortization of net loss		2,023			1,864			—
Amortization of prior service (credit) cost		(685	)		(410	)		140

Net periodic postretirement benefit cost	$	13,462		$	14,044		$	10,838

The weighted-average discount rate assumed to determine the net periodic postretirement benefit cost were 6.25%, 6.75%, and 7.25% for the years ended December 31, 2004, 2003, and 2002, respectively.

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


	Year Ended
	December 31, 2004			December 31, 2003
	(In Thousands)
Change in benefit obligation:
Benefit obligation at beginning of period	$	131,915		$	121,111
Service cost		4,474			4,964
Interest cost		7,650			7,626
Plan amendment		—			(11,601	)
Actuarial (gain) loss		(13,290	)		13,470
Benefits paid		(4,963	)		(3,655	)

Benefit obligation at end of period	$	125,786		$	131,915

Funded status	$	(125,786	)	$	(131,915	)
Unrecognized net actuarial loss		32,675			47,988
Unrecognized prior service credit		(9,173	)		(9,858	)

Accrued postretirement benefit obligation		(102,284	)		(93,785	)
Amount included in Current liabilities		5,579			4,899

Noncurrent liability	$	(96,705	)	$	(88,886	)

The weighted-average assumptions used to determine the benefit obligations as of the end of each year are as follows:


	Year Ended
	December 31, 2004		December 31, 2003
Discount rates	5.75	%	6.25	%
Measurement date	12/31/2004		12/31/2003

The assumed health care cost trend rates used to determine the benefit obligation as of the end of each year are as follows:

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 Point Increase		1-Percentage Point Decrease
	(In Thousands)
Effect on total service and interest cost components	$	2,276	$	(1,806	)
Effect on accumulated postretirement benefit obligation	$	20,498	$	(16,610	)

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (“without subsidy” represents expected payments had the Medicare subsidy not been introduced):


	Expected Benefit Payments
	With Subsidy		Without Subsidy
	(In Thousands)
2005	$	5,579	$	5,579
2006		5,457		5,457
2007		5,355		5,951
2008		5,852		6,487
2009		6,486		7,168
Years 2010 to 2014		39,963		43,870

On December 8, 2003, the Medicare Modernization Act was enacted. The Medicare Modernization Act introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a federal subsidy to sponsors of retiree benefit care plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company included the effects of the Medicare Modernization Act in its financial statements as of July 1, 2004 in accordance with FSP 106-2. Incorporation of the provisions of the Medicare Modernization Act resulted in a reduction in the net periodic postretirement benefit obligation as of July 1, 2004 of $27.2 million. The impact of the Medicare Modernization Act resulted in a reduction in the net periodic postretirement benefit cost of $2.1 million for the second half of 2004. Certain definitions and interpretations, yet to be issued by the federal government, could require the Company to adjust future estimates.

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

Multi-Employer Benefits

Under the Coal Act, coal producers are required to fund medical and death benefits of certain retired union coal workers based on premiums assessed by the UMWA Benefit Funds. Based on available information at December 31, 2004, the Company’s obligation (discounted at 5.75%) under the Coal Act is estimated at approximately $64.3 million. The Company’s estimated obligation at December 31, 2003 was $61.2 million (discounted at 6.25%). The Company treats its obligation under the Coal Act as a participation in a multi-employer plan and records the cost of the Company’s obligation as expense as payments are assessed. The Company’s expense related to this obligation for the years ended December 31, 2004, 2003, and 2002, totaled $6.7 million, $4.7 million, and $4.1 million, respectively.

14.

Stock-Based Compensation Plans

Massey’s executive stock plans provide for grants of non-qualified stock options, incentive stock options, stock appreciation rights (“SARs”), shadow stock and restricted stock awards. All executive stock plans are administered by the Compensation Committee of the Board of Directors (the “Compensation Committee”) comprised of independent outside directors. Option exercise prices, determined by the Committee, are equal to the average of the high and low of the quoted market price of the Company’s common stock on the date of grant. Options and SARs normally extend for 10 years and become exercisable over a vesting period determined by the Compensation Committee, which can include accelerated vesting for achievement of performance or stock price objectives. Additionally, two restricted stock plans provide 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.

During the year ended December 31, 2004, the Company issued 474,320 non-qualified stock options with four year cliff vesting with accelerated vesting if performance criteria are achieved after year two or year three. These options expire ten years after the date of grant. During the year ended December 31, 2003, the Company issued 534,881 non-qualified stock options with annual vesting of 25% and 161,500 non-qualified stock options that vest after four years, all of which expire ten years after the date of grant. During the year ended December 31, 2002, the Company issued 519,873 non-qualified stock options with annual vesting of 25% and 163,400 non-qualified stock options that vest after four years, all of which expire ten years after the date of grant.

