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, 2010

OR

o 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. 001-07775

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	Name of each exchange on which registered
Common Stock, $0.625 par value	New York Stock Exchange

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

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

 Yes x    No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  

Yes o   No  x   

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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes x    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes x    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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.   o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check One):

Large accelerated filer  x	Accelerated filer  o
Non-accelerated filer  o	Smaller reporting company  o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x   

The aggregate market value of the common stock held by non-affiliates of the registrant on June 30, 2010, was $2,778,027,977 based on the last sales price reported that date on the New York Stock Exchange of $27.35 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 (“Common Stock”), outstanding as of February 15, 2011 — 103,454,816 shares.

DOCUMENTS INCORPORATED BY REFERENCE

            Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2011 Annual Meeting of Stockholders, which proxy statement will be filed no later than 120 days after the close of the registrant’s fiscal year ended December 31, 2010.

Forward Looking Statements

From time to time, we make certain comments and disclosures in reports, including this report, or through statements made by our officers that may be forward-looking in nature. Examples include statements related to our future outlook, anticipated capital expenditures, projected cash flows and borrowings and sources of funding. We caution readers that forward-looking statements, including disclosures that use words such as “anticipate,” “believe,” “estimate,” “expect,” “goal,” “intend,” “may,” “objective,” “plan,” “project,” “target,” “will” and similar words or statements are subject to certain risks, trends 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 the expectations 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. These assumptions are 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 circumstances and events beyond our control. We disclaim any intent or obligation to update these forward-looking statements unless required by securities law, and we caution the reader not to rely on them unduly. We have based any forward-looking statements we have made on our current expectations and assumptions about future events and circumstances that are subject to risks, uncertainties and contingencies that could cause results to differ materially from those discussed in the forward-looking statements, including, but not limited to:

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(i)	our cash flows, results of operations or financial condition;
(ii)	the impact of the Upper Big Branch ("UBB") mine tragedy;
(iii)	the successful completion of acquisition, disposition or financing transactions and the effect thereof on our business;
(iv)	our ability to successfully integrate the operations we acquire, including as a result of the acquisition of Cumberland Resources Corporation and certain affiliated entities ("Cumberland");
(v)	governmental policies, laws, regulatory actions and court decisions affecting the coal industry or our customers’ coal usage;
(vi)	legal and administrative proceedings, settlements, investigations and claims and the availability of insurance coverage related
	thereto;
(vii)	inherent risks of coal mining beyond our control, including weather and geologic conditions or catastrophic weather-related
	damage;
(viii)	inherent complexities make it more difficult and costly to mine in Central Appalachia than in other parts of the United States;
(ix)	our production capabilities to meet market expectations and customer requirements;
(x)	our ability to obtain coal from brokerage sources or contract miners in accordance with their contracts;
(xi)	our ability to obtain and renew permits necessary for our existing and planned operations in a timely manner;
(xii)	the cost and availability of transportation for our produced coal;
(xiii)	our ability to expand our mining capacity;
(xiv)	our ability to manage production costs, including labor costs;
(xv)	adjustments made in price, volume or terms to existing coal supply agreements;
(xvi)	the worldwide market demand for coal, electricity and steel;
(xvii)	environmental concerns related to coal mining and combustion and the cost and perceived benefits of alternative sources of
	energy such as natural gas and nuclear energy;
(xviii)	competition among coal and other energy producers, in the United States and internationally;
(xix)	our ability to timely obtain necessary supplies and equipment;
(xx)	our reliance upon and relationships with our customers and suppliers;
(xxi)	the creditworthiness of our customers and suppliers;
(xxii)	our ability to attract, train and retain a skilled workforce to meet replacement or expansion needs;
(xxiii)	our assumptions and projections concerning economically recoverable coal reserve estimates;
(xxiv)	our failure to enter into anticipated new contracts;
(xxv)	future economic or capital market conditions;
(xxvi)	foreign currency fluctuations;
(xxvii)	the availability and costs of credit, surety bonds and letters of credit that we require;
(xxviii)	the lack of insurance against all potential operating risks;
(xxix)	our assumptions and projections regarding pension and other post-retirement benefit liabilities;
(xxx)	our interpretation and application of accounting literature related to mining specific issues;
(xxxi)	the successful implementation of our strategic plans and objectives for future operations and expansion or consolidation;
(xxxii)	the ability to obtain regulatory approvals of the proposed merger ("the Merger") with Alpha Natural Resources, Inc. ("Alpha") on the proposed terms and schedule;
(xxxiii)	the failure of our stockholders or Alpha’s stockholders to approve the transactions contemplated by the Merger;
(xxxiv)	the outcome of pending or potential litigation related to the Merger;
(xxxv)	the risk that the combined businesses of Massey Energy Company and Alpha will not be integrated successfully or such integration may be more difficult, time-consuming or costly than expected;
(xxxvi)	uncertainty of the expected financial performance of Alpha following completion of the Merger;
(xxxvii)	Alpha’s ability to achieve the cost savings and synergies contemplated by the Merger within the expected time frame;
(xxxviii)	uncertainty of the effect of the Merger on relationships with customers, employees or suppliers;
(xxxix)	the calculations of, and factors that may impact the calculations of, the acquisition price in connection with the Merger and the allocation of such acquisition price to the net assets acquired in accordance with applicable accounting rules and methodologies; and
(xxxx)	the diversion of management’s time and attention from our ongoing business during the time period leading up to the Merger.

We are including this cautionary statement in this document to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. Any forward-looking statements should be considered in context with the various disclosures made by us about our businesses, including without limitation the risk factors more specifically described below in Item 1A. Risk Factors of this Annual Report on Form 10-K.

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2010 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	29
Item 1B.	Unresolved Staff Comments	44
Item 2.	Properties	45
Item 3.	Legal Proceedings	45
Item 4.	[Removed and reserved]	49
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	50
Item 6.	Selected Financial Data	53
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	55
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	74
Item 8.	Financial Statements and Supplementary Data	75
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	120
Item 9A.	Controls and Procedures	120
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	123
Item 11.	Executive Compensation	125
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	125
Item 13.	Certain Relationships and Related Transactions, and Director Independence	125
Item 14.	Principal Accountant Fees and Services	126
PART IV
Item 15.	Exhibits and Financial Statement Schedules	127
SIGNATURES		132

Annual Stockholders Meeting

Our 2011 Annual Meeting of Stockholders will be held at 9:00 a.m. EDT on Tuesday, June 14, 2011 at The Jefferson Hotel, 101 West Franklin Street, Richmond, Virginia 23220.

iii

Part I

Because certain terms used in the coal industry may be unfamiliar to many investors, we have provided a Glossary of Selected Terms beginning on page 25 at the end of Item 1. Business.

Item 1. Business

Business Overview

A.T. Massey Coal Company, Inc. (“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. On November 30, 2000, we completed a reverse spin-off which separated Fluor Corporation into two entities:  the “new” Fluor Corporation and Fluor Corporation which retained our coal-related businesses and was subsequently renamed Massey Energy Company (“Massey”).  Massey has been a separate, publicly traded company since December 1, 2000.

We are one of the largest coal producers in the United States and we are the largest coal company in Central Appalachia, our primary region of operation, in terms of tons produced in 2010 and total coal reserves currently controlled.

We produce, process and sell bituminous coal of various steam and metallurgical grades, primarily of a low sulfur content, through our 25 processing and shipping centers (“Resource Groups”), many of which receive coal from multiple mines. At January 31, 2011, we operated 84 mines, including 66 underground mines (one of which employs both room and pillar and longwall mining) and 18 surface mines (with 12 highwall miners in operation) in West Virginia, Kentucky and Virginia.  The number of mines that we operate may vary from time to time depending on a number of factors, including the existing demand for and price of coal, exhaustion of economically recoverable reserves and availability of experienced labor.

Customers for our steam coal product include primarily electric power utility companies who use our coal as fuel for their steam-powered generators.  Customers for our metallurgical coal include primarily steel producers who use our coal to produce coke, which is in turn used as a raw material in the steel manufacturing process.

Cumberland Acquisition

On April 19, 2010, we completed the acquisition of Cumberland Resources Corporation and certain affiliated entities (“Cumberland”) for a purchase price of $644.7 million in cash and 6,519,034 shares of our common stock (the “Cumberland Acquisition”).  Prior to the acquisition, Cumberland was one of the largest privately held coal producers in the United States.  The Cumberland operations include primarily underground coal mines in Southwestern Virginia and Eastern Kentucky.  As a result of the acquisition, we obtained an estimated 415 million tons of contiguous coal reserves. We also obtained a preparation plant in Kentucky served by the CSX railroad and a preparation plant in Virginia served by the Norfolk Southern railroad.  We did not incur or assume any third-party debt as a result of the Cumberland Acquisition.  The Cumberland Acquisition increases our metallurgical coal reserves, strengthens our ability to globally market steam and metallurgical quality coal, and optimizes both operational best practices and working capital generation.

Merger with Alpha Natural Resources, Inc.

On January 28, 2011, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Alpha Natural Resources, Inc., a Delaware corporation (“Alpha”), and Mountain Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiary of Alpha (“Merger Sub”), providing for the acquisition of Massey by Alpha.  Subject to the terms and conditions of the Merger Agreement, Massey will be merged with and into Merger Sub (the “Merger”), with Massey surviving the Merger as a wholly owned subsidiary of Alpha.

At the effective time of the Merger, each share of our Common Stock issued and outstanding immediately prior to the effective time (other than shares owned by (i) Alpha, us or Merger Sub or their respective subsidiaries (which will be cancelled) or (ii) stockholders who have properly exercised and perfected appraisal rights under Delaware law) will be converted into the right to receive 1.025 shares of Alpha common stock and $10.00 in cash, without interest (the “Massey Merger Consideration”).  No fractional shares of Alpha common stock will be issued in the Merger, and our stockholders will receive cash in lieu of fractional shares, if any, of common stock. Immediately upon completion of the Merger, our stockholders will own approximately 46% of the combined company.

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The consummation of the Merger is subject to certain conditions, including (i) the adoption by our stockholders of the Merger Agreement and (ii) the approval by the Alpha stockholders of (x) an amendment to Alpha’s certificate of incorporation to increase the number of shares of Alpha common stock that Alpha is authorized to issue in order to permit issuance of the Alpha common stock in connection with the Merger and (y) the issuance of Alpha common stock in connection with the Merger.  In addition, the Merger is subject to clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended (the “HSR Act”), as well as other customary closing conditions.

The Merger Agreement contains customary covenants, including covenants providing for each of the parties: (i) to conduct its operations in all material respects according to the ordinary and usual course of business consistent with past practice during the period between the execution of the Merger Agreement and the closing of the Merger; (ii) to use reasonable best efforts to cause the transaction to be consummated; (iii) not to initiate, solicit or knowingly encourage inquiries, proposals or offers relating to alternate transactions or, subject to certain exceptions, engage in any discussions or negotiations with respect thereto; and (iv) to call and hold a special stockholders’ meeting and, subject to certain exceptions, recommend adoption of the Merger Agreement, in our case, and amendment of the Alpha certificate of incorporation and issuance of Alpha common stock in connection with the Merger, in the case of Alpha.

The Merger Agreement also contains certain termination rights and provides that, (i) upon termination of the Merger Agreement under specified circumstances, including, but not limited to, a change in the recommendation of our board of directors or termination of the Merger Agreement to enter into a written definitive agreement for a “superior proposal”, we will owe Alpha a cash termination fee of $251 million; (ii) upon the termination of the Merger Agreement under specified circumstances, including, but not limited to, a change in the recommendation of the board of directors of Alpha or termination of the Merger Agreement to enter into a written definitive agreement for a “superior proposal”, Alpha will owe us a cash termination fee of $252 million; and (iii) upon the termination of the Merger Agreement due to Alpha’s failure to obtain the required stockholder approval at the Alpha stockholders’ meeting in the absence of a competing proposal, Alpha will owe us a cash termination fee of $72 million. In addition, Alpha is obligated to pay a cash termination fee of $360 million to us if all the conditions to closing have been met and the Merger is not consummated because of a breach by Alpha’s lenders of their obligations to finance the Merger.

Industry Overview

Coal accounted for 23% of the energy consumed (excluding certain alternative fuels including wind, geothermal and solar power generators) by the United States and 29% of energy consumed globally in 2009, according to the BP Statistical Review of World Energy (“BP”). In 2009, coal was the fuel source of 44% of the electricity generated nationwide, as reported by the Energy Information Administration (“EIA”), a statistical agency of the United States Department of Energy.

According to BP, in 2009, the United States was the second largest coal producer in the world, exceeded only by China. Other leading coal producers include Australia, India, Indonesia, South Africa and the Russian Federation. According to BP, the United States has the largest coal reserves in the world, with proved reserves totaling 238 billion tons. The Russian Federation ranks second in proved coal reserves with 157 billion tons, followed by China with 115 billion tons, according to BP.  The United States has more than 200 years of coal reserves at current production rates.

United States coal production has more than doubled over the last 40 years. In 2010, total United States coal production, as estimated by EIA, was 1.1 billion tons. The primary producing regions by tons were as follows:

Region	% of Total
Powder River Basin		47	%
Central Appalachia		17	%
Northern Appalachia		12	%
West (other than Powder River Basin)		11	%
Midwest		10	%
All other		3	%
Total		100	%

The EIA estimated that approximately 69% of United States coal was produced by surface mining methods in 2009. The remaining 31% was produced by underground mining methods, which include room and pillar mining and longwall mining (more fully described in Item 1. Business, under the heading “Mining Methods”).

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Coal is used in the United States by utilities to generate electricity, by steel companies to make steel products, and by a variety of industrial users to produce heat and to 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 Gulf Coast terminals. The breakdown of United States coal consumption for the first nine months of 2010 as estimated by EIA is as follows:

End Use	% of Total
Electric Power		93	%
Other Industrial		5	%
Coke		2	%
Residential and Commercial	< 1		%
Total		100	%

Coal has long been favored as an electricity generating fuel 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.  The EIA estimates the average cost of various fossil fuels for generating electricity in 2009 was as follows:

Electricity Generation Source	Average Cost  per million BTU
Petroleum Liquids	$	10.26
Natural Gas	$	4.74
Coal	$	2.21
Petroleum Coke	$	1.61

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 United States electricity generation by fuel source in the first nine months of 2010, as estimated by EIA, is as follows:

Electricity Generation Source	% of Total
Coal		45	%
Natural Gas		24	%
Nuclear		19	%
Hydroelectric		6	%
Oil and other (solar, wind, etc.)		6	%
Total		100	%

Demand for electricity has historically been driven by United States economic growth but it can fluctuate from year to year depending on weather patterns. In the first eleven months of 2010, electricity generation in the United States increased 4% from the same period in 2009, but the average growth rate in the past decade was approximately 1% per year according to EIA estimates. 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 World Coal Association (“WCA”), in 2009, the United States ranked sixth among worldwide exporters of coal.  Australia was the largest exporter, with other major exporters including Indonesia, the Russian Federation, Colombia, South Africa and Canada.  According to Energy Ventures Analysis, Inc. (“EVA”), United States exports increased by 38% in 2010 compared to 2009. The usage breakdown for United States coal exports of 81 million tons was 31% for electricity generation and 69% for steel production. In 2010, United States coal exports were shipped to more than 40 countries. The largest purchaser of United States exported utility coal in 2010 continued to be Canada, which took 7.8 million tons or 31% of total utility coal exports. This was down 4% compared to the 8.2 million tons exported to Canada in 2009. Overall steam coal exports increased 10% in 2010 compared to 2009. The largest purchaser of United States exported metallurgical coal was Brazil, which imported approximately 7.9 million tons from the United States, or 14% of total United States metallurgical coal exports. In total, metallurgical coal exports increased 56% in 2010, compared to 2009.

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

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During the past ten years, the global marketplace for coal has experienced swings in the demand/supply balance.  In periods of supply shortfall, as occurred from 2003 to early 2006 and again in late 2007 through late 2008, the prices for coal reached record highs in the United States. The increased worldwide demand was primarily driven by higher prices for oil and natural gas and economic expansion, particularly in China, India and elsewhere in Asia. At the same time, infrastructure and regulatory limitations in China contributed to a tightening of worldwide coal supply, affecting global prices of coal. The economic growth in China and India caused an increase in worldwide demand for raw materials and a disruption of expected coal exports from China to Japan, Korea and other countries.  In late 2008, the United States and world economies entered into an economic recession and financial credit crisis that reduced the demand for coal.  The world economy began to recover from the recession in 2010.  The resulting resurgence in steel demand and production led to increased demand for metallurgical coal, which has pushed up the price for this grade of coal.

Metallurgical grade coal is distinguished by special quality characteristics that include high carbon content, low volatile matter, low expansion pressure, low sulfur content and various other chemical attributes. The primary concentration of United States metallurgical coal reserves is located in the Central Appalachian region. EVA estimates that the Central Appalachian region supplied 91% of domestic metallurgical coal and 70% of United States exported metallurgical coal during 2009.

For 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. Low sulfur coals, such as those produced in the western United States and in Central Appalachia, generally demand a higher price due to restrictions on sulfur emissions imposed by the Federal Clean Air Act, as amended, and implementing regulations (“Clean Air Act”) and the volatility in sulfur dioxide (“SO2”) allowance prices that occurred in recent years when the demand for all specifications of coal increased. SO2 allowances permit utilities to emit a higher level of SO2 than otherwise required under the Clean Air Act regulations. The demand and premium price for low sulfur coal is expected to diminish as more utilities install scrubbers at their coal-fired plants.

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”), approximately two-thirds of United States coal shipments in recent years were transported via railroads. Final delivery to consumers often involves more than one transportation mode. A significant portion of United States production is delivered to customers via barges on the inland waterway system and ships loaded at Great Lakes ports.

Neither we nor any of our subsidiaries are affiliated with or have any investment in BP, EIA, EVA or WCA. We are a member of the NMA.

Mining Methods

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

In the underground room and pillar method of mining, continuous miners 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 upon retreat. 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 1,000 feet in width, cutting a slice approximately 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 to extract coal deposits found close to the surface. This method involves removal of overburden (earth and rock covering coal) with heavy earth moving equipment, including large shovels and explosives, followed by extraction of coal from coal seams. After extraction of coal, disturbed parcels of land are reclaimed by replacing overburden and reestablishing vegetation and plant life.

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Highwall mining is used in connection with surface mining. A highwall mining system consists of a remotely controlled continuous miner, 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 1,000 feet. Multiple, parallel openings are driven into the highwall, separated by narrow pillars that extend the full depth of the hole.

Use of continuous miners in the room and pillar method of underground mining represented approximately 55% of our 2010 coal production. Production from underground longwall mining operations constituted approximately 2% of our 2010 production. Surface mining represented approximately 35% of our 2010 coal production. Highwall mining represented approximately 8% of our 2010 coal production.

Mining Operations

We currently have 25 distinct Resource Groups, including seventeen in West Virginia, six in Kentucky and two 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 fourteen distinct underground or surface mines. Our mines have been developed at strategic locations in close proximity to our preparation plants and rail shipping facilities.

We currently operate solely in the Central Appalachian region, which is the principal source of low sulfur bituminous coal in the United States, used for power generation, metallurgical coke production and industrial boilers. Central Appalachian coal accounted for 17% of 2010 United States coal production according to EIA.

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The following map provides the location of our operations within the Central Appalachian region:

6

The following table provides key operational information on our Resource Groups in 2010:

Resource Group Name	Location (County)	Active/ Inactive	Mine Type		Active Mine Count (1)		Mining Equipment	Transportation	2010 Production (2)		2010 Shipments (3)		Year Established or Acquired
									(Thousands of Tons)
West Virginia Resource Groups
Black Castle	Boone	Active		S		1	HW	truck, barge		2,994		2,127		1987
Delbarton	Mingo	Active		U		2		NS		655		980		1999
Edwight	Raleigh	Active		S		1		CSX		1,217		—		2003
Elk Run	Boone	Active		U		5		CSX		2,105		3,590		1978
Endurance	Boone	Inactive						CSX		—		—		2001
Green Valley	Nicholas	Active		U		3		CSX		707		844		1996
Guyandotte	Wyoming	Active		U		1		NS		292		282		2006
Independence	Boone	Active		U		3	LW	CSX		1,106		2,292		1994
Inman	Boone	Active		U		1		CSX		591		—		2008
Logan County	Logan	Active		S/U		6	HW	CSX		1,917		894		1998
Mammoth	Kanawha	Active		U		5		barge/NS		1,845		4,907		2004
Marfork	Raleigh	Active		S/U		8	HW	CSX		3,190		4,821		1993
Nicholas Energy	Nicholas	Active		S/U		2	HW	NS		2,224		2,364		1997
Progress	Boone	Active		S		1	HW	CSX		3,041		1,785		1998
Rawl	Mingo	Active		U		4	HW	NS		980		62		1974
Republic Energy	Raleigh	Active		S		2	HW	truck		3,136		50		2004
Stirrat	Logan	Active						CSX		—		812		1993
Kentucky Resource Groups
Coalgood Energy	Harlan	Active		S/U		1	HW	CSX		429		458		2005
Long Fork	Pike	Active						NS		—		1,546		1991
Martin County	Martin	Active		S/U		3	HW	NS		1,230		1,225		1969
New Ridge	Pike	Active						CSX		—		480		1992
Sidney	Pike	Active		S/U		7	HW	NS		3,032		1,742		1984
Black Mountain	Harlan, Letcher	Active		S/U		14		CSX		3,378		3,199		2010
Virginia Resource Group
Knox Creek	Tazewell	Active		S/U		2	HW	NS		551		567		1997
Cumberland	Wise	Active		S/U		12		NS		2,126		2,109		2010
Total						84				36,746		37,136

(1)	Active mine count as of January 31, 2011.
(2)	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 extracted from the ground.
(3)	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.
S	– surface mine
U	– underground mine
HW	– highwall miners operated in conjunction with surface mines
LW	– longwall mine
NS	– Norfolk Southern Railway Company
CSX	– CSX Transportation

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The following descriptions of the Resource Groups are current as of January 31, 2011:

West Virginia Resource Groups

Black Castle. The Black Castle complex includes a large surface mine, two highwall miners, the Homer III direct-ship and washed coal loadout, a stoker plant, and the Omar preparation plant. Some of the surface mine coal is trucked to the stoker plant where the coal is crushed and screened. The stoker product is trucked to river docks for barge delivery or trucked directly to customers. A portion of the coal is trucked to the Omar plant, where it is crushed and shipped to customers or, if the coal needs processing, it is belted to the preparation plant at the Independence Resource Group for processing and shipment. The direct-ship facility at the preparation plant can crush 500 tons per hour and the preparation plant can process 600 tons per hour. The Omar preparation plant serves CSX rail system customers with unit train shipments of up to 110 railcars. Coal is also trucked to the Homer III loadout where it is crushed and shipped to customers by rail, trucked to river docks for barge delivery, or trucked directly to customers. The Homer III loadout serves CSX rail system customers with unit train shipments of up to 100 railcars. The Omar preparation plant was not utilized for processing coal in 2010.

Delbarton. The Delbarton complex includes two underground room and pillar mines and a preparation plant. Production from one mine is transported via underground conveyor belt and from the other mine is trucked to the Delbarton preparation plant. The Delbarton preparation plant also processes coal from a surface mine 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.

Edwight. The Edwight complex includes a surface mine and the Goals preparation plant. Production from the surface mine is transported via conveyor system to the Goals preparation plant. 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.

Elk Run. The Elk Run complex produces coal from five underground room and pillar mines, which is belted to the Elk Run preparation plant. Additionally, Elk Run processes coal produced by surface mines of the Progress Resource Group and 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 that produces screened, small dimension coal for certain of our industrial customers. Customer shipments are loaded on the CSX rail system in unit trains of up to 150 railcars.

Endurance. The Endurance complex includes an idle surface mine and a direct-ship loadout. When in production, a portion of the production from the surface mine is loaded for shipment to customers at the direct-ship loadout and the remainder is trucked to the preparation plant at the Independence Resource Group for processing.

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

Guyandotte. The Guyandotte complex includes one underground room and pillar mine. The mine belts coal to a third-party preparation plant for washing and shipment to customers via the Norfolk Southern railway system.

Independence. The Independence complex includes the Revolution longwall mine, two underground room and pillar mines and a preparation plant. Production from the underground mines is transported via overland conveyor system to the Independence preparation plant. The surface mine at the Black Castle Resource Group belts coal requiring processing to the Independence preparation plant. 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.

Inman. The Inman complex includes one underground room and pillar mine and a preparation plant. Production from the underground mine is transported via overland conveyor system to the preparation plant. The Inman plant has a processing capacity of 800 tons per hour. Coal processed at the preparation plant is belted to the Black Castle Resource Group’s Homer III loadout where it is loaded and shipped to customers via the CSX rail system in unit trains of up to 100 railcars.

Logan County. The Logan County complex includes three surface mines, a highwall miner, three underground room and pillar mines and the Zigmond preparation plant. Production from two of the underground mines is belted directly to the Zigmond plant. Production from the third mine is transported via off road truck to the Zigmond plant. Two surface mines and the highwall miner production are transported by belt to the Zigmond plant. Production from the third surface mine is transported via truck to the Feats Loadout or the Delbarton Resource Group Preparation Plant. The Feats Loadout can service customers via the CSX rail system with unit train shipments of up to 80 cars. The Zigmond plant began production in November 2010, replacing the old preparation plant that was destroyed by a fire in August 2009. The Zigmond Plant has a capacity of 1,200 tons per hour. Customers are served via the CSX rail system with unit trains of up to 150 cars.

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Mammoth. The Mammoth complex operates five underground room and pillar mines and a preparation plant. Coal is transported to the preparation plant using a conveyor system. The plant has a 1,200 tons per hour processing facility capacity with barge loading capabilities on the upper Kanawha River and a rail loading facility that services customers on the Norfolk Southern railway with unit trains of up to 130 railcars.

Marfork. The Marfork complex includes six underground room and pillar mines, two surface mines, two highwall miners and a preparation plant. Production from the five of the underground mines is belted directly to the Marfork preparation plant while production from the remaining underground mine is belted to Edwight Resource Group’s Goals preparation plant. Production from the surface mines and the highwall miners is trucked to the Marfork preparation plant, the Elk Run Resource Group’s preparation plant and/or the Black Castle Resource Group’s direct-ship loadout. 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 one underground room and pillar mine, a surface mine, a highwall miner and a preparation plant. Coal from the underground mine is transported to the preparation plant for processing via conveyor system. Coal from the highwall miner and the portion of surface mined coal requiring processing is transported to the preparation plant using off-road trucks. Coal not requiring processing is transported via off-road trucks to a conveyor system that moves the coal directly to a rail loadout facility. The plant has a processing capacity of 1,200 tons per hour. Coal shipments are loaded into rail cars for delivery via the Norfolk Southern railway in unit trains of up to 140 railcars, or are transported via on-highway trucks to the Mammoth Resource Group’s barge loading facility.

Progress. The Progress complex includes the large Twilight surface mine and a highwall miner.  Production from the Twilight surface mine is transported via underground conveyor to the Elk Run Resource Group for processing and rail shipment.

Rawl. The Rawl complex includes a surface mine and highwall miner, three underground room and pillar mines, and a preparation plant. Production from two of the underground mines is transported via truck to the preparation plant of the Stirrat Resource Group.  The production from the third underground mine, the surface mine and highwall miner is transported via truck to Rawl’s Sprouse Creek preparation plant.  The Sprouse Creek plant, which was reactivated in 2010, has a throughput capacity of 800 tons per hour. Customers are served by the Sprouse Creek plant via the Norfolk Southern railway with unit trains of up to 150 railcars.

Republic Energy. The Republic Energy complex consists of two surface mines and a highwall miner. Direct-ship coal is trucked using on-highway trucks to various docks on the Kanawha River for barge delivery to customers and to the Marfork Resource Group for rail delivery to customers.  Coal requiring processing is trucked using on-highway trucks to Mammoth Resource Group’s preparation plant for processing and barge or train delivery to customers.

Stirrat. The Stirrat complex includes a preparation plant and the Superior loadout, which was idled in 2009. The Superior loadout serves CSX railway customers with unit trains of up to 100 railcars. The Stirrat preparation plant cleans coal from two adjacent underground room and pillar mines of the Rawl Resource. The plant has a rated capacity of 600 tons per hour. Customers are served via the CSX rail system with unit trains of up to 100 railcars.

Kentucky Resource Groups

Coalgood Energy. The Coalgood Energy complex includes one surface mine, one highwall miner, a direct-ship loadout and a preparation plant. The coal from the surface mine is trucked off-road to the loadout, which serves CSX railway customers with unit trains of up to 100 railcars.  Production from the highwall miner is transported via truck to the preparation plant. The Coalgood Energy preparation plant has a throughput capacity of 800 tons per hour. Coal from this preparation plant is loaded onto trains from the direct-ship loadout.

Long Fork. The Long Fork preparation plant processes coal produced by four underground room and pillar mines of the Sidney Resource Group. All production is transported via conveyor system to the Long Fork preparation plant for processing and shipping to customers. 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.

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Martin County. The Martin County complex includes two underground room and pillar mines, one surface mine, a highwall miner and a preparation plant.  Direct-ship coal production from the surface mine is shipped to river docks via truck. Surface mine and highwall miner coal requiring processing and production from the underground mines is transported by conveyor belt or truck to the preparation plant. Martin County’s preparation plant has a throughput capacity of 1,500 tons per hour, although the throughput capacity is limited due to decreased impoundment availability. The coal from the preparation plant can be 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 preparation plant of the Sidney Resource Group and coal trucked directly from Sidney’s surface mine. The New Ridge preparation plant has a capacity of 800 tons per hour. The preparation plant is currently idle but may be reactivated from time to time during 2011 as needed. 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, one surface mine, a highwall miner and a preparation plant. Four of the underground mines transport coal via underground conveyor system to the Long Fork Resource Group for processing and shipment, and the remainder of the underground mines transport production via truck to Sidney’s preparation plant. A portion of the coal from Sidney’s preparation plant and coal from the surface mine are trucked to the New Ridge Resource Group for loading into railroad cars. Sidney’s preparation plant has a capacity of 1,500 tons per hour. The rail loading facility at the preparation plant serves customers on the Norfolk Southern rail system with unit trains of up to 140 railcars.  

Black Mountain. The Black Mountain complex, acquired in the Cumberland Acquisition, includes thirteen underground room and pillar mines, one surface mine, a direct-ship loadout and a preparation plant. One of the underground mines transports coal via conveyor system to the Cave Branch preparation plant for processing and shipment; the production from the other thirteen underground mines and the surface mine are trucked to the preparation plant, which serves CSX railway customers with unit trains of up to 110 railcars.  The Cave Branch preparation plant has a feed capacity of 1,800 tons per hour. Coal from this preparation plant is loaded onto trains from a batch weigh loadout.

Virginia Resource Group

Knox Creek. The Knox Creek complex includes one underground room and pillar mine, one surface mine, one highwall miner and a preparation plant. Production from the underground mine is belted by conveyor system to the preparation plant, while coal requiring processing from the surface mine, including coal from the highwall miner, is trucked to the preparation plant. The preparation 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.

Cumberland.The Cumberland complex, acquired in the Cumberland Acquisition, includes eleven underground room and pillar mines, one surface mine, a direct-ship loadout and a preparation plant. The production from the underground and surface mines is trucked to the preparation plant, which serves Norfolk Southern railway customers with unit trains of up to 110 railcars.  Limited coal is trucked using on-highway trucks to various river docks for barge delivery to customers. The preparation plant has a feed capacity of 1,250 tons per hour. Coal from this preparation plant is loaded onto trains from a batch weigh loadout.

 Coal Reserves

We estimate that, as of December 31, 2010 we had total recoverable reserves of approximately 2.8 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 1.8 billion tons of 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 approximately 1.0 billion tons of our 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.

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

As with most coal-producing companies in Central Appalachia, the majority of our coal reserves are controlled pursuant to leases from third-party landowners. The leases are generally long-term in nature (original term five to fifty 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. 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 14% of our reserve holdings are owned and require no royalty or per ton payment to other parties. Royalty expense for coal reserves from our producing properties (owned and leased) was approximately 5.0% of Produced coal revenue for the year ended December 31, 2010.

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hss

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, 2010:

Recoverable Reserves (1)
Resource Group	Location (2)	Total		Proven		Probable		Assigned (3)		Unassigned (3)		Owned		Leased
(In Thousands of Tons)
West Virginia
Black Castle	Boone County		63,314		48,656		14,658		62,700		614		—		63,314
Delbarton	Mingo County		285,106		120,440		164,666		139,608		145,498		25		285,081
Edwight	Raleigh County		4,506		4,506		—		4,506		—		—		4,506
Elk Run	Boone County		105,256		72,857		32,399		79,235		26,021		4,372		100,884
Endurance	Boone County		20,871		20,871		—		20,871		—		20,831		40
Green Valley	Nicholas County		15,290		15,290		—		14,500		790		5,001		10,289
Guyandotte	Wyoming County		45,035		17,366		27,669		2,100		42,935		330		44,705
Independence	Boone County		60,815		48,324		12,491		30,293		30,522		10,004		50,811
Inman	Boone County		44,784		43,269		1,515		—		44,784		—		44,784
Logan County	Logan County		101,039		83,800		17,239		74,019		27,020		2,388		98,651
Mammoth	Kanawha County		128,994		100,023		28,971		72,127		56,867		41,729		87,265
Marfork	Raleigh County		126,096		97,969		28,127		68,413		57,683		815		125,281
Nicholas Energy	Nicholas County		78,158		43,377		34,781		35,742		42,416		25,992		52,166
Progress	Boone County		47,031		47,031		—		47,031		—		—		47,031
Rawl	Mingo County		111,101		84,013		27,088		77,301		33,800		1,333		109,768
Republic Energy	Raleigh County		74,299		63,102		11,197		74,299		—		—		74,299
Stirrat	Logan County		5,293		3,476		1,817		412		4,881		—		5,293
Kentucky
Coalgood Energy	Harlan County		18,580		10,955		7,625		2,986		15,594		2,704		15,876
Long Fork	Pike County		4,964		2,764		2,200		264		4,700		—		4,964
Martin County	Martin County		45,747		29,058		16,689		1,905		43,842		1,336		44,411
New Ridge	Pike County		—
Sidney	Pike County		117,186		63,046		54,140		117,186		—		7,028		110,158
Black Mountain	Harlan/Letcher County		236,939		188,506		48,433		110,365		126,574		159		236,780
Virginia
Knox Creek	Tazewell County		61,737		46,756		14,981		32,605		29,132		4,552		57,185
Cumberland	Wise County		163,068		124,362		38,706		77,039		86,030		—		163,068
Subtotal			1,965,209		1,379,817		585,392		1,145,507		819,703		128,599		1,836,610
Land Management Companies: (4)
Black King	Boone County, WV		53,530		40,798		12,732		770		52,760		15,656		37,874
	Raleigh County, WV
Boone East	Boone County, WV		123,566		87,136		36,430		3,009		120,557		57,982		65,584
	Kanawha County, WV
Boone West	Lincoln County, WV		241,974		92,201		149,773		10,496		231,478		65,553		176,421
	Logan County, WV
Ceres Land	Raleigh County, WV		11,933		10,197		1,736		—		11,933		—		11,933
Rostraver Energy	Various counties, PA		99,580		49,943		49,637		—		99,580		71,222		28,358
Lauren Land	Mingo County, WV		170,956		104,364		66,592		85		170,871		17,597		153,359
	Logan County, WV
	Various counties, KY
New Market Land	Wyoming County, WV		5,884		—		5,884		—		5,884		102		5,782
Raven Resources	Raleigh County, WV		18,978		18,978		—		—		18,978		—		18,978
	Boone County, WV
Tennessee Consolidated Coal	Various counties, TN		26,907		1,332		25,575		—		26,907		24,054		2,853
Subtotal Land Management			753,308		404,949		348,359		14,360		738,948		252,166		501,142
Other	N/A		57,733		29,606		28,127		—		57,733		3,112		54,621
Total			2,776,250		1,814,372		961,878		1,159,867		1,616,384		383,877		2,392,373

(1)	Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered from the reserve base taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law.
(2)	All of the recoverable reserves listed are in Central Appalachia, except for the Rostraver reserves, which are located in Northern Appalachia and Lauren Land reserves, a portion of which are located in the Illinois Basin. The reserve numbers of each Resource Group contain a moisture factor specific to the particular reserves of that Resource Group. The moisture factor represents the average moisture present in our 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 third-party and are dedicated to a specific permitted mine of the lessee.
(4)	Land management companies are our subsidiaries whose primary purposes are to acquire and hold our reserves.

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The categorization of the “quality” (i.e., sulfur content, Btu, coal type, etc.) of coal reserves is as follows as of December 31, 2010:

			Recoverable Reserves (1)
	Recoverable Reserves		Sulfur Content					Avg. Btu as Received (3)
Resource Group				+1% (2)	-1% (2)	Compliance (2)				Coal Type (4)
(In Thousands of Tons Except Average Btu as Received)
West Virginia
Black Castle		63,314		24,549	38,765		20,766		12,700	Utility
Delbarton		285,106		111,954	173,152		127,073		13,350	High Vol Met and Utility
Edwight		4,506		1,628	2,878		3,306		12,550	High Vol Met and Utility
Elk Run		105,256		45,975	59,281		49,483		13,700	High Vol Met and Utility
Endurance		20,871		6,443	14,428		6,381		11,850	Utility
Green Valley		15,290		2,397	12,893		13,833		13,100	High Vol Met, Mid Vol Met, and Industrial
Guyandotte		45,035		—	45,035		45,035		13,850	Low Vol Met
Independence		60,815		23,818	36,997		437		12,650	High Vol Met and Utility
Inman		44,784		26,672	18,112		19,549		12,650	High Vol Met and Utility
Logan County		101,039		33,195	67,844		43,408		12,050	High Vol Met, Utility, and Industrial
Mammoth		128,994		22,391	106,603		40,145		12,150	High Vol Met and Utility
Marfork		126,096		50,535	75,561		37,732		14,050	High Vol Met and Utility
Nicholas Energy		78,158		37,528	40,630		16,581		12,450	High Vol Met and Utility
Progress		47,031		—	47,031		29,843		12,350	High Vol Met and Utility
Rawl		111,101		26,627	84,474		61,528		12,350	High Vol Met and Utility
Republic		74,299		15,994	58,305		36,980		12,450	High Vol Met and Utility
Stirrat		5,293		—	5,293		5,293		12,300	High Vol Met and Utility
Kentucky
Coalgood Energy		18,580		3,630	14,950		9,106		13,100	Utility and Industrial
Long Fork		4,964		3,500	1,464		—		12,850	Utility
Martin County		45,747		33,762	11,985		4,888		12,500	Utility
New Ridge		—					—		—	N/A
Sidney		117,186		44,970	72,216		51,559		13,200	Utility
Black Mountain		236,939		106,245	130,694		63,185		12,500	High Vol Met and Utility
Virginia
Knox Creek		61,737		8,964	52,773		37,921		12,350	High Vol Met and Utility
Cumberland		163,068		97,164	65,904		20,206		12,500	High Vol Met and Utility
Subtotal		1,965,209		727,941	1,237,268		744,238
Land Management Companies:
Black King		53,530		15,570	37,960		36,858		12,150	Low Vol Met, High Vol Met and Utility
Boone East		123,566		31,145	92,421		27,207		12,500	Low Vol Met, High Vol Met and Utility
Boone West		241,974		130,290	111,684		79,369		13,350	High Vol Met and Utility
Ceres Land		11,933		3,619	8,314		259		12,700	High Vol Met and Utility
Rostraver Energy		99,580		99,580	—		—		14,050	High Vol Met, Utility, and Industrial
Lauren Land		170,956		88,195	82,761		62,286		12,700	High Vol Met and Utility
New Market Land		5,884		—	5,884		5,884		12,700	High Vol Met and Low Vol Met
Raven Resources		18,978		7,449	11,529		1,369		12,100	High Vol Met and Utility
Tennessee Consolidated Coal		26,907		20,353	6,554		4,816		13,000	Mid Vol Met, Utility, and Industrial
Subtotal Land Management		753,308		396,201	357,107		218,048
Other		57,733		6,638	51,095		45,947		12,800	Various
Total		2,776,250		1,130,780	1,645,470		1,008,233

(1)	The reserve numbers of each Resource Group contain a moisture factor specific to the particular reserves of that Resource Group. The moisture factor represents the average moisture present in our 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 is included in the -1% column.
(3)	Represents an estimate of the average Btu per pound present in our coal, as it is received by the customer.
(4)	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.