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 100,161 shares, 192,024 shares and 477,987 shares for the years ended December 31, 2004, December 31, 2003 and December 31, 2002, respectively. The weighted average fair value of restricted stock awards as of the date of grant was $28.70, $12.94 and $5.62 per share for the years ended December 31, 2004, 2003, and 2002, respectively. Vested restricted stock is included in the weighted average shares outstanding calculation for basic earnings per share. Unvested restricted stock is included in the weighted average shares outstanding calculation for diluted earnings per share. See Note 2, “Significant Accounting Policies—Earnings Per Share” for further discussion.

As permitted by SFAS 123, the Company has elected to continue following the guidance of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” for measurement and recognition of stock-based transactions with employees. Expenses related to the Company’s stock compensation plans include amortization of restricted stock value, and expense related to those instruments paid out in cash that derive their value based on the price of the Company’s stock (these include SARs, shadow stock, and incentive units intended to compensate for the tax payable on vesting restricted stock awards). For the years ended December 31, 2004, 2003, and 2002, expenses related to the Company’s various stock compensation plans (with the exception of stock options) totaled $29.7 million, $14.8 million and $3.6 million, respectively. Under APB Opinion No. 25, no compensation cost is recognized for the Company’s stock option plans because vesting provisions are based only on the passage of time and because the Company granted the options at an exercise price equal to the average of the high and low of the quoted market price of the Company’s stock on the date of grant. See Note 2, “Significant Accounting Policies—Stock Plans” for the pro forma impact of options. See also Note 2, “Significant Accounting Policies—Accounting Pronouncements” for a discussion of SFAS 123R.

The following table summarizes stock option activity:


	Number of Options		Weighted Average Exercise Price Per Share
Outstanding at December 31, 2001	2,021,703		$	15.25
Granted	683,273		$	5.79
Expired or Cancelled	(264,772	)	$	13.64
Exercised	(125,689	)	$	11.17

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

Outstanding at December 31, 2003	2,748,625		$	13.23
Granted	474,320		$	29.95
Expired or Cancelled	(135,967	)	$	10.42
Exercised	(890,064	)	$	13.32

Outstanding at December 31, 2004	2,196,914		$	16.98


Exercisable at:
December 31, 2001		1,083,704
December 31, 2002		1,075,763
December 31, 2003		1,243,111
December 31, 2004		776,143

Characteristics of outstanding stock options at December 31, 2004 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	399,069	7.7	$	5.98	90,431	$	5.36
$10.57 – 10.93	178,166	4.9	$	10.91	178,166	$	10.91
$12.28 – 13.60	607,550	8.9	$	13.55	128,685	$	13.55
$15.81 – 20.11	537,809	6.4	$	19.58	378,861	$	19.50
$29.95	474,320	9.9	$	29.95	—	$	—

$ 5.21 – 29.95	2,196,914	8.0	$	16.98	776,143	$	14.90

At December 31, 2004, there were 3,670,222 shares available for future grant under the Company’s stock plans. Available for grant includes shares, which may be granted as either stock options, or restricted stock, as determined by the Compensation Committee under the Company’s various stock plans.

15.

Impairment of Long-Lived Assets

During the third quarter of 2004, the Company recorded a charge to Depreciation, depletion and amortization in the amount of $6.1 million (pre-tax) related to the write off of certain capitalized development costs and an investment in an active gas well:

•

The Upper Cedar Grove mine of the Independence resource group was idled in August 2001 due to poor mining conditions. The mine entries were planned to be used for future transportation of coal from adjacent coal mines. During the third quarter of 2004, management determined that the conditions of the mine entries had deteriorated and were no longer usable for transportation of coal. Unamortized development costs of approximately $2.7 million were written off during the third quarter of 2004 as a result of the Upper Cedar Grove mine closure.

•

The Company owns a 25% working interest in the LeJeune No. 1 gas well in Pointe Coupee, Louisiana. During the third quarter of 2004, the Company was informed by the operator of the gas well that the current production zone had ceased producing gas earlier than expected, significantly reducing the estimated remaining reserves in the well. Unamortized development and initial drilling costs of $3.4 million were written off during the third quarter of 2004 as a result of the reduction in projected production from the LeJeune No. 1 gas well.

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

•

During the third quarter of 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.

16.

Appalachian Synfuel, LLC

Appalachian Synfuel, LLC (“Appalachian Synfuel”) was formed in 1997. As a provider of synthetic fuel, Appalachian Synfuel generates tax credits for its owners; however, because of the Company’s tax position it is unable to utilize the tax credits generated by Appalachian Synfuel. In order to monitize the value of the Company’s investment, the Company sought to sell an interest in Appalachian Synfuel to an entity that could benefit currently from the tax credits generated. In order to facilitate such a transaction, the synfuel operating agreement was amended to divide the ownership interest into three tranches, Series A, Series B and Series C.