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Compliance compared to non-compliance coal

Coals are sometimes characterized as compliance or non-compliance coal. The phrase compliance coal, as it is commonly used in the coal industry, refers to compliance only with sulfur dioxide emissions standards imposed by Title IV of the Clean Air Act and indicates that when burned, the coal will produce emissions that will meet the current standard without further cleanup. A coal that is considered a compliance coal for meeting sulfur dioxide standards may not meet an emission standard for a different pollutant such as mercury. Moreover, the term compliance coal is always used with reference to the then current regulatory limit. Clean air regulations that further restrict sulfur dioxide emissions will likely reduce significantly the amount of coal that can be labeled compliance. Currently, coal classified as compliance coal will meet the power plant emission standard of 1.2 pounds of sulfur dioxide per million Btu’s of fuel consumed. At December 31, 2010, approximately 1.0 billion tons, or 36%, of our coal reserves met the current standard as compliance coal.

Distribution

We employ transportation specialists who negotiate freight and terminal agreements with various providers, including railroads, barge lines, ocean-going vessels, 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.

Our 2010 shipments of 37.1 million tons were loaded from 25 mining complexes. Rail shipments constituted 82% of total shipments, with 35% loaded on Norfolk Southern trains and 65% loaded on CSX trains. The balance was shipped from mining complexes via truck or barge.

Approximately 14% of production was ultimately delivered via the inland waterway system. Coal is loaded directly into barges, or is transported by rail or truck to docks on the Ohio, Big Sandy and Kanawha Rivers and then ultimately transported by barge to electric utilities, integrated steel producers and industrial consumers served by the inland waterway system. We also moved approximately 4% of our production to Great Lakes’ ports for transport to various United States and Canadian customers and 17% of our production to Gulf of Mexico and East Coast ports for transport to export customers.

Customers and Coal Contracts

We have coal supply commitments with a wide range of electric utilities, steel manufacturers, industrial customers and energy traders and brokers. By offering coal of both steam and metallurgical grades, we are able to serve a diverse customer base. This market diversity allows us to adjust to changing market conditions and sustain high sales volumes. The majority of our customers purchase coal for terms of one year or longer, but we also supply coal on a spot basis for some customers. At December 31, 2010, approximately 34%, 52% and 14% of Trade receivables represents amounts due from utility customers, metallurgical customers and industrial customers, respectively, compared with 61%, 19% and 20%, respectively, as of December 31, 2009. No single customer accounted for 10% or more of fiscal year 2010 Produced coal revenue or produced tons.

As is customary in the coal industry, we enter into long-term contracts (one year or more in duration) with many of our customers. These arrangements allow customers to secure a supply for their future needs and provide us with greater predictability of sales volume and sales prices. 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 United States Department of Labor. Coal quality specifications may be especially stringent for steel customers.

For the year ended December 31, 2010, approximately 99% of coal sales volume was pursuant to long-term contracts. We anticipate that in 2011, coal sales volume percentage pursuant to long-term arrangements will be comparable to 2010. As of February 16, 2011, we had contractual sales commitments of approximately 86 million tons, including commitments subject to price reopener and/or optional tonnage provisions. Remaining contractual terms of our sales commitments range from one to nine years with an average volume-weighted remaining term of approximately 2.9 years. Seventy-nine percent of our total contracted sales tons are priced. As of February 16, 2011, we have committed approximately 95% of our expected 2011 production. In addition, we purchase coal from third-party coal producers from time to time to supplement production and resell this coal to customers.

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Suppliers

The main types of goods we purchase are mining equipment and replacement parts, explosives, fuel, tires, steel-related (including roof control) products and lubricants. Although we have many well-established, strategic relationships with our key suppliers, we do not believe that we are dependent on any of our individual suppliers, except as noted below. The supplier base providing mining materials has been relatively consistent in recent years, although there continues to be some consolidation. Consolidation of suppliers of explosives has limited the number of sources for these materials. Although our current supply of explosives is concentrated with one supplier, some alternative sources are available to us in the regions where we operate. Further consolidation of underground equipment suppliers has resulted in a situation where purchases of certain underground mining equipment are concentrated with one principal supplier; however, supplier competition continues to develop. In recent years, demand for certain surface and underground mining equipment and off-the-road tires has increased. As a result, lead times for certain items have generally increased, although no material impact is currently expected to our cash flows, results of operations or financial condition.

Competition

The coal industry in the United States and overseas is highly competitive, with numerous producers selling into all markets that use coal. We compete against large and small producers in the United States and overseas. The NMA estimated that in 2009 there were 28 coal companies in the United States with annual production of 5 million or more tons, which together account for approximately 87% of United States production. According to the NMA, we were the sixth largest coal company in terms of tons produced in 2009, exceeded by Peabody Energy Corporation, Rio Tinto Energy America, Inc., Arch Coal, Inc., Alpha and CONSOL Energy Inc.

We compete 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 of our control, including demand for electricity and steel, general economic conditions, environmental and governmental regulations, weather, technological developments, and the availability and cost of alternative fuel sources. We sell coal to foreign electricity generators and to the more specialized metallurgical coal market, both of which are significantly affected by international demand and competition.

Historically, global coal markets have responded to increased demand and higher prices for coal by increasing production and supply. In recent years, however, industry capacity expansion has been somewhat limited by the increased costs of mining, high capital requirements, labor shortages, transportation issues related to rail, barge and truck shipments, higher costs related to compliance with new and increasingly stringent regulations, the difficulty of obtaining permits and bonding and other factors. We also believe that capacity expansion for some competitors may be limited by coal seam degradation and reserve depletion.  While these constraints persist in major coal producing countries and regions, periods of supply and demand imbalance may be extended and increased pricing volatility may result.

During 2010, we substantially increased our coal reserves principally through the acquisition of Cumberland.  During 2010 we also completed several coal reserve trades and acquisitions that increased our total reserve base.  These transactions, in addition to adjustments made in conjunction with normal annual review and re-evaluation of reserves, and offset by 37 million tons of coal produced, resulted in a net increase of 366 million tons of coal reserves during the year.  Following this increase, we estimate that we had 2.8 billion tons of proven and probable coal reserves at December 31, 2010.

Other Related Operations

We have other related operations and activities in addition to our normal coal production and sales business. The following business activities are included in this category:

Coal Handling Joint Venture. We hold a 50% interest in a joint venture that owns and operates third-party end-user coal handling facilities. Certain of our subsidiaries currently operate the coal handling facilities for the joint venture.

Gas Operations. We hold interests in operations that produce, gather and market natural gas from shallow reservoirs in the Appalachian Basin. In the eastern United States, 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 us range from 2,500 to 5,800 feet.

Nearly all of our gas production is from operations in southern West Virginia. In this region, we own and operate approximately 160 wells, 200 miles of gathering line, and various small compression facilities. Our West Virginia operations control approximately 28,000 acres of natural gas drilling rights and 11,000 acres of coalbed methane drilling rights. In addition, we own a majority working interest in 50 wells operated by others, and minority working interests in approximately 13 wells operated by others. The December 2010, average daily net production, from the 228 wells owned or controlled, was 1.8 million cubic feet per day. We do not consider our current gas production level, revenues or costs to be material to our cash flows, results of operations or financial condition.

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Other. From time to time, we also engage in the sale of certain non-strategic assets such as timber, oil and gas rights, surface properties and reserves. In addition, we have 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 several metallurgical and 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. We work closely with customers to provide other services in response to the current needs of each individual customer.

Marketing and Sales

Our 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, 2010, we sold 37.1 million tons of produced coal for total Produced coal revenue of $2.6 billion. The breakdown of produced tons sold by market served was 70% utility, 21% metallurgical and 9% industrial. Sales were concluded with over 100 customers. Export shipment revenue totaled approximately $557.7 million, representing approximately 21% of 2010 Produced coal revenue. In 2010, we exported shipments to customers in 14 countries across the globe, which included destinations in Europe, Asia, Africa, South America and North America. Sales are made in United States dollars, which minimizes foreign currency risk.

Employees and Labor Relations

As of December 31, 2010, we had 7,359 employees, including 91 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.

Environmental, Safety and Health Laws and Regulations

The coal mining industry is subject to regulation by federal, state and local authorities on matters such as the discharge of materials into the environment, employee health and safety, permitting and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, water appropriation and legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, endangered plant and wildlife protection, limitations on land use, and storage of petroleum products and substances that are regarded as hazardous under applicable laws. The possibility exists that new legislation or regulations may be adopted that could have a significant impact on our mining operations or on our customers’ ability to use coal.

Numerous governmental permits and approvals are required for mining operations. Regulations provide that a mining permit or modification can be delayed, refused or revoked if an officer, director or a stockholder with a 10% or greater interest in the entity is affiliated with or is in a position to control another entity that has outstanding permit violations. Thus, past or ongoing violations of federal and state mining laws by individuals or companies no longer affiliated with us could provide a basis to revoke existing permits and to deny the issuance of addition permits. We are required to prepare and present to federal, state or local authorities data and/or analysis pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment, public and employee health and safety. All requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Accordingly, the permits we need for our mining and gas operations may not be issued, or, if issued, may not be issued in a timely fashion. Permits we need may involve requirements that may be changed or interpreted in a manner that restricts our ability to conduct our mining operations or to do so profitably. Future legislation and administrative regulations may increasingly emphasize the protection of the environment, health and safety and, as a consequence, our activities may be more closely regulated. Such legislation and regulations, as well as future interpretations of existing laws, may require substantial increases in equipment and operating costs, delays, interruptions or a termination of operations, the extent of which cannot be predicted.

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While it is not possible to quantify the expenditures we incur to maintain compliance with all applicable federal and state laws, those costs have been and are expected to continue to be significant. We post surety performance bonds or letters of credit pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, often including the cost of treating mine water discharge when necessary. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers. We endeavor to conduct our mining operations in compliance with all applicable federal, state and local laws and regulations. However, even with our substantial efforts to comply with extensive and comprehensive regulatory requirements, violations during mining operations occur from time to time. In 2007, the United States Environmental Protection Agency (“EPA”) filed suit against us and twenty-seven of our subsidiaries alleging violations of the Federal Clean Water Act. In January 2008, we announced that we had agreed with EPA to settle the lawsuit for a payment of $20 million in penalties. In 2010, we spent approximately $18.4 million to comply with environmental laws and regulations, of which $9.6 million was for reclamation, including $6.3 million for final reclamation. None of these expenditures were capitalized. We anticipate spending approximately $50.9 million and $42.5 million in such non-capital expenditures in 2011 and 2012, respectively. Of these expenditures, $38.7 million and $29.9 million for 2011 and 2012, respectively, are anticipated to be for final reclamation.

Emission Control Technology. We own a majority interest in Coalsolv, LLC (“Coalsolv”), which holds the United States marketing rights for the coal-fired plant emission control technologies developed by Cansolv Technologies, Inc. (“Cansolv”). Cansolv’s technologies remove sulfur dioxide (SO2), nitrogen oxide (NOx), mercury, carbon dioxide (CO2), and other greenhouse gases from flue gas emissions. The Cansolv process has been utilized at various industrial facilities around the world, with additional projects underway in China and Canada. Through Coalsolv, we contributed funds for a pilot plant that has been utilized in the United States and Canada for the testing and piloting of the Cansolv SO2, NOX, mercury and CO2 capture technology on coal-fired power plants.

Mine Safety and Health

Stringent health and safety standards have been in effect since Congress enacted the Federal Coal Mine Health and Safety Act of 1969. The Federal Coal 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. A further expansion occurred in June 2006 with the enactment of the Mine Improvement and New Emergency Response Act of 2006 (“MINER Act”).

The MINER Act and related Mine Safety and Health Administration (“MSHA”) regulatory actions require, among other things, improved emergency response capability, increased availability of emergency breathable air, enhanced communication and tracking systems, more available mine rescue teams, increased mine seal strength and monitoring of sealed areas in underground mines, and larger penalties by MSHA for noncompliance by mine operators. Coal producing states, including West Virginia and Kentucky, have passed similar legislation.

           In 2008, MSHA published final rules implementing Section 4 of the MINER Act that addressed mine rescue, sealing of abandoned areas, refuge alternatives, fire prevention and detection, use of air from the belt entry and civil penalty assessments.  MSHA also provided guidance on wireless communication and electronic tracking systems and new requirements for the plugging of coal bed methane wells with horizontal branches in coal seams.  Two additional regulations were also published related to measures to achieve alcohol and drug free mines and the use of coal mine dust personal monitors. In February 2009, the United States Court of Appeals for the District of Columbia Circuit held that the 2008 rules were not sufficient to satisfy the requirements of the MINER Act in certain respects, and remanded those portions of the rules to MSHA for reconsideration. New rules issued by the MSHA will likely contain more stringent provisions regarding training of rescue teams.

Although we do not believe we can quantify a specific amount of our capital and operational expenditures related to health and safety regulations, we have undertaken an analysis of our expenditures with the goal of preparing a reasonable estimate of such expenditures. Based on this analysis, we believe a reasonable estimate of capital expenditures related to health and safety regulations is approximately $18.4 million and $24.4 million for the fiscal years ended December 31, 2010 and 2009, respectively. These capital expenditures were primarily for mine communication systems, mine seals, safety shelters and self-rescuer caches, requirements that were put in place with the MINER Act.  In addition, we believe a reasonable estimate of operational expenditures related to health and safety regulations is approximately $52.2 million and $40.5 million for the fiscal years ended December 31, 2010 and 2009, respectively. These expenditures include labor and supply costs incurred to support our mine rescue teams, our corporate safety department, safety personnel at our mine sites, the payment of safety bonuses, fire suppression costs and other general safety supplies. These expenditures do not include certain other capital and operational expenditures related to production that indirectly contribute to the safe operation of our coal mines. Consequently, we believe that our total capital and operational expenditures related to safety are likely in excess of these amounts.

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On October 19, 2010, MSHA issued a proposed rule, 75 Fed. Reg. 64412 (“PR1”), which would lower the current two milligram dust standard to one milligram gradually over a two-year period, mandate the use of continuous personal dust monitors, address extended work shifts, redefine normal production shifts, require additional medical surveillance examinations for miners, and provide for the use of a single, full-shift sample to determine compliance.

The current respirable coal mine dust exposure standard would be reduced as follows:

● The current limit would be lowered to 1.7 mg/m3 six months after the final rule's effective date.

● The limit would be lowered to 1.5 mg/m3 12 months after the final rule's effective date.

● The limit would be lowered to 1.0 mg/m3 24 months after the final rule's effective date.

● The limit for miners who show evidence of developing pneumoconiosis would be reduced to 0.5 mg/m3 six months after the final rule's effective date.

● Additionally, the limit for intake air at underground mines would be reduced to 0.5 mg/m3 six months after the final rule's effective date.

The PR1 would phase in the required use of the Continuous Personal Dust Monitor (“CPDM”).  The CPDMs would electronically store all respirable dust sampling data collected during a shift and would be sent to MSHA electronically.  The CPDMs would be optional for surface coal mines and for non-production areas of underground coal mines (such as outby areas).

Other changes include: requiring sampling of extended work shifts to account for occupational exposures of greater than eight hours per shift; requiring sampling when production is equivalent to or greater than the level of average production level over the last 30 production shifts; requiring spirometry testing, occupational history and symptom assessment to be implemented, in addition to the chest x-ray exam currently required for underground coal miners and medical surveillance; and finally, a single, full-shift sample collected by MSHA or the mine operator would be used to determine compliance rather than averaging multiple dust samples of different miners’ exposures per the current requirements.

The PR1 is out for comment until May 2, 2011.

On September 23, 2010, MSHA promulgated an Emergency Temporary Standard (“ETS”) requiring that the total incombustible content (“TIC”) of the combined coal, rock and other dusts in underground coal mines be at least 80%. 75 Fed. Reg. 57849 (Sept. 23, 2010). In addition, the ETS requires that where methane is present in any ventilating current, the TIC of such combined dust shall be increased 0.4% for each 0.1% of methane. The ETS revised the existing standard, 30 C.F.R. § 75.403, which permitted TIC of combined dusts to be 65% in areas of a mine other than return air courses.

The ETS serves as an emergency temporary final rule with immediate effect and provides for an opportunity for notice and comment, after which MSHA will issue a new final standard. The new final standard must be issued within nine months of the promulgation of the ETS and may differ from the ETS.

On February 2, 2011, MSHA published proposed changes to 30 C.F.R. Part 104 regarding the Pattern of Violations (“POV”) program (“PR2”).  Under the PR2, MSHA will consider all significant and substantial (“S&S”) citations and orders issued, including non-final citations and orders, when determining POV status.  The existing initial screening criteria found at 30 C.F.R. § 104.2 will be eliminated.  Additionally, the PR2 removes the potential POV notice and instead will post the pattern criteria online so that operators can track their status.  MSHA will also post compliance data that the agency will use on its website and provide access to mine operators in a searchable form.  Finally, mines will be reviewed at least twice annually for POV status under the PR2.  The new POV status will utilize similar criteria as to what is currently set forth in 30 C.F.R. § 104.3, including the history of S&S violations, § 104(b) failure to abate orders for S&S violations, § 104(d) citations and orders for an unwarrantable failure to comply, § 107(a) imminent danger orders, § 104(g) orders for untrained miner withdrawal orders, and other information “that demonstrates a serious safety or health management problem at the mine, such as accident, injury and illness records.”  Mitigating circumstances will also be considered, including changes in ownership, however, it is unclear at what point in the process the mine operator may offer such information to MSHA.

The PR2 is out for comment until April 4, 2011. 

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On December 27, 2010, MSHA issued a proposed rule, 75 Fed. Reg. 81165 (“PR3”), to revise the requirements for pre-shift, supplemental, on-shift and weekly examinations of underground coal mines.  The PR3 would add the requirement that operators identify violations of mandatory health or safety standards and would also require the mine operator to record and correct these violations, note the actions taken to correct the conditions and review with mine examiners (e.g., the mine foreman, assistant mine foreman or other certified persons) on a quarterly basis all citations and orders issued in areas where pre-shift, supplemental, on-shift and weekly examinations are required.

The PR3 is out for comment until February 25, 2011.

We are committed to providing a safe workplace for all of our employees. Our company has in place health and safety programs that include extensive employee training, accident prevention, workplace inspection, emergency response, accident investigation, regulatory compliance and program auditing. The objectives of our health and safety programs are to eliminate workplace incidents, comply with all mining-related regulations and provide support for both regulators and the industry to improve mine safety. Our company has a process of training, mentoring, monitoring, reduction of risk through safety innovation and recognition of safety excellence. We believe that superior safety and health performance leads to achieving productivity and financial goals, with overarching benefits for our stockholders, the community and the environment.

The states in which we operate have state 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 for protection of employee health and safety affecting any segment of industry in the United States. While regulation has a significant effect on our operating costs, our United States competitors are subject to the same regulation.

Our safety performance is measured in a variety of different ways, including through accident and violation experience expressed in terms of Non-Fatal Days Lost (NFDL) injury incident rates, Total Reported Incident Rates (TRIR) and Violations per Inspection Day (VPID).  The NFDL incident rate represents the number of non-fatal injuries that result in days away from work, statutory days charged, or days of restricted work activity annually per 100 employees.  The TRIR represents the number of NFDL injuries, injuries requiring medical treatment and fatalities occurring annually per 100 employees.  The VPID measure represents the average number of violations issued by MSHA per inspection day (each day constitutes 5 on-site inspection hours).

The Bituminous Coal Industry (BCI) performance based on MSHA data and expressed in terms of NFDL rate, TRIR and VPID,  is used as a benchmark by which to measure the safety performance of our operations. These metrics are also used to benchmark our performance against that of our competitors. Our preliminary estimate of our 2010 NFDL rate is 3.13 compared to a preliminary 2010 BCI NFDL rate of 2.53.  Our preliminary estimate of our 2010 TRIR of  5.03 compared to a preliminary 2010 BCI TRIR of 3.84.  Our preliminary estimate of our 2010 VPID performance is 0.65 compared to an estimated BCI VPID of 0.75. In addition, while our mining operations continue to receive citations, orders and notices of violation from mine health and safety regulatory agencies, we attempt to promptly abate the condition cited, whether or not we challenge the validity of the issuance. Additionally, we either pay the assessed penalties or contest the matter if we dispute the alleged facts behind the violation or the amount of the assessed penalty.  We are not satisfied with the number of citations, orders and notices of violation we have received from MSHA and other regulatory agencies. With a great sense of urgency, we have been renewing our efforts and commitment to significantly reduce the number of mine health and safety violations issued to our operations.  Our goal is to fully comply with all applicable regulatory requirements.

In addition, while we receive citations, orders and notices of violation from MSHA and other regulatory agencies on a frequent basis, we attempt to promptly abate the condition cited, whether or not we agree as to whether the condition constitutes a violation. Additionally, we either pay the assessed penalties, or if we dispute the alleged facts behind the violation or the amount of the penalty relative to the violation, we contest the matter. We are not satisfied with the number of citations, orders and notices of violation we have received from MSHA and other regulatory agencies. With a great sense of urgency, we have been renewing our efforts and commitment to significantly reduce the number of infractions received from MSHA and other regulatory agencies.  Our goal is to fully comply with the regulations issued by MSHA and other regulatory agencies.

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 we 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, we are also liable under various state statutes for black lung claims. Federal benefits are offset by any state benefits paid.

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Workers’ Compensation. We are liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in the states in which we have operations. Workers’ compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation owed to an employee injured in the course of employment.

Coal Industry Retiree Health Benefit Act of 1992 and Tax Relief and Retiree Health Care Act of 2006. 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 Benefit Fund (“CBF”) into which “signatory operators” and “related persons” are obligated to pay annual premiums for covered beneficiaries. The Coal Act also created a second benefit fund, the 1992 Benefit Plan, for miners who retired between July 21, 1992 and September 30, 1994 and whose former employers are no longer in business. On December 20, 2006, President Bush signed the Tax Relief and Retiree Health Care Act of 2006. This legislation includes important changes to the Coal Act that impacts all companies required to contribute to the CBF. Effective October 1, 2007, the SSA revoked all beneficiary assignments made to companies that did not sign a 1988 UMWA contract (“reachback companies”), but phased-in their premium relief. As a pre-1988 signatory, our related reachback companies received the applicable premium relief. Effective October 1, 2007, reachback companies paid only 55% of their plan year 2008 assessed premiums, 40% of their plan year 2009 assessed premiums, and 15% of their plan year 2010 assessed premiums. General United States Treasury money will be transferred to the CBF to make up the difference. After 2010, reachback companies have no further obligations to the CBF, and transfers from the United States Treasury will cover all of the health care costs for retirees and dependents previously assigned to reachback companies.

Pension Protection Act. The Pension Protection Act of 2006 (“Pension Act”) has simplified and transformed the rules governing the funding of defined benefit plans, accelerated funding obligations of employers, made permanent certain provisions of the Economic Growth and Tax Relief Reconciliation Act of 2001, made permanent the diversification rights and investment education provisions for plan participants and encouraged automatic enrollment in defined contribution 401(k) plans. In general, most provisions of the Pension Act took effect for plan years beginning on or after December 31, 2007. Plans generally are required to set a funding target of 100% of the present value of accrued benefits and sponsors are required to amortize unfunded liabilities over a seven year period. The Pension Act included a funding target phase-in provision consisting of a 92% funding target in 2008, 94% in 2009, 96% in 2010 and 100% thereafter. Plans with a funded ratio of less than 80%, or less than 70% using special assumptions, are deemed to be “at risk” and are subject to additional funding requirements. As of December 31, 2010, our pension plan was underfunded by $79.7 million.  We currently expect to make contributions in 2011 of approximately $20 million. The funded status at the end of fiscal year 2011, and the need for additional future required contributions will depend primarily on the actual return on assets during the year and the discount rate at the end of the year.

Patient Protection and Affordable Care Act. In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was enacted, potentially impacting our costs to provide healthcare benefits to our eligible active and certain retired employees, and our costs to provide workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (black lung disease).  Implementation of this legislation is planned to occur in phases over a number of years.

Required changes that affected us in the short term included raising the maximum age for covered dependents to receive benefits, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual, among other requirements.  Required changes that could affect us in the long term include a tax on “high cost” plans (excise tax) and the elimination of annual dollar limits per covered individual, among other requirements.

One provision of the legislation changes the tax treatment for Medicare drug subsidies.  Beginning in fiscal year 2014, the tax deduction available to us will be reduced to the extent our drug expenses are reimbursed under the Medicare Part D retiree drug subsidy program.  Because retiree health care liabilities and the related tax impacts are already reflected in our Consolidated Financial Statements, we were required to recognize the full accounting impact of this accounting standard update in the period in which the PPACA was signed into law.  The total non-cash charge to Income tax expense in 2010 related to the reduction in the tax benefit was $2.6 million.

Significant uncertainties exist regarding the excise tax on high cost plans. Because of those uncertainties, calculation of a precise liability for this excise tax is impossible at this time. Based on our understanding of the law and regulations as they exist today, we have concluded that the tax will not impact the liability related to our retiree medical plan.  We anticipate that future commentary and additional regulations will clarify many of the uncertainties which exist today.  We will continue to monitor the emerging regulations and will update our expectations on the effect to our retiree medical liability as necessary. The retiree medical plan has been deemed to be a retiree only plan, thus no plan changes related to PPACA coverage enhancements were made for 2010. We continue to analyze this legislation to determine the full extent of the impact of the required changes on our employee healthcare plans and the resulting costs.

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The PPACA also amended previous legislation related to coal workers’ pneumoconiosis (black lung disease), providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims.  In order to reflect the potential impact of the PPACA reforms, we have incorporated the following changes into the valuation of our black lung liabilities:

● Increased disability incidence rates for both active and terminated miners,

● Increased approval rates for Federal claims in adjudication,

● Assumed that 100% of widows of deceased miners will file a successful death benefit claim, and

● Assumed that a portion of previously closed claims will re-file and be awarded disability benefits

We are continuing to monitor the impact of these changes to our current population of beneficiaries and claimants and the effect on potential future claims.

Environmental Laws

Surface Mining Control and Reclamation Act. The Surface Mining Control and Reclamation Act, (“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 $0.315 per ton on surface-mined coal and $0.135 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. We accrue for reclamation and mine-closing liabilities in accordance with accounting principles generally accepted in the United States (“GAAP”). See Note 13 to the Notes to 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 of the United States 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 are typically placed in fills in adjacent valleys and hollows. Likewise, coal refuse disposal areas and coal processing slurry impoundments are located in valleys and hollows. These areas frequently 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. Discharges from these structures require permits under Section 402 of the Clean Water Act. Section 402 discharge permits are generally not suitable for authorizing the construction of fills in navigable waters.

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 our mining facilities, by far their greatest impact on us 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 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 and a corresponding decrease in revenue and profits.  

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National Ambient Air Quality Standards. Ozone is produced by a combination of two precursor pollutants: volatile organic compounds and nitrogen oxide, a by-product of coal combustion. Particulate matter is emitted by sources burning coal as fuel, including coal fired power plants. States are required to submit to the EPA revisions to their State Implementation Plans (“SIPs”) that demonstrate the manner in which the states will attain National Ambient Air Quality Standards (“NAAQS”) every time a NAAQS is revised by the EPA. In 2006, the EPA adopted a new NAAQS for fine particulate matter, which a number of states and environmental advocacy groups challenged as not sufficiently stringent to satisfy Clean Air Act requirements; in February 2009, the United States Court of Appeals for the District of Columbia Circuit agreed that the EPA had inadequately explained its decision regarding several aspects of the NAAQS and remanded those to the EPA for reconsideration, a process that could lead to more stringent NAAQS for fine particulate matter. The EPA also adopted a more stringent ozone NAAQS on March 27, 2008. In addition, in 2009 and early 2010, the EPA has proposed even more stringent NAAQS for ozone, SO2, and NO2. Revised SIPs for ozone, SO2, NO2, and fine particulates could require electric power generators to further reduce particulate, nitrogen oxide and sulfur dioxide emissions. In addition to the SIP process, the Clean Air Act permits states to assert claims against sources in other “upwind” states alleging that emission sources including coal fired power plants in the upwind states are preventing the “downwind” states from attaining a NAAQS. The new NAAQS for ozone and fine particulates, as well as claims by affected states, could result in additional controls being required of coal fired power plants and we are unable to predict the effect on markets for our coal. 

Acid Rain Control Provisions. The acid rain control provisions promulgated as part of the Clean Air Act Amendments of 1990 in Title IV of the Clean Air Act (“Acid Rain program”) required reductions of sulfur dioxide emissions from power plants. The Acid Rain program is now a mature program and we believe that any market impacts of the required controls have likely been factored into the price of coal in the national coal market.

Regional Haze Program. The EPA promulgated a regional haze program designed to protect and to improve visibility at and around so-called Class I Areas, which are generally National Parks, National Wilderness Areas and International Parks. This program may restrict the construction of new coal-fired power plants whose operation may impair visibility at and around the Class I Areas. Moreover, the program requires 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. States were required to submit Regional Haze SIPs to the EPA by December 17, 2007. Many states did not meet the December 17, 2007, deadline, and on February 4, 2011, several environmental groups (including the Sierra Club and  Environmental Defense Fund) notified the EPA that they intend to sue the EPA under the citizen suit provision of the Clean Air Act for failure to enforce the regional haze rule. We are unable to predict the impact on the coal market of either the states’ failure to submit Regional Haze SIPs by the deadline or the potential litigation.

New Source Review Program. Under the Clean Air Act, new and modified sources of air pollution must meet certain new source standards (“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. Some of these lawsuits have been settled, with the owners agreeing to install additional pollution control devices in their coal-fired plants. The remaining litigation and the uncertainty around the New Source Review Program rules could adversely impact utilities’ demand for coal in general or coal with certain specifications, including the coal we produce.

Multi-Pollutant Strategies. In March 2005, the EPA issued two closely related rules designed to significantly reduce levels of sulfur dioxide, nitrogen oxide and mercury: the Clean Air Interstate Rule (“CAIR”) and the Clean Air Mercury Rule (“CAMR”). CAIR sets a “cap-and-trade” program in 28 states and the District of Columbia to establish emissions limits for sulfur dioxide and nitrogen oxide on electric utility generators (“EGU”), by allowing utilities to buy and sell credits to assist in achieving compliance with the NAAQS for eight hour ozone and fine particulates. CAMR as promulgated will cut mercury emissions nearly 70% by 2018 through a “cap-and-trade” program. Both rules were challenged in numerous lawsuits and the United States Court of Appeals for the District of Columbia Circuit vacated CAMR and remanded it to the EPA for reconsideration on February 8, 2008. The same court vacated the CAIR on July 11, 2008, but subsequently revised its remedy to a remand to the EPA for reconsideration on December 23, 2008. The EPA proposed a CAIR replacement rule (dubbed the Clean Air Transport Rule or “CATR”) on August 2, 2010 and has stated its intent to finalize the CATR in mid-2011. In addition, the EPA Administrator announced in December 2009 that the EPA would propose a new air toxics Maximum Achievable Control Technology (“MACT”) standard for EGU’s in 2010 and finalize it in 2011. The MACT has not been proposed yet but EPA has been sued for failure to promulgate the rule. Under a draft consent decree, EPA’s revised schedule calls for a March 2011 proposal and November 2011 final rule. The new rule will regulate several air toxics in addition to mercury and will likely have a significant impact on the levels of controls required on EGU’s. Regardless of the outcome of litigation on either rule, stricter controls on emissions of SO2, NOX and mercuryare likely in some form. Any such controls may have an impact on the demand for our coal. 

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Global Climate Change

Global climate change continues to attract considerable public and scientific attention. Widely publicized scientific reports, such as the Fourth Assessment Report of the Intergovernmental Panel on Climate Change released in 2007, have also engendered widespread concern about the impacts of human activity, especially fossil fuel combustion, on global climate change. A considerable and increasing amount of attention in the United States is being paid to global climate change and to reducing greenhouse gas emissions, particularly from coal combustion by power plants. According to the EIA report, “Emissions of Greenhouse Gases in the United States 2007,” coal combustion accounts for 30% of man-made greenhouse gas emissions in the United States. Legislation was introduced in Congress in the past several years to reduce greenhouse gas emissions in the United States and, although no bills to reduce such emissions have yet to pass both houses of Congress, bills to reduce such emissions remain pending and others are likely to be introduced. President Obama campaigned in favor of a “cap-and-trade” program to require mandatory greenhouse gas emissions reductions and since his election has continued to express support for such legislation, contrary to the previous administration.

The issue of greenhouse gasses has been the subject of a number of recent court cases. Most recently, in the case of Massachusetts v. EPA, the United States Supreme Court (“Supreme Court”) found that greenhouse gases are air pollutants covered by the Clean Air Act.  The Supreme Court held that the administrator of the EPA must determine whether emissions of greenhouse gases from new motor vehicles cause or contribute to air pollution that may reasonably be anticipated to endanger public health or welfare, or whether the science is too uncertain to make a reasoned decision.  The Supreme Court decision resulted from a petition for rulemaking under section 202(a) of the Clean Air Act filed by more than a dozen environmental, renewable energy, and other organizations. On December 7, 2009, the EPA Administrator signed two distinct findings regarding greenhouse gases under section 202(a) of the Clean Air Act. One finding is that the current and projected concentrations of the six key well-mixed greenhouse gases--carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)--in the atmosphere threaten the public health and welfare of current and future generations. The second finding is that the combined emissions of these well-mixed greenhouse gases from new motor vehicles and new motor vehicle engines contribute to the greenhouse gas pollution which threatens public health and welfare. While those findings did not themselves impose any requirements on industry or other entities, the actions were a prerequisite to finalizing the EPA’s proposed greenhouse gas emission standards for light-duty vehicles, which were finalized by the EPA and the Department of Transportation’s National Highway Safety Administration on April 1, 2010. In addition, those findings have triggered reporting, permitting and other requirements for stationary sources regarding CO2 and other greenhouse gasses. Those requirements may have a significant, but undetermined impact on the ability to mine and use coal.

In December 2009, 192 countries attended the Copenhagen Climate Change Summit to discuss actions to be taken to combat global climate change. Leaders from more than two dozen countries representing over 80% of the world’s SO2 emissions negotiated the Copenhagen Accord, which puts a non-binding expectation on all of the major emitting countries to officially record their commitments to reduce SO2 emissions by January 31, 2010. The United States participated in the conference and stated a goal to reduce emissions in the range of 17% below 2005 levels by 2020, 42% below 2005 levels by 2030, and 83% below 2005 levels by 2050, which is substantially in line with the energy and climate legislation passed by the United States House of Representatives in 2009.  The 2010 United Nations Climate Change Conference was held in Cancun, Mexico, in late 2010. The outcome of that summit was an agreement, though not a binding treaty, that states that the participating parties recognize that (1) climate change represents an urgent and potentially irreversible threat to human societies and the planet, required to be urgently addressed by all parties, (2) warming of the climate system is unequivocal and that most of the observed increase in global average temperatures since the mid twentieth century is very likely due to the observed increase in anthropogenic greenhouse gas concentrations, (3) deep cuts in global greenhouse gas emissions are required, with a view to reducing global greenhouse gas emissions so as to hold the increase in global average temperature below 2°C above pre-industrial levels, (4) parties should take urgent action to meet this long-term goal, consistent with science and on the basis of equity, and (5) addressing climate change requires a paradigm shift towards building a low-carbon society. The agreement also calls on rich countries to reduce their greenhouse gas emissions as pledged in the Copenhagen Accord, and for developing countries to plan to reduce their emissions.

The ultimate outcome of the Copenhagen Accord and any treaty or other arrangement ultimately adopted by the United States or other countries, may have a material adverse impact on the global supply and demand for coal. This is particularly true if cost effective technology for the capture and sequestration of carbon dioxide is not sufficiently developed. Technologies that may significantly reduce emissions into the atmosphere of greenhouse gases from coal combustion, such as carbon capture and sequestration (which captures carbon dioxide at major sources such as power plants and subsequently stores it in nonatmospheric reservoirs such as depleted oil and gas reservoirs, unmineable coal seams, deep saline formations, or the deep ocean) have attracted and continue to attract the attention of policy makers, industry participants and the public. For example, in July 2008, the EPA proposed rules that would establish, for the first time, requirements specifically for wells used to inject carbon dioxide into geologic formations. No regulations have been promulgated yet, but the issue of carbon sequestration results in considerable uncertainty, not only regarding rules that may become applicable to carbon dioxide injection wells but also concerning liability for potential impacts of injection, such as groundwater contamination or seismic activity. In addition, technical, environmental, economic or other factors may delay, limit, or preclude large-scale commercial deployment of such technologies, which could ultimately provide little or no significant reduction of greenhouse gas emissions from coal combustion.

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Global climate change continues to attract considerable public and scientific attention and a considerable amount of legislative attention in the United States is being paid to global climate change and the reduction of greenhouse gas emissions, particularly from coal combustion by power plants.  Enactment of laws and passage of regulations regarding greenhouse gas emissions by the United States or some of its states, or other actions to limit carbon dioxide emissions, could result in electric generators switching from coal to other fuel sources.

Permitting and Compliance

Our operations are principally regulated under surface mining permits issued pursuant to the SMCRA and state counterpart laws. Such permits are issued for terms of five years with the right of successive renewal. We currently have over 500 surface mining permits. In conjunction with the surface mining permits, most operations hold national pollutant discharge elimination system permits pursuant to the Clean Water Act and state counterpart water pollution control laws for the discharge of pollutants to waters. These permits are issued for terms of five years. Additionally, the Clean Water Act requires permits for operations that fill waters of the United States. Valley fills and refuse impoundments are authorized under permits issued under the Clean Water Act by the United States 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. Both types of Clean Water Act permits have been more difficult to obtain in Central Appalachia under policies adopted by the current EPA administration.  In January 2011, however, a federal district court ruled that a challenge by the National Mining Association to some of these policies will likely succeed.  See NMA v. Jackson, No. 10-1220 (D.D.C.).

We believe we have obtained all permits required for current operations under the SMCRA, Clean Water Act and Clean Air Act and corresponding state laws. We believe that we are in compliance in all material respects with such permits, and routinely correct violations in a timely fashion in the normal course of operations. We believe the expiration dates of the permits are largely immaterial. The law provides for a right of successive renewal for SMCRA permits; however, it is unclear at this time whether permit renewals under the Clean Water Act and Clean Air Act will be met with increased scrutiny by the EPA. 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, our cost of obtaining a permit is rarely more than $500,000, and our 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 our 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.

We believe, based upon present information available to us, that accruals with respect to future environmental costs are adequate. For further discussion of our costs, see Note 13 to the Notes to Consolidated Financial Statements. However, the imposition of more stringent requirements under environmental laws or regulations, new developments or changes regarding site cleanup costs or the allocation of such costs among potentially responsible parties, or a determination that we are 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.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), and similar state laws affect coal mining operations by, among other things, imposing cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare or the environment. Under CERCLA and similar state laws, joint and several liability may be imposed on waste generators, site owners and lessees and others regardless of fault or the legality of the original disposal activity. Although the EPA excludes most wastes generated by coal mining and processing operations from the hazardous waste laws, such wastes can, in certain circumstances, constitute hazardous substances for the purposes of CERCLA. In addition, the disposal, release or spilling of some products used by coal companies in operations, such as chemicals, could implicate the liability provisions of the statute. Under the EPA’s Toxic Release Inventory process, companies are required annually to report the use, manufacture or processing of listed toxic materials that exceed defined thresholds, including chemicals used in equipment maintenance, reclamation, water treatment and ash received for mine placement from power generation customers. Our current and former coal mining operations incur, and will continue to incur, expenditures associated with the investigation and remediation of facilities and environmental conditions under CERCLA.

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Endangered Species Act

The federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of endangered species may have the effect of prohibiting or delaying us from obtaining mining permits and may include restrictions on timber harvesting, road building and other mining or agricultural activities in areas containing the affected species. Based on the species that have been identified on our properties to date and the current application of applicable laws and regulations, we do not believe there are any species protected under the Endangered Species Act that would materially and adversely affect our ability to mine coal from our properties in accordance with current mining plans.

Available Information

We make available, free of charge through our Internet website, www.masseyenergyco.com, our 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, our Corporate Governance Guidelines, codes of ethics and the charters of the Audit, Compensation, Executive, Finance, Governance and Nominating, Safety and Environmental, and Public Policy Committees. These materials also 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.