Under the amended Appalachian Synfuel agreement, the Series A owner generally is entitled to the risks and rewards of the first 475,000 tons of production, including the right to the related tax credits. The Series B owner is generally entitled to the risks and rewards of all excess production up to the rated capacity of 1.2 million tons. The Series C owner is entitled to the amount of working capital on the day of the sales transaction. The Series C owner is responsible for providing recourse working capital loans to Appalachian Synfuel going forward at a specified indexed interest rate. As a result, the Series C owner will fund the daily operations of Appalachian Synfuel. The Series C owner also has the responsibility at the end of the term of the Appalachian Synfuel agreement to wind up the affairs of Appalachian Synfuel, 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 Appalachian Synfuel, contingent upon favorable IRS rulings, which were received in September 2001 and in June 2002, respectively. The Company received cash of $7.2 million, a recourse promissory note for $34.6 million that is being paid in quarterly installments of $1.9 million including interest, and a contingent promissory note that is paid on a cents per Section 29 credit dollar earned based on synfuel tonnage shipped. Deferred gains of $14.3 million and $19.1 million as of December 31, 2004 and 2003, respectively, are included in Other noncurrent liabilities to be recognized ratably though 2007. Massey’s subsidiary, Marfork Coal Company, Inc., manages the facility under an operating agreement.

17.

Concentrations of Credit Risk and Major Customers

The Company is engaged in the production of coal for the electric generating industry, and industrial customers and metallurgical coal for the steel industry. Steam coal sales accounted for approximately 56%, 64% and 60% of produced coal revenue for the years ended December 31, 2004, 2003, and 2002, respectively. Metallurgical coal sales accounted for approximately 33%, 26% and 30% of produced coal revenue for the years ended December 31, 2004, 2003, and 2002, respectively. Industrial coal sales for the years ended December 31, 2004, 2003, and 2002, were 11%, 10% and 10% of produced coal revenue, respectively.

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

For the years ended December 31, 2004, 2003 and 2002, approximately 13%, 14% and 12%, respectively, of produced coal revenue was attributable to affiliates of DTE Energy Corporation. For the year ended December 31, 2004, approximately 10% of produced coal revenue was attributable to affiliates of American Electric Power Company, Inc. For the year ended December 31, 2002, approximately 11% of produced coal revenue was attributable to affiliates of Duke Energy Corporation. At December 31, 2004, approximately 57%, 27% and 16% of consolidated trade receivables represent amounts due from utility customers, metallurgical customers and industrial customers, respectively, compared with 53%, 28% and 19%, respectively, as of December 31, 2003.

The Company’s trade accounts receivable are subject to potential default by customers. Certain of the Company’s customers have filed for bankruptcy resulting in bad debt reserve charges to the Company. In an effort to mitigate credit-related risks in all customer classifications, Massey maintains a credit policy, which requires scheduled reviews of customer creditworthiness and continuous monitoring of customer news events that might have an impact on their financial condition. Negative credit performance or events may trigger the application of tighter terms of sale, requirements for collateral or, ultimately, a suspension of credit privileges. The Company establishes its bad debt reserve to specifically consider customers in financial difficulty and other potential receivable losses. In establishing its reserve, the Company considers the financial condition of its individual customers, and probability of recovery in the event of default. The Company charges off uncollectible trade receivables once legal potential for recovery is exhausted.

18.

Fair Value of Financial Instruments

The following methods and assumptions were used by the Company in estimating its fair value disclosures for financial instruments as of December 31, 2004 and 2003:

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

Long-term debt: At December 31, 2004, the fair value estimate of the Company’s 6.625% Senior Notes, 6.95% Senior Notes, 2.25% Convertible Senior Notes and 4.75% Convertible Senior Notes outstanding was $1,095.2 million based on available market information at that date. At December 31, 2003, the fair value of the 6.625% Senior Notes, 6.95% Senior Notes, and 4.75% Convertible Senior Notes outstanding was $836.9 million based on available market information at that date.

Capital lease obligations: The fair value estimate of the Company’s capital lease obligations at December 31, 2004 is based on estimated borrowing rates used to discount the cash flows to their present value. At December 31, 2004, the fair value estimate of the Company’s capital lease obligations was $38.6 million. At December 31, 2003, the carrying value of the capital lease obligations approximated the fair value as the leases were entered into in December 2003.

Interest rate swap: The fair value estimate is based on the cost that would be incurred to terminate the contract. The Company would have paid $1.5 million and $3.2 million to terminate the interest rate swap contract in place as of December 31, 2004 and 2003, respectively. The fair value of the swap is recorded in Other noncurrent liabilities.

19.

Contingencies and Commitments

Contingencies

Harman Case

In December 1997, the Company’s then subsidiary Wellmore Coal Corporation (“Wellmore”) declared force majeure under its coal supply agreement with Harman Mining Corporation (“Harman”) and reduced the amount of coal to be purchased from Harman. On October 29, 1998, Harman and its sole shareholder sued the Company and certain of its subsidiaries in the Circuit Court of Boone County, West Virginia, alleging that the Company and such subsidiaries tortiously interfered with Wellmore’s agreement with Harman, causing Harman to go out of business. On August 1, 2002, the jury awarded the plaintiffs $50 million in compensatory and punitive damages. On July 17, 2003, the Court ordered the Company to post a $55 million letter of credit. On June 30, 2004, the Court denied the Company’s motion to eliminate or reduce punitive damages. The Company awaits rulings on its August 29, 2002, motions to eliminate or reduce the verdict and for a new trial. The Company has accrued a liability of $34.8 million, including $6.8 million of interest, which is included in Other current liabilities in the Consolidated Financial Statements. The Company believes this accrual is a fair estimate of the eventual total payout in this case.

Martin County Impoundment Discharge

On October 11, 2000, a partial failure of the coal refuse impoundment of Martin County Coal Corporation, a subsidiary of the Company, released approximately 250 million gallons of coal slurry into two tributary streams of the Big Sandy River in eastern Kentucky. As of December 31, 2004, the Company had incurred a total of approximately $77.1 million of cleanup and other spill related costs, including claims, fines and other items, of which $73.5 million has been paid or reimbursed by insurance companies. Remaining issues include (i) six lawsuits (one seeking class certification) in the Circuit Court of Martin County, Kentucky, asserting claims for personal injury, property and other damages, and seeking unquantified compensatory and punitive damages; (ii) various citations and penalties issued by the Federal Mine Safety and Health Administration (“MSHA”) initially totaling approximately $110,000, subsequently reduced to $5,500, appealed by both MSHA and the Company; and (iii) subpoenas from a federal grand jury of the U.S. District Court for the Eastern District of Kentucky, to which the Company responded. The Company believes it has insurance coverage applicable to these items and that they will be resolved without a material impact on its cash flows, results of operations or financial condition.

West Virginia Flooding

Since July 2001, seven subsidiaries of the Company have been named, along with approximately 170 other companies, in 35 separate complaints filed in the Circuit Courts of Boone, Fayette, Kanawha, McDowell, Mercer, Raleigh and Wyoming Counties, West Virginia. These cases cover approximately 2,200 plaintiffs who filed suit on behalf of themselves and others similarly situated, seeking unquantified damages for property damage and personal injuries arising out of flooding that occurred on or about July 8, 2001. The Supreme Court of Appeals of West Virginia transferred these cases, along with approximately 21 additional flood damage cases not involving the Company’s subsidiaries, to the Circuit Court of Raleigh County, West Virginia, to be handled by a mass litigation panel. On August 1, 2003, the panel certified nine questions to the Supreme Court of Appeals, which were answered on December 9, 2004. The Company believes that it has insurance coverage applicable to these items.

In August 2004, five of the same seven subsidiaries of the Company were named in six civil actions filed in Boone, McDowell, Mingo, Raleigh, Summers, and Wyoming Counties, West Virginia, seeking unquantified damages for property damage and personal injuries arising out of flooding on or about May 2, 2002. These complaints name approximately 360 plaintiffs and 35 defendants. The Company’s subsidiaries responded, filing motions to dismiss or, in the alternative, for a more definite statement of the allegations. These claims are not part of the mass litigation noted above. The Company believes these matters will be resolved without a material impact on its cash flows, results of operations or financial condition.

Delbarton Water Claims

In July 2002, two cases were filed by approximately 230 plaintiffs in the Circuit Court of Mingo County, West Virginia, alleging that the Company’s Delbarton Mining Company’s mining activities destroyed nearby residents’ water supplies. On September 17, 2004, the jury awarded $1.6 million in compensatory damages. The Court denied plaintiffs’ request for a new trial and litigation costs. Plaintiffs seek an award of attorneys’ and experts’ fees. The Company believes it has insurance coverage applicable to this item and it will be resolved without a material impact on its cash flows, results of operations or financial condition.

Shareholder Suit

On August 5, 2002, one shareholder filed a suit styled as a derivative action in the Circuit Court of Boone County, West Virginia, naming the Company, each of its then directors, and certain of its current and former officers. The suit alleges (i) breach of fiduciary duties against all of the defendants for refusing to cause the Company to comply with environmental, labor and securities laws, and (ii) improper insider trading by certain of the Company’s current and former officers. Plaintiff claims to seek recovery on behalf of the Company of unquantified damages. The Company’s Directors & Officers insurance carrier partially disputed coverage. On May 24, 2004, the Company filed a third party complaint against such carrier in the underlying lawsuit, seeking a declaration that the policy covers all claims made, full reimbursement of legal fees, and indemnification from damages assessed in the suit, if any. The Company awaits rulings on those items and its October 31, 2003, motions to dismiss the lawsuit. The Company believes this matter will be resolved without a material impact on its cash flows, results of operations or financial condition.