Executive Officers of the Registrant

Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Executive Officers of the Registrant” (included herein pursuant to Item 401(b) of Regulation S-K).

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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.

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.

Compliance coal. Described in Item 1. Business, under the heading “Coal Reserves.”

Continuous miner. A mining machine with a continuously rolling cutting cylinder 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 in a preparation plant.

Deep mine. An underground coal mine.

Dragline. A large machine used in the surface mining process to remove the overburden, or layers of earth and rock covering a coal seam. The dragline has a large bucket suspended from the end of a long boom. The bucket, which is suspended by cables, is able to scoop up substantial amounts of overburden as it is dragged across the excavation area.

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.

Illinois Basin. The Illinois Basin consists of the coal producing areas in Illinois, Indiana and western Kentucky.

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 heat content, but low ash content.

Mine. A mine consists of those operating assets necessary to produce coal from surface or underground locations.

Nitrogen oxide (NOx). Nitrogen oxide is produced as a gaseous by-product of coal combustion.

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Northern Appalachia. Northern Appalachia consists of the bituminous coal producing areas in the states of Pennsylvania, Ohio and Maryland and in the northern part of West Virginia.

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 an underground mine, sometimes left permanently to support surface structures.

Powder River Basin. The Powder River Basin consists of the coal producing areas in southeast Montana and northeast Wyoming.

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

Probable reserves. Described in Item 1. Business, under the heading “Coal Reserves.”  

Proven reserves. Described in Item 1. Business, 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 1. Business, under the heading “Coal Reserves.”

Resource Group. An organizational unit, generally located within a specific geographic locale, that contains one or more of the following operations related to the mining, processing or shipping of coal:  underground mine, surface mine, preparation plant or load-out facility.

Roof. The stratum of rock or other mineral above a coal seam; the overhead surface of a coal working place.

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 and other greenhouse gases 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. Also known as utility coal.

Stoker coal. Coal that is sized to a specific, standard range. Stoker coal is typically one quarter inch by one and one quarter to one and three quarter inch.

Sulfur. One of the elements present in varying quantities in coal that reacts with air when coal is burned to form sulfur dioxide.

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.

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Sulfur dioxide (SO2). Sulfur dioxide is produced as a gaseous by-product of coal combustion.

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 approximately 2,240 pounds; a “metric” ton is approximately 2,205 pounds. The short ton is the unit of measure referred to in this Annual Report on 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 railroad train of a specified number of railroad 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. Also known as steam coal.

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Item 1A. Risk Factors

We are subject to a variety of risks, including, but not limited to, those risk factors set forth below and those referenced herein to other Items contained in this Annual Report on Form 10-K, including Item 1. Business, under the headings “Customers and Coal Contracts,” “Competition,” “Environmental, Safety and Health Laws and Regulations,” Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”), under the headings “Critical Accounting Estimates and Assumptions,” “Certain Trends and Uncertainties” and elsewhere in MD&A.

Risks Related to the Cumberland Acquisition

We completed the Cumberland Acquisition on April 19, 2010. We have integrated Cumberland’s operations into two new resource groups, Black Mountain Resource Group, which includes operations located in Kentucky and Cumberland Resource Group, which includes operations located in Virginia. As of January 31, 2011, the Black Mountain Resource Group consisted of 13 underground mines, 8 of which were self-operated and five of which were operated by contractors, and one surface mine operated by contractors; the Cumberland Resource Group consisted of 11 underground mines, all of which were self-operated and one surface mine operated by contractors. A portion of Cumberland’s workforce includes contract employees and substantially all of its mining operations occur on properties that it leases. Cumberland’s business, financial condition and results of operations are subject to many of the same risks associated with our operations. These risks are discussed in this Form 10-K, and include, but are not limited to the following additional risk factors:

We may not realize the expected benefits of the Cumberland Acquisition because of integration difficulties and other challenges.

The success of the Cumberland Acquisition will depend, in part, on our ability to realize the anticipated benefits from integrating Cumberland’s business with our existing businesses. The integration process may be complex, costly and time-consuming. The difficulties of integrating the operations of Cumberland’s business include, among others:

● failure to implement our business plan for the combined business;

● unanticipated issues in integrating Cumberland’s operations with ours;

● unanticipated disruptions in our business, including relationships with customers;

● unanticipated changes in applicable laws and regulations;

● failure to retain key employees;

● failure to retain key customers;

● failure to increase metallurgical coal production or sales;

● operating risks inherent in Cumberland’s business and our business;

● the impact on our internal controls and compliance with the regulatory requirements under the  Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley”);

● unanticipated issues, expenses and liabilities; and

● difficulties in fully identifying and evaluating potential liabilities, risks and operating issues.

We may not be able to maintain the levels of revenue, earnings or operating efficiency that each of us and Cumberland had achieved or might achieve separately. In addition, we may not accomplish the integration of Cumberland’s business smoothly, successfully or within the anticipated costs or timeframe.

The new obligations of Cumberland becoming part of a public company may require significant resources and management attention.

Upon consummation of the Cumberland Acquisition, we acquired a privately-held company that had not previously been required to prepare or file periodic and other reports with the SEC under applicable federal securities laws, to comply with the requirements of the federal securities laws applicable to public companies, including rules and regulations implemented by the SEC and the Public Company Accounting Oversight Board or to document and assess the effectiveness of its internal control over financial reporting in order to satisfy the requirements of Section 404 of Sarbanes-Oxley. We will need to include an assessment of our internal control over financial reporting that includes the Cumberland business in our periodic reports by December 31, 2011. Establishing, testing and maintaining an effective system of internal control over financial reporting requires significant resources and time commitments on the part of our management and our finance and accounting staff, may require additional staffing and infrastructure investments, could increase our legal, insurance and financial compliance costs and may divert the attention of management. In addition, our actual operating costs may exceed the operating costs set forth in our pro forma financials. Moreover, if we discover aspects of Cumberland’s internal control over financial reporting that require improvement, we cannot be certain that our remedial measures will be effective. Any failure to implement required new or improved controls, or difficulties encountered in their implementation could adversely affect our financial and operating results, investor’s confidence or increase our risk of material weaknesses in internal control over financial reporting.

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Risks Related to the Merger

Until the effective date of the Merger or the termination of the Merger Agreement in accordance with its terms, we and Alpha are prohibited from entering into certain business combination transactions.

During the period that the Merger Agreement is in effect, the Alpha board of directors may not withdraw or adversely modify its recommendation of approval by the Alpha stockholders of the amendment to the Alpha certificate of incorporation and the issuance of shares of Alpha common stock pursuant to the Merger Agreement and our board of directors may not withdraw or adversely modify its recommendation of approval by our stockholders of the Merger, neither board may recommend an acquisition proposal other than the Merger or negotiate or authorize negotiations with a third party regarding an acquisition proposal other than the Merger, except as permitted by certain limited exceptions in the Merger Agreement or required by their fiduciary duties and subject to the other requirements of the Merger Agreement. The foregoing prohibitions could have the effect of delaying other strategic transactions and may, in some cases, make it impossible to pursue other strategic transactions that are available only for a limited time.

We and Alpha must obtain required approvals and governmental and regulatory consents to complete the Merger, which, if delayed, not granted or granted with unacceptable conditions, may jeopardize or delay the Merger, result in additional expenditures of money and resources and/or reduce the anticipated benefits of the Merger.

The Merger is subject to customary closing conditions.  These closing conditions include, among others, the receipt of required approvals of our and Alpha’s respective stockholders and the expiration or termination of all waiting periods under applicable antitrust laws, including the applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (“HSR Act”) and foreign antitrust laws.

The governmental agencies from which the parties will seek these approvals have broad discretion in administering the governing regulations.  As a condition to their approval of the Merger, agencies may impose requirements, limitations or costs or require divestitures or place restrictions on the conduct of the combined company’s business after consummation of the Merger.  These requirements, limitations, costs, divestitures or restrictions could jeopardize or delay the consummation of the Merger or may reduce the anticipated benefits of the business combination.  Neither us nor Alpha has any obligation to complete the Merger if, as a condition to their approval, regulators require any sale, divestiture or disposition of, or prohibition or limitation on the ownership or operation by us or Alpha of any portion of either of our respective business, properties or assets if such actions would have a material adverse effect on Alpha and its subsidiaries, taken as a whole, or us and our subsidiaries, taken as a whole.  Further, no assurance can be given that the required stockholder approvals will be obtained or that the required closing conditions will be satisfied, and, if all required consents and approvals are obtained and the closing conditions are satisfied, no assurance can be given as to the terms, conditions and timing of the approvals.  If Alpha agrees to any material requirements, limitations, costs, divestitures or restrictions in order to obtain any approvals required to consummate the Merger, these requirements, limitations, costs, divestitures or restrictions could adversely affect Alpha’s ability to integrate its operations with our operations or reduce the anticipated benefits of the Merger.  This could result in a failure to consummate the Merger or have a material adverse effect on the business and results of operations of the combined company after consummation of the Merger.  We and Alpha will also be obligated to pay certain transaction-related fees and expenses in connection with the Merger, whether or not the Merger is completed.

Whether or not the Merger is completed, the announcement and pendency of the Merger could cause disruptions in our and Alpha’s respective businesses, which could have an adverse effect on each of our respective businesses and financial results.

Whether or not the Merger is completed, the announcement and pendency of the Merger could cause disruptions in our and Alpha’s respective businesses. Specifically:

● our and Alpha’s current and prospective employees might experience uncertainty about their future roles with the combined company following the Merger, which might adversely affect the combined company’s ability to retain key managers and other employees; and

● the attention of our and Alpha’s respective management might be directed toward the completion of the Merger.

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In addition, we and Alpha have each diverted significant management resources in an effort to complete the Merger and are each subject to restrictions contained in the Merger Agreement on the conduct of each of our respective businesses.  If the Merger is not completed, we and Alpha will have incurred significant costs, including the diversion of management resources, for which they will have received little or no benefit.  Further, we may be required to pay to Alpha a termination fee of $251 million and Alpha may be required to pay us a termination fee of between $72 million and $360 million if the Merger Agreement is terminated, depending on the specific circumstances of the termination.

The combined company may fail to realize the cost savings estimated as a result of the Merger.

The success of the Merger will depend, in part, on the combined company’s ability to realize the anticipated synergies, business opportunities and growth prospects from combining the businesses of Massey and Alpha.  The combined company may never realize these anticipated synergies, business opportunities and growth prospects.  Integrating operations will be complex and will require significant efforts and expenditures on the part of both us and Alpha.  Employees might leave or be terminated because of the Merger.  Management of the combined company might have its attention diverted while trying to integrate operations and corporate and administrative infrastructures.  The combined company might experience increased competition that limits its ability to expand its business, and it might not be able to capitalize on expected business opportunities, including retaining current customers.  The combined company’s management may be unable to successfully manage the combined company’s exposure to pending and potential litigation.  The combined company may be required by its regulators to undertake certain remedial measures upon the closing of the Merger, and the combined company’s management may not be able to successfully implement those and other remedial measures.  The combined company may experience difficulties in applying Alpha’s Running Right safety program at our legacy Massey mines and facilities after consummation of the Merger.  Moreover, assumptions underlying estimates of expected cost savings may be inaccurate and general industry and business conditions might deteriorate.  If any of these factors limit the combined company’s ability to integrate the operations of Massey and Alpha successfully or on a timely basis, the expectations of future results of operations, including certain cost savings and synergies expected to result from the Merger, might not be met.

In addition, we and Alpha have operated and, until the completion of the Merger, will continue to operate, independently.  It is possible that the integration process could result in the loss of key employees, the disruption of each company’s ongoing businesses, tax costs or inefficiencies, or inconsistencies in standards, controls, information technology systems, procedures and policies, any of which could adversely affect the combined company’s ability to maintain relationships with clients, employees or other third parties or the combined company’s ability to achieve the anticipated benefits of the Merger or could reduce the combined company’s earnings.

The market price of the combined company’s common stock after the Merger might be affected by factors different from, or in addition to, those affecting the market prices of our and Alpha's common stock currently.

Our business and Alpha’s business differ and, accordingly, the results of operations of the combined company and the market price of the combined company's common stock after the Merger may be affected by factors different from those currently affecting the independent results of operations of each of us and Alpha.

The combined company following the Merger may not pay dividends in the foreseeable future, and our current stockholders may have to rely on increases in the trading price of the combined company’s common stock for returns on their investment following the Merger.

Our stockholders have historically received quarterly dividends from us, while Alpha stockholders have not historically received regularly paid dividends.  The payment of dividends by the combined company after the Merger will be subject to the determination of the combined company’s board of directors.  Decisions regarding whether to pay dividends and the amount of any dividends to be paid will be based on compliance with the Delaware General Corporation Law, compliance with agreements governing the combined company’s indebtedness, earnings, cash requirements, results of operations, cash flows and financial condition and other factors that the combined company board of directors may consider to be important.  As such, the combined company following the Merger may not pay any regular dividends in the foreseeable future should its board of directors so determine, in which case our former stockholders who become stockholders of Alpha following the Merger would no longer be able to rely on receiving regular dividend payments and they (and other Alpha stockholders) would have to rely on increases in the trading price of the combined company’s common stock for any returns on their investment.

Our stockholders will become stockholders of Alpha upon receipt of shares of Alpha common stock, which may change certain rights and privileges our stockholders hold as stockholders of Massey.

Our stockholders will receive Alpha common stock as part of the consideration in connection with the Merger.  Although Massey and Alpha are incorporated under Delaware law, there are a number of differences between the rights of our stockholders and the rights of Alpha’s stockholders.

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The consummation of the Merger will constitute a change of control under our existing indebtedness and may permit counterparties to other agreements to terminate those agreements.

Under our existing credit agreement and instruments governing our 6.875% senior notes due 2013 ("6.875% Notes") and 3.25% convertible senior notes due 2015 ("3.25% Notes"), the Merger will constitute a change of control.  Such a change in control will cause the indebtedness under our ABL Facility to become immediately due and payable.  Under instruments governing our 6.875% Notes, if a change in control occurs, holders of these notes may require us to buy back the notes for a price equal to 101% of the notes’ principal amount, plus any interest which has accrued and remains unpaid as of the repurchase date.  The 6.875% Notes are also redeemable at a price equal to 101.719% of the notes’ principal amount through December 14, 2011, and thereafter at a price equal to 100% of the notes’ principal amount, in each case, plus any interest that has accrued and remains unpaid on the redemption date.  Under the instruments governing our 3.25% Notes, if a change of control occurs, holders of such series of our 3.25% Notes may require us to buy back the notes for a price equal to 100% of the notes’ principal amount, plus any interest that has accrued and remains unpaid as of the repurchase date. The holders of our 3.25% Notes may require us to pay a make-whole conversion premium if less than 90% of the consideration paid to our stockholders is Alpha common stock, as would be the case at current market prices.  Alpha intends to redeem the outstanding principal amount of 2.25% senior notes due 2024 ("2.25% Notes"), which are redeemable on or after April 6, 2011, at a price equal to 100% of the notes’ principal amount plus any interest which has accrued and remains unpaid on the redemption date.  The combined company may not be able to refinance our existing debt or have sufficient funds available for any repurchases that could be required by a change of control, either of which may have an adverse effect on the value of the combined company’s common stock.

In addition, certain of our leases, surety bond indemnity agreements and other agreements permit a counterparty to terminate the agreement because consummation of the Merger would cause a default or violate an anti-assignment, change of control or similar clause.  If this happens, the combined company may have to seek to replace any such agreement with a new agreement.  We cannot assure our stockholders that the combined company will be able to replace a terminated agreement on comparable terms or at all.  Depending on the importance of a terminated agreement to our business, failure to replace that agreement on similar terms or at all may increase the costs to the combined company of operating our business or prevent the combined company from operating part of our business following the Merger.

The combined company’s anticipated level of indebtedness could impact its operations and liquidity, and could, during the period in which debt is outstanding, have important consequences to holders of its common stock.

For example, it could:

● cause the combined company to use a portion of its cash flow from operations for debt service rather than for its operations;

● cause the combined company to be less able to take advantage of significant business opportunities, such as acquisition opportunities, and to react to changes in market or industry conditions;

● cause the combined company to be more vulnerable to general adverse economic and industry conditions;

● cause the combined company to be disadvantaged compared to competitors with less leverage;

● result in a downgrade in the rating of combined company’s indebtedness which could increase the cost of further borrowings; and

● subject the combined company to interest rate risk because some of its borrowing will be at variable rates of interest.

If the combined company following the Merger is unable to comply with restrictions in the proposed Alpha financing package, the indebtedness thereunder could be accelerated.

The credit facilities, loan agreements and potential bonds contemplated by the commitment letter received by Alpha will impose restrictions on the combined company following the Merger and require certain payments of principal and interest over time.  A failure to comply with these restrictions or to make these payments could lead to an event of default that could result in an acceleration of the indebtedness.  We cannot make any assurances that the combined company’s future operating results will be sufficient to ensure compliance with the covenants in its agreements or to remedy any such default.  In the event of an acceleration of this indebtedness, the combined company may not have or be able to obtain sufficient funds to make any accelerated payments.

Our and Alpha’s officers and directors may have financial interests in the Merger that are different from, or in addition to, the interests of our and Alpha’s respective stockholders.

When considering the recommendation of our and Alpha’s respective boards of directors with respect to the Merger, our and Alpha’s respective stockholders should be aware that some of our and Alpha’s directors and executive officers have interests in the Merger that might be different from, or in addition to, their interests as stockholders and the interests of our and Alpha’s stockholders generally. These interests include, among others, potential payments under employment agreements and change in control severance agreements, rights to acceleration of vesting and exercisability of options, and acceleration of vesting of restricted stock, restricted stock units and restricted cash units as a result of the Merger and rights to ongoing indemnification and insurance coverage by Alpha for acts or omissions occurring prior to the Merger.  As a result of these interests, these directors and executive officers might be more likely to support and to vote to adopt the Merger Agreement than if they did not have these interests.  Stockholders should consider whether these interests might have influenced these directors and executive officers to support or recommend adoption of the Merger Agreement.

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Upon completion of the Merger, our stockholders will receive, in addition to the $10.00 per share cash portion of the Merger consideration, 1.025 shares of Alpha common stock for each share of Common Stock, which will expose our stockholders to the risk of market fluctuations in the price of Alpha common stock.

Upon completion of the Merger, our stockholders will receive 1.025 shares of Alpha common stock and $10.00 in cash for each share of Common Stock.  The per-share Merger consideration will not be adjusted prior to completion of the Merger for changes in the market price of either Alpha common stock or the Common Stock or for share repurchases or issuances of common stock by Alpha or us.  Such market price fluctuations or changes in the number of outstanding shares of Alpha or Common Stock may affect the value that our stockholders will receive upon completion of the Merger.  Stock price changes may result from a variety of factors, many of which are out of our control, including general market and economic conditions, changes in businesses, operations and prospects and regulatory considerations, and risks discussed in this section of this Annual Report on Form 10-K.  Neither us nor Alpha are permitted to terminate the Merger Agreement or resolicit the vote of either of our  or Alpha's respective stockholders solely because of changes in the market price of either of our or Alpha's shares of common stock.

The prices of Alpha common stock and Common Stock at the completion of the Merger may vary from their respective prices on the date the Merger Agreement was executed, on the date of this Form 10-K and on the date of the special meetings. As a result, the value represented by the exchange ratio will also vary.  Because the date that the Merger becomes effective may be later than the date of the special meetings, at the time of our special meeting, our stockholders will not know the exact market value of Alpha common stock that they will receive upon completion of the Merger.

We are subject to contractual restrictions in the Merger Agreement that may hinder operations pending the merger.

The Merger Agreement restricts us, without Alpha’s consent, from making certain acquisitions and taking other specified actions until the Merger occurs or the Merger Agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the Merger or termination of the Merger Agreement.

Alpha must incur additional indebtedness to acquire the shares of Common Stock and to refinance our debt following the Merger.  We expect that the combined company will be able to make all required principal and interest payments when due, but cannot guarantee it.

The combined company’s indebtedness following consummation of the Merger is expected to be higher than the sum of Alpha’s and our current indebtedness.  Based upon current levels of operations and anticipated growth and past experience in paying down past acquisitions, we expect that the combined company will be able to generate sufficient cash flow to make all of the principal and interest payments under this indebtedness when such payments are due, but cannot guarantee it.

The issuance of shares of Alpha common stock to our stockholders in the Merger will substantially reduce the percentage ownership interest of our current stockholders.

If the Merger is consummated, each of our stockholders will become a stockholder of Alpha with a percentage ownership of the combined company that is significantly smaller than the stockholder’s percentage ownership of us prior to the Merger. Based on the number of shares of Common Stock and Alpha common stock outstanding on January 28, 2011, immediately upon completion of the Merger, our current stockholders are expected to hold approximately 46% of the total shares of the combined company. The issuance of shares of Alpha common stock to our stockholders in the Merger will cause a significant reduction in the relative percentage interest of our current stockholders in earnings, voting, liquidation value and book and market value of the combined company.  If we are unable to realize the benefits currently anticipated from the Merger, our stockholders will experience dilution of their ownership interest without receiving any commensurate benefit. As a result of these reduced ownership percentages, our stockholders will have less influence on the management and policies of the combined company than they now have with respect to us.

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We and our directors and officers are named parties to a number of actions, including various actions relating to the UBB incident and safety conditions at our mines, and further actions may be filed against us, including by the U.S. Attorney’s Office.

A number of actions are pending in Delaware and West Virginia state courts and federal courts relating to safety conditions at our mines, the UBB incident and other related matters.  These include derivative actions against our current and former directors and officers.  We and our officers and directors may be subject to future claims, including from families of the 29 miners that died in the UBB incident.  In addition, the U.S. Attorney’s Office and the federal MSHA in conjunction with the State of West Virginia are currently investigating the UBB incident.  The outcomes of these pending and potential claims and investigations are uncertain.  Depending on the outcome, these actions could have adverse financial effects or cause reputational harm to us or the combined company following the Merger.  We or following the Merger, the combined company, may not resolve these claims favorably or may not successfully implement remedial safety measures imposed as a result of some of these actions and investigations.  In addition, if the Merger is consummated, plaintiffs in the pending derivative actions against our current and former directors and officers, which we refer to as the derivative plaintiffs, and other plaintiffs who have filed suit challenging the Merger have asserted that, if the Merger is completed the derivative plaintiffs may lose standing to assert those claims.

Following the Merger, the combined company will have significantly less cash on hand than Alpha and Massey collectively prior to the Merger, which could adversely affect the combined company’s ability to grow and to perform.

Following the Merger, after repayment of certain of our indebtedness and all other pro forma adjustments relating to the Merger, the combined company will have significantly less cash on hand than Alpha and Massey collectively prior to the Merger, which could adversely affect the combined company’s ability to grow and to perform.  No assurances can be given as to the actual amount of cash and cash equivalents that the combined company will have on hand following the Merger.

Risks Related to Massey

We could be negatively impacted by the competitiveness of the markets in which we compete and declines in the market demand for coal.

We compete with coal producers in various regions of the United States and overseas for domestic and international sales. Continued domestic demand for our coal and the prices that we 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. In recent years, the competitive environment for coal was impacted by sustained growth in a number of the largest markets in the world, including the United States, China, Japan and India, where demand for both electricity and steel supported pricing for steam and metallurgical coal. The economic stability of these markets has a significant effect on the demand for coal and the level of competition in supplying these markets. The cost of ocean transportation and the value of the United States dollar in relation to foreign currencies significantly impact the relative attractiveness of our coal as we compete on price with other foreign coal producing sources. During the last several years, the United States coal industry has experienced increased consolidation, which has contributed to the industry becoming more competitive. Increased competition by competing coal producers or producers of alternate fuels in the markets in which we serve could cause a decrease in demand and/or pricing for our coal, adversely impacting our cash flows, results of operations or financial condition.

Portions of our coal reserves possess quality characteristics that enable us to mine, process and market them as either metallurgical coal or high quality steam coal, depending on the prevailing conditions in the markets for metallurgical and steam coal. A decline in the metallurgical market relative to the steam market could cause us to shift coal from the metallurgical market to the steam market, potentially reducing the price we could obtain for this coal and adversely impacting our cash flows, results of operations or financial condition.

Demand for our coal depends on its price and quality and the cost of transporting it to our customers.

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 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 higher costs for labor (including reserves for future costs associated with labor benefits and health care) and capital costs (including costs for mining equipment and construction of extensive ventilation systems). As of January 31, 2011, we operated 66 active underground mines, including one that employs both room and pillar and longwall mining, and 18 active surface mines, with 12 highwall miners.

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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 our ability to compete with other energy sources and on our cash flows, results of operations or financial condition. Conversely, significant decreases in transportation costs could result in increased competition from coal producers in other parts of the country or the world, including coal imported into the United States. For instance, coal mines in the western United States could become an increasingly attractive source of coal to consumers in the eastern part of the United States if the costs of transporting coal from the west were significantly reduced and/or rail capacity was increased.

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

Our results are highly dependent upon the prices we receive for our coal. Decreased demand for coal, both domestically and internationally, could cause spot prices and the prices we are able to negotiate on long-term contracts to decline. The lower prices could negatively affect our cash flows, results of operations or financial condition, if we are unable to increase productivity and/or decrease costs in order to maintain our margins.

We depend on continued demand from our customers.

Reduced demand from or the loss of our largest customers could have an adverse impact on our ability to achieve 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 our contracts with customers expire, 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 arrangements. 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 our coal on comparable terms.

There may be adverse changes in price, volume or terms of our existing coal supply agreements.

Many of our coal supply agreements contain provisions that permit the parties to adjust the contract price upward or downward at specified times (e.g., quarterly, semi-annually, annually or less frequently).  A recent trend is for contracts for export metallurgical coal to be re-priced quarterly, rather than the previous standard of annually. These contracts may be adjusted based on inflation or deflation and/or changes in the factors affecting the cost of producing coal, such as taxes, fees, royalties and changes in the laws regulating the mining, production, sale or use of coal. In a limited number of contracts, failure of the parties to agree on a price under those provisions may allow either party to terminate the contract. Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer for the duration of specified events beyond the control of the affected party. Most coal supply agreements contain provisions requiring us to deliver coal meeting quality thresholds for certain characteristics such as Btu, sulfur content, ash content, grindability and ash fusion temperature. Failure to meet these specifications could result in economic penalties, including price adjustments, the rejection of deliveries or termination of the contracts.

Our financial condition may be adversely affected if we are required by some of our customers to provide performance assurances for certain below-market sales contracts.

Contracts covering a significant portion of our contracted sales tons contain provisions that could require us to provide performance assurances if we experience a material adverse change or, under certain other contracts, if the customer believes our creditworthiness has become unsatisfactory. Generally, under such contracts, performance assurances are only required if the contract price per ton of coal is below the current market price of the coal. In addition, we may from time to time enter into coal sale agreements that require a posting of collateral to the extent we are “out of the money” on the total contracted sales in excess of $15 million (as of December 31, 2010, no posting was required). Certain of the contracts limit the amount of performance assurance to a per ton amount in excess of the contract price, while others have no limit. The performance assurances are generally provided by the posting of a letter of credit, cash collateral, other security, or a guaranty from a creditworthy guarantor. As of December 31, 2010, we have not received any requests from any of our customers to provide performance assurances. If we are required to post performance assurances on some or all of our contracts with performance assurances provisions, there could be a material adverse impact on our cash flows, results of operations or financial condition.

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Some of our customers may be unwilling to take all of their contracted tonnage or may request a price lower than their contracted price.

Some of our customers may experience lower demand for their products and services due to the weak economy and some may switch to electricity generation from coal burning plants to natural gas plants if the price of natural gas drops low enough.  The lower demand for our customers’ products may result in lower demand for the coal used in their business.  Any reduction in demand from our customers could have an adverse effect on our cash flows, results of operations or financial condition.

The level of our indebtedness could adversely affect our ability to grow and compete and prevent us from fulfilling our obligations under our contracts and agreements.

At December 31, 2010, we had $1,316.2 million of total debt outstanding, which represented 42.5% of our total book capitalization. We have significant debt, lease and royalty obligations. Our ability to satisfy debt service, lease and royalty obligations and to effect any refinancing of debt will depend upon future operating performance, which will be affected by prevailing economic conditions in the markets that we serve as well as financial, business and other factors, many of which are beyond our control. We may be unable to generate sufficient cash flow from operations and future borrowings, or other financings may be unavailable in an amount sufficient to enable us to fund our debt service, lease and royalty payment obligations or our other liquidity needs.  We also may be able to incur substantial additional debt in the future under the terms of our $200 million asset-based loan credit facility (“ABL Facility”) or by other means. Our ABL Facility provides for a revolving line of credit of up to $200.0 million, of which $122.8 million was available as of December 31, 2010. The addition of new debt to our current debt levels could increase the related risks that we now face.

Our relative amount of debt could have material consequences to our business, including, but not limited to: (i) making it more difficult to satisfy debt covenants and debt service, lease payments and other obligations; (ii) making it more difficult to pay quarterly dividends as we have in the past; (iii) increasing our vulnerability to general adverse economic and industry conditions; (iv) limiting our ability to obtain additional financing to fund future acquisitions, working capital, capital expenditures or other general corporate requirements; (v) reducing the availability of cash flows from operations to fund acquisitions, working capital, capital expenditures or other general corporate purposes; (vi) limiting our flexibility in planning for, or reacting to, changes in the business and the industry in which we compete; or (vii) placing us at a competitive disadvantage with competitors with relatively lower amounts of debt. Any of the above-listed factors could have an adverse effect on our business, financial condition and results of operations and our ability to meet our debt payment obligations.

The covenants in our credit facility and the indentures governing debt instruments impose restrictions that may limit our operating and financial flexibility.

Our ABL Facility contains a number of significant restrictions and covenants that may limit our ability and our subsidiaries’ ability to, among other things: (1) incur additional indebtedness; (2) increase common stock dividends above specified levels; (3) make loans and investments; (4) prepay, redeem or repurchase debt; (5) engage in mergers, consolidations and asset dispositions; (6) engage in affiliate transactions; (7) create any lien or security interest in any real property or equipment; (8) engage in sale and leaseback transactions; and (9) make distributions from subsidiaries. A decline in our operating results or other adverse factors, including a significant increase in interest rates, could result in us being unable to comply with a Minimum Consolidated Fixed Charge Ratio of 1.00 to 1.00 covenant contained in the ABL Facility, which become operative only when our Average Excess Availability (as defined in the ABL Facility) is less than Minimum Availability Amount ($30 million at December 31, 2010).

The indentures governing certain of our senior notes also contain a number of significant restrictions and covenants that may limit our ability and our subsidiaries’ ability to, among other things: (1) incur additional indebtedness; (2) subordinate indebtedness to other indebtedness unless such subordinated indebtedness is also subordinated to the notes; (3) pay dividends or make other distributions or repurchase or redeem our stock or subordinated indebtedness; (4) make investments; (5) sell assets and issue capital stock of restricted subsidiaries; (6) incur liens; (7) enter into agreements restricting our subsidiaries’ ability to pay dividends; (8) enter into sale and leaseback transactions; (9) enter into transactions with affiliates; and (10) consolidate, merge or sell all or substantially all of our assets.

If we violate these covenants and are unable to obtain waivers from our lenders, our debt under these agreements would be in default and could be accelerated by the lenders and, in the case of an event of default under our ABL Facility, it could permit the lenders to foreclose on our assets securing the loans under the ABL Facility. If the indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we are able to obtain new financing, it may not be on commercially reasonable terms or on terms that are acceptable to us. If our debt is in default for any reason, our cash flows, results of operations or financial condition could be materially and adversely affected. In addition, complying with these covenants may also cause us to take actions that are not favorable to our stockholders and holders of our senior notes and may make it more difficult for us to successfully execute our business strategy and compete against companies that are not subject to such restrictions.

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

Federal and state laws require bonds to secure our obligations to reclaim lands used for mining, to pay federal and state workers’ compensation and to satisfy other miscellaneous obligations. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral upon those renewals. We are also subject to increases in the amount of surety bonds required by federal and state laws as these laws change or the interpretation of these laws changes. Our failure to maintain, or inability to acquire, surety bonds that are required by state and federal law would have a material adverse impact on us, possibly by prohibiting us from developing properties that we desire to develop. 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 our senior notes or revolving credit facilities; (iii) our inability 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 or issue new bonds.

We depend on our ability to continue acquiring and developing economically recoverable coal reserves.

A key component of our future success is our 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 our cash flows, results of operations or financial condition.

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

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves, including many factors beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by us. Some of the factors and assumptions that impact economically recoverable reserve estimates include: (1) geological conditions; (2) historical production from the area compared with production from other producing areas; (3) the effects of regulations and taxes by governmental agencies; (4) future prices; and (5) future operating costs.

Each of these factors may 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, our estimates may not accurately reflect our actual reserves. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material.

Mining in Central Appalachia is more complex and involves more regulatory constraints than mining in other areas of the United States, which could affect our mining operations and cost structures in these areas.

The geological characteristics of Central Appalachian coal reserves, such as depth of overburden and coal seam thickness, make them complex and costly to mine. As mines become depleted, replacement reserves may not be available when required or, if available, may not be capable of being mined at costs comparable to those characteristic of the depleting mines. In addition, as compared to mines in other regions, permitting, licensing and other environmental and regulatory requirements are more costly and time consuming to satisfy. These factors could materially adversely affect the mining operations and cost structures of, and our customers’ ability to use coal produced by, our mines in Central Appalachia.

Defects in title or loss of any leasehold interests in our properties could limit our ability to mine our properties or result in significant unanticipated costs.

A significant portion of our mining operations occurs on properties that we lease. Title defects or the loss of leases could adversely affect our ability to mine the reserves covered by those leases. Our current practice is to obtain a title review from a licensed attorney prior to leasing property. We generally have not obtained title insurance in connection with acquisitions of coal reserves. In some cases, the seller or lessor warrants property title. Separate title confirmation sometimes is not required when leasing reserves where mining has occurred previously. Our right to mine some of our reserves may be adversely affected if defects in title or boundaries exist. In order to obtain leases to conduct our mining operations on property where these defects exist, we may have to incur unanticipated costs. In addition, we may not be able to successfully negotiate new leases for properties containing additional reserves, or maintain our leasehold interests in properties where we have not commenced mining operations during the term of the lease.

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If the coal industry experiences overcapacity in the future, our profitability could be impaired.

An increase in the demand for coal could attract new investors to the coal industry, which could spur the development of new mines, and result in added production capacity throughout the industry. Higher price levels of coal could also encourage the development of expanded capacity by new or existing coal producers. Any resulting increases in capacity could reduce coal prices and reduce our margins.

An inability of brokerage sources or contract miners to fulfill the delivery terms of their contracts with us could reduce our profitability.

We sometimes obtain coal from brokerage sources and contract miners to fulfill deliveries under our coal supply agreements. Some of our brokerage sources and contract miners may experience adverse geologic mining, escalated operating costs and/or financial difficulties that make their delivery of coal to us at the contracted price difficult or uncertain. Our profitability or exposure to loss on transactions or relationships such as these may be affected based upon the reliability of the supply or the ability to substitute, when economical, third-party coal sources, with internal production or coal purchased in the market and other factors.

Decreased availability or increased costs of key equipment, supplies or commodities such as diesel fuel, steel, explosives, magnetite and tires could decrease our profitability.

Our operations are dependent on reliable supplies of mining equipment, replacement parts, explosives, diesel fuel, tires, magnetite and steel-related products (including roof bolts). If the cost of any mining equipment or key supplies increases significantly, or if they should become unavailable due to higher industry-wide demand or less production by suppliers, there could be an adverse impact on our cash flows, results of operations or financial condition. The supplier base providing mining materials and equipment has been relatively consistent in recent years, although there continues to be consolidation. This consolidation has resulted in a situation where purchases of explosives and certain underground mining equipment are concentrated with single suppliers. In recent years, mining industry demand growth has exceeded supply growth for certain surface and underground mining equipment and heavy equipment tires. As a result, lead times for certain items have generally increased.

Transportation disruptions could impair our ability to sell coal.

We are dependent on our transportation providers to provide access to markets. Disruption of transportation services because of weather-related problems, strikes, lockouts, fuel shortages or other events could temporarily impair our ability to supply coal to customers. Our ability to ship coal could be negatively impacted by a reduction in available and timely rail service. Lack of sufficient resources to meet a rapid increase in demand, a greater demand for transportation to export terminals and rail line congestion all could contribute to a disruption and slowdown in rail service.

Severe weather may affect our ability to mine and deliver coal.

Severe weather, including flooding and excessive ice or snowfall, when it occurs, can adversely affect our ability to produce, load and transport coal, which may negatively impact our cash flows, results of operations or financial condition.

Federal, state and local laws and government regulations applicable to operations increase costs and may make our coal less competitive than other coal producers.

We incur substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species laws, regulations and enforcement policies. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations. The costs of compliance with applicable regulations and liabilities assessed for compliance failure could have a material adverse impact on our cash flows, results of operations or financial condition.

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Although we do not believe we can quantify a specific amount of our capital and operational expenditures related to health and safety regulations, we have undertaken an analysis of our expenditures with the goal of preparing a reasonable estimate of such expenditures. Based on this analysis, we believe a reasonable estimate of capital expenditures related to health and safety regulations is approximately $18.4 million and $24.4 million for the fiscal years ended December 31, 2010 and 2009, respectively. These capital expenditures were primarily for mine communication systems, mine seals, safety shelters, and self-rescuer caches, requirements that were put in place with the MINER Act.  In addition, we believe a reasonable estimate of operational expenditures related to health and safety regulations is approximately $52.2 million and $40.5 million for the fiscal years ended December 31, 2010 and 2009, respectively. These expenditures include labor and supply costs incurred to support our mine rescue teams, our corporate safety department, safety personnel at our mine sites, the payment of safety bonuses, fire suppression costs, and other general safety supplies. These expenditures do not include certain other capital and operational expenditures related to production that indirectly contribute to the safe operation of our coal mines. Consequently, we believe that our total capital and operational expenditures related to safety are likely in excess of these amounts, and, therefore, represent a substantial cost to us.

New legislation and new regulations may be adopted which could materially adversely affect our mining operations, cost structure or our customers’ ability to use coal. New legislation and new regulations may also require us, as well as our customers, to change operations significantly or incur increased costs. The EPA has undertaken broad initiatives to increase compliance with emissions standards and by providing incentives to our customers to decrease their emissions, often by switching to an alternative fuel source,  or imposing costs if they do not switch fuels, by requiring them to install scrubbers or other expensive emissions reduction equipment at their coal-fired plants.

Our operations may adversely impact the environment which could result in material liabilities to us.

The processes required to mine coal may cause certain impacts or generate certain materials that might adversely affect the environment from time to time. The mining processes we use could cause us to become subject to claims for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, groundwater, and other media. Such claims may arise, for example, out of conditions at sites that we currently own or operate, as well as at sites that we previously owned or operated, or may acquire. Our liability for such claims may be joint and several, so that we may be held responsible for more than our share of the contamination or other damages, or even for the entire claim.

Certain coal that we mine needs to be cleaned at preparation plants, which generally require coal refuse areas and/or slurry impoundments. Such areas and impoundments are subject to extensive regulation and monitoring. Slurry impoundments have been known to fail, releasing large volumes of coal slurry into nearby surface waters and property, resulting in damage to the environment and natural resources, as well as injuries to wildlife. We maintain coal refuse areas and slurry impoundments at a number of our mining complexes. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental impact and associated liability, as well as for fines and penalties.

Drainage flowing from or caused by mining activities can be acidic with elevated levels of dissolved metals, a condition referred to as acid mine drainage (“AMD”).  Although we do not currently face material costs associated with AMD, it is possible that we could incur significant costs in the future.

These and other similar unforeseen impacts that our operations may have on the environment, as well as exposures to certain substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect us and could have a material adverse impact on our cash flows, results of operations or financial condition.

MSHA or other federal or state regulatory agencies may order certain of our mines to be temporarily or permanently closed, which could adversely affect our ability to meet our customers’ demands.

MSHA or other federal or state regulatory agencies may order certain of our mines to be temporarily or permanently closed. Our UBB mine at our Performance resource group in West Virginia is currently closed following the April 5, 2010 explosion, and we cannot predict at this time when it will reopen. Our customers may challenge our issuance of force majeure notices in connection with such closures. If these challenges are successful, we may have to purchase coal from third-party sources to satisfy those challenges; negotiate settlements with customers, which may include price reductions, the reduction of commitments or the extension of the time for delivery; terminate customers’ contracts; and/or face claims initiated by our customers against us. The resolution of these challenges could have a material adverse impact on our cash flows, results of operations or financial condition.

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We must obtain governmental permits and approvals for mining operations, which can be a costly and time-consuming process, can result in restrictions on our operations and is subject to litigation that may delay or prevent us from obtaining necessary permits.

Our operations are principally regulated under surface mining permits issued pursuant to the SMCRA and state counterpart laws. Such permits are issued for terms of five years with the right of successive renewal. Additionally, the Clean Water Act requires permits for operations that discharge into waters of the United States. Valley fills and refuse impoundments are authorized under permits issued by the United States Army Corps of Engineers. Such permitting under the Clean Water Act has been a frequent subject of litigation by environmental advocacy groups that has resulted in periodic declines in such permits issued by the United States Army Corps of Engineers. Additionally, certain surface mines and preparation plants have permits issued pursuant to the Clean Air Act and state counterpart laws allowing and controlling the discharge of air pollutants. Regulatory authorities exercise considerable discretion in the timing of permit issuance. Recently the EPA has taken a more active role in the review of permit applications, resulting in a substantial slow down in the issuance of most mining permits and a virtual standstill in the issuance of surface mining permits.  Requirements imposed by these authorities may be costly and time-consuming and may result in delays in, or in some instances preclude, the commencement or continuation of development or production operations. Adverse outcomes in lawsuits challenging permits or failure to comply with applicable regulations could result in the suspension, denial or revocation of required permits, which could have a material adverse impact on our cash flows, results of operations or financial condition.

The loss of key personnel or the failure to attract qualified personnel could affect our ability to operate the Company effectively.

The successful management of our business is dependent on a number of key personnel. Our future success will be affected by our continued ability to attract and retain highly skilled and qualified personnel. There are no assurances that key personnel will continue to be employed by us or that we will be able to attract and retain qualified personnel in the future. Failure to retain or attract key personnel could have an adverse affect on our cash flows, results of operations or financial condition.

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

Coal mining continues to be a labor-intensive industry. From time to time, we have encountered a shortage of experienced mine workers when the demand and prices for all specifications of coal we mine increased appreciably. During those periods, the hiring of these less experienced workers negatively impacted our productivity and cash costs. A lack of skilled miners could have an adverse impact on our labor productivity and cost and our ability to meet current production requirements to fulfill existing sales commitments or to expand production to meet the increased demand for coal.

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

At December 31, 2010, approximately 1.2% of our total workforce was represented by the UMWA. Our unionized workforce is spread out amongst five of our coal preparation plants. In 2010, these preparation plants handled approximately 25% of our coal production. We are currently operating under the terms and conditions of expired agreements. In connection with these negotiations and with respect to our unionized operations generally, there may be an increased risk of strikes and other labor disputes, as well as higher labor costs. If some or all of our current open shop operations were to become unionized, we could be subject to additional risk of work stoppages, other labor disputes and higher labor costs, which could adversely affect the stability of production and reduce net income.

Inflationary pressures on supplies and labor may adversely affect our profit margins.

Although inflation in the United States has been relatively low in recent years, over the course of the last two to three years, we have been significantly impacted by price inflation in many of the components of our cost of produced coal revenue, such as fuel, steel and labor. If the prices for which we sell our coal do not increase in step with rising costs or if these costs do not decline sufficiently, our profit margins would be reduced and our cash flows, results of operations or financial condition would be adversely affected.

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

SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as most aspects of deep mining. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our engineering expertise related to these requirements. The estimate of ultimate reclamation liability is reviewed periodically by management and engineers. The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly.

Our future expenditures for postretirement benefit and pension obligations could be materially higher than we have predicted if our underlying assumptions are incorrect.

We are subject to long-term liabilities under a variety of benefit plans and other arrangements with current and former employees. These obligations have been estimated based on actuarial assumptions, including actuarial estimates, assumed discount rates, estimates of life expectancy, expected returns on pension plan assets and changes in healthcare costs.

If our assumptions relating to these benefits change in the future or are incorrect, we may be required to record additional expenses, which would reduce our profitability. In addition, future regulatory and accounting changes relating to these benefits could result in increased obligations or additional costs, which could also have a material adverse impact on our cash flows, results of operations or financial condition. See also Notes 9, 14 and 15 of the Notes to Consolidated Financial Statements for further discussion.

Our pension plans are currently underfunded and we may have to make significant cash payments to the plans, reducing the cash available for our business.

We sponsor a qualified non-contributory defined benefit pension plan, which covers substantially all administrative and non-union employees.  We currently expect to make contributions in 2011 of approximately $20 million. If the performance of the assets in our pension plans does not meet our expectations, or if other actuarial assumptions are modified, our contributions could be higher than we expect.

The value of the assets held in our pension plans was adversely affected by the disruptions in the financial markets that occurred in recent years, and the applicable discount rates applied in determining our pension liabilities have also been negatively affected by the crisis in the financial markets. As a result, as of December 31, 2010, our annual measurement date, our pension plan was underfunded by $79.7 million (based on the actuarial assumptions used in the application of GAAP). Our pension plans are subject to the Employee Retirement Income Security Act of 1974 (“ERISA”). Under ERISA, the Pension Benefit Guaranty Corporation (“PBGC”), has the authority to terminate an underfunded pension plan under limited circumstances. In the event our pension plan is terminated for any reason while the plan is underfunded, we will incur a liability to the PBGC that may be equal to the entire amount of the underfunding.

Provisions in our restated certificate of incorporation and restated bylaws, the agreements governing our indebtedness and Delaware law may discourage a takeover attempt even if doing so might be beneficial to our shareholders.

Provisions contained in our restated certificate of incorporation and restated bylaws could impose impediments to the ability of a third-party to acquire us even if a change of control would be beneficial to our stockholders. Provisions of our restated certificate of incorporation and restated bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our restated certificate of incorporation authorizes our Board of Directors to determine the rights, preferences, privileges and restrictions of unissued series of preferred stock, without any vote or action by our stockholders. Thus, our Board of Directors can authorize and issue shares of preferred stock with voting or conversion rights that could adversely affect the voting or other rights of holders of Common Stock. We are also subject to provisions of Delaware law that prohibit us from engaging in any business combination with any “interested stockholder,” meaning, generally, that a stockholder who beneficially owns more than 15% of Common Stock cannot acquire us for a period of three years from the date this person became an interested stockholder unless various conditions are met, such as approval of the transaction by our Board of Directors. These provisions may have the effect of delaying or deterring a change of control of our Company, and could limit the price that certain investors might be willing to pay in the future for shares of Common Stock.

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If a “fundamental change” (as defined in the indenture governing the 3.25% Notes) occurs, holders of the 3.25% Notes will have the right, at their option, either to convert their 3.25% Notes or require us to repurchase all or a portion of their 3.25% Notes, and holders of the 2.25% Notes will have the right to require us to repurchase all or a portion of their notes. In the event of a “make-whole fundamental change” (as defined in the indenture governing the 3.25% Notes), we also may be required to increase the conversion rate applicable to any 3.25% Notes surrendered for conversion. In addition, the indentures for the convertible notes prohibit us from engaging in certain mergers or acquisitions unless, among other things, the surviving entity is a U.S. entity that assumes our obligations under the convertible notes. Certain of our debt instruments impose similar restrictions on us, including with respect to mergers or consolidations with other companies and the sale of substantially all of our assets. These provisions could prevent or deter a third-party from acquiring us even where the acquisition could be beneficial to you.

We may not realize all or any of the anticipated benefits from acquisitions we undertake, as acquisitions entail a number of inherent risks.

From time to time we expand our business and reserve position through acquisitions of businesses and assets, mergers, joint ventures or other transactions. Such transactions involve various inherent risks, such as:

§ uncertainties in assessing the value, strengths and potential profitability of, and identifying the extent of all weaknesses, risks, contingent and other liabilities (including environmental liabilities) of, acquisition or other transaction candidates;

§ the potential loss of key customers, management and employees of an acquired business;

§ the ability to achieve identified operating and financial synergies anticipated to result from an acquisition or other transaction;

§ problems that could arise from the integration of the acquired business;

§ the risk of obtaining mining permits for acquired coal assets; and

§ unanticipated changes in business, industry or general economic conditions that affect the assumptions underlying the acquisition or other transaction rationale.

Any one or more of these and other factors could cause us not to realize the benefits anticipated to result from the acquisition of businesses or assets or could result in unexpected liabilities associated with these acquisitions.

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

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

Terrorist attacks and threats, escalation of military activity in response to such attacks, civil unrest or acts of war may negatively affect our cash flows, results of operations or financial condition.

Our 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 our control, such as terrorist attacks, civil unrest, and acts of war. Future terrorist attacks against United States targets, rumors or threats of war, actual conflicts or civil unrest involving the United States or its allies, or military or trade disruptions affecting customers may have a material adverse affect on operations. As a result, there could be delays or losses in transportation and deliveries of coal to customers, decreased sales of coal and extension of time for payment of accounts receivable from customers. Strategic targets such as energy-related assets may be at greater risk of future terrorist attacks than other targets in the United States. In addition, such disruptions 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 cash flows, results of operations or financial condition.

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Coal mining is subject to inherent risks, some for which we maintain third-party insurance and some for which we self-insure.

Our operations are subject to certain events and conditions that could disrupt operations, including fires and explosions, accidental mine water discharges, coal slurry releases and impoundment failures, natural disasters, equipment failures, maintenance problems and flooding. We maintain 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 insurance policies and insurers may contest their obligations to make payments. Failures by insurers to make payments could have a material adverse effect on our cash flows, results of operations or financial condition. We self-insure our highwall miners and underground equipment, including our longwall. We do not currently carry business interruption insurance.

Changes in federal or state income tax laws, particularly in the area of percentage depletion, could cause our financial position and profitability to deteriorate.

The federal government has been reviewing the income tax laws relating to the coal industry regarding percentage depletion benefits. If the percentage depletion tax benefit was reduced or eliminated, our cash flows, results of operations or financial condition could be materially impacted.

We are subject to various legal proceedings, which may have a material effect on our business.

We are party to a number of legal proceedings incident to normal business activities. Some of the allegations brought against us are with merit, while others are not. We are also subject to legal proceedings as a result of the April 5, 2010 explosion at our Upper Big Branch mine at our Performance resource group in West Virginia.  There is always the potential that an individual matter or the aggregation of many matters could have a material adverse effect on our cash flows, results of operations or financial position. See Note 22 of the Notes to Consolidated Financial Statements for a more complete discussion.

Changes in federal or state income tax laws, particularly in the area of percentage depletion, could cause our financial position and profitability to deteriorate.

The federal government has been reviewing the income tax laws relating to the coal industry regarding percentage depletion benefits. If the percentage depletion tax benefit was reduced or eliminated, our cash flows, results of operations or financial condition could be materially impacted.

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Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties

We own and lease properties totaling more than one million acres in West Virginia, Kentucky, Virginia, Pennsylvania and Tennessee. In addition, certain of our owned or leased properties are leased or subleased to third-party tenants. Our current practice is to obtain a title review from a licensed attorney prior to purchasing or leasing property. We generally have not obtained title insurance in connection with acquisitions of coal reserves. In some cases, the seller or lessor warrants property title. We have not required title confirmation in certain cases under long-standing lease agreements where we are now the current lessee and the lease covers property where mining has occurred previously.  We currently own or lease the equipment that is utilized in mining operations. The following table describes the location and general character of our major existing facilities, exclusive of mines, coal preparation plants and their adjoining offices.

Administrative Offices:

Richmond, Virginia	Owned	Massey Corporate Headquarters
Julian, West Virginia	Owned	Massey Operational Headquarters

For a description of mining properties, see Item 1. Business, under the heading “Mining Operations” and “Coal Reserves.”

Item 3. Legal Proceedings

Derivative Litigation

A number of purported stockholders have brought lawsuits derivatively on behalf of Massey Energy Company (“Massey”), in West Virginia and Delaware state courts, in connection with the April 5, 2010, tragedy at UBB and related claims.

West Virginia

On April 15, 2010, purported Massey stockholder, Manville Personal Injury Settlement Trust (“Manville”), filed a derivative lawsuit in the Circuit Court of Kanawha County, alleging that certain current and former members of the Board of Directors and Massey officers breached their fiduciary duties by failing to monitor and oversee the Company’s employees, which failure allegedly resulted in the tragedy at UBB (the “Manville Action”).  Manville seeks (1) a declaration that defendants have violated their fiduciary duties to the Company; (2) an award against all defendants for the amount of damages sustained by the Company as a result of any breach of fiduciary duties; and (3) an award to Manville for costs and disbursements of the action.  On June 7, 2010, Manville—now joined by two additional stockholders, the California State Teachers’ Retirement System and Amalgamated Bank, as Trustee for the Longview Collection Investment Funds (together with Manville, the “Manville Plaintiffs”)—amended its complaint, adding additional allegations relating to the defendants’  alleged breaches of fiduciary duties.

On April 21, 2010, purported Company stockholder, International Union of Operating Engineers Pension Fund of Eastern Pennsylvania and Delaware (“IUOE”), filed a derivative lawsuit in the Circuit Court of Wyoming County, alleging that certain current and former members of the Board of Directors breached their fiduciary duties by failing to monitor and oversee the Company’s employees, which failure allegedly resulted in failures to comply with applicable health, safety and environmental laws and regulations (the “West Virginia IUOE Action”).  IUOE seeks (1) a declaration that defendants breached their fiduciary duties; (2) compensatory and consequential damages to the Company; and (3) an award to IUOE of fees and expenses incurred in pursuing this action.  As described below, the West Virginia IUOE Action has been dismissed without prejudice and refiled in Delaware Chancery Court.

On April 22, 2010, purported Company stockholder, Philip R. Arlia (“Arlia”), filed a derivative lawsuit in the Circuit Court of Raleigh County, alleging that certain current and former members of the Board of Directors and Company officers breached their fiduciary duties, committed gross mismanagement and abused their abilities to control the Company by (1) failing to monitor and oversee Company employees, which failure allegedly resulted in the tragedy at UBB, fines against the Company for safety-related violations and lawsuits on behalf of injured workers, residents and others; (2) awarding Chairman Blankenship allegedly excessive compensation; (3) making false and misleading statements to Company stockholders; and (4) failing to prevent Chairman Blankenship’s alleged “sharp business practices” (the “Arlia Action”).  Arlia seeks (1) a declaration that defendants have breached and are breaching their fiduciary duties; (2) an award of compensatory and punitive damages; (3) an award to Arlia of costs and disbursements; (4) an injunction compelling the Board of Directors to cause the Company, its executives and managers not to violate applicable safety and environmental laws, rules and regulations; and (5) the appointment of an independent corporate monitor for the development and implementation of safety and environmental compliance protocols.  As described below, the Arlia Action has been consolidated with the Manville Action.

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On April 23, 2010, purported Company stockholder, Louisiana Municipal Police Employees Retirement System (“LAMPERS”), filed a derivative lawsuit in the Circuit Court of Wyoming County, alleging that certain current and former members of the Board of Directors and Company officers breached their fiduciary duties by failing to monitor and oversee Massey’s employees, which failure allegedly resulted in the tragedy at UBB (the “West Virginia LAMPERS Action”).  LAMPERS seeks (1) an award of damages sustained by the Company as a result of defendants’ breaches of fiduciary duties and (2) an award to LAMPERS of the costs and disbursements of the action.  As described below, the West Virginia LAMPERS Action has been dismissed without prejudice and LAMPERS has joined in IUOE’s refiled suit in Delaware Chancery Court.

On April 27, 2010, purported Company stockholder, Brian Lynch (“Lynch”), filed a derivative lawsuit in the Circuit Court of Raleigh County, alleging that certain current and former members of the Board of Directors and Company officers breached their fiduciary duties, wasted corporate assets and unjustly enriched themselves by (1) failing to monitor and oversee the Company’s employees, which failure allegedly resulted in the tragedy at UBB and systematic violations of safety and environmental rules and regulations; (2) making false and misleading statements to the Company’s stockholders; and (3) accepting compensation while breaching their fiduciary duties (the “Lynch Action”).  Lynch seeks (1) an award for all damages sustained as a result of defendants’ various alleged breaches of fiduciary duty; (2) an order requiring Chairman Blankenship to step down as Chairman and CEO, directing Company to separate position of Chairman and CEO and directing the Company to take certain actions to improve its internal controls relating to worker safety; (3) equitable and/or injunctive relief restricting defendants’ assets so as to assure that plaintiff has an effective remedy; (4) disgorgement of all compensation paid by the Company to defendants; and (5) an award of fees, costs and expenses to Lynch.  As described below, the Lynch Action has been consolidated with the Manville Action.

On May 13, 2010, the defendants in the Manville Action (the “Manville Defendants”) filed a Joint Motion to Transfer and Consolidate, requesting that the Circuit Court of Kanawha County transfer the West Virginia IUOE, Arlia, West Virginia LAMPERS and Lynch Actions to the Circuit Court of Kanawha County and consolidate all five actions before it for all purposes. On June 24, 2010, the Circuit Court of Wyoming County ordered that the West Virginia IUOE and West Virginia LAMPERS Actions be dismissed without prejudice, at the request of IUOE and LAMPERS, respectively.  On July 1, 2010, the Circuit Court of Kanawha County granted the Manville Defendants’ Joint Motion to Transfer and Consolidate and ordered that the Arlia and Lynch Actions be transferred to the Circuit Court of Kanawha County and consolidated with the Manville Action for all purposes.  The court’s order did not merge the suits into a single case and, therefore, although the Arlia and Lynch Actions are consolidated with the Manville Action, Arlia and Lynch continue to assert their claims independently.

On July 2, 2010, the Manville Defendants filed a Joint Motion to Stay, requesting that the Circuit Court of Kanawha County stay the consolidated actions pending resolution of a stockholder derivative action brought by the New Jersey Building Laborers Pension Fund (“NJBL”) in the Court of Chancery of the State of Delaware, described below.

On July 19, 2010, the Manville Defendants filed Joint Motions to Dismiss the Manville Action on the grounds that the Manville Plaintiffs did not make a pre-suit demand on the Board of Directors or allege with particularity why such demand was excused and because the Manville Plaintiffs failed to state a claim upon which relief could be granted.  On August 11, 2010, Manville filed a Motion to Consolidate the Manville Action with the contempt proceeding, described below.  The Manville Defendants’ Joint Motion to Stay and Joint Motions to Dismiss are pending before the Circuit Court of Kanawha County.

Delaware

On April 23, 2010, purported Company stockholder, NJBL, filed a derivative lawsuit in the Chancery Court, alleging that certain current and former members of the Board of Directors breached their fiduciary duties by failing to monitor and oversee Massey’s employees, which failure allegedly resulted in approximately $43 million in fines over the past five years and in the tragedy at UBB (the “NJBL Action”).  NJBL seeks (1) an award of damages against each defendant for restitution, compensatory, punitive and exemplary damages; (2) removal of Chairman Blankenship from office; and (3) an award to NJBL for its costs and disbursements and reasonable allowances for fees.  On July 7, 2010, NJBL amended its complaint, adding additional allegations relating to the defendants’ alleged breaches of fiduciary duty.

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On June 24, 2010, purported Company stockholder, IUOE, refiled the West Virginia IUOE Action, which it had dismissed without prejudice, in the Chancery Court (the “Delaware IUOE Action”).  The refiled action was similar substantively to the West Virginia IUOE Action.  On July 7, 2010, IUOE—now joined by LAMPERS—amended its complaint, adding additional allegations relating to the defendants’ alleged breaches of fiduciary duties.  The amended complaint seeks (1) an award against defendants for restitution and/or compensatory damages in favor of Massey; (2) removal of Chairman Blankenship from office; and (3) an award to IUOE and LAMPERS of their costs, disbursements and reasonable allowances for fees for counsel and experts.

On June 29, 2010, purported Company stockholder, Sandy Taylor (“Taylor”), filed a derivative lawsuit in the Chancery Court (the “Taylor Action”), alleging that certain current and former members of the Board of Directors and officers breached their fiduciary duties and wasted corporate assets by failing to monitor and oversee the Company’s employees, which failure allegedly resulted in the tragedy at UBB.  Taylor seeks (1) a declaration that defendants breached their fiduciary duties; (2) compensatory and consequential damages to the Company; (3) an award to Taylor for the costs and disbursements of the action; (4) an order directing the Company to take all necessary actions to reform and improve its corporate governance and internal procedures with respect to its mining operations; and (5) an order directing Massey to take all necessary actions to ensure that reasonably suitable safety systems are in force at all Massey mines.

On July 2, 2010, Taylor filed a Motion for Consolidation and Appointment of Lead Plaintiff and Lead Counsel, requesting that the court consolidate the Taylor, Delaware IUOE and NJBL Actions and all related subsequent actions; appoint Taylor as lead plaintiff for all actions and appoint Taylor’s counsel as lead counsel and liaison counsel, respectively.  On July 15, 2010, NJBL, IUOE and LAMPERS jointly filed a Motion for Consolidation, Appointment as Lead Plaintiffs and Appointment of Co-Lead Counsel, requesting that the court consolidate the NJBL, Delaware IUOE and Taylor Actions; appoint NJBL, IUOE and LAMPERS as co-lead plaintiffs; and approve NJBL, IUOE and LAMPERS’ counsel as co-lead counsel.

On July 22, 2010, purported Company stockholder, Helene Hutt (“Hutt”), filed a derivative lawsuit in the Chancery Court (the “Hutt Action”), alleging that certain current and former members of the Board of Directors and officers breached their fiduciary duties by failing to monitor and oversee Company employees, which failure allegedly resulted in the tragedy at UBB.  Hutt seeks (1) an award in favor of the Company for the amount of damages sustained by it as a result of defendants’ alleged breaches of their fiduciary duties; (2) removal of Chairman Blankenship from office; (3) equitable and/or injunctive relief restricting the proceeds of defendants’ trading activities or their other assets to assure that Hutt has an effective remedy; (3) disgorgement of all profits, benefits and other compensation obtained by defendants; and (4) an award to Hutt of the costs and disbursements of the action, including reasonable attorneys’ fees. On July 29, 2010, Hutt filed a Motion for Appointment of Lead Plaintiff, Lead Counsel and Liaison Counsel, requesting that the court appoint Hutt as lead plaintiff and appoint her counsel as co-lead counsel and as Delaware liaison counsel for all plaintiffs.  In her motion, Hutt stated that she did not oppose the motions for consolidation filed by Taylor and NJBL, IUOE and LAMPERS.

On September 7, 2010, Taylor withdrew her Motion for Consolidation and Appointment of Lead Plaintiff and Lead Counsel and requested that the court grant NJBL, IUOE and LAMPERS’ Motion for Consolidation, Appointment as Lead Plaintiffs and Appointment of Co-Lead Counsel.

On October 19, 2010, Hutt, Taylor, NJBL, IUOE and LAMPERS informed the court that they had reached an agreement to consolidate the respective actions and submitted a Stipulation and (Proposed) Order of Consolidation for the Chancery Court’s approval.  The Stipulation provides for the consolidation of the actions and the appointment of NJBL, IUOE, LAMPERS and Hutt as Co-Lead Plaintiffs.  The Stipulation further provides that the Co-Lead Plaintiffs must file an Amended and Consolidated Shareholder Derivative Complaint five business days after all Co-Lead Plaintiffs are granted access to certain documents that were produced by the Company to Hutt in response to a demand under Section 220 of the Delaware General Corporation Law.  On October 21, 2010, the Chancery Court approved the Stipulation and ordered that the actions be consolidated for all purposes.

We and the Defendants have insurance coverage applicable to these matters.  We believe these matters will be resolved without a material adverse impact on our cash flows, results of operations or financial condition.

Federal Class Actions

There are presently two purported class actions brought in connection with alleged violations of the Federal securities laws pending in the United States District Court for the Southern District of West Virginia.

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On April 29, 2010, Macomb County Employees’ Retirement System (“Macomb”) filed a purported class action, alleging violations of Section 10(b) of the Exchange Act by certain Company officers and Section 20(a) of the Exchange Act by these same officers, as well as certain current and former directors in connection with allegedly false and misleading statements regarding the Company’s safety record (the “Macomb Action”).  Macomb seeks (1) an award of damages to Macomb and the members of the purported class and (2) an award to Macomb of reasonable costs and attorneys’ fees.

On May 28, 2010, the Firefighters’ Retirement System of Louisiana (“Firefighters”) brought a purported class action, alleging substantially similar violations as Macomb, against the same defendants, as well as another director and officer (the “Firefighters Action”).  Firefighters seeks (1) an award of damages to Firefighters and the members of the purported class and (2) an award to Firefighters of reasonable costs and attorneys’ fees.

On June 28, 2010, four purported class members (the Massachusetts Pension Reserves Investment Trust, the MEE Investor Group (a group of three individual stockholders), David Wagner and the Wayne County Employees’ Retirement System) filed separate motions requesting that the court consolidate the Macomb and Firefighters Actions, appoint each purported class member as lead plaintiff and approve each purported class member’s choice of lead counsel.  The MEE Investor Group subsequently withdrew its motion.  The Wayne County Employees’ Retirement System subsequently filed notice stating that it supported the Massachusetts Pension Reserves Investment Trust’s motion, and the court thereafter denied the Wayne County Employees’ Retirement System’s motion as moot. David Wagner’s and the Massachusetts Pension Reserves Investment Trust’s Motions for Consolidation are pending before the court.

We and the Defendants have insurance coverage applicable to these matters.  We believe these matters will be resolved without a material adverse impact on our cash flows, results of operations or financial condition.

Contempt Proceeding

On July 2, 2007, Manville, the same stockholder-plaintiff that initiated the Manville Action described above, filed a complaint in the Circuit Court of Kanawha County, West Virginia alleging that the Company’s Board of Directors and certain of its officers had breached their fiduciary duties by consciously failing to cause the Company’s employees to comply with certain environmental and worker-safety laws and regulations.  On May 20, 2008, the parties executed a Stipulation of Settlement (“Stipulation”), which provided for a broad release of all claims that were or could have been asserted derivatively on behalf of the Company in exchange for, among other things, an agreement that the Board of Directors “shall make a Corporate Social Responsibility report to its stockholders on an annual basis that shall include, among other things, a report on the Company’s environmental and worker safety compliance”.  On June 30, 2008, the Court approved the Stipulation and dismissed Manville’s claims with prejudice (the “Order”).  On April 16, 2010, Manville filed an application in the Circuit Court of Kanawha County, West Virginia requesting that the court initiate civil contempt proceedings against the current members of the Board of Directors in connection with alleged violations of the Order.  Specifically, Manville alleges that the 2009 CSR Report did not contain a sufficient “report on . . . worker safety compliance”.  Manville also requested expedited discovery to determine whether other violations of the Order have occurred.  On April 22, 2010, the court issued an order for a rule to show cause, initiating the contempt proceedings.  On July 13, 2010, the court stayed discovery and set a conference date of August 20, 2010, and further ordered that a response to Manville’s application be filed by July 23, 2010.  On July 23, 2010, defendants filed a response to Manville’s application.  On August 3, 2010, Manville filed a reply to defendants’ response to Manville’s application.

On August 11, 2010, Manville filed a Motion to Consolidate the Manville Action, described above, with the contempt proceeding.  On August 18, 2010, defendants filed an opposition to Manville’s Motion to Consolidate.  This motion remains pending before the Circuit Court of Kanawha County.

We and the Defendants have insurance coverage applicable to these matters.  We believe these matters will be resolved without a material adverse impact on our cash flows, results of operations or financial condition.

Merger Litigation

On January 29, 2011, we and Alpha entered into an Agreement and Plan of Merger.  Since the date of the announcement, actions have been filed in the U.S. District Court for the Eastern District of Virginia challenging the Merger. The complaints, which we believe are without merit and which we are challenging vigorously, allege, among other things, that our directors violated their fiduciary duty to our stockholders and that the price to be paid for us by Alpha was too low and that the Merger should not be consummated.

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Other Legal Proceedings

We are parties to a number of other legal proceedings, incident to our normal business activities.  These include, for example, contract disputes, personal injury claims, property damage claims, environmental and safety issues, and employment matters.   While we cannot predict the outcome of any of these proceedings, based on our current estimates we do not believe that any liability arising from these matters individually or in the aggregate should have a material adverse impact upon our consolidated cash flows, results of operations or financial condition.  It is possible, however, that the ultimate liabilities in the future with respect to these lawsuits and claims, in the aggregate, may be materially adverse to our cash flows, results of operations or financial condition.

We strive to maintain compliance with all applicable laws at all times. Shortly after the UBB tragedy, the number of citations, orders and notices of violation issued by MSHA and other regulatory agencies increased significantly.  When we receive a citation, order, or notice of violation, we attempt to promptly abate the condition cited, whether or not we agree as to whether the condition constitutes a violation.  Additionally, we either pay the assessed penalties, or, if we dispute the alleged facts behind the violation or the amount of the penalty relative to the violation, we contest the matter.  While these matters have not previously resulted in a material adverse impact on our cash flows, results of operations or financial condition, they could in the future have such an impact.  In addition, if one or more of our operations is placed on a pattern of violations by the regulatory authorities, such designation and the enhanced enforcement regime that accompanies such designation could have a material adverse effect on our cash flows, results of operations or financial condition.

We continue to move forward with a great sense of urgency, intensifying our efforts and commitment to significantly reduce the number of infractions received from MSHA and other regulatory agencies.  As an example of our commitment, on October 29, 2010, we idled production at our 92 underground coal producing sections to conduct site specific training at these operations and to reinforce the fact that we expect our miners to follow all safety rules and regulations.  We reviewed past violations at these operations and emphasized best practices to eliminate future violations.  In addition, each mine conducted its own safety inspection and all identified safety infractions were remediated before recommencing production.

Additional legal proceedings required by this Item 3 are contained in Note 22, “Contingencies” to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, which is incorporated herein by reference.

Specialized Disclosures

The information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and proposed Item 106 of Regulation S-K is included in exhibit 99.1 to this Annual Report on Form 10-K.

Item 4. [Removed and reserved]

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Part II

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

Common Stock

Common Stock is listed on the New York Stock Exchange (“NYSE”) and trades under the symbol MEE. As of February 15, 2011, there were 103,454,816 shares outstanding and approximately 5,796 stockholders of record of 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 2009
Quarter ended March 31, 2009	$	18.69	$	9.62	$	0.06
Quarter ended June 30, 2009	$	26.46	$	9.80	$	0.06
Quarter ended September 30, 2009	$	33.51	$	15.85	$	0.06
Quarter ended December 31, 2009	$	44.40	$	25.52	$	0.06
Fiscal Year 2010
Quarter ended March 31, 2010	$	54.66	$	37.41	$	0.06
Quarter ended June 30, 2010	$	54.80	$	27.18	$	0.06
Quarter ended September 30, 2010	$	34.60	$	25.85	$	0.06
Quarter ended December 31, 2010	$	54.00	$	30.72	$	0.06

Dividends

On February 15, 2011, our Board of Directors declared a dividend of $0.06 per share, payable on March 31, 2011, to shareholders of record on March 17, 2011.

Our current dividend policy anticipates the payment of quarterly dividends in the future. The ABL Facility and our 6.875% senior notes due 2013 (the “6.875% Notes”) contain provisions that restrict us from paying dividends in excess of certain amounts. The ABL Facility limits the payment of dividends to $85 million annually on Common Stock. The 6.875% Notes limit the payment of dividends to $25 million annually on Common Stock, plus the availability in the Restricted Payments Baskets (as defined in the Indenture governing the 6.875% Notes). In addition, dividends can be paid only so long as no default exists under the ABL Facility or the 6.875% 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, where we are incorporated, on our 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 our future earnings, financial condition, and capital requirements.

In addition, under the terms of the Merger Agreement, during the period before the closing of the Merger, we are prohibited from declaring, setting aside or paying any dividend or other distribution except for our regular quarterly cash dividend, which is not to exceed $0.06 per share.

Convertible Debt Securities

Our 2.25% Notes are convertible by holders into shares of Common Stock during certain periods under certain circumstances. As of December 31, 2010, the price per share of Common Stock had reached the specified threshold for conversion.  Consequently, the 2.25% Notes are convertible until March 31, 2011, the last day of our first quarter.  The 2.25% Notes may be convertible beyond this date if the specified threshold for conversion is met in subsequent quarters.  If all of the 2.25% Notes outstanding at December 31, 2010 had been eligible for conversion and were converted at that date, we would have issued 287,113 shares of Common Stock. No conversions occurred during the year. See Note 10 to the Notes to Consolidated Financial Statements for further discussion of conversion features of the 2.25% Notes.

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Our 3.25% Notes are convertible under certain circumstances and during certain periods into (i) cash, up to the aggregate principal amount of the 3.25% Notes subject to conversion and (ii) cash, Common Stock or a combination thereof, at our election in respect to the remainder (if any) of our conversion obligation. Effective December 31, 2010, the conversion rate has been adjusted to 11.4542 shares of Common Stock per $1,000 principal amount of 3.25% Notes. The adjustment of the conversion rate is a result of us increasing our cash dividend from $0.05 to $0.06 per share of Common Stock in the fourth quarter of 2008. As of December 31, 2010, the price per share of Common Stock had not reached the specified threshold for conversion. No conversions occurred during the year. See Note 10 to the Notes to Consolidated Financial Statements for further discussion of conversion features of the 3.25% Notes.

Repurchase Program

On November 14, 2005, our Board of Directors authorized a stock repurchase program (the “Repurchase Program”), authorizing us to repurchase shares of Common Stock. We may repurchase Common Stock from time to time, as determined by authorized officers, up to an aggregate amount not to exceed $500 million (excluding commissions) with free cash flow as existing financing covenants may permit. Existing covenants currently allow for up to approximately $1.3 billion of share repurchases. As of December 31, 2010, we had $388 million available under the current authorization. The stock repurchases may be conducted on the open market, through privately negotiated transactions, through derivative transactions or through purchases made in accordance with Rule 10b5-1 of the Securities Exchange Act of 1934, as amended (“Exchange Act”), in compliance with the SEC’s regulations and other legal requirements. The Repurchase Program does not require us to acquire any specific number of shares and may be terminated at any time. During 2010, 861,439 shares were repurchased at an average price of $36.92 per share and classified as Treasury stock. The Merger Agreement generally restricts, subject to certain limited exceptions, including, without limitation, Alpha’s prior written consent, our ability to repurchase outstanding Common Stock during the interim period between the execution of the Merger Agreement and the consummation of the Merger (or the date on which the Merger Agreement is terminated).

The following table summarizes information about shares of Common Stock that were purchased during the fourth quarter of 2010.

Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plan
October 1 through October 31		—		—		—		—
November 1 through November 30		—		—		—		—
December 1 through December 31		—		—		—		—
Total		—				—		5,932,726	(1)

(1) Calculated using $388 million that may yet be purchased under our share repurchase program and $65.43, the closing price of Common Stock as reported on the New York Stock Exchange on February 15, 2011.

Common Stock Offering Program

On February 3, 2009, pursuant to Rule 424(b)(5), we filed a prospectus supplement with the Securities and Exchange Commission (“SEC”) allowing us to sell up to five million shares of Common Stock from time to time in our discretion.  The proceeds from any shares of Common Stock sold will be used for general corporate purposes, which may include funding for acquisitions or investments in business, products, technologies, and repurchases and repayment of our indebtedness. As of January 31, 2011, no shares of Common Stock had been sold pursuant to this program. The Merger Agreement generally restricts, subject to certain limited exceptions, including, without limitation, Alpha’s prior written consent, our ability to sell shares of outstanding Common Stock during the interim period between the execution of the Merger Agreement and the consummation of the Merger (or the date on which the Merger Agreement is terminated).

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Common Stock Issuance

On March 23, 2010, we completed a registered underwritten public offering of 9,775,000 shares of Common Stock at a public offering price of $49.75 per share, resulting in proceeds to us of $466.7 million, net of fees.  In April 2010, we used the net proceeds of this offering and 6,519,034 shares of Common Stock (fair valued at $289.5 million on the day of the acquisition) to fund a portion of the consideration for the acquisition of Cumberland.  See Note 3 to the Notes to Consolidated Financial Statements for a more complete discussion.

Transfer Agent and Registrar

The transfer agent and registrar for Common Stock is American Stock Transfer & Trust Company, LLC, Shareholder Services Group, 6201 15th Avenue, Brooklyn, New York 11219, toll free (800) 813-2847, or if outside the United States at (718) 921-8124.

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Item 6. Selected Financial Data

SELECTED FINANCIAL DATA

	Year Ended December 31,
	2010			2009		2008		2007		2006
	(In Millions, Except Per Share, Per Ton, And Number Of Employees Amounts)
CONSOLIDATED STATEMENT OF INCOME DATA:
Produced coal revenue	$	2,609.7		$	2,318.5	$	2,559.9	$	2,054.4	$	1,902.3
Total revenue		3,039.0			2,691.2		2,989.8		2,413.5		2,219.9
(Loss) Income before interest and income taxes		(138.3	)		227.0		128.7		179.7		111.0
(Loss) Income before cumulative effect of accounting change		(166.6	)		104.4		47.8		94.1		41.6
Net (loss) income		(166.6	)		104.4		47.8		94.1		41.0
(Loss) Income per share - Basic (1)
(Loss) Income before cumulative effect of accounting change	$	(1.71	)	$	1.23	$	0.58	$	1.17	$	0.51
Net (loss) income	$	(1.71	)	$	1.23	$	0.58	$	1.17	$	0.50
(Loss) Income per share - Diluted (1)
(Loss) Income before cumulative effect of accounting change	$	(1.71	)	$	1.22	$	0.58	$	1.17	$	0.51
Net (loss) income	$	(1.71	)	$	1.22	$	0.58	$	1.17	$	0.50
Dividends declared per share	$	0.24		$	0.24	$	0.21	$	0.17	$	0.16
CONSOLIDATED BALANCE SHEET DATA:
Working capital	$	454.0		$	869.7	$	731.3	$	522.6	$	445.2
Total assets		4,611.0			3,799.7		3,672.4		2,860.7		2,740.7
Long-term debt		1,303.9			1,295.6		1,310.2		1,102.7		1,102.3
Shareholders’ equity		1,780.5			1,256.3		1,126.6		784.0		697.3
OTHER DATA:
EBIT (2)	$	(138.3	)	$	227.0	$	128.7	$	179.7	$	111.0
EBITDA (2)	$	267.3		$	497.2	$	386.1	$	425.7	$	341.5
Average cash cost per ton sold (3)	$	60.05		$	50.48	$	46.65	$	41.20	$	40.95
Produced coal revenue per ton sold	$	70.27		$	63.26	$	62.50	$	51.55	$	48.71
Capital expenditures	$	434.9		$	274.5	$	736.5	$	270.5	$	298.1
Produced tons sold		37.1			36.7		41.0		39.9		39.1
Tons produced		36.7			38.0		41.1		39.5		38.6
Number of employees		7,359			5,851		6,743		5,407		5,517

(1) In accordance with GAAP, the effect of certain dilutive securities was excluded from the calculation of the diluted income (loss) per common share for the years ended December 31, 2010, 2009, 2008, 2007 and 2006, as such inclusion would result in antidilution.

 (2) EBIT is defined as (Loss) Income before interest and taxes. EBITDA is defined as (Loss) Income before interest and taxes before deducting Depreciation, depletion, and amortization (“DD&A”). Although neither EBIT nor EBITDA are measures of performance calculated in accordance with GAAP, we believe that both measures are useful to an investor in evaluating us because they are widely used in the coal industry as measures to evaluate a company’s operating performance before debt expense and as a measure of its cash flow. Neither EBIT nor EBITDA purport to represent operating income, net income or cash generated by operating activities and should not be considered in isolation or as a substitute for measures of performance calculated in accordance with GAAP. In addition, because neither EBIT nor EBITDA are 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 GAAP measure of Net income to EBIT and to EBITDA.