West Virginia Trucking

In January 2003, an advocacy group representing residents in the Counties of Boone, Raleigh and Kanawha, West Virginia, and other plaintiffs, filed 16 suits in the Circuit Court of Kanawha County, West Virginia against the Company and 12 subsidiaries. Plaintiffs alleged that defendants illegally transported coal in overloaded trucks, causing damage to state roads, thereby interfering with plaintiffs’ use and enjoyment of their properties and their right to use the public roads. Plaintiffs seek injunctive relief and unquantified compensatory and punitive damages. The Supreme Court of Appeals of West Virginia referred the consolidated lawsuits, and three similar lawsuits against other coal and transportation companies not involving the Company’s subsidiaries, to the Circuit Court of Lincoln County, West Virginia, to be handled by a mass litigation panel. In March 2004, seven residents of Mingo County, West Virginia, filed a similar lawsuit in the Circuit Court of Mingo County, West Virginia, against the Company and three subsidiaries, raising similar claims and seeking similar relief. The Supreme Court of Appeals referred this case to the mass litigation panel also. The plaintiffs in all five trucking cases have requested that the cases be further consolidated, the scope of their claims be expanded statewide, claims be added against land companies, and class action status be granted. The Company believes that it has insurance coverage applicable to these items and they will be resolved without a material impact on its cash flows, results of operations or financial condition.

Nationwide Permit 21

On October 23, 2003, various environmental groups sued the U.S. Army Corps of Engineers (the “Corps”) in the United States District Court for the Southern District of West Virginia (“SDWV”). The lawsuit sought to invalidate Nationwide Permit 21 (“NWP 21”), a general permit issued by the Corps under Section 404 of the Clean Water Act authorizing the discharge of fill material into streams for purposes such as the construction of valley fills and refuse impoundments. Plaintiffs maintained that NWP 21 was improperly issued and that valley fills and refuse impoundments must receive individual permits, which require more detailed permit applications and reviews. The Company’s Green Valley Coal Company subsidiary and five coal trade associations intervened in the litigation to protect coal company interests and to support the continued use of NWP 21. On July 8, 2004, the Court suspended certain NWP 21 authorizations for valley fills and surface impoundments in the SDWV if construction had not commenced as of July 8, 2004. On August 13, 2004, the Court expanded its ruling to include all NWP 21 authorizations for valley fills and surface impoundments in the SDWV. The Corps and coal industry intervenors appealed to the United States Court of Appeals for the Fourth Circuit. On January 27, 2005, a similar lawsuit challenging NWP 21 was filed against the Corps by various environmental groups in the United States District Court for the Eastern District of Kentucky. The Company believes these matters will be resolved without a material impact on its cash flows, results of operations or financial condition.

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

* * * * * * * *

Commitments

As of December 31, 2004, the Company had commitments to purchase from external production sources 0.8 million, 0.2 million and 0.2 million tons of coal at a cost of $29.5 million, $10.7 million and $10.7 million in 2005, 2006 and 2007, respectively. In addition, as of December 31, 2004 the Company had commitments to purchase $98.3 million of capital assets and other services during 2005.

20.

Quarterly Information (Unaudited)

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


	Three Months Ended
	March 31, 2004			June 30, 2004⁽¹⁾			September 30, 2004⁽²⁾			December 31, 2004⁽³⁾
	(In Thousands, Except Per Share Amounts)
Total revenue	$	410,857		$	466,688		$	436,733		$	452,366
Income before interest and taxes		3,328			28,817			6,186			7,858
(Loss) Income before taxes		(7,760	)		10,723			(4,711	)		(3,895	)
Net (loss) income		(2,183	)		12,599			1,990			1,446
(Loss) Income per share:
Basic	$	(0.03	)	$	0.17		$	0.03		$	0.02
Diluted	$	(0.03	)	$	0.16		$	0.03		$	0.02

	Three Months Ended
	March 31, 2003			June 30, 2003			September 30, 2003⁽⁴⁾			December 31, 2003⁽⁵⁾
	(In Thousands, Except Per Share Amounts)
Total revenue	$	378,063		$	397,312		$	396,833		$	399,151
(Loss) Income before interest and taxes		(9,767	)		3,311			2,199			(13,285	)
Loss before taxes		(17,763	)		(5,586	)		(7,392	)		(29,910	)
Loss before cumulative effect of accounting change		(9,598	)		(2,197	)		(3,854	)		(16,684	)
Net loss		(17,478	)		(2,197	)		(3,854	)		(16,684	)
Loss per share (Basic and Diluted):
Loss before cumulative effect of accounting change	$	(0.13	)	$	(0.03	)	$	(0.05	)	$	(0.22	)
Net loss	$	(0.24	)	$	(0.03	)	$	(0.05	)	$	(0.22	)

⁽¹⁾	Income for the second quarter of 2004 includes a charge of $8.4 million pre-tax related to the Company’s reassessment of its potential liability for the Harman Case. See Note 19 for further information.

⁽²⁾

Income for the third quarter of 2004 includes a charge of $6.1 million pre-tax related to the write off of certain capitalized development costs and an investment in an active gas well (see Note 15 for further information); a gain of $3.0 million pre-tax related to a refund of black lung excise taxes paid on coal export sales tonnage; and a benefit of $5.6 million related to the release of a federal income tax reserve due to the closing of a statutory period.

⁽³⁾	Income for the fourth quarter of 2004 includes a reduction in bad debt reserves of $4.3 million pre-tax due to the re-evaluation of the Company’s total reserve, in light of improved market conditions for the steel industry and the Company’s tighter credit terms.

⁽⁴⁾	During the third quarter of 2003, the Company received $21.0 million for the settlement of a property and business interruption claim, which, after adjusting for a previously booked receivable and claim settlement expenses, resulted in a gain of $17.7 million pre-tax.

⁽⁵⁾	Loss for the fourth quarter of 2003 includes charges of $6.3 million pre-tax related to the write off of deferred financing costs due to the cancellation of the Company’s credit facilities resulting from the issuance of the 6.625% Senior Notes. See Note 8 for further information.

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.

Item 9A.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures and Changes in Internal Control Over Financial Reporting

The Company has established disclosure controls and procedures to ensure that information relating to the Company, including its consolidated subsidiaries, required to be disclosed by the Company in the reports that the Company files or submits under the Exchange Act, is accumulated and communicated to the Company’s management, including its principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of December 31, 2004, the principal executive officer and principal financial officer of the Company have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(c) and 15d-15(c) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by the Company in reports that it files or furnishes under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There has been no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2004, that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting, except that for the controls over fixed asset management, transfers and recording, management instituted, in the fourth quarter of 2004, additional training of employees that were responsible for these controls and improved monitoring of these controls by management.

Management’s Evaluation of Internal Control Over Financial Reporting

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, management is required to include in this Form 10-K an internal control over financial reporting report wherein management states its responsibility for establishing and maintaining adequate internal control structure and procedures for financial reporting and assesses the effectiveness of such structure and procedures. This management report follows.

MANAGEMENT REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of Massey Energy Company (“Massey”) is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Massey’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Massey’s internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of Massey; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of management and the directors of Massey; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Massey’s assets that could have a material effect on the Company’s financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Massey’s management assessed the effectiveness of Massey’s internal control over financial reporting as of December 31, 2004. In making this assessment, Massey used the criteria in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment based on those criteria, Massey’s management has concluded that, as of December 31, 2004, internal control over financial reporting is effective.

The Company’s management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which follows immediately hereafter.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Massey Energy Company

We have audited management’s assessment, included in the accompanying Management Report on Internal Control Over Financial Reporting, that Massey Energy Company maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Massey Energy Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, management’s assessment that Massey Energy Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Massey Energy Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Massey Energy Company at December 31, 2004 and December 31, 2003, and the related consolidated statements of income, cash flows, and shareholders’ equity for each of the three years in the period ended December 31, 2004 of Massey Energy Company and our report dated March 14, 2005 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Richmond, Virginia

March 14, 2005

Item 9B.

Other Information

None.

Part III

Item 10.

Directors and Executive Officers of the Registrant

The following information is incorporated by reference from the Company’s definitive proxy statement pursuant to Regulation 14A, which will be filed not later than 120 days after the close of Massey’s fiscal year ended December 31, 2004:

•

Information regarding the directors required by this item is found under the heading Election of Directors.

•

Information regarding Massey’s Audit Committee required by this item is found under the heading Committees of the Board.

•

Information regarding Section 16(a) Beneficial Ownership Reporting Compliance required by this item is found under the heading Section 16(a) Beneficial Ownership Reporting Compliance.

•

Information regarding Massey’s Code of Ethics required by this item is found under the heading Code of Ethics.

•

The information concerning the executive officers of Massey required by this item is included in Part I, Item 1, of this Form 10-K.

Because the Company’s common stock is listed on the NYSE, the Company’s chief executive officer is required to make, and he has made, an annual certification to the NYSE stating that he was not aware of any violation by the Company of the corporate governance listing standards of the NYSE. The Company’s chief executive officer made his annual certification to that effect to the NYSE as of June 4, 2004. In addition, the Company has filed, as exhibits to the Annual Report on Form 10-K, the certifications of the Company’s principal executive officer and principal financial officer required under Section 302 of the Sarbanes Oxley Act of 2002 to be filed with the SEC regarding the quality of the Company’s public disclosure.

Item 11.

Executive Compensation

Information required by this item is included in the Compensation Committee Report on Executive Compensation and Executive Compensation and Other Information sections of the definitive proxy statement pursuant to Regulation 14A, involving the election of directors, which is incorporated herein by reference and will be filed not later than 120 days after the close of Massey’s fiscal year ended December 31, 2004.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information required by this item is included in the Stock Ownership of Directors and Executive Officers, Stock Ownership of Certain Beneficial Owners, and Equity 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, 2004.

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, 2004.

Item 14.

Principal Accountant Fees and Services

Information concerning principal accounting fees and services contained under the heading The Audit Committee Report in the definitive proxy statement pursuant to Regulation 14A, which is incorporated by reference and will be filed not later than 120 days after the close of Massey’s fiscal year ended December 31, 2004.