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	Year Ended December 31,
	2010			2009		2008		2007		2006
	(In Millions)
Net (loss) income	$	(166.6	)	$	104.4	$	47.8	$	94.1	$	41.0
Cumulative effect of accounting change, net of tax		—			—		—		—		0.6
Income tax (benefit) expense		(67.0	)		32.9		1.1		35.4		3.4
Net interest expense and gain (loss) on short-term investment		95.3			89.7		79.8		50.2		66.0
EBIT		(138.3	)		227.0		128.7		179.7		111.0
Depreciation, depletion and amortization		405.6			270.2		257.4		246.0		230.5
EBITDA	$	267.3		$	497.2	$	386.1	$	425.7	$	341.5

 (3) Average cash cost per ton is calculated as the sum of Cost of produced coal revenue (excluding Selling, general and administrative expense (“SG&A”) and DD&A), divided by the number of produced tons sold. In 2009, in order to conform more closely to common industry reporting practices, we have changed our calculation of cash cost to exclude SG&A expense. This change has been reflected in the presentation of data for both the current and comparative past reporting periods in this report. Although Average cash cost per ton is not a measure of performance calculated in accordance with GAAP, we believe that it is useful to investors in evaluating us 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 GAAP. 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 GAAP measure of Total costs and expenses to Average cash cost per ton.

	Year Ended December 31,
	2010			2009			2008		2007		2006
	(In Millions, Except Per Ton Amounts)
Total costs and expenses	$	3,177.3		$	2,464.2		$	2,861.1	$	2,233.8	$	2,108.8
Less: Freight and handling costs		252.4			218.2			306.4		167.6		156.5
Less: Cost of purchased coal revenue		86.1			57.1			28.5		95.2		62.6
Less: Depreciation, depletion and amortization		405.6			270.2			257.4		246.0		230.5
Less: Selling, general and administrative		113.3			97.4			77.0		75.8		53.8
Less: Other expense		8.1			8.7			3.2		7.3		6.2
Less: Litigation charge		—			—			250.1		—		—
Less: Loss on financing transactions		—			0.2			5.0		—		—
Less: (Gain) loss on derivative instruments		(21.1	)		(37.6	)		22.6		—		—
Less:  Upper Big Branch mine charge (a)		100.2			—			—		—		—
Average cash cost	$	2,232.7		$	1,850.0		$	1,910.9	$	1,641.9	$	1,599.2
Average cash cost per ton	$	60.05		$	50.48		$	46.65	$	41.20	$	40.95

(a) The twelve months ended December 31, 2010, include pre-tax charges of $166.5 million in incurred costs, asset impairments and accrued reserves associated with the tragic accident at the UBB that occurred in April 2010 (see Notes 6, 15 and 22 to the Notes to Consolidated Financial Statements for further discussion). The table below summarizes expenses incurred by us related to the UBB tragedy, broken down by the financial statement line where the expenses were included:

Expense related to the UBB tragedy	$	166.5
Less: Expense included in SG&A		2.7
Less: Expense included in DD&A		63.6
UBB charge included in Costs of produced coal revenue	$	100.2

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

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to help the reader understand the Company, our operations and our present business environment. The MD&A is provided as a supplement to, and should be read in conjunction with, our consolidated financial statements and the accompanying notes thereto contained in Item 8 of this report. From time to time, we may make statements that may constitute “forward-looking statements” within the meaning of the “safe-harbor” provisions of the Private Securities Litigation Reform Act of 1995. These statements are based on our then current expectations and are subject to a number of risks and uncertainties that could cause actual results to differ materially from those addressed in the forward-looking statements. Please see “Forward-Looking Statements” on page i hereto which are incorporated herein and the risk factors that may cause such a difference, which are set forth in Item 1A. Risk Factors and are incorporated herein.

Executive Overview

We operate coal mines and processing facilities in Central Appalachia, which generate revenues and cash flow through the mining, processing and selling of steam and metallurgical grade coal, primarily of low sulfur content. We also generate income and cash flow through other coal-related businesses. Other revenue is obtained from royalties, rentals, gas well revenues, gains on the sale of non-strategic assets and miscellaneous income.

We reported a net loss for the year ended December 31, 2010 of $166.6 million, or $1.71 per share, compared to net income for 2009 of $104.4 million, or $1.22 per diluted share. The results of 2010 were negatively impacted by the following pre-tax items: $166.5 million expense related to the UBB tragedy (see Notes 6, 15 and 22 of the Notes to Consolidated Financial Statements for further discussion), and a $8.5 million charge recorded in relation to a customer pricing dispute $46.1 million in pre-tax amortization expense related to above-market sales contracts and other intangible assets acquired in the Cumberland acquisition, $20.5 million in pre-tax expense for impairment charges related to idled mines, $12.0 million of Sales, General and Administrative expense (“SG&A”) for benefits provided to our former Chairman and CEO in accordance with his retirement agreement, which was effective December 31, 2010 .  The results of 2010 were favorably impacted by the following pre-tax items: $9.7 million from the settlement of certain claims against a service provider, $7.2 million related to the sale of a claim in a customer bankruptcy proceeding, a pre-tax gain of $18.4 million from insurance proceeds received in association with the fire at the Bandmill preparation plant, a gain of $8.9 million on exchanges of coal reserves, and a $21.1 million gain on derivative instruments.  Net income in 2009 included pre-tax gains totaling $33.6 million for the sale and exchange of coal reserve interests and other assets with third-parties and a net pre-tax gain of $37.6 million on derivative instruments.

In 2010, we substantially increased our coal reserves principally through the acquisition of Cumberland.  During 2010 we also completed several coal reserve trades and acquisitions that increased our total reserve base. These transactions, in addition to adjustments made in conjunction with normal annual review and re-evaluation of reserves, and offset by 37 million tons of coal produced, resulted in a net increase of 366 million tons of coal reserves during the year.  We estimate that we had approximately 2.8 billion tons of proven and probable coal reserves as of December 31, 2010.

Produced tons sold were 37.1 million in 2010, compared to 36.7 million in 2009.  We produced 36.7 million and 38.0 million tons in 2010 and 2009, respectively.  The lower coal production in 2010 was primarily the result of discrete geologic conditions, increased regulatory enforcement actions and related temporary shutdowns, and higher ratios on surface mines. Produced coal shipments were adversely affected by the lower production, inconsistent rail service and delays of export shipments at the ports.

During 2010, Produced coal revenue increased by 13% compared to 2009, mainly attributable to the addition of higher priced utility coal contracts assumed in the acquisition of Cumberland in April 2010 and higher shipments of metallurgical tons at improved average prices in 2010.  Our average Produced coal revenue per ton sold in 2010 increased to $70.27 compared to $63.26 in 2009.  Our average Produced coal revenue per ton in 2010 for metallurgical tons sold increased by 5% to $100.68 from $95.93 in 2009.

Our Average cash cost per ton sold was $60.05 in 2010, compared to $50.48 in 2009 (2010 excludes the costs associated with the tragic event at the UBB mine in April 2010).  The key drivers of the increase in average cash cost per ton were, in order of magnitude, surface mine supplies and repairs, higher surface mine ratios, lower productivity in underground mines, lower productivity of highwall miners and higher sales related costs driven by higher revenue per ton.

On April 5, 2010, an accident occurred at the UBB mine of our Performance resource group, tragically resulting in the deaths of 29 miners and seriously injuring two miners.  The MSHA and the State of West Virginia are conducting a joint investigation into the cause of the accident.  We are also conducting our own investigation.  We believe these investigations will continue for the foreseeable future, and we cannot provide any assurance as to their outcome, including whether we will become subject to possible civil penalties or enforcement actions.  In order to accommodate these investigations, the mine will continue to be closed for an extended period of time, the length of which we cannot predict at this time.  It is also possible that we may be required by regulators to permanently close this mine.

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We have recorded a $78 million liability in Other current liabilities at December 31, 2010, which represents our best estimate of the probable loss related to potential future litigation settlements associated with the UBB tragedy.  Two of the victims’ families have filed wrongful death suits against us, while seven of the victims’ families have signed agreements to settle their claims (four of which have been finalized after receiving the required judicial approval).  Insurance recoveries related to our general liability insurance policy that are deemed probable and that are reasonably estimable have been recognized in the Consolidated Statements of Income to the extent of the related losses.  Such recognized recoveries for litigation settlements associated with the UBB tragedy totaled $78 million and are included in Trade and other accounts receivable at December 31, 2010.

On April 19, 2010, we completed the acquisition of Cumberland for a purchase price of $934.2 million ($644.7 million in cash and $289.5 million in shares of Common Stock).  Prior to the acquisition, Cumberland was one of the largest privately held coal producers in the United States with 2009 produced coal revenue of $550 million generated from the production and sale of 8.0 million tons of high quality Central Appalachian coal. We did not incur or assume any third-party debt as a result of the Cumberland acquisition.  The Cumberland operations include primarily underground coal mines in Southwestern Virginia and Eastern Kentucky.  As a result of the acquisition, we obtained an estimated 415 million tons of contiguous coal reserves.  We obtained a preparation plant in Kentucky served by the CSX railroad and a preparation plant in Virginia served by the Norfolk Southern railroad. Of the estimated reserves, we believe more than half (216 million tons) have metallurgical coal qualities.  Total revenue reported in the Consolidated Statements of Income for the year ended 2010, included $438.2 million from operations acquired from Cumberland.  See Note 3 to the Notes to Consolidated Financial Statements for further discussion.

Merger with Alpha

On January 28, 2011, we entered into the Merger Agreement with Alpha and Merger Sub, providing for the acquisition of Massey by Alpha.  Subject to the terms and conditions of the Merger Agreement, we will be merged with and into Merger Sub, with Massey surviving the Merger as a wholly owned subsidiary of Alpha.

At the effective time of the Merger, each share of our Common Stock issued and outstanding immediately prior to the effective time (other than shares owned by (i) Alpha, us or Merger Sub or their respective subsidiaries (which will be cancelled) or (ii) stockholders who have properly exercised and perfected appraisal rights under Delaware law) will be converted into the right to receive 1.025 shares of Alpha common stock and $10.00 in cash, without interest.  No fractional shares of Alpha common stock will be issued in the Merger, and our stockholders will receive cash in lieu of fractional shares, if any, of Common Stock. Immediately upon completion of the Merger, our stockholders will own approximately 46% of the combined company.

The consummation of the Merger is subject to certain conditions, including (i) the adoption by our stockholders of the Merger Agreement and (ii) the approval by the Alpha stockholders of (x) an amendment to Alpha’s certificate of incorporation to increase the number of shares of Alpha common stock that Alpha is authorized to issue in order to permit issuance of the Alpha common stock in connection with the Merger and (y) the issuance of Alpha common stock in connection with the Merger.  In addition, the Merger is subject to the HSR Act, as well as other customary closing conditions.

The Merger Agreement contains customary covenants, including covenants providing for each of the parties: (i) to conduct its operations in all material respects according to the ordinary and usual course of business consistent with past practice during the period between the execution of the Merger Agreement and the closing of the Merger; (ii) to use reasonable best efforts to cause the transaction to be consummated; (iii) not to initiate, solicit or knowingly encourage inquiries, proposals or offers relating to alternate transactions or, subject to certain exceptions, engage in any discussions or negotiations with respect thereto; and (iv) to call and hold a special stockholders’ meeting and, subject to certain exceptions, recommend adoption of the Merger Agreement, in our case, and amendment of the Alpha certificate of incorporation and issuance of Alpha common stock in connection with the Merger, in the case of Alpha.

The Merger Agreement also contains certain termination rights and provides that, (i) upon termination of the Merger Agreement under specified circumstances, including, but not limited to, a change in the recommendation of our board of directors or termination of the Merger Agreement to enter into a written definitive agreement for a “superior proposal”, we will owe Alpha a cash termination fee of $251 million; (ii) upon the termination of the Merger Agreement under specified circumstances, including, but not limited to, a change in the recommendation of the board of directors of Alpha or termination of the Merger Agreement to enter into a written definitive agreement for a “superior proposal”, Alpha will owe us a cash termination fee of $252 million; and (iii) upon the termination of the Merger Agreement due to Alpha’s failure to obtain the required stockholder approval at the Alpha stockholders’ meeting in the absence of a competing proposal, Alpha will owe us a cash termination fee of $72 million. In addition, Alpha is obligated to pay a cash termination fee of $360 million to us if all the conditions to closing have been met and the Merger is not consummated because of a breach by Alpha’s lenders of their obligations to finance the Merger.

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 Results of Operations

2010 Compared with 2009

Revenues

	Year Ended December 31,
(In Thousands)	2010		2009		Increase (Decrease)			% Increase (Decrease)
Revenues
Produced coal revenue	$	2,609,659	$	2,318,489	$	291,170			13	%
Freight and handling revenue		252,409		218,203		34,206			16	%
Purchased coal revenue		91,566		62,721		28,845			46	%
Other revenue		85,340		91,746		(6,406	)		(7	% )
Total revenues	$	3,038,974	$	2,691,159	$	347,815			13	%

The following is a breakdown, by market served, of the changes in produced tons sold and average produced coal revenue per ton sold for 2010 compared to 2009:

	Year Ended December 31,
(In Millions, Except Per Ton Amounts)	2010		2009		Increase (Decrease)			% Increase (Decrease)
Produced tons sold:
Utility		25.9		26.6		(0.7	)		(3	%)
Metallurgical		7.9		7.4		0.5			7	%
Industrial		3.3		2.7		0.6			22	%
Total		37.1		36.7		0.4			1	%
Produced coal revenue per ton sold:
Utility	$	61.37	$	53.69	$	7.68			14	%
Metallurgical		100.68		95.93		4.75			5	%
Industrial		67.40		68.33		(0.93	)		(1	%)
Weighted average		70.27		63.26		7.01			11	%

Shipments of metallurgical and industrial coal increased in 2010, compared to 2009, to meet higher demand in 2010 as economic conditions have improved.  Shipments of utility coal decreased in 2010, compared to 2009, primarily due to lower customer demand in the second half of 2010 as electric utilities continued to draw down from previously high stockpile levels and low production levels.  The average per ton sales price for utility coal was higher in 2010, compared to 2009, mainly attributable to the addition of higher priced utility coal contracts assumed in the acquisition of Cumberland.

Freight and handling revenue increased due to an increase in the number of export contracts in which customers were required to pay freight in 2010, compared to 2009.  Export coal shipments decreased slightly to 5.6 million tons in 2010 from 5.7 million tons shipped in 2009.  Overall revenue per ton for export tons shipped increased to $99.04 during 2010, from $82.30 during 2009.

Purchased coal revenue increased in 2010, compared to 2009, primarily due to a 27% increase in the amount of purchased tons sold and a significant increase in average selling price.  Purchased coal revenue per ton increased to $76.50 during 2010, from $66.43 during 2009, as a result of a change in the mix of purchased coal that included more purchased metallurgical coal shipments during 2010, compared to 2009.

Other revenue includes refunds on railroad agreements, royalties related to coal lease agreements, gas well revenue, gains on the sale of non-strategic assets and reserve exchanges, joint venture revenue and other miscellaneous revenue.  Other revenue for 2010 includes an $11.2 million (pre-tax) gain on insurance recovery related to the Bandmill preparation plant fire, a $9.7 million (pre-tax) gain from the settlement of certain claims against a service provider, $7.2 million (pre-tax) related to the sale of a claim in a customer bankruptcy proceeding, and a pre-tax gain of $6.9 million on exchanges of coal reserves.  Other revenue for 2009 includes pre-tax gains of $26.5 million on the exchange of coal reserves and other assets, and $7.1 million for the sale of our interest in certain coal reserves.

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Costs

	Year Ended December 31,
							Increase			% Increase
(In Thousands)	2010			2009			(Decrease)			(Decrease)
Costs and expenses
Cost of produced coal revenue	$	2,332,851		$	1,850,058		$	482,793			26	%
Freight and handling costs		252,409			218,203			34,206			16	%
Cost of purchased coal revenue		86,127			57,108			29,019			51	%
Depreciation, depletion and amortization, applicable to:
Cost of produced coal revenue		363,748			268,317			95,431			36	%
Selling, general and administrative		41,814			1,860			39,954			2,148	%
Selling, general and administrative		113,340			97,381			15,959			16	%
Other expense		8,072			8,705			(633	)		(7	%)
Loss on financing transactions		—			189			(189	)		(100	%)
Gain on derivative instruments		(21,078	)		(37,638	)		16,560			(44	%)
Total costs and expenses	$	3,177,283		$	2,464,183		$	713,100			29	%

Cost of produced coal revenue increased in 2010, compared to 2009.  Factors leading to the increase were lower productivity attributable to discrete geologic conditions, increased regulatory scrutiny and related temporary shutdowns, increased labor turnover rates, higher repairs and supplies expenses, and a higher percentage of underground mine production, which has a higher per ton cost than surface mining.  The UBB tragedy contributed $100.2 million to our Cost of produced coal revenue in 2010.

Freight and handling costs increased due to an increase in the number of export contracts in which customers were required to pay freight in 2010, compared to 2009.  Export coal shipments decreased slightly to 5.6 million tons in 2010 from 5.7 million tons shipped in 2009.

Cost of purchased coal revenue increased in 2010, compared to 2009, primarily due to a 27% increase in the amount of purchased tons sold.  In addition, 2009 included a $7.6 million reduction for a black lung excise tax refund received in 2009.

Depreciation, depletion and amortization applicable to Cost of produced coal revenue increased in 2010, compared to 2009, due to the addition of the operations from the Cumberland acquisition and the $63.6 million impairment of assets at UBB and $20.5 million of impairment charges for unamortized mine development costs at certain idled mines (see Note 6 to the Notes to Consolidated Financial Statements for further discussion).  Depreciation, depletion and amortization applicable to SG&A increased in 2010, compared to 2009 as a result of amortization expense recorded on coal sales contracts acquired in April 2010 as part of the acquisition of Cumberland (see Notes 3 and 7 to the Notes to Consolidated Financial Statements for further discussion).

SG&A expense increased due to a charge of $12.0 million for benefits provided to our former Chairman and CEO in accordance with his retirement agreement, an $8.5 million charge recorded in relation to a customer pricing dispute, $2.7 million related to the UBB tragedy, and increased advertising and public relations expenses, which were partially offset by lower executive incentive compensation resulting from weaker operating results.

Other expense includes a $5.0 million and $6.0 million reserve for bad debt related to a note receivable from a supplier in 2010 and 2009, respectively.

Gain on derivative instruments for 2010, represents a gain on derivative instruments of $21.1 million ($15.1 million of unrealized losses plus $36.2 million of realized gains due to settlements on existing purchase and sales contracts).  Gain on derivative instruments for 2009, represents a gain on derivative instruments of $37.6 million ($53.1 million of unrealized gains less $15.5 million of realized losses due to settlements on existing purchase and sales contracts). See Note 19 in the Notes to Consolidated Financial Statements for further discussion.

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Interest

Interest income decreased in 2010, compared to 2009, primarily as a result of $8.7 million of interest income on black lung excise tax refunds received in 2009.  Additionally, due to historically low interest rates, we experienced a significant reduction in interest earned on money market funds during 2010, compared to 2009, and the reduction in our average cash and cash equivalents balance during 2010, compared to 2009.

Interest expense includes $19.9 million and $18.4 million of non-cash interest expense for the amortization of the discount of our 3.25% Notes for 2010 and 2009, respectively (see Note 10 to the Notes to Consolidated Financial Statements for further discussion).

Gain on short-term investment

Gain on short-term investment reflects the difference between our book value in the Reserve Primary Fund (the “Primary Fund”) and total distributions received from the fund.  At December 31, 2009, our investment in the Primary Fund was $10.9 million, net of a $6.5 million write-down recorded in 2008.  During 2010, we received distributions from the Primary Fund in the amount of $15.6 million. Consequently, we recorded a $4.7 million gain.

Income Taxes

Income tax benefit was $67.0 million for 2010, compared with tax expense of $32.9 million for 2009. The income tax rate for 2010 was favorably impacted by percentage depletion allowances and unfavorably impacted by changes in the valuation allowance related principally to the generation of federal net operating losses. The income tax rate in 2010 and 2009 was negatively impacted by nondeductible penalties. The 2010 income tax rate was unfavorably impacted by nondeductible executive compensation related benefits provided to our former Chairman and CEO in accordance with his retirement agreement. Also impacting the 2010 income tax rate was a $2.6 million discrete charge related to a reduction in tax benefits as a result of the PPACA signed into law in March 2010. Impacting the 2009 income tax rate was a favorable adjustment in connection with the election to forego bonus depreciation, allowing us to claim a refund for alternative minimum tax credits.

2009 Compared with 2008

Revenues

	Year Ended December 31,
					Increase			% Increase
(In Thousands)	2009		2008		(Decrease)			(Decrease)
Revenues
Produced coal revenue	$	2,318,489	$	2,559,929	$	(241,440	)		(9	%)
Freight and handling revenue		218,203		306,397		(88,194	)		(29	%)
Purchased coal revenue		62,721		30,684		32,037			104	%
Other revenue		91,746		92,779		(1,033	)		(1	%)
Total revenues	$	2,691,159	$	2,989,789	$	(298,630	)		(10	%)

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The following is a breakdown, by market served, of the changes in produced tons sold and average produced coal revenue per ton sold for 2009 compared to 2008:

	Year Ended December 31,
(In Millions, Except Per Ton Amounts)	2009		2008		Increase (Decrease)			% Increase (Decrease)
Produced tons sold:
Utility		26.6		27.0		(0.4	)		(1	%)
Metallurgical		7.4		9.9		(2.5	)		(25	%)
Industrial		2.7		4.1		(1.4	)		(34	%)
Total		36.7		41.0		(4.3	)		(10	%)
Produced coal revenue per ton sold:
Utility	$	53.69	$	49.92	$	3.77			8	%
Metallurgical		95.93		97.07		(1.14	)		(1	%)
Industrial		68.33		61.78		6.55			11	%
Weighted average		63.26		62.50		0.76			1	%

Shipments of all grades of coal decreased in 2009, compared to 2008, due to lower customer demand, as the United States and world economies suffered through a severe recession during 2009. Demand for utility coal was also negatively affected by increasing coal stockpiles due to utilities shifting to gas fired generation. The average per ton sales price for industrial and utility coal was higher in 2009, compared to 2008, attributable to prices contracted during periods when demand and pricing were elevated for all grades of coal in the United States.

Freight and handling revenue decreased due to a reduction in the number of contracts in which customers were required to pay freight in 2009, compared to 2008, and by a decrease in export tons sold from 8.1 million in 2008, to 5.7 million in 2009.

Purchased coal revenue increased in 2009, compared to 2008, as a result of 0.5 million tons increase in the number of purchased tons shipped.

Other revenue includes refunds on railroad agreements, royalties related to coal lease agreements, gas well revenue, gains on the sale of non-strategic assets and reserve exchanges, joint venture revenue and other miscellaneous revenue. Other revenue for 2009 includes pre-tax gains of $26.5 million on the exchange of coal reserves and other assets, and $7.1 million for the sale of our interest in certain coal reserves. Other revenue for 2008 includes a pre-tax gain of $32.4 million on the exchange of coal reserves.

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Costs

	Year Ended December 31,
						Increase			% Increase
(In Thousands)	2009			2008		(Decrease)			(Decrease)
Costs and expenses
Cost of produced coal revenue	$	1,850,058		$	1,910,953	$	(60,895	)		(3	%)
Freight and handling costs		218,203			306,397		(88,194	)		(29	%)
Cost of purchased coal revenue		57,108			28,517		28,591			100	%
Depreciation, depletion and amortization, applicable to:
Cost of produced coal revenue		268,317			253,737		14,580			6	%
Selling, general and administrative		1,860			3,590		(1,730	)		(48	%)
Selling, general and administrative		97,381			77,015		20,366			26	%
Other expense		8,705			3,207		5,498			171	%
Litigation charge		—			250,061		(250,061	)		(100	%)
Loss on financing transactions		189			5,006		(4,817	)		(96	%)
Gain on derivative instruments		(37,638	)		22,552		(60,190	)		(267	%)
Total costs and expenses	$	2,464,183		$	2,861,035	$	(396,852	)		(14	%)

Cost of produced coal revenue decreased due to fewer tons sold in 2009, compared to 2008, offset by increased productions costs, higher labor costs, and higher equipment rental costs.

Freight and handling costs decreased due to a reduction in the number of contracts in which customers were required to pay freight in 2009, compared to 2008, and by a decrease in export tons sold from 8.1 million in 2008, to 5.7 million in 2009.

Costs of purchased coal revenue increased in 2009, compared to 2008, as a result of 0.5 million tons increase in the number of purchased tons shipped, offset by a decrease due to a $7.6 million black lung excise tax refund recorded in 2009.

Depreciation, depletion and amortization applicable to Cost of produced coal revenue increased due to impact of various of our capital projects that went into service during 2008.

SG&A expense increased in 2009, compared to 2008, primarily due to an increase in stock-based compensation accruals in 2009, caused by an increase in our stock price during 2009 as compared to 2008.

Other expense includes a $6.0 million reserve for bad debt for 2009 related to a note receivable from a supplier.

Litigation charge represents an accrual for a specific legal action related to the litigation with Wheeling-Pittsburgh that was recorded in 2008.

Loss on financing transactions in 2009, relates to the $0.2 million loss recognized from the purchase of $11.9 million of our 3.25% Notes on the open market.  Loss on financing transactions in 2008, relates to a $4.1 million gain recognized from the purchase of $19.0 million of our 3.25% Notes on the open market during 2008, offset by a $9.1 million of fees incurred for the tender offer on our 6.625% Notes during 2008. See Note 10 in the Notes to Consolidated Financial Statements for further discussion.

Gain on derivative instruments represents a gain of $37.6 million ($53.1 million of unrealized gains due to fair value measurement adjustments and $15.5 million of realized losses due to settlements on existing contracts) related to purchase and sales contracts that did not qualify for the NPNS exception in 2009 (see Note 19 in the Notes to Consolidated Financial Statements for further discussion).

Interest

Interest income decreased in 2009, compared to 2008, primarily as a result of a significant reduction in the interest rates earned on our interest bearing investments. During 2009 and 2008, we recorded $8.7 million and $7.0 million, respectively, of interest income on black lung excise tax refunds.

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Interest expense increased primarily as a result of $18.4 million in 2009, compared to $6.9 million in 2008, of non-cash interest expense for the amortization of the discount recorded on our 3.25% Notes.  Additionally, interest expense for 2008 includes $1.9 million (pre-tax) for the write-off of unamortized financing fees and $4.2 million for the write-off of unamortized interest rate swap termination payment (see Note 10 in the Notes to Consolidated Financial Statements for further discussion).

Loss on short-term investment

Loss on short-term investment represents a pro rata share of the estimated loss in our investment in the Primary Fund of $6.5 million (see Note 20 to the Notes to Consolidated Financial Statements for further discussion).

Income Taxes

Income tax expense was $32.9 million for 2009, compared with a tax expense of $1.1 million for 2008. The income tax rates for 2009 and 2008 were favorably impacted by percentage depletion allowances and the usage of net operating loss carryforwards. The income tax rate in 2009 and 2008 was negatively impacted by nondeductible penalties. Also impacting the 2009 and 2008 income tax rate were favorable adjustments in connection with the election to forego bonus depreciation and claim a refund for alternative minimum tax credits. Because of the discrete tax events occurring in 2009, the tax rate for 2009 may not be indicative of future tax rates. The income tax rate in 2008 was negatively impacted by a nondeductible EPA settlement and an increase in deferred tax asset valuation allowances related principally to federal net operating losses. The 2008 rate was also favorably impacted by the adjustment of reserves in connection with the closing of a prior period audit by the IRS.

Liquidity and Capital Resources

At December 31, 2010, our available liquidity was $450.0 million, comprised of Cash and cash equivalents of $327.2 million and $122.8 million of availability from our asset-based revolving credit facility (“ABL”). Our total debt-to-book capitalization ratio was 42.5% at December 31, 2010.

Debt was comprised of the following:

	December 31,			December 31,
	2010			2009
	(In Thousands)
6.875% senior notes due 2013, net of discount	$	757,462		$	756,727
3.25% convertible senior notes due 2015, net of discount		546,323			526,435
6.625% senior notes due 2010		—			21,949
2.25% convertible senior notes due 2024		9,647			9,647
Capital lease obligations		2,747			4,328
Total debt		1,316,179			1,319,086
Amounts due within one year		(12,327	)		(23,531	)
Total long-term debt	$	1,303,852		$	1,295,555

See Note 10 in the Notes to Consolidated Financial Statements for further discussion of our debt and debt-related covenants.

6.625% Notes

During January 2010, we redeemed at par the remaining $21.9 million of our 6.625% senior notes due 2010.

Convertible Debt Securities

On January 1, 2009, new accounting guidance became effective relating to our 3.25% Notes, which was retroactively applied, as required. We separately account for the liability and equity components in a manner reflective of our nonconvertible debt borrowing rate, which was determined to be 7.75% at the date of issuance of the 3.25% Notes. The discount associated with the 3.25% Notes is being amortized via the effective-interest method increasing the reported liability until the notes are carried at par value on their maturity date. We recognized $19.9 million and $18.4 million of pre-tax non-cash interest expense for the amortization of the discount for the year ended December 31, 2010 and 2009, respectively.

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Asset-Based Credit Facility

On November 8, 2010, we entered into an amended and restated asset-based revolving credit agreement, which provides for available borrowings, including letters of credit, of up to $200 million, depending on the level of eligible inventory and accounts receivable.  Subject to certain conditions, at any time prior to maturity, we may elect to increase the size of the facility up to $250 million if lenders willing to support the additional $50 million can be identified.  The previous asset-based revolving credit agreement provided for available borrowings, including letters of credit, of up to $175 million, depending on the level of eligible inventory and accounts receivable.  In addition, we extended the facility’s maturity to May 2015.  As of December 31, 2010, there were $77.2 million of letters of credit issued and there were no outstanding borrowings under this facility.

Authorized Common Stock

On October 6, 2010, at a Special Meeting of Stockholders, our stockholders approved an increase of authorized shares of Common Stock from 150,000,000 to 300,000,000 shares.

Common Stock Offering Program

On February 3, 2009, pursuant to Rule 424(b)(5), we filed a prospectus supplement with the Securities and Exchange Commission (“SEC”) allowing us to sell up to 5.0 million shares of Common Stock from time to time in our discretion.  The proceeds from any shares of Common Stock sold will be used for general corporate purposes, which may include funding for acquisitions or investments in business, products, technologies, and repurchases and repayment of our indebtedness. The Merger Agreement generally restricts, subject to certain limited exceptions, including, without limitation, Alpha’s prior written consent, our ability to sell shares of our outstanding Common Stock during the interim period between the execution of the Merger Agreement and the consummation of the Merger (or the date on which the Merger Agreement is terminated).

Common Stock Issuance

On March 23, 2010, we completed a registered underwritten public offering of 9,775,000 shares of Common Stock at a public offering price of $49.75 per share, resulting in proceeds to us of $466.8 million, net of fees.  In April 2010, we used the net proceeds of this offering and 6,519,034 shares of Common Stock (fair valued at $289.5 million on the day of the acquisition) to fund a portion of the consideration for the acquisition of Cumberland.  See Note 3 and 7 to the Notes to Consolidated Financial Statements for a more complete discussion.

Repurchase Program

The Board of Directors has authorized a total of $500 million (excluding commissions) to repurchase Common Stock under our share repurchase program (the “Repurchase Program”). We may repurchase shares of Common Stock from time to time in compliance with the SEC’s regulations and other legal requirements, and subject to market conditions and other factors. The share repurchase program does not require us to acquire any specific number of shares and may be terminated at any time. The Merger Agreement generally restricts, subject to certain limited exceptions, including, without limitation, Alpha’s prior written consent, our ability to repurchase our outstanding Common Stock during the interim period between the execution of the Merger Agreement and the consummation of the Merger (or the date on which the Merger Agreement is terminated).
 

Common Stock Repurchases

During 2010, we repurchased 861,439 shares of Common Stock at an average price of $36.92, for a total cost of $31.8 million.  The Common Stock was repurchased under our Repurchase Program. Prior to this share repurchase, we had $420 million available under the 2005 authorization. Shares repurchased in 2010 under our Repurchase Program have been recorded as Treasury stock in the Consolidated Balance Sheet.

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Cash Flow

Net cash provided by operating activities was $267.9 million for 2010, compared to $288.9 million for 2009. Cash provided by operating activities reflects Net income adjusted for non-cash charges and changes in working capital requirements. The decrease in cash provided by operating activities is primarily the result of an increase in cash cost per ton of produced coal that was larger than the increase in average produced coal revenue per ton.  This decrease would have been larger except for the recovery in 2010 of $72.0 million of cash as collateral for an appeal bond we had been required to post related to litigation against us recorded in Other current assets during 2009.

Net cash utilized by investing activities was $1,029.2 million and $211.6  million for 2010 and 2009, respectively. The cash used in investing activities reflects capital expenditures in the amount of $434.9 million and $274.6 million for 2010 and 2009, respectively. These capital expenditures are for replacement of mining equipment, the expansion of mining and shipping capacity, additional preparation plant capacity, and projects to improve the efficiency of mining operations. The 2010 acquisition of Cumberland resulted in a net cash outflow of $630.0 million (net of cash acquired of $14.7 million).  Additionally, 2010 and 2009 included $4.6 million and $19.0 million, respectively, of proceeds provided by the sale of assets.

Net cash provided by financing activities was $422.7 million for 2010, compared to net cash utilized by financing activities of $18.5 million for 2009. Financing activities reflect changes in debt levels, common stock offerings, exercising of stock options, payments of dividends and cash receipts generated from sale-leaseback transactions. Financing activities for 2010 primarily reflects a registered underwritten public equity offering, resulting in proceeds to us of $466.7 million, net of fees, partially offset by the repayment of our 6.625% Notes of $21.9 million.  During 2010, we repurchased shares of Common Stock for $31.8 million.  Financing activities for 2010 and 2009 also reflects payments of $23.5 million and $20.4 million, respectively, for the regular quarterly dividend on shares of Common Stock.  Members exercising stock options during 2010 and 2009 resulted in cash inflows of $18.3 million and $11.3 million, respectively.  Proceeds from sale-leaseback transactions resulted in cash inflows of $16.5 million for 2010. Additionally, financing activities for 2009 reflects $10.0 million utilized for the purchase of some of our 3.25% Notes on the open market.

We believe that cash on hand, cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, scheduled debt payments, potential share repurchases and debt repurchases, anticipated dividend payments, expected settlements of outstanding litigation, anticipated capital expenditures and costs related to the UBB tragedy (see Notes 6, 15 and 22 to the Notes to Consolidated Financial Statements), including any increased premiums for insurance, any claims that may be asserted against us and other expenses that are not covered, in whole or in part, by our insurance policies, for at least the next twelve months.  Nevertheless, our ability to satisfy our debt service obligations, repurchase shares and debt, pay dividends, pay settlements or judgments in respect of pending litigation, fund planned capital expenditures or pay the costs related to the UBB tragedy, will substantially depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry, debt covenants and financial, business and other factors, some of which are beyond our control. (See also “Concentration of Credit Risk and Major Customers” in Note 18 in the Notes to Consolidated Financial Statements.)

We frequently evaluate potential acquisitions.  As a result of the cash needs we have described above and possible acquisition opportunities, in the future we may consider a variety of financing sources, including debt or equity financing.  Currently, other than our ABL, we have no commitments for any additional financing.  We cannot be certain that we will be able to obtain additional financing on terms that we find acceptable, if at all, through the issuance of equity securities or the incurrence of additional debt.  Additional equity financing may dilute our stockholders, and debt financing, if available, may among other things, restrict our ability to repurchase shares of Common Stock, declare and pay dividends and raise future capital.  If we are unable to obtain additional needed financing, it may prohibit us from making acquisitions, capital expenditures and/or investments, which could materially and adversely affect our prospects for long-term growth.

We are subject to various covenants contained in the Merger Agreement that restrict our ability to operate our business outside the ordinary course of business pending consummation of the Merger, and subject to certain limited exceptions, including, without limitation, Alpha’s prior written consent, it restricts us from taking certain specified actions until the merger is complete or the agreement is terminated, including, without limitation, not exceeding a certain amount in capital expenditures, not making certain acquisitions, not entering into certain types of contracts and other matters. As such, our ability to address the short-term and long-term liquidity requirements may be impacted by these restrictions.

Contractual Obligations

We have various contractual obligations that are recorded as liabilities within the Consolidated Financial Statements in this Annual Report on Form 10-K. 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 our significant obligations as of December 31, 2010 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 Consolidated Financial Statements, such as Accounts payable and Payroll and employee benefits. In addition, the Merger Agreement contains termination rights for both us and Alpha and provides that, if we terminate the Merger Agreement under specified circumstances, we may be required to pay a termination fee of $252 million.

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	Payments Due by Period (In Thousands)
	Total		Within 1 Year		1-3 Years		3-5 Years		Beyond 5 Years
Long-term debt (1)	$	1,688,529	$	73,887	$	907,773	$	695,196	$	11,673
Capital lease obligations (2)		2,795		2,690		70		35		—
Operating lease obligations (3)		254,612		92,135		130,807		31,670		—
Coal lease obligations (4)		202,599		42,333		63,447		33,248		63,571
Purchased coal obligations (5)		51,281		51,281		—		—		—
Other purchase obligations (6)		34,406		23,972		6,956		3,478		—
Total Obligations	$	2,234,222	$	286,288	$	1,109,053	$	763,627	$	75,244

(1) Long-term debt obligations reflect the contractually stated future interest and principal payments of our fixed rate senior unsecured notes outstanding as of December 31, 2010. See Note 10 to the Notes to Consolidated Financial Statements for additional information.

(2) Capital lease obligations include the amount of imputed interest over the terms of the leases. See Note 17 to the Notes to Consolidated Financial Statements for additional information.

(3) See Note 17 to the Notes to Consolidated Financial Statements for additional information.

(4) Coal lease obligations include 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, we have generally assumed that minimum royalties on such leases will be paid for a period of 20 years.

(5) Purchased coal obligations represent commitments to purchase coal from external production sources under firm contracts as of December 31, 2010.

(6) Other purchase obligations primarily include capital expenditure commitments for surface mining and other equipment as well as purchases of materials and supplies. We have purchase agreements with vendors for most types of operating expenses. However, our 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 include 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, we have liabilities relating to pension and other postretirement benefits, work related injuries and illnesses, and mine reclamation and closure. As of December 31, 2010, payments related to these items are estimated to be:

Payments Due by Years (In Thousands)
Within 1 Year		1 - 3 Years		3 - 5 Years
$	85,172	$	155,225	$	163,152

Our determination of these noncurrent liabilities is calculated annually and is based on several assumptions, including then-prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated. Moreover, in particular for periods after 2010, the estimates may change from the amounts included in the table, and may change significantly, if assumptions change to reflect changing conditions. These assumptions are discussed in the Notes to Consolidated Financial Statements and in Critical Accounting Estimates and Assumptions of this MD&A section.

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Off-Balance Sheet Arrangements

In the normal course of business, we are 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 consolidated balance sheets, and, except for the operating leases, which are discussed in Note 17 to the Notes to Consolidated Financial Statements, 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.

From time to time we use bank letters of credit to secure our obligations for workers’ compensation programs, various insurance contracts and other obligations. At December 31, 2010, we had $135.4 million of letters of credit outstanding of which $58.2 million was collateralized by $59.4 million of cash deposited in restricted, interest bearing accounts pledged to issuing banks and $77.2 million was issued under our asset based lending arrangement. No claims were outstanding against those letters of credit as of December 31, 2010.

We use surety bonds to secure reclamation, workers’ compensation, wage payments and other miscellaneous obligations. As of December 31, 2010, we had $373.5 million of outstanding surety bonds. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $352.4 million, and other miscellaneous obligation bonds of $21.1 million. These bonds are renewed annually. Outstanding surety bonds of $46.9 million are secured with letters of credit. 

Generally, the availability and market terms of surety bonds continue to be challenging. If we are unable to meet certain financial tests applicable to some of our surety bonds, if our debt ratings are reduced to certain levels, or to the extent that surety bonds otherwise become unavailable, we would need to replace the surety bonds or seek to secure them with letters of credit, cash deposits, or other suitable forms of collateral.

A downgrade in our debt ratings could adversely affect our borrowing capacity and costs, the costs of maintaining certain contractual relationships and future financings.

Certain Trends and Uncertainties

Our inability to satisfy contractual obligations may adversely affect profitability.