Part IV

Item 15.

Exhibits and Financial Statement Schedules

(a)	Documents filed as part of this report:


1. Financial Reports:

Consolidated Statements of Income for the Fiscal Years Ended December 31, 2004, 2003, and 2002

Consolidated Balance Sheets at December 31, 2004 and 2003

Consolidated Statements of Cash Flows for the Fiscal Years Ended December 31, 2004, 2003, and 2002

Consolidated Statements of Shareholders’ Equity for the Fiscal Years Ended December 31, 2004, 2003, and 2002

Notes to Consolidated Financial Statements

2. 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

3. Exhibits:


Exhibit No.		Description
3.1		Certificate of Ownership and Merger merging Massey Energy Company with and into Fluor Corporation accompanied by Restated Certificate of Incorporation of Massey Energy Company, 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 November 15, 2004) of Massey Energy Company [filed as Exhibit 3.i to Massey’s current report on Form 8-K filed November 17, 2004 and incorporated by reference]

4.1		Massey Energy Company Investor Services Program [filed as Exhibit 4.1 to Massey’s annual report on Form 10-K for the fiscal year ended December 31, 2003 and incorporated by reference]

4.2		Indenture dated as of February 18, 1997 between Fluor Corporation and Banker’s Trust Company, trustee, in connection with the Company’s 6.95% Senior Notes [filed as Exhibit 4.1 to Massey’s current report on Form 8-K filed March 7, 1997 and incorporated by reference]

4.3		First Supplemental Indenture, dated as of February 9, 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, in connection with the Company’s 6.95% Senior Notes [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]

4.4		Senior Indenture, dated May 29, 2003, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors and Wilmington Trust Company, as Trustee, in connection with the Company’s 4.75% Convertible Senior Notes [filed as Exhibit 4.1 to Massey’s current report on Form 8-K filed May 30, 2003 and incorporated by reference]

4.5		First Supplemental Indenture, dated May 29, 2003, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors and Wilmington Trust Company, as Trustee, supplementing that certain Senior Indenture dated May 29, 2003, in connection with the Company’s 4.75% Convertible Senior Notes [filed as Exhibit 4.2 to Massey’s current report on Form 8-K filed May 30, 2003 and incorporated by reference]

4.6		Registration Rights Agreement, dated May 29, 2003, by and among Massey Energy Company, and Citigroup Global Markets Inc. and UBS Warburg LLC in connection with the Company’s 4.75% Convertible Senior Notes [filed as Exhibit 4.4 to Massey’s Form S-3 Registration Statement filed July 18, 2003 and incorporated by reference]

4.7		Indenture, dated November 10, 2003, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors and Wilmington Trust Company, as Trustee, in connection with the Company’s 6.625% Senior Notes [filed as Exhibit 4.1 to Massey’s current report on Form 8-K filed November 12, 2003 and incorporated by reference]


4.8		Registration Rights Agreement, dated November 10, 2003, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and UBS Securities LLC, Citigroup Global Markets Inc. and PNC Capital Markets, Inc., as the Initial Purchasers, in connection with the Company’s 6.625% Senior Notes [filed as Exhibit 4.2 to Massey’s current report on Form 8-K filed November 12, 2003 and incorporated by reference]

4.9		Second Supplemental Indenture, dated April 7, 2004, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and Wilmington Trust Company, as Trustee, supplementing that certain Senior Indenture dated May 29, 2003, in connection with the Company’s 2.25% Convertible Senior Notes [filed as Exhibit 4.1 to Massey’s current report on Form 8-K filed April 4, 2004 and incorporated by reference]

4.10		Registration Rights Agreement, dated April 7, 2004, by and among Massey Energy Company, subsidiaries of Massey Energy Company, as Guarantors, and UBS Securities LLC, acting on their own behalf and the Initial Purchasers, in connection with the Company’s 2.25% Convertible Senior Notes [filed as Exhibit 4.2 to Massey’s current report on Form 8-K filed April 4, 2004 and incorporated by reference]

10.1		Credit Agreement dated as of January 20, 2004, among A. T. Massey Coal Company, Inc. and certain of its subsidiaries, as Borrowers, Massey Energy Company and certain of its subsidiaries, as Guarantors, Wells Fargo Foothill, LLC and Fleet Capital Corporation, as Co-Syndication Agents, General Electric Capital Corporation, as Documentation Agent, The CIT Group/Business Credit, Inc., as Collateral Agent, UBS Securities LLC, as Arranger, UBS AG, Stamford Branch, as Administrative Agent, and UBS Loan Finance LLC, as Swingline Lender, and the lenders party thereto [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed January 30, 2004 and incorporated by reference]

10.2		First Amendment to that certain Credit Agreement dated January 20, 2004, effective as of March 12, 2004 [filed as Exhibit 10.1 to Massey’s quarterly report on Form 10-Q for the period ended September 30, 2004 and incorporated by reference]

10.3		Third Amendment to that certain Credit Agreement dated January 20, 2004, effective as of June 28, 2004 [filed as Exhibit 10.2 to Massey’s quarterly report on Form 10-Q for the period ended September 30, 2004 and incorporated by reference] *

10.4		Massey Energy Company 1982 Shadow Stock Plan (as amended and restated effective November 30, 2000) [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]

10.5		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]

10.6		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]

10.7		Massey Energy Company 1997 Stock Appreciation Rights Plan (as amended and restated effective November 30, 2000) [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]

10.8		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]

10.9		Massey Executive Deferred Compensation Program (as amended and restated as of January 1, 2005) [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed February 25, 2005 and incorporated by reference]

10.10		A.T. Massey Coal Company, Inc. Executive Deferred Compensation Plan (as amended and restated as of January 1, 2005) [filed as Exhibit 10.3 to Massey’s current report on Form 8-K filed February 25, 2005 and incorporated by reference]

10.11		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]

10.12		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]


10.13		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]

10.14		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]

10.15		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]

10.16		Massey Energy Company Non-Employee Director Compensation Summary [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed December 22, 2004 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 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]

10.19		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]

10.20		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 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) [filed as Exhibit 10.1 to Massey’s quarterly report on Form 10-Q for the period ended June 30, 2002 and incorporated by reference]

10.21		Amendment No. 1 dated as of February 22, 2005 to that certain Amended and Restated Employment Agreement dated as of November 1, 2001, effective May 1, 2005 [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed February 25, 2005 and incorporated by reference]

10.22		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]

10.23		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]

10.24		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]

10.25		Massey Energy Company 2005 Long Term Incentive Award Program as reported on Massey’s current report on Form 8-K [filed December 21, 2004 and incorporated by this reference]

10.26		Massey Energy Company 2005 Bonus Program as reported on Massey’s current report on Form 8-K [filed December 21, 2004 and incorporated by this reference]

10.27		Cash bonus awards paid to Massey’s named executive officers pursuant to the Massey Energy Company 2004 Bonus Program as reported on Massey’s current report on Form 8-K [filed February 25, 2005 and incorporated by this reference]

10.28		Cash bonus target awards set for Massey’s named executive officers and specific performance criteria set for certain key employees pursuant to the Massey Energy 2005 Bonus Program as reported on Massey’s current report on Form 8-K [filed February 25, 2005 and incorporated by this reference]

10.29		Base salary amounts set for Massey’s named executive officers as reported on Massey’s current report on Form 8-K [filed March 15, 2005 and incorporated by this reference]

21		Massey Energy Company Subsidiaries [filed herewith]

23		Consent of Independent Auditors [filed herewith]

24		Manually signed Powers of Attorney executed by Massey directors [filed herewith]

31.1		Certification of Chief Executive Officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 [filed herewith]


31.2		Certification of Chief Financial Officer, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 [filed herewith]

32.1		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 [furnished herewith]

32.2		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 [furnished herewith]

*	There is no second amendment.

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
March 16, 2005

	By:	/s/ E. B. TOLBERT
		Eric B. Tolbert,
		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	March 16, 2005

Principal Financial Officer:

/S/ E. B. TOLBERT E. B. Tolbert	Vice President and Chief Financial Officer	March 16, 2005

Principal Accounting Officer:

/S/ D. W. OWINGS D. W. Owings	Controller	March 16, 2005

Other Directors:

* J. C. Baldwin	Director	March 16, 2005

* J. B. Crawford	Director	March 16, 2005

* E. G. Gee	Director	March 16, 2005

* W. R. Grant	Director	March 16, 2005

* B. R. Inman	Director	March 16, 2005

* D. R. Moore	Director	March 16, 2005

* M. R. Seger	Director	March 16, 2005



By:	/s/ T. J. DOSTART	March 16, 2005
	T. J. Dostart
	Attorney-in-fact

Manually signed Powers of Attorney authorizing Baxter F. Phillips, Jr., Thomas J. Dostart and Jeffrey M. Jarosinski, and each of them, to sign the annual report on Form 10-K for the fiscal year ended December 31, 2004 and any amendments thereto as attorneys-in-fact for certain directors and officers of the registrant are included herein as Exhibits 24.

MASSEY ENERGY COMPANY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS

(In Thousands of Dollars)


Description	Balance at Beginning of Period	Amounts Charged to Costs and Expenses		Deductions⁽¹⁾		Other⁽²⁾	Balance at End of Period
YEAR ENDED DECEMBER 31, 2004
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable	8,350	(3.516	)	(594	)	—	4,240
YEAR ENDED DECEMBER 31, 2003
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable	8,775	(255	)	(176	)	6	8,350
YEAR ENDED DECEMBER 31, 2002
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable	11,281	(2,706	)	—		200	8,775

⁽¹⁾	Reserves utilized, unless otherwise indicated.

⁽²⁾	Reclassifications, unless otherwise indicated.