From time to time, we have disputes with customers over the provisions of sales agreements relating to, among other things, coal pricing, quality, quantity, delays and force majeure declarations. Our inability to satisfy contractual obligations could result in the purchase of coal from third-party sources to satisfy those obligations, the negotiation of settlements with customers, which may include price reductions, the reduction of commitments or the extension of the time for delivery, and customers terminating contracts, declining to do future business with us, or initiating claims against us. A few of our customers have notified us of losses they have allegedly incurred due to alleged shortfalls in contracted coal shipments. We believe that factors beyond our control or responsibility account for most or all of the shortfalls. However, we may not be able to resolve all of these disputes, or other disputes with customers over sales agreements, in a satisfactory manner, which could result in the payment of substantial damages or otherwise harm our reputation and our relationships with our customers (see Note 22 to the Notes to Consolidated Financial Statements for further discussion).

The global financial crisis may have an impact on our business, financial condition and liquidity in ways that we currently cannot predict.

The recent credit crisis and related turmoil in the global financial markets, which has begun to ease during the past year, has had and may continue to have an impact on our business, financial condition and liquidity.

The recent recession caused contraction in the availability of credit in the marketplace.  In addition to the impact that the global financial crisis has already had on us, we may face significant challenges if conditions in the financial markets do not continue to improve or worsen. In addition, our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access these markets, which could have an impact on our flexibility to react to changing economic and business conditions and could potentially reduce our sources of liquidity.  Moreover, volatility and disruption of financial markets could limit our customers’ ability to obtain adequate financing to maintain operations and result in a decrease in sales volume that could have a negative impact on our cash flows, results of operations or financial condition.

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Capital and credit market volatility may affect our costs of borrowing.

While we maintain business relationships with a diverse group of financial institutions, their continued viability is not certain. Difficulties at one or more such financial institutions could lead them not to honor their contractual credit commitments under our ABL Facility or to renew their extensions of credit or provide new sources of credit.  In recent years, the capital and credit markets have been highly volatile as a result of adverse conditions that have caused the failure and near failure of a number of large financial services companies.  If the capital and credit markets again experience volatility and the availability of funds becomes limited, we may incur increased costs associated with borrowings.  While we believe that governmental and regulatory scrutiny reduced the risk of further deterioration or contraction of capital and credit markets, there can be no certainty that our liquidity will not be negatively impacted by adverse conditions in the capital and credit markets.  

We may be adversely affected by a decline in the financial condition and creditworthiness of our customers.

In an effort to mitigate credit-related risks in all customer classifications, we maintain a credit policy, which requires scheduled reviews of customer creditworthiness and continuous monitoring of customer news events that might have an impact on their financial condition. Negative credit performance or other events may trigger the application of tighter terms of sale, requirements for collateral or guaranties or, ultimately, a suspension of credit privileges. The creditworthiness of customers can limit who we can do business with and at what price. For the year ended December 31, 2010, approximately 99% of coal sales volume was pursuant to long-term contracts. We anticipate that in 2011, the percentage of our sales pursuant to long-term contracts will be comparable with the percentage of our sales for 2010. For 2011, approximately 50% of our projected sales tons are contracted to be sold to our ten largest customers. Many of our customers, including many of our large customers, experienced lower demand and weaker financial performance due to the recent recession. If one or more of our larger customers fails to make payment for our sales to them, there could be an adverse effect on our cash flows, results of operations or financial condition.

We have contracts to supply coal to energy trading and brokering companies who resell the coal to the ultimate users. We are subject to being adversely affected by any decline in the financial condition and creditworthiness of these energy trading and brokering companies. In addition, as one of the largest suppliers of metallurgical coal to the United States steel industry and a significant exporter to foreign users, we are subject to being adversely affected by any decline in the financial condition or production volume of both United States and foreign steel producers.

We must obtain governmental permits and approvals for mining operations, which can be a costly and time-consuming process, can result in restrictions on our operations, and is subject to litigation that may delay or prevent us from obtaining necessary permits.

Our operations are principally regulated under surface mining permits issued pursuant to the Surface Mining Control and Reclamation Act and state counterpart laws. Such permits are issued for terms of five years with the right of successive renewal. Separately, the Clean Water Act requires permits for operations that discharge into waters of the United States. Valley fills and refuse impoundments are authorized under permits issued by the U.S. Army Corps of Engineers (the “Corps”). The EPA has the authority, which it has rarely exercised until recently, to object to permits issued by the Corps.  While the Corps is authorized to issue permits even when the EPA has objections, the EPA does have the ability to override the Corps decision and “veto” the permits. In September 2009, the EPA announced it had identified 79 pending permit applications for Appalachian surface coal mining, under a coordination process with the Corps and the United States Department of the Interior entered into in June 2009, that EPA believes warrant further review because of its continuing concerns about water quality and/or regulatory compliance issues.  These include five of our permit applications.  While the EPA has stated that its identification of these 79 permits does not constitute a determination that the mining involved cannot be permitted under the Clean Water Act and does not constitute a final recommendation from the EPA to the Corps on these projects, it is unclear how long the further review will take for our five permits or what the final outcome will be. It is also unclear what impact this process may have on our future applications for surface coal mining permits. A federal court ruled in January 2011 that the EPA’s new coordination process likely was unlawful, but the federal court has not issued a final ruling and the EPA has not changed its coordination process. Permitting under the Clean Water Act has been a frequent subject of litigation by environmental advocacy groups that has resulted in periodic delays in such permits issued by the Corps. Additionally, certain operations (particularly preparation plants) have permits issued pursuant to the Clean Air Act and state counterpart laws allowing and controlling the discharge of air pollutants. Regulatory authorities exercise considerable discretion in the timing of permit issuance. Requirements imposed by these authorities may be costly and time-consuming and may result in delays in, or in some instances preclude, the commencement or continuation of development or production operations. Adverse outcomes in lawsuits challenging permits or failure to comply with applicable regulations could result in the suspension, denial or revocation of required permits, which could have a material adverse impact on our cash flows, results of operations or financial condition. See also Note 22, “Contingencies – Surface Mining Fills” to the Notes to Consolidated Financial Statements.

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Further developments in connection with legislation, regulations or other limits on greenhouse gas emissions and other environmental impacts from coal combustion, both in the United States and in other countries where we sell coal, could have a material adverse effect on our cash flows, results of operations or financial condition.

Recent healthcare legislation could adversely affect our financial condition and results of operations.

In March 2010, the PPACA was enacted, potentially impacting our costs to provide healthcare benefits to our eligible active and certain retired employees, and our costs to provide workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (black lung disease).  Implementation of this legislation is planned to occur in phases over a number of years.

Required changes that affected us in the short term included raising the maximum age for covered dependents to receive benefits, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual, among other requirements.  Required changes that could affect us in the long term include a tax on “high cost” plans (excise tax) and the elimination of annual dollar limits per covered individual, among other requirements.

One provision of the legislation changes the tax treatment for Medicare drug subsidies.  Beginning in fiscal year 2014, the tax deduction available to us will be reduced to the extent our drug expenses are reimbursed under the Medicare Part D retiree drug subsidy program.  Because retiree health care liabilities and the related tax impacts are already reflected in our Consolidated Financial Statements, we were required to recognize the full accounting impact of this accounting standard update in the period in which the Act was signed into law.  The total non-cash charge to Income tax expense related to the reduction in the tax benefit was $2.6 million, recorded in the first quarter of 2010.

Significant uncertainties exist regarding the excise tax on high cost plans. Because of those uncertainties, calculation of a precise liability for this tax is impossible at this time. Based on our understanding of the law and regulations as they exist today, we have concluded that the tax will not impact our retiree medical plan liability.  We anticipate that future commentary and additional regulations will clarify many of the uncertainties which exist today.  We will continue to monitor the emerging regulations and will update our expectations on the effect to the retiree medical liability as necessary. The retiree medical plan has been deemed to be a retiree only plan, thus no plan changes related to Health Care Reform coverage enhancements were made for 2011. We continue to analyze this legislation to determine the full extent of the impact of the required changes on our employee healthcare plans and the resulting costs.

The PPACA also amended previous legislation related to coal workers’ pneumoconiosis (black lung), providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims.  In order to reflect the potential impact of the PPACA reforms, we have incorporated the following changes into the valuation of the black lung liabilities:

● Increased disability incidence rates for both active and terminated miners

● Increased approval rates for Federal claims in adjudication

● We assume that 100% of widows of deceased miners will file a successful death benefit claim

● We assume that a portion of previously closed claims will re-file and be awarded disability benefits

We are continuing to monitor the impact of these changes to our current population of beneficiaries and claimants and the effect on potential future claims.

Increased regulatory scrutiny subsequent to the tragedy at our UBB mine has had and may continue to have a negative impact on our business.

Subsequent to the April 5, 2010 UBB tragedy, MSHA has significantly increased regulatory scrutiny in our mines.  The increased regulatory scrutiny significantly impacted our productivity and operating results for the last three quarters of 2010.  If MSHA continues to order certain of our mines to be temporarily closed or permanently closes such mines, our ability to meet our customers’ demands could be adversely affected, which would adversely affect our financial position, results of operations and cash flows.

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We may be required to recognize additional charges in our financial results for losses related to the tragedy at our UBB mine.

As a result of the UBB tragedy on April 5, 2010, we have recognized a pre-tax charge of $166.5 million, which was reported as part of our financial earnings for 2010.  This charge relates to the benefits being provided to the families of the fallen miners, costs associated with the rescue and recovery efforts, an impairment charge for the write-off of equipment, mine development and longwall panel costs impacted by the tragedy, possible legal and other contingencies.  Given the uncertainty of the outcome of current investigations, including whether we become subject to possible civil penalties or enforcement actions, it is possible that the total costs incurred related to this tragedy could exceed our current estimates.  We continue to evaluate the impact of this event on our business, and these reviews may result in future additional charges and costs, which would adversely affect our financial position, results of operations and cash flows.

Federal, state and local laws and government regulations applicable to mining operations may increase our costs.

We incur substantial costs and liabilities under increasingly strict federal, state and local environmental, health and safety and endangered species laws, regulations and enforcement policies.  Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens, the issuance of injunctions to limit or cease operations, the suspension or revocation of permits and other enforcement measures that could have the effect of limiting production from our operations.  In this regard, MSHA and the State of West Virginia are conducting a joint investigation into the cause of the April 5, 2010 accident at our UBB mine at our Performance resource group in West Virginia.  The costs of compliance with applicable regulations and liabilities assessed for compliance failure could have a material adverse impact on our cash flows, results of operations or financial condition.

New legislation and new regulations, including legislation and regulations resulting from the April 5, 2010 accident at our UBB mine, may be adopted which could materially adversely affect our mining operations, cost structure or our customers’ ability to use coal.  New legislation and new regulations may also require us, as well as our customers, to significantly change operations or incur increased costs.  The EPA has undertaken broad initiatives to increase compliance with emissions standards and to provide incentives to our customers to decrease their emissions, often by switching to an alternative fuel source or by installing scrubbers or other expensive emissions reduction equipment at their coal-fired plants.

Critical Accounting Estimates and Assumptions

The preparation of financial statements in conformity with GAAP 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 could introduce substantial volatility to our costs. The following critical accounting estimates and assumptions were used in the preparation of the financial statements:

Business Combinations

We account for our business combinations under the acquisition method of accounting.  The total cost of acquisitions is allocated to the underlying identifiable net tangible and intangible assets based on their respective estimated fair values.  Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, with assistance of third party valuation services, and often involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the net identifiable tangible and intangible assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually or more frequently if indicators of impairment exist. As a result of the Cumberland Acquisition, we recorded Goodwill in our Consolidated Balance Sheet. We determined that the goodwill generated from the acquisition was directly attributable to the operating efficiencies at the Cumberland entities. Therefore, the goodwill was allocated entirely to the Cumberland reporting unit.

On an ongoing basis, absent any impairment indicators, we perform goodwill impairment testing as of October 1 of each year. We test consolidated goodwill for impairment using a fair value approach at the reporting unit level, and perform the goodwill impairment test in two steps.  Step one compares the fair value of the reporting unit to its carrying amount. If step one indicates that an impairment potentially exists, the second step is performed to measure the amount of impairment, if any. Goodwill impairment exists when the estimated fair value of goodwill is less than its carrying value.

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For purposes of the step one analysis, an estimate of fair value for the reporting unit is derived from a combination of the income approach and the market approach.  Under the income approach, the fair value of each reporting unit is based on the present value of estimated future cash flows. The income approach is dependent on a number of significant management assumptions including markets, sales volumes and prices, costs to produce, capital spending, working capital changes and the discount rate. The discount rate is commensurate with the risk inherent in the projected cash flows and reflects the rate of return required by an investor in the current economic conditions.  Under the market approach, estimates of prices reasonably expected to be realized from the sale of the reporting unit are used to determine the fair value of the reporting unit.

For purposes of the step two analysis, an estimate of the fair value of goodwill is derived using the same methodology for determining goodwill recognized in a business combination (i.e., the fair value of the reporting unit is allocated to all the assets and liabilities, including any unrecognized intangible assets, as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid to acquire the reporting unit, with the residual then recorded as goodwill).

Our annual goodwill impairment review performed on October 1, 2010 for the $36.7 million of goodwill recorded in our Consolidated Balance Sheet indicated the fair value of the reporting unit exceeded its carrying value.

Insurance Recoveries

Insurance recoveries that are deemed to be probable and reasonably estimable are recognized to the extent of the related loss.  Insurance recoveries which result in gains, including recoveries under business interruption coverage, are recognized only when realized by settlement with the insurers.  The evaluation of insurance recoveries requires estimates and judgments about future results which affect reported amounts and certain disclosures. Actual results could differ from those estimates.

Defined Benefit Pension Plans

The estimated cost and benefits of non-contributory defined benefit pension plans are determined by independent actuaries, who, with management’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, forecasted cash flows were discounted using each year’s associated spot interest rate on high quality fixed income investments.  At December 31, 2010 and 2009, the discount rate used to determine defined benefit pension liability was 5.50% and 6.00%, respectively.  The impact of lowering the discount rate 0.25% for 2010 would have increased the 2010 net periodic pension expense by approximately $2.3 million.  The rate of increase in compensation levels is determined based upon our long-term plans for such increases.  The rate of increase in compensation levels used was 3.0% for the years ended December 31, 2010 and 2009.  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.  During 2009, we made a temporary shift in our pension investments’ targeted asset allocation in response to the volatility and uncertainty in the financial markets.  We invested a large percentage of plan assets in debt securities with a fixed duration with the intent to return to the long-term targeted asset allocation upon maturity of the fixed duration investments.  As we plan to return to our targeted asset allocation, we believe the expected long-term rate of return on plan assets of 8.0% continues to be appropriate.  The expected long-term rate of return on plan assets used to determine expense in each period was 8.0% for both of the years ended December 31, 2010 and 2009.  A 0.5% decrease in the expected long-term rate of return assumption would have increased the 2010 net periodic pension expense by approximately $1.3 million.  The actuarial assumptions we use may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants.  While we believe that the assumptions used are appropriate, differences in actual experience or changes in assumptions might materially affect our financial position or results of operations.  See Note 9 to the Notes to Consolidated Financial Statements for further discussion on our pension plans. 

Coal Workers’ Pneumoconiosis

We are responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, and various states’ statutes, for the payment of medical and disability benefits to eligible recipients resulting from occurrences of coal workers’ pneumoconiosis disease (black lung).  An annual evaluation is prepared by independent actuaries, who, after review and approval by management, use various assumptions regarding disability incidence, medical costs trend, cost of living trend, mortality, death benefits, dependents and interest rates.  We record expense related to this obligation using the service cost method. At December 31, 2010 and 2009, the discount rate used to determine the black lung liability was 5.50% and 6.00%, respectively. In addition, the PPACA amended previous legislation related to black lung, providing automatic extensions of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims including previously closed claims.  The impact of these changes to our current population of beneficiaries and claimants resulted in an estimated $11.3 million increase to our black lung obligation at December 31, 2010.  We will continue to evaluate the impact of these changes to our current population of beneficiaries and claimants and the effect on potential future claims. Included in Note 15 to the Notes to Consolidated Financial Statements is a medical cost trend and cost of living trend sensitivity analysis.

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Workers’ Compensation and Supplemental Benefits

Our operations have workers’ compensation coverage through a combination of either self-insurance, participation in a state run program, or commercial insurance. We accrue for the self-insured liability by recognizing cost when it is probable that the liability has been incurred and the cost can be reasonably estimated. The workers’ compensation benefits offered in response to the UBB tragedy were measured and are being paid from our existing plan. In addition to workers’ compensation, we offered certain supplemental benefits to the families of the fallen miners. To assist in the determination of these estimated liabilities, we utilize the services of third-party administrators who derive claim reserves from historical experience. These third-party administrators provide information to independent actuaries, who after review and consultation with management with regards to actuarial assumptions, including discount rate, prepare an evaluation of the self-insured liabilities. Actual experience in settling these liabilities could differ from these estimates, which could increase our costs. See Note 15 to the Notes to Consolidated Financial Statements for further discussion on workers’ compensation and supplemental benefits. At December 31, 2010 and 2009, the discount rate used to determine the self-insured workers’ compensation liability obligation was 4.50% and 4.75%, respectively.  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 our costs. See Note 15 to the Notes to Consolidated Financial Statements for further discussion on workers’ compensation.

Other Postretirement Benefits

Our 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.  We pay costs as incurred by participants.  The estimated cost and benefits of the retiree health care plans are determined by independent actuaries, who, after review and approval by management, use various actuarial assumptions, including discount rate, expected trend in health care costs and per capita claims costs.  At December 31, 2010 and 2009, the discount rate used to determine the other postretirement benefit liability was 5.50% and 6.00%, respectively.  The impact of lowering the discount rate 0.25% for 2010 would have increased the 2010 net periodic postretirement benefit cost by approximately $0.4 million.  At December 31, 2010, assumptions of our health care plans’ cost trend were projected at annual rates of 8.1% for pre-Medicare claims, 8.3% for Medicare-eligible claims and 7.0% for Medicare supplemental plans, all ranging down to 4.5% by 2029 and remaining level thereafter.  The impact of increasing the health care cost trend rate by 1.0% would have increased the 2010 net periodic postretirement benefit cost by approximately $1.5 million.  Included in Note 14 to the Notes to 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.  Total reclamation and mine-closing liabilities are based upon permit requirements and engineering estimates related to these requirements.  GAAP 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.  Management and engineers periodically review the estimate of ultimate reclamation liability and the expected period in which reclamation work will be performed.  In estimating future cash flows, we considered the estimated current cost of reclamation and applied inflation rates and a third-party profit, as necessary.  The third-party profit is an estimate of the approximate markup that would be charged by contractors for work performed on our behalf.  The discount rate applied is based on the rates of treasury bonds with maturities similar to the estimated future cash flow, adjusted for our credit standing.  The estimated liability can change significantly if actual costs vary from assumptions or if governmental regulations change significantly.

Contingencies

We are parties to a number of legal proceedings, incident to our normal business activities.  These matters include contract disputes, personal injury claims, property damage claims, environmental issues and employment and safety matters.  While we cannot predict the outcome of these proceedings, based on our current estimates, we do not believe that any liability arising from these matters individually or in the aggregate should have a material impact upon our consolidated cash flows, results of operations or financial condition.  However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims, in the aggregate, may be material to our cash flows, results of operations or financial condition.  See Item 3. Legal Proceedings and Note 22 to the Notes to Consolidated Financial Statements for further discussion on our contingencies.

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Income Taxes

Deferred tax assets and liabilities are recognized using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities.  Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized.  In evaluating the need for a valuation allowance, we take into account various factors, including tax attribute carrybacks, the future reversals of existing taxable temporary differences, the expected level of future taxable income and available tax planning strategies. If actual results differ from the assumptions made in the evaluation of our valuation allowance, we record a change in valuation allowance through income tax expense in the period such determination is made.

We are required to establish reserves based upon management’s assessment of exposure associated with tax positions taken relative to temporary and permanent tax differences and tax credits, plus penalties and interest, if any, on the accrued uncertain tax positions.  The tax reserves are analyzed periodically and adjustments are made as events occur to warrant adjustment to the reserves. Management believes that we have adequately provided for any income taxes that may ultimately be paid with respect to all open tax years.

 Coal Reserve Values

There are numerous uncertainties inherent in estimating quantities and values of economically recoverable coal reserves.  Many of these uncertainties are beyond our control.  As a result, estimates of economically recoverable coal reserves are by their nature uncertain.  Information about our reserves consists of estimates based on engineering, economic and geological data assembled and analyzed by our internal engineers, geologists and financial associates.  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.  Variances would affect both the Consolidated Statements of Income, in the form of revenue and expenditures, as well as the Consolidated Balance Sheets, in the form of valuation of coal reserves, depletion rates and potential impairment.

Derivative Instruments

Upon entering into each coal sales and coal purchase contract, we evaluate each of our contracts to determine if it qualifies for the normal purchase normal sale (“NPNS”) exception prescribed by current accounting guidance.  We use coal purchase contracts to supplement our produced and processed coal in order to provide coal to meet customer requirements under sales contracts.  We are exposed to certain risks related to coal price volatility.  The purchases and sales contracts we enter into allow us to mitigate a portion of the underlying risk associated with coal price volatility.  The majority of our contracts qualify for the NPNS exception and therefore are not accounted for at fair value.  For those contracts that do not qualify for the NPNS exception at inception or lose their designation at some point during the duration of the contract, the contracts are required to be accounted for as derivative instruments and must be recognized as assets or liabilities and measured at fair value.  Those contracts that do not qualify for the NPNS exception have not been designated as cash flow or fair value hedges and, accordingly, the net change in fair value is recorded in current period earnings.  Our coal sales and coal purchase contracts that do not qualify for the NPNS exception as prescribed by current accounting guidance are offset on a counterparty-by-counterparty basis for derivative instruments executed with the same counterparty under a master netting arrangement.

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In evaluating our contracts for the NPNS exception at inception, we consider many factors, including management’s intent and ability to physically deliver or take physical delivery of the coal, as well as the counterparty’s intent and ability to physically accept or deliver coal.  These factors may change over the duration of a contract, due to, for example, the counterparty’s inability to physically accept or deliver coal or to our decision to net settle a portion or all of a forward contract by entering into an offsetting contract.  These facts and circumstances may cause a contract to no longer qualify for the NPNS exception.  If a contract originally evaluated as qualifying for the NPNS exception no longer qualifies, it is prospectively accounted for as a derivative instrument and recognized as an asset or liability and measured at fair value.  To the extent there is an increase in the number of contracts that do not qualify for the NPNS exception, it could have a significant impact on our results of operations or financial condition.  See Note 19 to the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.

Recent Accounting Pronouncements

Refer to Note 1 in the Notes to Consolidated Financial Statements for information concerning the effect of recent accounting pronouncements.

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Item 7A. Quantitative and Qualitative Discussions about Market Risk

Our net interest expense is currently not sensitive to changes in the general level of short-term interest rates. At December 31, 2010, all of the outstanding $1,316.2 million of our debt was under fixed-rate instruments.  However, if it should become necessary to borrow under our ABL Facility, those borrowings would be made at a variable rate.  Interest income is sensitive to changes in short-term interest rates.

In 2010, we primarily managed market price risk for coal through the use of long-term coal supply agreements, which are contracts with a term of one year or more in duration, rather than through the use of derivative instruments.  We estimate that the percentage of tons sold pursuant to these long-term contracts was 99% for our fiscal year ended December 31, 2010.  We anticipate that in 2011, the percentage of our tons sold pursuant to long-term contracts will be comparable with the percentage of our sales for 2010. 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 our sales that are subject to these long-term agreements, we have less coal available with which to capitalize on stronger coal prices if and when they arise.  In addition, because long-term contracts may allow the customer to elect volume flexibility based on requirements, our ability to realize the higher prices that may be available in the spot market may be restricted when customers elect to purchase higher volumes under such contracts, or our exposure to market-based pricing may be increased should customers elect to purchase fewer tons.

From time to time we may also purchase coal directly from third parties to supplement our produced and processed coal in order to provide coal to meet customer requirements under sales contracts.  Certain of our purchase and sale contracts do not qualify for the NPNS exception and are accordingly measured at fair value in current period earnings.  The use of purchase and sales contracts which do not qualify for the NPNS exception could materially affect our results of operations as a result of the requirement to mark them to market at the end of each reporting period.

These transactions give rise to commodity price risk, which represents the potential gain or loss that can be caused by an adverse change in the price of coal.  Outstanding purchase and sales contracts at December 31, 2010, that do not qualify for the NPNS exception are summarized as follows:

	Price Range		Tons Outstanding		Delivery Period
Purchase Contracts		$66.00		360,000	1/1/2011 - 12/31/2011
Sales Contracts		$64.35-$105.00		600,000	1/1/2011 - 12/31/2011

As of December 31, 2010, a hypothetical increase of 10% in the forward market price would result in an additional fair value loss recorded for these derivative instruments of $1.9 million.  A hypothetical decrease of 10% in the forward market price would result in a reduction in the fair value loss recorded for these derivative instruments of $1.9 million.

74

Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2010 and 2009, and the related consolidated statements of income, shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2010. 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, 2010 and 2009, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.  Also, in our opinion, the related 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.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Massey Energy Company’s internal control over financial reporting as of December 31, 2010, 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 1, 2011 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Richmond, Virginia

March 1, 2011

75

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENTS OF INCOME

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2010			2009			2008
Revenues	$	2,609,659		$	2,318,489		$	2,559,929
Produced coal revenue		252,409			218,203			306,397
Freight and handling revenue		91,566			62,721			30,684
Purchased coal revenue		85,340			91,746			92,779
Other revenue		3,038,974			2,691,159			2,989,789
Total revenues
Costs and expenses
Cost of produced coal revenue		2,332,851			1,850,058			1,910,953
Freight and handling costs		252,409			218,203			306,397
Cost of purchased coal revenue		86,127			57,108			28,517
Depreciation, depletion and amortization, applicable to:
Cost of produced coal revenue		363,748			268,317			253,737
Selling, general and administrative		41,814			1,860			3,590
Selling, general and administrative		113,340			97,381			77,015
Other expense		8,072			8,705			3,207
Litigation charge		—			—			250,061
Loss on financing transactions		—			189			5,006
(Gain) loss on derivative instruments		(21,078	)		(37,638	)		22,552
Total costs and expenses		3,177,283			2,464,183			2,861,035
(Loss) Income before interest and taxes		(138,309	)		226,976			128,754
Interest income		2,293			12,583			23,576
Interest expense		(102,243	)		(102,294	)		(96,866	)
Gain (loss) on short-term investment		4,662			—			(6,537	)
(Loss) Income before taxes		(233,597	)		137,265			48,927
Income tax benefit (expense)		67,010			(32,832	)		(1,098	)
Net (loss) income	$	(166,587	)	$	104,433		$	47,829
Net (loss) income per share
Basic	$	(1.71	)	$	1.23		$	0.58
Diluted	$	(1.71	)	$	1.22		$	0.58
Shares used to calculate net (loss) income per share
Basic		97,545			84,992			81,816
Diluted		97,545			85,598			82,895

See Notes to Consolidated Financial Statements

76

MASSEY ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)

	December 31,			December 31,
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	327,179		$	665,762
Short-term investment		—			10,864
Trade and other accounts receivable, less allowance of $906 and $1,303, respectively		296,770			121,577
Inventories		289,027			269,826
Income taxes receivable		10,912			10,546
Other current assets		193,176			235,990
Total current assets		1,117,064			1,314,565
Property, plant and equipment, net		3,217,685			2,344,770
Intangible assets, net		120,923			—
Goodwill		36,707			—
Other noncurrent assets		118,603			140,336
Total assets	$	4,610,982		$	3,799,671
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Accounts payable, principally trade and bank overdrafts	$	245,312		$	164,979
Short-term debt		12,327			23,531
Payroll and employee benefits		95,446			63,590
Other current liabilities		309,980			192,835
Total current liabilities		663,065			444,935
Noncurrent liabilities
Long-term debt		1,303,852			1,295,555
Deferred income taxes		163,383			209,230
Pension obligation		79,721			55,610
Other noncurrent liabilities		620,499			538,058
Total noncurrent liabilities		2,167,455			2,098,453
Total liabilities		2,830,520			2,543,388
Shareholders’ Equity
Capital stock
Preferred – authorized 20,000,000 shares without par value; none issued		—			—
Common – authorized 300,000,000 shares and 150,000,000 shares, respectively of $0.625 par value; issued 102,496,160 and 86,213,582 shares, respectively		64,561			53,868
Treasury stock, 861,439 shares at cost		(31,822	)		—
Additional capital		1,343,966			568,995
Retained earnings		526,025			716,089
Accumulated other comprehensive loss		(122,268	)		(82,669	)
Total shareholders’ equity		1,780,462			1,256,283
Total liabilities and shareholders’ equity	$	4,610,982		$	3,799,671

See Notes to Consolidated Financial Statements

77

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2010			2009			2008
Cash Flows from Operating Activities	$	(166,587	)	$	104,433		$	47,829
Net (loss) income
Adjustments to reconcile Net income to Cash provided by operating activities:
Depreciation, depletion and amortization		321,477			270,177			257,327
Impairment of Upper Big Branch assets		63,577			—			—
Impairment of unamortized development costs		20,623			—			—
Bond discount amortization		20,508			19,054			8,028
Share-based compensation expense		11,099			12,747			13,856
Deferred income taxes		(65,753	)		18,407			5,573
Gain on disposal of assets		(3,808	)		(15,984	)		(2,926	)
Gain on reserve exchanges		(6,879	)		(26,537	)		(32,449	)
Reserve on note receivable		4,953			6,000			—
Loss on financing transactions		—			369			11,431
Gain on insurance recovery		(11,180	)		—			—
Net unrealized losses (gains) in derivative instruments		15,140			(53,116	)		22,552
(Gain) loss on short-term investment		(4,662	)		—			6,537
Accretion of asset retirement obligations		17,358			13,991			11,844
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(126,772	)		100,020			(77,953	)
Increase in inventories		(7,259	)		(36,658	)		(49,808	)
(Increase) decrease in income taxes receivable		(1,387	)		(2,350	)		10,048
Decrease (increase) in other current assets		22,382			(67,075	)		49,079
Increase in other assets		(4,976	)		(1,589	)		(9,621	)
Increase (decrease) in accounts payable		55,549			(79,222	)		95,995
Increase in other accrued liabilities		115,999			9,882			21,189
Increase in pension obligation		2,108			10,796			1,625
Increase (decrease) in other noncurrent liabilities		2,723			10,916			(118	)
Asset retirement obligation payments		(6,324	)		(5,352	)		(4,957	)
Cash provided by operating activities		267,909			288,909			385,081
Cash Flows from Investing Activities
Capital expenditures		(434,855	)		(274,552	)		(736,529	)
Purchase of acquired company, net of cash acquired		(629,977	)		—			—
Redesignation of cash equivalent to short-term investment		—			—			(217,900	)
Proceeds from redemption of short-term investment		15,526			28,519			171,980
Proceeds from sale of assets		4,550			19,010			5,958
Proceeds from insurance recovery related to loss on Bandmill plant		15,561			15,395			—
Cash utilized by investing activities		(1,029,195	)		(211,628	)		(776,491	)
Cash Flows from Financing Activities
Issuance of common stock		466,707			—			258,188
Repurchases of common stock		(31,822	)		—			—
Repayments of capital lease obligations		(1,581	)		(2,584	)		(1,911	)
Proceeds from issuance of 3.25% convertible senior notes		—			—			674,136
Repurchase of 3.25% convertible senior notes		—			(9,982	)		(10,450	)
Repayment for 6.625% senior notes		(21,949	)		—			(322,139	)
Redemption of 4.75% convertible senior notes		—			(70	)		—
Proceeds from sale-leaseback transactions		16,477			—			41,318
Cash dividends paid		(23,477	)		(20,421	)		(21,310	)
Proceeds from stock options exercised		18,348			11,306			16,519
Excess income tax benefit (expense) from stock option exercises		—			3,235			(1,164	)
Cash provided (utilized) by financing activities		422,703			(18,516	)		633,187
(Decrease) increase in cash and cash equivalents		(338,583	)		58,765			241,777
Cash and cash equivalents at beginning of period		665,762			606,997			365,220
Cash and cash equivalents at end of period	$	327,179		$	665,762		$	606,997
Supplemental Cash Flow Information
Cash paid during the period for income taxes	$	129		$	13,539		$	4,219

See Notes to Consolidated Financial Statements.

78

MASSEY ENERGY COMPANY

CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY

(In Thousands, Except Per Share Amounts)

												Accumulated
												Other						Total
	Common Stock					Additional			Retained			Comprehensive			Treasury			Shareholders’
	Shares			Amount		Capital			Earnings			(Loss)			Stock			Equity
Balance at December 31, 2007		79,944		$	51,743	$	237,684		$	601,587		$	(27,024	)	$	(79,986	)	$	784,004
Net income										47,829									47,829
Other comprehensive (loss):
Pension and postretirement plans, net of deferred tax of $47,528													(74,338	)					(74,338	)
Comprehensive (loss) income																			(26,509	)
Adoption of accounting standards:
Equity component of 3.25% convertible senior notes							98,397												98,397
Dividends declared ($0.21 per share)										(17,339	)								(17,339	)
Stock option expense							8,204												8,204
Exercise of stock options		787			492		16,027												16,519
Stock option tax expense							(1,164	)											(1,164	)
Restricted stock		300			185		5,467												5,652
Issuance of stock for debt conversion		34			21		639												660
Issuance of additional common shares		4,370			937		177,265									79,986			258,188
Balance at December 31, 2008		85,435		$	53,378	$	542,519		$	632,077		$	(101,362	)	$	—		$	1,126,612
Net income										104,433									104,433
Other comprehensive income:
Pension and postretirement plans, net of deferred tax of ($9,105)													18,693						18,693
Comprehensive income (loss)																			123,126
Dividends declared ($0.24 per share)										(20,421	)								(20,421	)
Stock option expense							6,197												6,197
Exercise of stock options		515			321		10,985												11,306
Stock option tax benefit							3,235												3,235
Restricted stock		262			169		6,381												6,550
Equity component of 3.25% convertible senior notes							(322	)											(322	)
Balance at December 31, 2009		86,212		$	53,868	$	568,995		$	716,089		$	(82,669	)	$	—		$	1,256,283
Net (loss)										(166,587	)								(166,587	)
Other comprehensive (loss):
Pension and postretirement plans, net of deferred tax of $15,444													(39,599	)					(39,599	)
Comprehensive (loss) income																			(206,186	)
Dividends declared ($0.24 per share)										(23,477	)								(23,477	)
Stock option expense							3,622												3,622
Exercise of stock options		719			451		17,897												18,348
Restricted stock		132			59		7,418												7,477
Share repurchase		(861	)													(31,822	)		(31,822	)
Issuance of additional common shares		16,294			10,183		746,034												756,217
Balance at December 31, 2010		102,496		$	64,561	$	1,343,966		$	526,025		$	(122,268	)	$	(31,822	)	$	1,780,462

See Notes to Consolidated Financial Statements.

79

1. Significant Accounting Policies

Basis of Presentation

The accompanying consolidated financial statements include the accounts of Massey Energy Company (“we”, “our”, or “us”), our wholly-owned and majority-owned direct and indirect subsidiaries.  Inter-company transactions and accounts are eliminated in consolidation.  We have no independent assets or operations.  We do not have a controlling interest in any separate independent operations.  Investments in business entities in which we do not have control, but have the ability to exercise significant influence over the operating and financial policies, are accounted for under the equity method.

All of our direct and substantially all of our indirect operating subsidiaries, each such subsidiary being indirectly 100% owned by us, fully and unconditionally, jointly and severally, guarantee our obligations under the 6.875% senior notes due 2013 (“6.875% Notes”), the 3.25% convertible senior notes due 2015 (“3.25% Notes”) and the 2.25% convertible senior notes due 2024 (“2.25% Notes”).  The subsidiaries not providing a guarantee of the 6.875% Notes, the 3.25% Notes and the 2.25% Notes are minor (as defined under Securities and Exchange Commission (“SEC”) Rule 3-10(h)(6) of Regulation S-X).  See Note 10 to the Notes to Consolidated Financial Statements for a more complete discussion of debt.

We have evaluated subsequent events through the date the Consolidated Financial Statements were issued. See Note 24 for more information.

Use of Estimates

The preparation of the financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported amounts.  These estimates 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 impairments of property, plant and equipment, defined benefit pension plans, coal workers’ pneumoconiosis (“black lung”), workers’ compensation and supplemental compensation benefits, other postretirement benefits, reclamation and mine closure obligations, contingencies and related insurance recoveries, income taxes, coal reserve estimates, stock options and derivative instruments.

Fair Value Measurements

We adopted new accounting guidance on January 1, 2008 and 2009, for financial and non-financial assets and liabilities, respectively, that requires their categorization based upon three levels of judgment associated with the inputs used to measure their fair value.  Neither adoption had a material impact on our financial position or results of operations.  See Note 20 to the Notes to Consolidated Financial Statements for more information.

In January 2010, the Financial Accounting Standards Board (the “FASB”) issued an accounting standard update, amending disclosure requirements related to Fair Value Measurements and Disclosures, as follows:

1. Significant transfers between Level 1 and 2 shall be disclosed separately, including the reasons for the transfers; and

2. Information about purchases, sales, issuances and settlements shall be disclosed separately in the reconciliation of activity in Level 3 fair value measurements.

This accounting standard update is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the reconciliation of activity in Level 3 fair value measurements, which are effective for interim and annual reporting periods beginning after December 15, 2010. The initial adoption of this accounting standard update did not have a material impact on our financial position or results of operations and the adoption for disclosures effective for interim and annual reporting periods beginning after December 15, 2010 is not expected to have a material impact on our cash flows, financial position or results of operations.  See Note 20 to the Notes to Consolidated Financial Statements for more information on our Fair Value Measurements and Disclosures.

Revenue Recognition

Produced coal revenue is realized and earned when title passes to the customer.  Coal sales are made to our customers under the terms of coal supply agreements, most of which are long-term (one year or greater).  Under the typical terms of these coal supply agreements, title and risk of loss transfer to the customer at the mine, dock, or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source(s) that serves each of our mines.  We incur certain “add-on” taxes and fees on coal sales.  Coal sales reported in Produced coal revenues include these “add-on” taxes and fees charged by various federal and state governmental bodies.

80

Freight and handling revenue consists of shipping and handling costs invoiced to coal customers and paid to third-party carriers. These revenues are directly offset by Freight and handling costs.

Purchased coal revenue represents revenue recognized from the sale of coal purchased from third-party production sources.  We take title to the purchased coal, which we then resell to our customers.  Typically, title and risk of loss transfer to the customer at the mine, dock or port, where coal is loaded to the rail, barge, ocean-going vessel, truck or other transportation source(s).

Other revenue includes refunds on railroad agreements, royalties related to coal lease agreements, gas well revenue, gains on the sale of non-strategic assets and reserve exchanges, joint venture revenue and other miscellaneous revenue.  Royalty income generally results from the lease or sublease of mineral rights to third parties, with payments based upon a percentage of the selling price or an amount per ton of coal produced.  Certain agreements require minimum lease payments regardless of the extent to which minerals are produced from the leasehold.  The terms of these agreements generally range from specified periods of 5 to 10 years, or can be for an unspecified period until all reserves are depleted.

Derivative Instruments

Our coal sales and coal purchase contracts that do not qualify for the normal purchase normal sale (“NPNS”) exception as prescribed by current accounting guidance are offset on a counterparty-by-counterparty basis for derivative instruments executed with the same counterparty under a master netting arrangement.

Cash and Cash Equivalents

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

Short-Term Investment

Short-term investment at December 31, 2009 was comprised of an investment in The Reserve Primary Fund (“Primary Fund”), a money market fund that suspended redemptions in September 2008 and was subsequently liquidated.  Upon suspension of redemptions, we determined that our investment in the Primary Fund did not meet the definition of a security, within the scope of current accounting guidance, since the equity investment no longer had a readily determinable fair value.  Therefore, the investment was classified as a short-term investment, subject to the cost method of accounting, on our Consolidated Balance Sheets.

Trade Receivables

Trade accounts receivable are recorded at the invoiced amount and are non-interest bearing.  We maintain a bad debt reserve based upon the expected collectability of our 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, 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.

81

Surface mine stripping costs

We account for the costs of removing overburden and waste materials (stripping costs) at surface mines differently, depending upon whether the costs are incurred prior to producing coal (pre-production) versus after a more than de minimis amount of shippable product is produced (post-production).  Production-related stripping costs are only included as a component of inventory if they are associated with extracted or saleable inventories.  Pre-production stripping costs are capitalized in mine development and amortized over the life of the developed pit consistent with coal industry practices.  Post-production stripping costs are expensed as incurred and recorded as Cost of produced coal revenue.

Pre-production stripping costs – At existing surface operations, additional pits may be added to increase production capacity in order to meet customer requirements.  These expansions may require significant capital to purchase additional equipment, expand the workforce, build or improve existing haul roads and create the initial pre-production box cut to remove overburden (i.e. advance stripping costs) for new pits at existing operations.  If these pits operate in a separate and distinct area of the mine, the costs associated with initially uncovering coal (i.e. advance stripping costs incurred for the initial box cuts) for production are capitalized in mine development and amortized over the life of the developed pit consistent with coal industry practices.

Post-production stripping costs – Where new pits are routinely developed as part of a contiguous mining sequence, we expense such costs as incurred.  The development of a contiguous pit typically reflects the planned progression of an existing pit, thus maintaining production levels from the same mining area utilizing the same employee group and equipment.

Income Taxes

We account for income taxes under the liability method, 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.  It also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, we take into account various factors, including carrybacks, the expected level of future taxable income and available tax planning strategies.  If actual results differ from the assumptions made in the evaluation of our valuation allowance, we record a change in valuation allowance through income tax expense in the period such determination is made.

A tax position is initially recognized in the financial statements when it is more likely than not the position will be sustained upon examination by applicable taxing authorities. Such tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with the taxing authority assuming full knowledge of the position and all relevant facts.  We accrue interest and penalties, if any, related to unrecognized tax benefits in Other noncurrent liabilities and recognize the related expense in Income tax expense.

Property, Plant and Equipment

Property, plant and equipment are carried at cost and stated net of accumulated depreciation.  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.  Costs incurred to maintain current production capacity at a mine and exploration expenditures are charged to operating costs as incurred, including costs related to drilling and study costs incurred to convert or upgrade mineral resources to reserves.  Development costs, including pre-production stripping costs, applicable to the opening of new coal mines and certain mine expansion projects are capitalized until production begins.  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 Other revenue.

Our 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 five to fifty 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.

82

Depreciation of buildings, plants and equipment is calculated on the straight-line method over their estimated useful lives or lease terms as follows:

	Years
Buildings and plants	20 to 30
Equipment	3 to 20
Capital leases	4 to 7

Ownership of assets under capital leases transfers to us at the end of the lease term.  Depreciation 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 adjusted for recoverability factors). As of December 31, 2010, approximately $227.7 million of costs associated with mining properties owned in fee and leased mineral rights are not currently subject to depletion as mining has not begun or production has been temporarily idled on the associated coal reserves.

We capitalize certain costs incurred in the development of internal-use software, including external direct material and service costs.  All costs capitalized are amortized using the straight-line method over the estimated useful life not to exceed 7 years.

Acquired Coal Sales Contracts, Transportation Contracts, and Mining Permits

Application of business combination accounting in connection with the acquisition of Cumberland Resources Corporation and certain affiliated entities ("Cumberland") resulted in the recognition of a significant asset for above market-priced coal sales contacts, transportation contracts, and mining permits on the date of the acquisition. Our coal sales contracts and transportation contracts are amortized based on the actual amount of tons shipped under each contract.  Mining permits are amortized using the units-of-production method over the estimated proven and probable reserve tons. These assets are recorded under the caption Intangible assets, net in the Consolidated Balance Sheets and the amortization expense is reflected under the caption Depreciation, depletion and amortization in the Consolidated Statements of Income.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the net identifiable tangible and intangible assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually or more frequently if indicators of impairment exist. As a result of the Cumberland Acquisition, we recorded Goodwill in our Consolidated Balance Sheet. We determined that the goodwill generated from the acquisition was directly attributable to the operating efficiencies at the Cumberland entities. Therefore, the goodwill was allocated entirely to the Cumberland reporting unit.

On an ongoing basis, absent any impairment indicators, we perform goodwill impairment testing as of October 1 of each year. We test consolidated goodwill for impairment using a fair value approach at the reporting unit level, and perform the goodwill impairment test in two steps.  Step one compares the fair value of the reporting unit to its carrying amount. If step one indicates that an impairment potentially exists, the second step is performed to measure the amount of impairment, if any. Goodwill impairment exists when the estimated fair value of goodwill is less than its carrying value.

For purposes of the step one analysis, an estimate of fair value for the reporting unit is derived from a combination of the income approach and the market approach.  Under the income approach, the fair value of each reporting unit is based on the present value of estimated future cash flows. The income approach is dependent on a number of significant management assumptions including markets, sales volumes and prices, costs to produce, capital spending, working capital changes and the discount rate. The discount rate is commensurate with the risk inherent in the projected cash flows and reflects the rate of return required by an investor in the current economic conditions.  Under the market approach, estimates of prices reasonably expected to be realized from the sale of the reporting unit are used to determine the fair value of the reporting unit.

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For purposes of the step two analysis, an estimate of the fair value of goodwill is derived using the same methodology for determining goodwill recognized in a business combination (i.e., the fair value of the reporting unit is allocated to all the assets and liabilities, including any unrecognized intangible assets, as if the reporting unit had been acquired in a business combination and the fair value of the reporting unit was the purchase price paid to acquire the reporting unit, with the residual then recorded as goodwill).

Our annual goodwill impairment review performed on October 1, 2010 for the $36.7 million of goodwill recorded in our Consolidated Balance Sheet indicated the fair value of the reporting unit exceeded its carrying value.

Asset Impairment and Disposal of Long-Lived Assets

Long-lived assets, such as property, equipment, mine development costs, owned and leased mineral rights longwall panel costs and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to its estimated fair value.  The fair value is determined using the estimated undiscounted cash flows expected to be generated by the assets along with, where appropriate, market inputs.  The determination of fair value requires the use of significant judgment and estimates about assumptions that management believes are appropriate in the circumstances although it is reasonably possible that actual performance will differ from these assumptions.  If the carrying amount of an asset exceeds its estimated fair value, an impairment charge is recognized equal to the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset.  See Note 6 to the Notes to Consolidated Financial Statements for more information.

Insurance Recoveries

Insurance recoveries that are deemed to be probable and reasonably estimable are recognized to the extent of the related loss.  Insurance recoveries that result in gains are recognized only when realized by settlement with the insurers.  The evaluation of insurance recoveries requires estimates and judgments about future results that affect reported amounts and certain disclosures. Actual results could differ from those estimates.

Advance Mining Royalties

Coal leases that 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, 2010 and 2009, advance mining royalties included in Other noncurrent assets totaled $43.5 million and $40.4 million, net of an allowance of $13.2 million and $12.8 million, respectively.

Reclamation

We record asset retirement obligations (“ARO”) 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. Management and engineers periodically review the estimate of ultimate reclamation liability and the expected period in which reclamation work will be performed. In estimating future cash flows, we consider the estimated current cost of reclamation and apply 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 our behalf.  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, we perform a certain amount of required reclamation of disturbed acreage as an integral part of our normal mining process; these costs are expensed as incurred.  See Note 13 for a more complete discussion of our reclamation liability.

Pension Plans

We sponsor a noncontributory defined benefit pension plan covering substantially all administrative and non-union employees.  Our policy is to annually fund the defined benefit pension plan at or above the minimum amount required by law.  We also sponsor a nonqualified supplemental benefit pension plan for certain salaried employees, which is unfunded.

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Costs of benefits to be provided under our defined benefit pension plans are accrued over the employees’ estimated remaining service life.  These costs are determined on an actuarial basis.  We recognize the funded status of our benefit plans in our Consolidated Balance Sheet and recognize as a component of Accumulated other comprehensive loss, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.  These amounts will be adjusted as they are subsequently recognized as components of net periodic benefit cost. See Note 9 for a more complete discussion of our pension plans.

Black Lung Benefits

We are responsible under the Federal Coal Mine Health and Safety Act of 1969, as amended, and under various states’ statutes for the payment of medical and disability benefits to employees and their dependents resulting from occurrences of black lung.  We provide for federal and state black lung claims principally through a self-insurance program.

Costs of benefits to be provided under our accumulated black lung obligations are accrued over the employees’ estimated remaining service life.  These costs are determined on an actuarial basis.  We recognize the funded status of our black lung obligations in our Consolidated Balance Sheet and recognize as a component of Accumulated other comprehensive loss, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.  We use the service cost method to account for our 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.  We amortize unrecognized actuarial gains and losses over a five-year period.  See Note 15 for a more complete discussion of black lung benefits.

Workers’ Compensation

We are liable for workers’ compensation benefits for traumatic injuries under state workers’ compensation laws in states in which we have operations.  Our operations have workers’ compensation coverage through a combination of either a self-insurance program, or commercial insurance through a deductible or first dollar insurance policy.  We record our self-insured liability on a discounted actuarial basis using various assumptions, including discount rate and future cost trends.  See Note 15 for a more complete discussion of workers’ compensation benefits.

Postretirement Benefits Other than Pensions

We sponsor defined benefit health care plans that provide postretirement medical benefits to eligible union and non-union members.  Costs of benefits to be provided under our postretirement benefits other than pensions are accrued over the employees’ estimated remaining service life.  These costs are determined on an actuarial basis.  We recognize the funded status of our benefit plans in our Consolidated Balance Sheet and recognize as a component of Accumulated other comprehensive loss, net of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost.  These amounts will be adjusted as they are subsequently recognized as components of net periodic benefit cost.

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.  We treat our obligation under the Coal Act as participation in a multi-employer plan and record the cost of our obligation as expense as payments are assessed.  See Note 14 for a more complete discussion of postretirement benefits other than pensions.

Stock-based Compensation

We measure the compensation cost of equity instruments based on their grant-date fair value, which is recognized as expense on a straight-line basis over the corresponding vesting period.  We use the Black-Scholes option-pricing model to determine the fair value of stock options as of the date of grant and certain liability awards with option characteristics (i.e., stock appreciation rights, or “SARs”).  See Note 16 for a more complete discussion of stock-based compensation.

Earnings per Share

Basic earnings per share is computed by dividing net income by the weighted-average number of outstanding common shares for the period. Diluted earnings per share reflects the potential dilution that could occur if instruments that may require the issuance of common shares in the future were settled and the underlying common shares were issued. Diluted earnings per share is computed by increasing the weighted-average number of outstanding common shares computed in basic earnings per share to include the additional common shares that would be outstanding after issuance and adjusting net income from changes that would result from the issuance. Only those securities that are dilutive are included in the calculation. See Note 2 for a more complete discussion.

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Recent Accounting Pronouncements

In April 2010, the FASB issued an accounting standard update, amending disclosure requirements related to income taxes as a result of the Patient Protection and Affordable Care Act (“PPACA”).  Beginning in fiscal year 2014, the tax deduction available to us will be reduced to the extent our drug expenses are reimbursed under the Medicare Part D retiree drug subsidy program.  Because retiree health care liabilities and the related tax impacts are already reflected in our Consolidated Financial Statements, we were required to recognize the full accounting impact of this accounting standard update in the period in which the PPACA was signed into law.  The total non-cash charge to Income tax expense related to the reduction in the tax benefit was $2.6 million, and was recorded in 2010.

2. Earnings Per Share

The number of shares of Common Stock used to calculate basic earnings per share for the year ended December 31, 2010, 2009 and 2008, is based on the weighted average of outstanding shares of Common Stock during the respective periods.  The number of shares of Common Stock used to calculate diluted earnings per share is based on the number of shares of Common Stock used to calculate basic earnings per share plus the dilutive effect of stock options and other stock-based instruments held by our employees and directors during each period and debt securities currently convertible into shares of Common Stock during each period.  The effect of dilutive securities issuances in the amount of 2.0 million, 1.2 million and 0.01 million shares of Common Stock for the year ended December 31, 2010, 2009, and 2008, respectively, were excluded from the calculation of diluted net (loss) income per share of Common Stock, as such inclusion would result in antidilution.

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

	Year Ended December 31,
	2010			2009		2008
	(In Thousands, Except Per Share Amounts)
Numerator:
Net (loss) income - numerator for basic	$	(166,587	)	$	104,433	$	47,829
Effect of convertible notes		—			174		188
Net (loss) income - numerator for diluted	$	(166,587	)	$	104,607	$	48,017
Denominator:
Weighted average shares - denominator for basic		97,545			84,992		81,816
Effect of stock options/restricted stock		—			317		772
Effect of convertible notes		—			289		307
Adjusted weighted average shares - denominator for diluted		97,545			85,598		82,895
Net (loss) income per share:
Basic	$	(1.71	)	$	1.23	$	0.58
Diluted	$	(1.71	)	$	1.22	$	0.58

The 2.25% Notes are convertible by holders into shares of Common Stock during certain periods under certain circumstances.  The 2.25% Notes were eligible for conversion at December 31, 2010.  If all of the 2.25% Notes outstanding at December 31, 2010 had been converted at that date, we would have issued 287,113 shares of Common Stock.

The 3.25% Notes are convertible under certain circumstances and during certain periods into (i) cash, up to the aggregate principal amount of the 3.25% Notes subject to conversion and (ii) cash, Common Stock or a combination thereof, at our election in respect to the remainder (if any) of our conversion obligation.  As of December 31, 2010, the 3.25% Notes had not reached the specified threshold for conversion.

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3. Acquisition of Cumberland

On April 19, 2010, we completed the acquisition of Cumberland for a purchase price of $644.7 million in cash and 6,519,034 shares of Common Stock.  Prior to the acquisition, Cumberland was one of the largest privately held coal producers in the United States.  Cumberland’s operations include primarily underground coal mines in Southwestern Virginia and Eastern Kentucky.  As a result of the acquisition, we obtained an estimated 415 million tons of contiguous coal reserves. We also obtained a preparation plant in Kentucky served by the CSX railroad and a preparation plant in Virginia served by the Norfolk Southern railroad.  We did not incur or assume any third-party debt as a result of the acquisition of Cumberland.  The acquisition of Cumberland increases our metallurgical coal reserves, strengthens our ability to globally market steam and metallurgical quality coal, and optimizes both operational best practices and working capital generation.

The acquisition of Cumberland was accounted for as a business combination.  The fair value of the total consideration transferred was $934.2 million.  The acquisition date fair value of each class of consideration transferred was as follows:

	(In Thousands)
Fair value of shares of Common Stock	$	289,511
Cash		644,730
Total purchase price	$	934,241

The Fair value of shares of Common Stock transferred was determined by using the Common Stock’s closing price of $44.41 on the day of the acquisition.

In determining the purchase price, we also considered Cumberland’s strong management team and the efficiency of its operations. Because these factors do not arise from contractual or other legal rights, nor are they separable, the value attributable to these factors is included in the amount recognized as goodwill.  The goodwill is deductible for tax purposes.

The purchase price was allocated to the assets acquired and liabilities assumed based on estimated fair values determined by appraisals of the assets acquired and liabilities assumed.  The final purchase price allocation was as follows:

(In Thousands)	Purchase Price Allocation
Cash and cash equivalents	$	14,753
Trade and other accounts receivable		52,802
Inventories		11,942
Other current assets		4,140
Net property, Plant and Equipment		763,083
Intangible assets, net		167,021
Goodwill		36,707
Other noncurrent Assets		529
Total assets		1,050,977
Accounts payable, principally trade and bank overdrafts		24,784
Payroll and employee benefits		8,648
Other current liabilities		25,624
Deferred income taxes		46,243
Other noncurrent liabilities		11,437
Total liabilities		116,736
Net assets acquired	$	934,241

Total revenues and (Loss) income before taxes reported in the Consolidated Statements of Income for the year ended December 31, 2010 included $438.2 million and $26.5 million, respectively, related to the operations acquired in the Cumberland acquisition.

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The following unaudited pro forma information has been prepared for illustrative purposes only and assumes the acquisition of Cumberland occurred at the beginning of each of the periods being presented.  The unaudited pro forma results have been prepared based on estimates and assumptions that we believe are reasonable; however, they are not necessarily indicative of the consolidated results of operations had the acquisition of Cumberland occurred at the beginning of each of the periods presented or of future results of operations.

	Year Ended December 31,
(In Thousands)	2010			2009
Total revenue
As reported	$	3,038,974		$	2,691,159
Pro forma	$	3,242,353		$	3,255,324
Net (loss) income
As reported	$	(166,587	)	$	104,433
Pro forma	$	(152,886	)	$	118,179

4. Inventories

Inventories consisted of the following:

	December 31, 2010		December 31, 2009
	(In Thousands)
Saleable coal	$	183,156	$	179,081
Raw coal		47,376		36,254
Subtotal coal inventory		230,532		215,335
Supplies inventory		58,495		54,491
Total inventory	$	289,027	$	269,826

Saleable coal represents coal ready for sale, including inventories designated for customer facilities under consignment arrangements of $34.8 million and $43.7 million at December 31, 2010 and 2009, respectively.  Raw coal represents coal that generally requires further processing prior to shipment to the customer.

5. Other Current Assets

Other current assets are comprised of the following:

	December 31, 2010		December 31, 2009
	(In Thousands)
Longwall panel costs	$	10,430	$	12,041
Deposits		105,216		133,794
Other		77,530		90,155
Total other current assets	$	193,176	$	235,990

During 2010, we impaired $5.1 million of Longwall panel costs deemed not to be recoverable at UBB due to an accident that occurred in April 2010.  See Note 6 to the Notes to Consolidated Financial Statements for more information.

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.  As of December 31, 2010 and 2009, Deposits includes $59.4 million and $46.0 million, respectively, of funds pledged as collateral to support $58.2 million and $45.1 million, respectively, of outstanding letters of credit.  In addition, Deposits at December 31, 2010 and 2009, includes $11.6 million and $12.1 million, respectively of United States Treasury securities supporting various regulatory obligations.  As of December 31, 2009, Deposits included a $72.0 million appeal bond we had been required to post related to litigation against us, which was released by the West Virginia Supreme Court of Appeals during the first quarter of 2010, as the final appeal of the case at the state level was resolved in our favor.  During 2010, we posted $9.3 million of cash as collateral for an appeal bond related to pending litigation with one of our customers (see Note 22 to the Notes to Consolidated Financial Statements for more information).  Deposits also includes $17.8 million and $1.6 million for future equipment deliveries as of December 31, 2010 and 2009, respectively.

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The Other caption in the table above at December 31, 2010 includes $10.0 million associated with the funding of a portion of our deferred compensation plan.

We have committed to the divestiture of certain mining equipment assets which are not part of our short-term mining plan.  At December 31, 2010, and 2009, the carrying amount of assets held for sale totaled $24.2 million and $22.3 million, respectively and is included in Other current assets.

6. Property, Plant and Equipment

Property, plant and equipment is comprised of the following:

	December 31,			December 31,
	2010			2009
	(In Thousands)
Land, buildings and equipment	$	2,983,866		$	2,631,886
Mining properties owned in fee and leased mineral rights		1,428,394			851,704
Mine development		1,221,529			1,131,707
Total property, plant and equipment		5,633,789			4,615,297
Less accumulated depreciation, depletion and amortization		(2,416,104	)		(2,270,527	)
Property, plant and equipment, net	$	3,217,685		$	2,344,770

Land, buildings and equipment includes gross assets under capital leases of $12.3 million and $12.9 million at December 31, 2010 and 2009, respectively

On April 5, 2010, an explosion occurred at the Upper Big Branch (“UBB”) mine of our Performance resource group, which damaged assets associated with the operation at UBB.  Therefore during 2010, we recorded impairment charges related to the UBB incident of $63.6 million, which are included in Depreciation, depletion and amortization applicable to Cost of produced coal revenue, in our Consolidated Statements of Income.  In accordance with relevant accounting requirements, Property, plant and equipment (which included mine development) and longwall panel costs located at or near UBB with a carrying amount of $35.4 million and $28.2 million (of which $5.1 million was considered current assets and $23.1 million noncurrent assets), respectively, were deemed to be destroyed or probable of abandonment.  Accordingly, the carrying value of the assets was completely written off.  There was approximately $14.9 million of assets at or near the UBB mine that were not impaired; our determination of recoverability related to these assets was based on our assumptions about future operations at UBB and possible alternatives to accessing the related coal reserves.  Given the ongoing investigations into the cause of the UBB tragedy and the uncertainty around the future operations at the UBB mine, there is a reasonable possibility that additional impairments could be recorded in future periods.

During 2010, we recorded $20.5 million of impairment charges for unamortized mine development costs at certain idled mines.  In light of increased regulatory scrutiny and the current production levels at certain of our mining locations,  management determined certain assets were unlikely to be recovered in future periods. The remaining carrying value of the unamortized mine development costs for these idled mines is immaterial. The charges are included in Depreciation, depletion and amortization in the Consolidated Statement of Income.

During 2010 and 2009, we received $22.2 million and $15.4 million, respectively, in insurance proceeds for reconstruction of the Bandmill preparation plant and reimbursement of related expense. Of the 2010 proceeds, $15.5 million are included in Cash utilized for investing and $6.7 million are included in Cash from operations in the Consolidated Statement of Cash Flows. The receipts received in 2010 resulted in a pre-tax gain of $18.4 million on insurance recovery related to the Bandmill preparation plant fire property insurance recovery. $11.2 million of the gain was recorded in Other revenue and $7.2 million of the gain was recorded in Cost of produced coal revenue in the Consolidated Statement of Income.

During 2010 and 2008 we sold and leased-back certain mining equipment. We received net proceeds of $16.5 million and $41.3 million, for the years ended December 31, 2010 and 2008, respectively, resulting in net deferred gains of $0.5 million and $2.4 million, respectively. During 2009, we had no material sale-leaseback transactions.

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7. Intangible assets

As part of the acquisition of Cumberland during 2010, we acquired Intangible assets with a fair value of $167.0 million.  Intangible assets are comprised of the following:

(In Thousands)	December 31, 2010
Coal sales contracts	$	96,870
Transportation contracts		61,700
Mining permits		8,451
Intangible assets, cost		167,021
Accumulated amortization		(46,098	)
Intangible assets, net	$	120,923

Our Coal sales contracts and Transportation contracts are amortized based on the actual amount of tons shipped under each contract.  Mining permits are amortized using the units-of-production method over the estimated proven and probable reserve tons.  For the year ended December 31, 2010, we recorded $46.1 million in amortization expense related to the Intangible assets in Depreciation, depletion, and amortization in the Consolidated Statement of Income.

Estimated amortization expense for Intangible assets for the next five calendar years is as follows:

(In Thousands)	Estimated Amortization Expense
2011	$	64,974
2012	$	8,374
2013	$	8,157
2014	$	7,926
2015	$	7,571

8. Goodwill

As a result of the acquisition of Cumberland during 2010, we recorded Goodwill in our Consolidated Balance Sheet.

(In Thousands)
Balance at December 31, 2009	$	—
Increase in goodwill due to acquisition of Cumberland		36,707
Balance at December 31, 2010	$	36,707

9. Pension Plans

Defined Benefit Pension Plans

We sponsor 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.  This last formula has a guaranteed rate of return on contributions of 4% for all contributions after December 31, 2003.  Funding for the plan is generally at the minimum contribution level required by applicable regulations. We made contributions of $19.8 million and $15.0 million to the qualified plan during 2010 and 2009, respectively.

An independent trustee holds the plan assets for the qualified defined benefit pension plan.  The plan assets include cash and cash equivalents, corporate and government bonds, preferred and common stocks and an investment in a group annuity contract.  We have an internal investment committee (“Investment Committee”) that sets investment policy, selects and monitors investment managers and monitors asset allocation.  Diversification of assets is employed to reduce risk.  The long-term target asset allocation is 65% for equity securities (including 50% domestic and 15% international) and 35% 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.

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In January 2009, the Investment Committee decided to reduce the targeted asset allocation for an interim period for equity securities to 25% of current plan assets given the recent volatility and uncertainty in the equity securities market.  The Investment Committee decided to invest $65 million of plan assets previously invested in equity securities in a fixed duration, fixed income strategy with an effective duration of approximately four years.  The Investment Committee expects to rebalance the asset portfolio consistent with the long-term target asset allocation at the maturity of the fixed income, fixed duration strategy.

To develop the expected long-term rate of return on assets assumption, we considered the historical returns and the future expectations for returns for each asset class, as well as the long-term target asset allocation of the pension portfolio.  This resulted in the selection of the 8.0% long-term rate of return on assets assumption for the year ended December 31, 2010.  As we plan to return to our targeted asset allocation, we believe the expected long-term rate of return on plan assets of 8.0% continues to be appropriate.

The asset allocation for our funded qualified defined benefit pension plan at the end of 2010 and 2009, is as follows:

	Percentage of Plan Assets at Year Ended
	December 31, 2010			December 31, 2009
Equity securities (domestic and international)		35.6	%		29.2	%
Debt securities		53.4	%		59.3	%
Other (includes cash, cash equivalents and a group annuity contract)		11.0	%		11.5	%
Total fair value of plan assets		100.0	%		100.0	%

Under the fair value hierarchy, our qualified defined benefit pension plan assets fall under Level I - quoted prices in active markets and Level II - other observable inputs (see Note 20 to the Notes to Consolidated Financial Statements for more information on the fair value hierarchy).  The following table provides the fair value by each major category of plan assets:

	December 31, 2010
	Level 1		Level 2
	(In Thousands)
Equity securities	$	73,681	$	—
Debt securities		—		143,315
Common/collective trust		—		21,858
Commingled short-term investment funds		—		20,055
Insurance contract				9,345
	December 31, 2009
	Level 1		Level 2
	(In Thousands)
Equity securities	$	49,461	$	—
Debt securities		—		145,563
Common/collective trust		—		19,697
Commingled short-term investment funds		—		13,270
Insurance contract		—		9,204

In addition to the qualified defined benefit pension plan noted above, we sponsor 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 Internal Revenue Service (“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 made by us.

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

	Year Ended
	December 31,			December 31,
	2010			2009
	(In Thousands)
Change in benefit obligation:
Benefit obligation at the beginning of the period	$	303,418		$	280,128
Service cost		10,148			9,405
Interest cost		17,942			16,875
Actuarial loss		42,436			8,300
Benefits paid		(11,933	)		(11,290	)
Benefit obligation at the end of the period		362,011			303,418
Change in plan assets:
Fair value at the beginning of the period		237,195			207,750
Actual return on assets		23,078			25,661
Company contributions		19,914			15,074
Benefits paid		(11,933	)		(11,290	)
Fair value of plan assets at end of period		268,254			237,195
Funded status	$	(93,757	)	$	(66,223	)
Qualified defined benefit pension plan, included in Pension obligation	$	(79,721	)	$	(55,610	)
Nonqualified supplemental benefit pension plan, included in Other noncurrent liabilities		(14,036	)		(10,613	)
Accrued Pension obligation recognized, net	$	(93,757	)	$	(66,223	)

The table below details the changes to Accumulated other comprehensive loss related to defined benefit pension plans:

	Year Ended
	December 31, 2010					December 31, 2009
	(In Thousands)
	Net loss		Prior service cost			Net loss			Prior service cost
January 1 beginning balance	$	78,006	$	9			89,260			34
Changes to Accumulated other comprehensive loss		14,650		(3	)		(11,254	)		(25	)
December 31 ending balance	$	92,656	$	6		$	78,006		$	9

We expect the estimated net loss and prior service cost for the defined benefit pension plan that will be amortized from accumulated other comprehensive income into net periodic benefit cost over the next fiscal year to be $16.6 million and $5,000, respectively.

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

	December 31,			December 31,
	2010			2009
Discount rates		5.50	%		6.00	%
Rates of increase in compensation levels		3.00	%		3.00	%

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

	Year Ended
	December 31,			December 31,			December 31,
	2010			2009			2008
	(In Thousands)
Service cost	$	10,148		$	9,405		$	8,680
Interest cost		17,942			16,875			15,881
Expected return on plan assets		(19,205	)		(16,359	)		(22,852	)
Recognized loss		14,302			17,447			770
Amortization of prior service cost		5			41			42
Net periodic pension expense	$	23,192		$	27,409		$	2,521

The assumptions used in determining pension expense for both the qualified defined benefit pension plan and nonqualified supplemental benefit pension plan are as follows:

	December 31,			December 31,			December 31,
	2010			2009			2008
Discount rates		6.00	%		6.10	%		6.50	%
Rates of increase in compensation levels		3.00	%		4.00	%		4.00	%
Expected long-term rate of return on plan assets		8.00	%		8.00	%		8.00	%

We expect to make contributions of approximately $20 million in 2011. We also expect to contribute approximately $0.9 million for benefit payments to participants in 2011 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)
2011	$	14,505
2012	$	15,120
2013	$	15,872
2014	$	16,896
2015	$	17,688
Years 2016 to 2020	$	104,022

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 to less than $600,000 for each of the years ended December 31, 2010, 2009, and 2008.

Defined Contribution Plan

We currently sponsor a defined contribution pension plan for certain union employees.  The plan is non-contributory and our contributions are based on hours worked.  Contributions to this plan were approximately $75,000 for each of the years ended December 31, 2010, 2009, and 2008.

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Salary Deferral and Profit Sharing (401(K)) Plan

We also sponsor three salary deferral and profit sharing plans covering substantially all administrative and non-union employees.  The maximum salary deferral rate is 75% of eligible pay, subject to IRS limitations.  Prior to May 1, 2009, we contributed an amount equal to 30% of the first 10% of each participant’s compensation contributed.  During 2010, we contributed amounts between 10% to 60% of the first 10% of each participant’s compensation contributed.  Our contributions aggregated approximately $4.4 million, $2.5 million and $4.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

10. Debt

Our debt is comprised of the following:

	December 31,			December 31,
	2010			2009
	(In Thousands)
6.875% senior notes due 2013, net of discount	$	757,462		$	756,727
3.25% convertible senior notes due 2015, net of discount		546,323			526,435
6.625% senior notes due 2010		—			21,949
2.25% convertible senior notes due 2024		9,647			9,647
Capital lease obligations		2,747			4,328
Total debt		1,316,179			1,319,086
Amounts due within one year		(12,327	)		(23,531	)
Total long-term debt	$	1,303,852		$	1,295,555

The weighted average effective interest rate of the outstanding borrowings was 7.3% at both December 31, 2010 and 2009.

Convertible Debt Securities

The discount associated with the 3.25% Notes is being amortized via the effective-interest method, increasing the reported liability until the notes are carried at par value on their maturity date.  We separately account for the liability and equity components in a manner reflective of our nonconvertible debt borrowing rate, which was determined to be 7.75% at the date of issuance. We recognized $19.9 million, $18.4 million, and $6.9 million of pre-tax non-cash interest expense for the amortization of the discount for the twelve months ended December 31, 2010, 2009, 2008, respectively.

6.625% Notes

During January 2010, we redeemed at par the remaining $21.9 million of our 6.625% senior notes due 2010.

Financing Transactions

On August 5, 2008, we commenced a consent solicitation and tender offer for any and all of the outstanding $335 million of 6.625% Notes and concurrently we commenced registered underwritten public offerings of convertible senior notes (the “3.25% Notes”) and shares of Common Stock and announced our intention to use the proceeds of the offerings to purchase some or all of the 6.625% Notes in the tender offer and for general corporate purposes.

On August 19, 2008, we settled with holders of $311.5 million of the 6.625% Notes, representing approximately 93% of the outstanding 6.625% Notes, who tendered their 6.625% Notes pursuant to our consent solicitation and tender offer for the 6.625% Notes.  The total consideration for these 6.625% Notes was $1,026.57 per $1,000 principal amount of the 6.625% Notes.  The total consideration included a consent payment of $25 per $1,000 principal amount of the 6.625% Notes.  In addition to the total consideration, holders also received interest which was accrued and unpaid since the previous interest payment date.

As a result of the consents of approximately 93% of the outstanding 6.625% Notes, we received the requisite consents to execute a supplemental indenture relating to the 6.625% Notes, which eliminated substantially all of the restrictive covenants in the 6.625% Notes’ indenture.

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On September 3, 2008, we settled with holders of an additional $1.6 million of the 6.625% Notes, who tendered their 6.625% Notes after the consent solicitation deadline.  The total consideration for these 6.625% Notes was $1,001.57 per $1,000 principal amount of the 6.625% Notes.  In addition to the total consideration, holders also received interest which was accrued and unpaid since the previous interest payment date.

During 2008, we recognized charges totaling $15.2 million, including $1.9 million for the write-off of unamortized financing fees and $4.2 million for the unamortized interest rate swap termination payment (as discussed below) recorded in Interest expense, and $9.1 million for the debt consent solicitation and tender offer recorded in Loss on financing transactions.

Fair Value Hedge Adjustment

On December 9, 2005, we exercised our right to terminate our interest rate swap agreement, which was designated as a hedge against a portion of the 6.625% Notes.  We paid a $7.9 million termination payment to the swap counterparty on December 13, 2005 (“Fair value hedge adjustment”).  The termination payment was being amortized into Interest expense through November 15, 2010, the maturity date of the 6.625% Notes.  As discussed in this Note under Financing Transactions above, on August 19, 2008, we settled with holders of approximately 93% of the outstanding 6.625% Notes that were tendered pursuant to our consent solicitation and tender offer for the 6.625% Notes.  As a result of the acceptance of the consent solicitation and tender offer of the 6.625% Notes, the remaining balance of the Fair value hedge adjustment of $4.2 million was written off to Interest expense.  For the year ended December 31, 2008, $5.1 million of the Fair value hedge adjustment was recorded in Interest expense.

6.875% Notes

The 6.875% Notes are unsecured obligations ranking equally with all other unsecured senior indebtedness of ours and are guaranteed by substantially all of our current and future subsidiaries, (the “Guarantors”). Interest on the 6.875% Notes is payable on December 15 and June 15 of each year.  We may redeem the 6.875% Notes, in whole or in part, for cash at any time on or after December 15, 2009 at a redemption price equal to 100% of the principal amount plus a premium declining ratably to par, plus accrued and unpaid interest.  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 6.875% Notes are minor (as defined under SEC Rule 3-10(h)(6) of Regulation S-X).

The 6.875% Notes contain a number of significant restrictions and covenants that limit our ability and our 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.  We are currently in compliance with all covenants.

3.25% Notes

On August 12, 2008, we issued $690 million of 3.25% Notes in a registered underwritten public offering, resulting in net proceeds to us of approximately $674.1 million.  The 3.25% Notes are guaranteed on a senior unsecured basis by the Guarantors.  The subsidiaries not providing a guarantee of the 3.25% Notes are minor (as defined under SEC Rule 3-10(h)(6) of Regulation S-X).  The guarantees are full and unconditional obligations of the Guarantors and are joint and several among the Guarantors.  The 3.25% Notes and the guarantees rank equally with all of our and the Guarantors’ existing and future senior unsecured indebtedness and rank senior to all of our and the Guarantors’ indebtedness that is expressly subordinated to the 3.25% Notes and the guarantees, but are effectively subordinated to all of our and the Guarantors’ existing and future senior secured indebtedness to the extent of the value of the assets securing the indebtedness and to all liabilities of our subsidiaries that are not Guarantors.

The 3.25% Notes bear interest at a rate of 3.25% per annum, payable semi-annually in arrears on August 1 and February 1 of each year.  The 3.25% Notes will mature on August 1, 2015, unless earlier repurchased by us or converted.

The 3.25% Notes are convertible in certain circumstances during certain periods at an initial conversion rate of 11.4106 shares of Common Stock per $1,000 principal amount of 3.25% Notes (which represented an initial conversion price of approximately $87.64 per share), subject to adjustment in certain circumstances.  The conversion rate as of December 31, 2010 was 11.4542 shares of Common Stock per $1,000 principal amount of 3.25% Notes.

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The 3.25% Notes are convertible under certain circumstances and during certain periods into (i) cash, up to the aggregate principal amount of the 3.25% Notes subject to conversion and (ii) cash, shares of Common Stock or a combination thereof, at our election in respect to the remainder (if any) of our conversion obligation.  Subject to earlier repurchase, the 3.25% Notes will be convertible only in the following circumstances and to the following extent:

● during any calendar quarter, if the closing sale price of our shares of Common Stock for each of 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the conversion price in effect on the last trading day of the immediately preceding calendar quarter;

● during the five consecutive business days immediately after any five consecutive trading day period (the “note measurement period”) in which the average trading price per $1,000 principal amount of 3.25% Notes was equal to or less than 97% of the average conversion value of the 3.25% Notes during the note measurement period;

● if we make certain distributions on our shares of Common Stock or engage in certain transactions; and

● at any time from, and including, February 1, 2015 until the close of business on the second business day immediately preceding August 1, 2015.

None of the 3.25% Notes are currently eligible for conversion.

The indenture governing the 3.25% Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee for the 3.25% Notes or the holders of not less than 25% in aggregate principal amount of the 3.25% Notes then outstanding may declare the unpaid principal of the 3.25% Notes and any accrued and unpaid interest thereon immediately due and payable.  In the case of certain events of bankruptcy, insolvency or reorganization relating to us, the principal amount of the 3.25% Notes together with any accrued and unpaid interest thereon will automatically become and be immediately due and payable.

During 2009 and 2008, we concluded open market purchases of our 3.25% Notes, reducing the net liability outstanding by $9.5 million ($11.9 million of principal amount less $2.4 million of debt discount) and $14.5 million ($19.0 million of principal amount less $4.5 million of debt discount) at a cost of $10.0 million and $10.4 million, respectively, plus accrued interest.  After reversal of the equity component of these convertible notes of $0.3 million and $0.04 million in 2009 and 2008, respectively, a loss of $0.2 million was recorded in 2009 and a gain of $4.1 million was recorded in 2008, in Loss on financing transactions.  Depending on market conditions and covenant restrictions, we may continue to make debt repurchases from time to time through open market purchases, private transactions or otherwise.

 2.25% Notes

The 2.25% Notes are unsecured obligations of ours, rank equally with all other unsecured senior indebtedness and are guaranteed by 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 2.25% Notes are minor (as defined under SEC Rule 3-10(h)(6) of Regulation S-X). Interest is payable semiannually on April 1 and October 1 of each year. We registered the 2.25% Notes with the SEC for resale.

Holders of the 2.25% Notes may require us 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 we experience certain specified types of fundamental changes on or before April 1, 2011, the holders may require us to purchase the notes for cash.  We may redeem all or a portion of the 2.25% 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% Notes are convertible during certain periods by holders into shares of Common Stock initially at a conversion rate of 29.7619 shares of Common Stock per $1,000 principal amount of 2.25% Notes (subject to adjustment upon certain events) under the following circumstances: (i) if the price of Common Stock issuable upon conversion reaches specified thresholds; (ii) if we redeem the 2.25% Notes; (iii) upon the occurrence of certain specified corporate transactions; or (iv) if the credit ratings assigned to the 2.25% Notes decline below certain specified levels.  Regarding the thresholds in (i) above, holders may convert each of their notes into shares of Common Stock during any calendar quarter (and only during such calendar quarter) if the last reported sale price of 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 Common Stock.  The conversion price is $33.60 per share. As of December 31, 2010, the price per share of Common Stock had reached the specified threshold for conversion.  Consequently, the 2.25% Notes are convertible until March 31, 2011, the last day of our first quarter.  The 2.25% Notes may be convertible beyond this date if the specified threshold for conversion is met in subsequent quarters.  If all of the 2.25% Notes outstanding at December 31, 2010 had been eligible for conversion and were converted at that date, we would have issued 287,113 shares of Common Stock.  No conversions occurred during the year.

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Asset-Based Lending Arrangement

On November 8, 2010, we entered into an amended and restated asset-based revolving credit agreement, which provides for available borrowings, including letters of credit, of up to $200 million, depending on the level of eligible inventory and accounts receivable.  Subject to certain conditions, at any time prior to maturity, we may elect to increase the size of the facility up to $250 million if lenders willing to support the additional $50 million can be identified.  The previous asset-based revolving credit agreement provided for available borrowings, including letters of credit, of up to $175 million, depending on the level of eligible inventory and accounts receivable.  In addition, we extended the facility’s maturity to May 2015.  As of December 31, 2010, there were $77.2 million of letters of credit issued and there were no outstanding borrowings under this facility.

The facility is collateralized by our accounts receivable, eligible coal inventories located at our facilities and on consignment at customers’ facilities, and other intangibles.  At December 31, 2010, total remaining availability was $122.8 million based on qualifying inventory and accounts receivable.

This facility contains a number of significant restrictions and covenants that limit our 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) make distributions from subsidiaries.  This facility also contains a financial covenant, which become operative only when our Average Excess Availability (as defined in the facility documents) is less than the greater of i) $30 million and ii) 15% of the aggregate amount of Revolving Commitments (as defined in the facility documents).  The financial covenant requires the maintenance of a Minimum Consolidated Fixed Charge Ratio of 1.00 to 1.00. We are currently in compliance with all covenants under the ABL Facility.

Debt Maturity

The aggregate amounts of scheduled long-term debt maturities assuming convertible notes are not eligible for conversion, including capital lease obligations, subsequent to December 31, 2010 are as follows:

	(In Thousands)
2011	$	2,680
2012		35
2013		760,035
2014		35
2015		659,063
Beyond 2015*		9,647

* The 2.25% Notes in the amount of $9.6 million included herein may be redeemed at the option of the holders in 2011. However, the 2.25% Notes are included at the contractually stated maturity date of 2024 in the above table.

Total interest paid for the years ended December 31, 2010, 2009 and 2008, was $77.5 million, $75.5 million and $70.3 million, respectively.

Off-Balance Sheet Arrangements

In the normal course of business, we are 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 consolidated balance sheets, and, except for the operating leases, which are discussed in Note 17 to the Notes to Consolidated Financial Statements, 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.

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From time to time we use bank letters of credit to secure our obligations for workers’ compensation programs, various insurance contracts and other obligations. At December 31, 2010, we had $135.4 million of letters of credit outstanding of which $58.2 million was collateralized by $59.4 million of cash deposited in restricted, interest bearing accounts pledged to issuing banks and $77.2 million was issued under our asset based lending arrangement. No claims were outstanding against those letters of credit as of December 31, 2010.

We use surety bonds to secure reclamation, workers’ compensation, wage payments and other miscellaneous obligations. As of December 31, 2010, we had $373.5 million of outstanding surety bonds. These bonds were in place to secure obligations as follows: post-mining reclamation bonds of $352.4 million, and other miscellaneous obligation bonds of $21.1 million. The bonds are renewed annually.  Outstanding surety bonds of $46.9 million are secured with letters of credit. 

Generally, the availability and market terms of surety bonds continue to be challenging. If we are unable to meet certain financial tests applicable to some of our surety bonds, or to the extent that surety bonds otherwise become unavailable, we would need to replace the surety bonds or seek to secure them with letters of credit, cash deposits, or other suitable forms of collateral.

11. Income Taxes

Income tax (benefit) expense included in the Consolidated Statements of Income is as follows:

	Year Ended December 31,
	2010			2009		2008
	(In Thousands)
Current:
Federal	$	(1,751	)	$	14,309	$	(4,597	)
State and local		494			116		122
Total current		(1,257	)		14,425		(4,475	)
Deferred:
Federal		(61,170	)		15,374		4,593
State and local		(4,583	)		3,033		980
Total deferred		(65,753	)		18,407		5,573
Income tax (benefit) expense	$	(67,010	)	$	32,832	$	1,098

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

	Year Ended December 31,
	2010			2009			2008
	(In Thousands)
U.S. statutory federal tax expense	$	(81,759	)	$	48,043		$	17,124
Increase (Decrease) resulting from:
State taxes		(4,276	)		550			66
Non-deductible penalties		6,410			4,903			6,240
Percentage depletion		(24,680	)		(33,918	)		(45,671	)
Non-deductible compensation		5,502			805			666
Medical subsidy adjustment		2,558			—			—
Valuation allowance adjustment		29,090			18,747			29,104
Alternative minimum tax credit refund, net of adjustment		—			(5,988	)		(4,770	)
Other, net		145			(310	)		(1,661	)
Income tax (benefit) expense	$	(67,010	)	$	32,832		$	1,098

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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 temporary differences giving rise to deferred tax assets and liabilities are as follows:

	December 31,			December 31,
	2010			2009
	(In Thousands)
Deferred tax assets:
Postretirement benefit obligations	$	140,657		$	113,757
Workers’ compensation		33,101			23,707
Reclamation and mine closure		68,524			52,286
Alternative minimum tax credit carryforwards		113,977			113,977
Litigation		9,376			3,534
Deferred compensation		32,038			31,766
Goodwill		18,041			—
Federal net operating loss		171,163			110,415
State net operating loss		30,651			24,264
Other		22,252			33,032
Total deferred tax assets		639,780			506,738
Valuation allowance for deferred tax assets		(253,328	)		(212,643	)
Total deferred tax assets, net of valuation allowance		386,452			294,095
Deferred tax liabilities:
Plant, equipment and mine development		(322,266	)		(282,030	)
Mining property and mineral rights		(155,170	)		(145,063	)
Intangibles		(11,254	)		—
Convertible Debt		(43,969	)		(51,725	)
Deferred royalties		(11,678	)		(11,298	)
Other		(5,498	)		(13,209	)
Total deferred tax liabilities		(549,835	)		(503,325	)
Deferred income taxes	$	(163,383	)	$	(209,230	)

Deferred tax assets include alternative minimum tax (“AMT”) credits of $114.0 million at both December 31, 2010 and 2009, federal net operating loss carryforwards of $528.8 million and $341.0 million as of December 31, 2010 and 2009, respectively, and net state net operating loss (“NOL”) carryforwards of $766.3 million and $606.6 million as of December 31, 2010 and 2009, respectively.  The AMT credits have no expiration date.  Federal NOL carryforwards expire beginning in 2018 and ending in 2025.  State NOL carryforwards expire beginning in 2016 and ending in 2025.

We have recorded a valuation allowance for a portion of deferred tax assets that management believes, more likely than not, will not be realized.  These deferred tax assets include AMT credits, federal NOL and state NOL carryforwards that will likely not be realized at the maximum effective tax rate. The valuation allowance increased for the year ended December 31, 2010, primarily as a result of the federal NOL and state NOL carryforwards discussed above.

 In June 2006, the FASB issued accounting guidance, effective January 1, 2007, to create a single model to address accounting for uncertainty in income tax positions.  A tax position is initially recognized in the financial statements when it is more likely than not the position will be sustained upon examination by applicable taxing authorities.  To determine if uncertainty exists in these income tax positions, such tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with the taxing authority assuming full knowledge of the position and all relevant facts.  During the years ended December 31, 2010 and 2009 we had no uncertain income tax positions and therefore no unrecognized tax benefits.  We accrue interest and penalties, if any, related to unrecognized tax benefits in Other noncurrent liabilities and recognize the related expense in Income tax expense.

We file income tax returns in the United States federal and various state jurisdictions, including West Virginia, Kentucky and Virginia.  The IRS has examined our federal income tax returns, or statutes of limitations have expired for years through 2006.  In the various states where we file state income tax returns, the state tax authorities have examined our state returns, or statutes of limitations have expired through 2005.  Management believes that we have adequately provided for any income taxes that may ultimately be paid with respect to all open tax years.

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12. Other Noncurrent Liabilities

Other noncurrent liabilities are comprised of the following:

	December 31,		December 31,
	2010		2009
	(In Thousands)
Reclamation (Note 13)	$	230,968	$	193,361
Other postretirement benefits (Note 14)		178,113		155,024
Workers’ compensation and black lung (Note 15)		155,685		98,227
Other		55,733		91,446
Total other noncurrent liabilities	$	620,499	$	538,058

13. Reclamation

Our reclamation liabilities primarily consist of spending estimates related to reclaiming surface land and support facilities at both surface and underground mines in accordance with federal and state reclamation laws as defined by each mine permit.  The obligation and corresponding asset are recognized in the period in which the liability is incurred.

We estimate our ultimate reclamation liability based upon detailed engineering calculations of the amount and timing of the future cash flows to perform the required work.  We consider the estimated current cost of reclamation and apply 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 our behalf.  The discount rate applied is based on the rates of treasury bonds with maturities similar to the estimated future cash flow, adjusted for our credit standing.

The following table describes all changes to our reclamation liability:

	December 31,			December 31,
	2010			2009
	(In Thousands)
Reclamation liability at beginning of period	$	234,562		$	186,180
Accretion expense		17,358			13,991
Liability assumed in business combination (Note 3)		9,748			—
Liability assumed/incurred		7,600			28,527
Liability disposed		—			(505	)
Revisions in estimated cash flows		6,747			11,721
Payments		(6,324	)		(5,352	)
Reclamation liability at end of period		269,691			234,562
Less amount included in Other current liabilities		38,723			41,201
Total reclamation, included in Other noncurrent liabilities	$	230,968		$	193,361

14. Other Postretirement Benefits

We sponsor 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.

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Net periodic postretirement benefit cost includes the following components:

	Year Ended
	December 31,			December 31,			December 31,
	2010			2009			2008
	(In Thousands)
Service cost	$	2,233		$	3,913		$	3,204
Interest cost		9,524			10,017			8,845
Amortization of net loss		3,178			2,303			813
Amortization of prior service credit		(2,878	)		(750	)		(750	)
Net periodic postretirement benefit cost	$	12,057		$	15,483		$	12,112

The discount rate assumed to determine the net periodic postretirement benefit cost was 6.00%, 6.10% and 6.50% for the years ended December 31, 2010, 2009 and 2008, respectively.

The following table sets forth the change in benefit obligation of our postretirement benefit plans:

	Year Ended
	December 31,			December 31,
	2010			2009
	(In Thousands)
Change in benefit obligation:
Benefit obligation at the beginning of the period	$	162,088		$	168,629
Service cost		2,233			3,913
Interest cost		9,524			10,017
Plan amendment		2,067			(27,595	)
Actuarial loss		16,188			13,951
Benefits paid		(6,077	)		(6,827	)
Benefit obligation at the end of the period	$	186,023		$	162,088
Accrued postretirement benefit obligation	$	186,023		$	162,088
Amount included in Payroll and employee benefits		7,910			7,064
Postretirement benefit obligation, included in Other noncurrent liabilities	$	178,113		$	155,024

During 2009, changes were made to the plan provisions and communicated to the participants that were to be effective January 1, 2010 and January 1, 2011. Effective January 1, 2010, we consolidated our self-insured Medicare-age non-union retiree plans into one insured plan. We paid 100% of the premium for fiscal year 2010 for each retiree. In subsequent years, retirees will be responsible for inflationary increases in the insurance premium.  Further, members hired after January 1, 2010 were required to pay 100% of the applicable Medicare Supplemental Plan monthly premium. Further, effective January 1, 2011, future non-union retirees will pay 50% of the premium for pre-65 coverage.  These changes decreased the December 31, 2009 postretirement benefit obligation by $27.6 million. During 2010, the change in the plan provision related to non-union retirees’ contributions that was to be effective January 1, 2011 was revoked increasing the postretirement benefit obligation by $2.1 million.

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The table below details the changes to Accumulated other comprehensive loss related to our post retirement benefit plans:

	Year Ended
	December 31, 2010					December 31, 2009
	(In Thousands)
	Net loss		Prior service credit			Net loss		Prior service credit
January 1 beginning balance	$	36,218	$	(20,980	)	$	29,111	$	(4,605	)
Changes to Accumulated other comprehensive loss		7,936		1,756			7,107		458
Plan Amendment		—		1,260			—		(16,833	)
December 31 ending balance	$	44,154	$	(17,964	)	$	36,218	$	(20,980	)

We expect to recognize $2.9 million of prior service credit and $4.1 million of net actuarial loss in 2011.

The discount rates used to determine the benefit obligations were 5.50% and 6.00% for the years ended December 31, 2010 and 2009, respectively.

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

	Year Ended December 31,
	2010		2009
Health care cost trend rate for next year *	8.1% / 8.3% / 7.0%		8.3% / 8.6% / 7.0%
Ultimate trend rate		4.50%		4.50%
Year that the rate reaches ultimate trend rate		2029		2029

* Initial trend rate for Pre-Medicare claims, initial trend rate for Medicare-Eligible, and initial trend rate for the Medicare Supplement Plan.

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 aggregate effects:

	1-Percentage Point Increase		1-Percentage Point Decrease
	(In Thousands)
Effect on total of service and interest costs components	$	1,493	$	(1,211	)
Effect on accumulated postretirement benefit obligation	$	24,108	$	(19,743	)

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the periods noted:

	Expected Benefit Payments
	(In Thousands)
2011	$	7,910
2012		8,466
2013		9,126
2014		9,611
2015		9,979
Years 2016 to 2020		55,571

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PPACA

The PPACA may potentially impact our costs to provide healthcare benefits to our eligible active and certain retired employees.  The PPACA has both short-term and long-term implications on healthcare benefit plan standards.  Implementation of this legislation is planned to occur in phases, with plan standard changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018.  Plan standard changes that could affect us in the short term include raising the maximum age for covered dependents to receive benefits, the elimination of lifetime dollar limits per covered individual and restrictions on annual dollar limits per covered individual, among other standard requirements.  Plan standard changes that could affect us in the long term include a tax on “high cost” plans (excise tax) and the elimination of annual dollar limits per covered individual, among other standard requirements.  We are currently analyzing this legislation to determine the full extent of the impact of the required plan standard changes on our employee healthcare plans and the resulting costs. Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds.  We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax.  We have estimated that the excise tax will not impact our postretirement benefit obligation.  Accordingly, as of December 31, 2010, we have not made any changes to our assumptions used to determine our postretirement benefit obligation.  With the exception of the excise tax, we do not believe any other plan standard changes will be significant to our future healthcare costs for eligible active employees and our postretirement benefit obligation for certain retired employees. However, we will need to continue to evaluate the impact of the PPACA in future periods as additional information and guidance becomes available.

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, 2010, our obligation under the Coal Act was estimated at approximately $20.3 million, compared to our estimated obligation at December 31, 2009 of $22.3 million.  The obligation was discounted using a 5.00% rate each year.  We treat our obligation under the Coal Act as participation in a multi-employer plan and record the cost of our obligation as expense as payments are assessed.  The expense related to this obligation for the years ended December 31, 2010, 2009 and 2008 totaled $1.7 million, $1.9 million and $2.3 million, respectively

The Tax Relief and Retiree Health Care Act of 2006 included important changes to the Coal Act that impacts all companies required to contribute to the CBF. Effective October 1, 2007, the Social Security Administration revoked all beneficiary assignments made to companies that did not sign a 1988 UMWA contract (“reachback companies”) but their premium relief is phased-in. The reachback companies paid their full premium obligation in the current plan year that ended September 30, 2007. However, they paid only 55%, 40% and 15% of their plan year 2008, 2009 and 2010 assessed premiums, respectively. General United States Treasury money will be transferred to the CBF to make up the difference. After 2010, we will have no further obligations to the CBF, and transfers from the United States Treasury will cover all of the health care costs for retirees and dependents previously assigned to us.

15. Workers’ Compensation and Black Lung Benefits

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

	Year Ended December 31,
	2010		2009
	(In Thousands)
Accrued self-insured black lung obligation	$	77,414	$	53,145
Workers’ compensation (traumatic injury)		98,003		61,792
Total accrued workers’ compensation and black lung		175,417		114,937
Less amount included in Other current liabilities		19,732		16,710
Workers’ compensation & black lung in Other noncurrent liabilities	$	155,685	$	98,227

The amount of workers’ compensation (traumatic liability) related to self-insurance was $96.4 million and $61.1 million at December 31, 2010 and 2009, respectively.  Weighted average actuarial assumptions used in the determination of the self-insured portion of workers’ compensation (traumatic injury) liability included  discount rates of 4.50% and 4.75% at December 31, 2010 and 2009, respectively, and the accumulated black lung obligation included a discount rate of 5.50% and 6.00% at December 31, 2010 and 2009, respectively.

During 2010, we recorded a charge of $25.4 million for workers’ compensation and supplemental compensation benefits related to the UBB tragedy.  The workers’ compensation benefits are being measured and paid from our existing plan.  Both the workers’ compensation and supplemental compensation benefits were calculated, in consultation with independent actuaries, who after review and approval by management with regards to actuarial assumptions, including discount rate, prepared an evaluation of the self-insured liabilities.  Actual experience in settling these liabilities could differ from these estimates.

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

	Year Ended December 31,
	2010			2009
	(In Thousands)
Beginning of year accrued self-insured black lung obligation	$	53,145		$	50,739
Service cost		3,155			3,689
Interest cost		3,309			2,872
Actuarial loss (gain)		20,166			(1,535	)
Benefit payments		(2,361	)		(2,620	)
Accrued self-insured black lung obligation	$	77,414		$	53,145

The table below details the changes to Accumulated other comprehensive loss related to black lung benefits:

	Year Ended
	December 31,			December 31,
	2010			2009
	(In Thousands)
January 1 beginning balance	$	(10,584	)	$	(12,438	)
Changes to Accumulated other comprehensive loss		14,000			1,854
December 31 ending balance	$	3,416		$	(10,584	)

We expect to recognize $1.1 million of net actuarial loss in 2011.

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

	Year Ended
	December 31,			December 31,			December 31,
	2010			2009			2008
	(In Thousands)
Self-insured black lung benefits:
Service cost	$	3,155		$	3,689		$	2,186
Interest cost		3,309			2,872			3,390
Amortization of actuarial gain		(2,785	)		(4,575	)		(3,489	)
		3,679			1,986			2,087
Other workers’ compensation benefits		66,409			26,816			27,965
	$	70,088		$	28,802		$	30,052

The PPACA amended previous legislation related to coal workers’ pneumoconiosis (black lung), providing automatic extensions of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims including previously closed claims.  The impact of these changes to our current population of beneficiaries and claimants results in an estimated $11.3 million increase to our obligation and is primarily included in Actuarial loss (gain) for the year ended December 31, 2010. During 2010, we recorded this estimate as an increase to our black lung liability and a decrease to our actuarial gain included in Accumulated other comprehensive loss on our Condensed Consolidated Balance Sheets.  We will continue to evaluate the impact of these changes on such claims and record any necessary charges in the period in which the additional liability is estimable.  We do not believe the impact of these changes will significantly impact our financial position or results of operations.

Payments for benefits, premiums and other costs related to black lung, workers’ compensation and supplemental compensation benefit liabilities were $35.3 million, $31.8 million, and $24.0 million for the twelve months ended December 31, 2010, 2009 and 2008, respectively.

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The actuarial assumptions used in the determination of self-insured black lung benefits expense included discount rates of 6.00%, 6.10% and 6.50% for the years ended December 31, 2010, 2009 and 2008, respectively.

Our 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.  We assume a 6.50% annual medical cost increase and a 3.0% cost of living increase in determining our black lung obligation and the annual black lung expense.  Assumed medical cost and cost of living increases significantly affect the amounts reported for our 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	$	229	$	(182	)
Effect on accumulated black lung obligation	$	1,953	$	(1,605	)
Increase/(decrease) in cost of living trend rate:
Effect on total service and interest cost components	$	1,026	$	(814	)
Effect on accumulated black lung obligation	$	9,099	$	(7,388	)

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)
2011	$	4,188
2012		4,402
2013		4,608
2014		4,811
2015		5,014
Years 2016 to 2020		27,608

Certain of our operations are fully insured by a third-party insurance provider for black lung claims.

16. Stock Plans

We have stock incentive plans to encourage employees and nonemployee directors to remain with the Company and to more closely align their interests with those of our shareholders.

Description of Stock Plans

The Massey Energy Company 2006 Stock and Incentive Compensation Plan (the “2006 Plan”), which was approved by our stockholders and became effective on June 28, 2006 replaced the five stock-based compensation plans (the “Prior Plans”) we had in place prior to the approval of the 2006 Plan, all of which had been approved by our stockholders. On May 19, 2009, the Company’s stockholders approved adding 1,550,000 shares to our 2006 Plan.  The stockholders also approved a limit to the maximum number of shares available for awards granted in any form provided under the 2006 Plan (other than stock options or stock appreciation rights (“SARS”)) to no more than 75% of the total number of issuable shares.  The Prior Plans include the following:

● Massey Energy Company 1996 Executive Stock Plan, as amended and restated effective November 30, 2000 (the “1996 Plan”),

● Massey Energy Company 1997 Stock Appreciation Rights Plan, as amended and restated effective November 30, 2000 (the “SAR Plan”),

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● Massey Energy Company 1999 Executive Performance Incentive Plan, as amended and restated effective November 30, 2000 (the “1999 Plan”),

● Massey Energy Company Stock Plan for Non-Employee Directors, as amended and restated effective May 24, 2005 (the “1995 Plan”), and

● Massey Energy Company 1997 Restricted Stock Plan for Non-Employee Directors, as amended and restated effective May 24, 2005 (the “1997 Plan”).

Stock-based compensation has been granted under the 2006 Plan and the Prior Plans in the manner described below.  Issued and outstanding stock-based compensation has been granted to officers and certain key employees in accordance with the provisions of the 1996 Plan, the SAR Plan, the 1999 Plan and the 2006 Plan.  Issued and outstanding stock-based compensation has been granted to non-employee directors in accordance with the provisions of the 1995 Plan, the 1997 Plan and the 2006 Plan.  The Compensation Committee of the Board of Directors administers the 1996 Plan, the 1999 Plan, the SAR Plan and the 2006 Plan.  A committee comprised of non-participating board members administers the 1995 Plan and the 1997 Plan.

The 1996 Plan provided for grants of stock options and restricted stock.  The 1999 Plan provided for grants of stock options, restricted stock, incentive awards and stock units.  The SAR Plan provided for grants of SARs.  The 1995 Plan provided for grants of restricted stock and restricted units.  The 1997 Plan provided for grants of restricted stock. As of June 28, 2006, grants can no longer be made under the Prior Plans, except for the 1996 Plan, under which grants could no longer be made as of March 2, 2006.  All awards previously granted that are outstanding under the Prior Plans will remain effective in accordance with the terms of their grant.

The aggregate number of shares of Common Stock that may be issued for future grant under the 2006 Plan as of December 31, 2010 was 2,499,217 shares, which was computed as the 3,500,000 shares specifically authorized in the 2006 Plan, plus the 1,550,000 shares added as part of the 2006 Plan amendments approved on May 19, 2009, less grants made in 2006, 2007, 2008, 2009, and 2010, plus the number of shares that (i) were represented by restricted stock or unexercised vested or unvested stock options that previously have been granted and were outstanding under the Prior Plans as of June 28, 2006 and (ii) expire or otherwise lapse, are terminated or forfeited, are settled in cash, or are withheld or delivered to us for tax purposes at any time after June 28, 2006.  The 2006 Plan provides for grants of stock options, SARs, restricted stock, restricted units, unrestricted stock and incentive awards.

Although we have not expressed any intent to do so, we have the right to amend, suspend, or terminate the 2006 Plan at any time by action of our Board of Directors.  However, no termination, amendment or modification of the 2006 Plan shall in any manner adversely affect any award theretofore granted under the 2006 Plan, without the written consent of the participant.  If a change in control were to occur (as defined in the plan documents), certain options may become immediately vested, but only upon termination of the option holder’s service.

Accounting for Stock-Based Compensation

Total compensation expense recognized for stock-based compensation (equity awards) during the year ended December 31, 2010, 2009 and 2008 was $11.1 million, $12.7 million and $13.9 million, respectively.  The total income tax benefit recognized in the consolidated statement of income for share based compensation arrangements during the year ended December 31, 2010, 2009 and 2008 was approximately $4.3 million, $5.0 million and $5.4 million, respectively. We recognize compensation expense on a straight-line basis over the vesting period for the entire award for any awards with graded vesting.

As of December 31, 2010 and 2009, there was $5.5 million and $5.8 million, respectively, of total unrecognized compensation cost related to stock options expected to be recognized over a weighted-average period of approximately 2.2 years.  In the years ended December 31, 2010, 2009, and 2008, we also reflected $0.0 million, $3.2 million, and ($1.2) million, respectively, of excess tax benefit (expense) as a financing cash flow in the consolidated statement of cash flows resulting from the exercise of stock options.

Equity instruments

We have granted stock options to employees under the 2006 Plan, the 1999 Plan and the 1996 Plan. These options typically have a requisite service period of three to four years, though there are some awards outstanding with requisite service periods of one year up to four years. Vesting generally occurs ratably over the requisite service period. The maximum contractual term of stock options granted is 10 years.

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We value stock options using the Black-Scholes valuation model, which employs certain key assumptions.  We estimate volatility using both historical and market data over the term of the options granted.  The dividend yield is calculated on the current annualized dividend payment and the stock price at the date of grant.  The expected option life is based on historical data and exercise behavior.  The risk-free interest rate is based on the zero-coupon Treasury bond rate in effect at the date of grant.  The fair value of options granted during the three years ended December 31, 2010, 2009 and 2008 was calculated using the following assumptions:

	Year Ended December 31,
Options Granted	2010			2009			2008
Number of shares underlying options		158,226			234,333			798,647
Contractual term in years		10			10			10
Assumptions used to estimate fair value:
Expected volatility		65	%		59% - 66	%		50% - 100	%
Weighted average volatility		65	%		66	%		71	%
Expected option life in years		4.3			4.3			1.3 - 4.3
Dividend yield		0.5%-0.8	%		0.7% - 1.8	%		0.4% - 1.5	%
Risk-free interest rate		1.2%-1.3	%		1.7% - 1.9	%		0.9% - 3.1	%
Weighted-average fair value estimates at grant date:
In thousands	$	3,835		$	3,845		$	6,820
Fair value per share	$	24.24		$	16.41		$	8.54

A summary of option activity under the plans for the year ended December 31, 2010 is presented below:

						Weighted
				Weighted		average
	Number of			average exercise		contractual		Aggregate
	Options			price		term (years)		Intrinsic Value
	(In Thousands, Except Exercise Price and Contractual Term)
Outstanding at December 31, 2009		2,053		$	27.05
Granted		158			49.13
Exercised		(718	)		25.53
Forfeited/expired		(64	)		30.37
Outstanding at December 31, 2010		1,429		$	30.12		6.7	$	33,624
Exercisable at December 31, 2010		962		$	28.44		5.7	$	24,245

We received $18.3 million, $11.3 million and $16.5 million in cash proceeds from the exercise of stock options for the years ended December 31, 2010, 2009 and 2008, respectively.  The intrinsic value of stock options exercised was $14.0 million, $7.5 million and $18.4 million for the years ended December 31, 2010, 2009 and 2008, respectively.

We have granted restricted stock to our employees under the 2006 Plan and 1999 Plan and to non-employee directors under the 1995 Plan and 1997 Plan. Restricted stock awards are valued on the date of grant based on the closing value of our stock.  As of December 31, 2010, there was $11.4 million of unrecognized compensation cost related to restricted stock expected to be recognized over the next three years.  Unearned compensation is recorded on a net basis in Additional capital.

A summary of the status of restricted stock at December 31, 2010, and changes for the year then ended is presented below:

				Weighted average
				grant date
(Shares In Thousands)	Shares			fair value
Unvested at December 31, 2009		576		$	28.48
Granted		165		$	48.20
Vested		(260	)	$	28.00
Forfeited		(90	)	$	34.41
Unvested at December 31, 2010		391		$	35.75

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The fair value of restricted stock vested during the years ended December 31, 2010, 2009, and 2008 was $7.3 million, $7.0 million and $6.7 million, respectively.

Liability instruments

We use the fair value method to recognize compensation cost associated with SARs.  During 2010 all outstanding SARs were exercised. At December 31, 2009 there were 150,000 SARs outstanding and exercisable.  The weighted average exercise price of these SARs was $36.50 per SAR at December 31, 2009; the weighted average contractual term was 5.3 years at December 31, 2009.

We also issue stock incentive units, which are classified as liabilities. They are settled with a cash payment for each unit vested, equal to the fair market value of Common Stock on the vesting date.

	For the years ended December 31,
	2010		2009
Awarded		85,238		218,364
Settled		132,410		150,829
Settlement amount (in millions)	$	6.1	$	5.2

17. Lease Obligations

We lease 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 or other non-performance covenants that may require an accelerated buyout of the lease if the covenants are violated.  Rental expense for the years ended December 31, 2010, 2009 and 2008 was $96.0 million, $81.8 million and $53.1 million, respectively.

During 2010 and 2008 we sold and leased-back certain mining equipment. We received net proceeds of $16.5 million and $41.3 million, for the years ended December 31, 2010 and 2008, respectively, resulting in net deferred gains of $0.5 million and $2.4 million, respectively. The gains are being recognized ratably over the term of the leases, which range from 4 to 8 years. At lease termination, the leases contain renewal and purchase options at an amount approximating fair value. The leases are being accounted for as operating leases. We did not engage in any material sale-leaseback transactions in 2009.

The following presents future minimum rental payments, by year, required under leases with initial terms greater than one year, in effect at December 31, 2010:

	Capital Leases		Operating Leases
	(In Thousands)
2011	$	2,680	$	92,135
2012		35		78,758
2013		35		52,049
2014		35		20,480
2015		—		11,190
Beyond 2015		—		—
Total minimum lease payments		2,795	$	254,612
Less imputed interest		38
Present value of minimum capital lease payments	$	2,747

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18. Concentrations of Credit Risk and Major Customers

We are engaged in the production of coal for the utility industry, steel industry and industrial markets.  The following chart lists the percentage of each type of Produced coal revenue generated by market:

	For the years ended December 31,
	2010			2009			2008
Utility coal		61	%		62	%		53	%
Metallurgical coal		31	%		30	%		37	%
Industrial coal		8	%		8	%		10	%

Our mining operations are conducted in southern West Virginia, eastern Kentucky and western Virginia.  We market our produced and purchased coal to customers in the United States and in international markets, including Canada and various European and Asian countries.  For the years ended December 31, 2010, 2009 and 2008 approximately 21%, 20% and 30%, respectively, of Produced coal revenue was attributable to sales to customers outside of the United States.

For the years ended December 31, 2009 and 2008, approximately 19% and 11%, respectively, of Produced coal revenue was attributable to sales to Constellation Energy Commodities Group, Inc. No single customer accounted for 10% or more of fiscal year 2010 Produced coal revenue or produced tons. At December 31, 2010, approximately 34%, 52% and 14% of Trade receivables represents amounts due from utility customers, metallurgical customers and industrial customers, respectively, compared with 61%, 19% and 20%, respectively, as of December 31, 2009.

Our Trade and other accounts receivable are subject to potential default by customers.  In prior years, certain of our customers have filed for bankruptcy resulting in bad debt charges.  In an effort to mitigate credit-related risks in all customer classifications, we maintain a credit policy, which requires scheduled reviews of customer creditworthiness and continuous monitoring of customer news events 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 guarantees or, ultimately, a suspension of credit privileges.  We also insure the receivables of certain customers whose financial condition puts them at a greater risk of loss; recoveries under this insurance program are subject to 10% co-insurance and a $4 million deductible. We establish bad debt reserves to specifically consider customers in financial difficulty and other potential receivable losses.  In establishing the reserve, we consider the financial condition of individual customers and probability of recovery in the event of default.  We charge off uncollectible receivables once legal potential for recovery is exhausted.  See Note 22 for a discussion of certain customer disputes.

19. Derivative Instruments

Upon entering into each coal sales and coal purchase contract, we evaluate each of our contracts to determine if it qualifies for the NPNS exception prescribed by current accounting guidance.  We use coal purchase contracts to supplement our produced and processed coal in order to provide coal to meet customer requirements under sales contracts.  We are exposed to certain risks related to coal price volatility.  The purchases and sales contracts we enter into allow us to mitigate a portion of the underlying risk associated with coal price volatility.  The majority of our contracts qualify for the NPNS exception and therefore are not accounted for at fair value.  For those contracts that do not qualify for the NPNS exception at inception or lose their designation at some point during the duration of the contract, the contracts are required to be accounted for as derivative instruments and must be recognized as assets or liabilities and measured at fair value.  Those contracts that do not qualify for the NPNS exception have not been designated as cash flow or fair value hedges and, accordingly, the net change in fair value is recorded in current period earnings.  Our coal sales and coal purchase contracts that do not qualify for the NPNS exception as prescribed by current accounting guidance are offset on a counterparty-by-counterparty basis for derivative instruments executed with the same counterparty under a master netting arrangement.

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Tons outstanding under coal purchase and coal sales contracts that do not qualify for the NPNS exception are as follows:

	December 31,		December 31,
	2010		2009
	(In Thousands)
Purchase contracts		360		980
Sales contracts		600		1,120

The fair values of our purchase and sales derivative contracts have been aggregated in the Consolidated Balance Sheets as of December 31, 2010 and December 31, 2009, as follows:

	December 31,		December 31,
	2010		2009
	(In Thousands)
Other current assets	$	15,424	$	30,564

We have recorded net gains related to coal sales and purchase contracts that did not qualify for the NPNS exception in the Consolidated Statements of Income under the caption Loss (gain) on derivative instruments.

	Year Ended December 31,
	2010			2009
	(In Thousands)
Realized (gains) losses due to settlements on existing contracts	$	(36,218	)	$	15,478
Unrealized losses (gains) on outstanding contracts		15,140			(53,116	)
Gain on derivative instruments	$	(21,078	)	$	(37,638	)

20. Fair Value of Financial Instruments

Financial and non-financial assets and liabilities that are required to be measured at fair value must be categorized based upon the levels of judgment associated with the inputs used to measure their fair value.  Hierarchical levels – directly related to the amount of subjectivity associated with the inputs used to determine the fair value of financial assets and liabilities – are as follows:

● Level 1 – Inputs are unadjusted, quoted prices in active markets for identical assets or liabilities at the measurement date.

● Level 2 – Inputs (other than quoted prices included in Level 1) are either directly or indirectly observable for the assets or liability through correlation with market data at the measurement date and for the duration of the instrument’s anticipated life.

● Level 3 – Inputs reflect management’s best estimate of what market participants would use in pricing the asset or liability at the measurement date.  Consideration is given to the risk inherent in the valuation technique and the risk inherent in the inputs to the model.

Each major category of financial assets and liabilities measured at fair value on a recurring basis are categorized in the tables below based upon the lowest level of significant input to the valuations.

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	December 31, 2010
	(In Thousands)
	Level 1		Level 2		Level 3		Total
Fixed income securities
U.S. Treasury securities	$	11,645	$	—	$	—	$	11,645
Certificates of Deposit		50,061		—		—		50,061
Money market funds
U.S. Treasury money market fund		20,399		—		—		20,399
Other money market funds		216,362		—		—		216,362
Derivative instruments		—		15,424		—		15,424
Total securities	$	298,467	$	15,424	$	—	$	313,891

	December 31, 2009
	(In Thousands)
	Level 1		Level 2		Level 3		Total
Fixed income securities
U.S. Treasury securities	$	12,147	$	—	$	—	$	12,147
Money market funds
U.S. Treasury money market fund		74,103		—		—		74,103
Other money market funds		689,470		—		—		689,470
Derivative instruments		—		30,564		—		30,564
Short-term investment		—		—		10,864		10,864
Total securities	$	775,720	$	30,564	$	10,864	$	817,148

Fixed income securities and money market funds

All fixed income securities are deposits, consisting of obligations of the United States Treasury and Certificates of Deposit (all insured by the Federal Deposit Insurance Corporation), supporting various regulatory obligations.  All investments in money market funds are cash equivalents or deposits pledged as collateral and are invested in prime money market funds and Treasury-backed funds.  Included in the money market funds are $59.4 million of funds pledged as collateral to support $58.2 million of outstanding letters of credit and $10.0 million associated with funding a portion of our deferred compensation obligation.  See Note 5 to the Notes to Consolidated Financial Statements for more information on deposits.

Derivative Instruments

Certain of our coal sales and coal purchase contracts that do not qualify for the NPNS exception at inception or lose their designation at some point during the life of the contract are accounted for as derivative instruments and are required to be recognized as assets or liabilities and measured at fair value.  To establish fair values for these contracts, we use bid/ask price quotations obtained from independent third-party brokers. We also consider the risk of nonperformance of or nonpayment by the counterparties when determining the fair values for these contracts by evaluating the credit quality and financial condition of each counterparty.  We could experience difficulty in valuing our derivative instruments if the number of third-party brokers should decrease or market liquidity is reduced.  See Note 19 to the Notes to Consolidated Financial Statements for more information.

Short-Term Investment

Short-term investment at December 31, 2009 was comprised of an investment in the Primary Fund, a money market fund that suspended redemptions and is being liquidated.  We determined that our investment in the Primary Fund as of December 31, 2009, no longer met the definition of a security, within the scope of current accounting guidance, since the equity investment no longer had a readily determinable fair value.  Therefore, the investment was classified as a short-term investment, subject to the cost method of accounting, on our Condensed Consolidated Balance Sheet.

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Assets Measured at Fair Value on a Recurring Basis Using Significant Unobservable Inputs (Level 3):

	Short-term
(In Thousands)	investment
Balance at December 31, 2009	$	10,864
Transfers out of Level 3		(15,526	)
Total gains or (losses) realized/unrealized included in earnings		4,662
Purchases, issuances, sales and settlements		—
Balance at December 31, 2010	$	—
Total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	—

At December 31, 2009, our investment in the Primary Fund was $10.9 million, net of a $6.5 million write-down recorded in 2008, which represented the difference between cost and estimated fair value.  During 2010, we received distributions totaling $15.6 million. We recorded a $4.7 million gain on short-term investments which represents the difference between book value and total redemptions received.  As of December 31, 2010, the estimated fair value of our unrecovered investment of $1.8 million in the Primary Fund was $0.

Asset and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances, for example, when there is evidence of impairment.

In accordance with relevant accounting requirements, Property, plant and equipment (which included mine development) and longwall panel costs located at or near the UBB mine with a carrying amount of $35.4 million and $28.2 million (of which $5.1 million was considered current assets and $23.1 million noncurrent assets), respectively, were deemed to be destroyed or probable of abandonment.  Additionally during 2010, we recorded $20.5 million of impairment charges for unamortized mine development costs at certain idled mines.

For the impairment tests, we compared the carrying value of the asset tested to its estimated fair value. The fair value was determined using the estimated undiscounted cash flows expected to be generated by the assets along with, where appropriate, market inputs.  The  remaining fair value of the impaired assets was deemed to be immaterial. The determination of fair value was based on our assumptions about future operations at these mines and possible alternatives to accessing the related coal reserves.  Specifically, given the ongoing investigations into the cause of the UBB tragedy and the uncertainty around the future operations at the UBB mine, there is a reasonable possibility that additional impairments could be recorded in future periods.

Other Financial Instruments

The following methods and assumptions were used to estimate the fair value of those financial instruments that are not required to be carried at fair value within our Consolidated Balance Sheets:

Short-term debt: The carrying amount reported in the Consolidated Balance Sheets for short-term debt approximates its fair value due to the short-term maturity of these instruments.

Long-term debt: The fair values of long-term debt are estimated using the most recent market prices quoted on or before December 31, 2010.

The carrying amounts and fair values of these financial instruments are presented in the table below. The carrying value of the 3.25% Notes reflected in Long-term debt in the table below reflects the full face amount of $659.1 million rather than the adjusted discounted value reflected in the Consolidated Balance Sheets (see Note 10 to the Notes to Consolidated Financial Statements for more information).

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	December 31, 2010				December 31, 2009
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In Thousands)
Short-term debt	$	12,327	$	12,327	$	23,531	$	23,465
Long-term debt	$	1,419,063	$	1,419,627	$	1,428,710	$	1,348,699

21. Common Stock

 On October 6, 2010, the Company’s stockholders approved an increase in the number of common shares authorized from 150,000,000 shares to 300,000,000 shares.

Common Stock Issuance

On March 23, 2010, we completed a registered underwritten public offering of 9,775,000 shares of our Common Stock at a public offering price of $49.75 per share, resulting in proceeds to us of $466.7 million, net of fees.  In April 2010, we used the net proceeds of this offering and 6,519,034 shares of Common Stock (fair valued at $289.5 million on the day of the acquisition) to fund a portion of the consideration for the acquisition of Cumberland.  See Note 3 to the Notes to Consolidated Financial Statements for a more complete discussion of the acquisition of Cumberland.

Common Stock Repurchases

During 2010, we repurchased 861,439 shares of Common Stock at an average price of $36.92, for a total cost of $31.8 million.  The Common Stock was repurchased under a stock repurchase program (the “Repurchase Program”) authorized by our Board of Directors on November 14, 2005, authorizing us to repurchase shares of Common Stock from time to time up to an aggregate amount not to exceed $500 million, as market conditions warrant and existing covenants permit.  Prior to this share repurchase, we had $420 million available under the 2005 authorization.   Shares repurchased in 2010 have been recorded as Treasury stock in the Consolidated Balance Sheet.

22. Contingencies

West Virginia Flooding

Since August 2004, five of our subsidiaries have been sued in six civil actions filed in the Circuit Courts of Boone, McDowell, Mingo, Raleigh, Summers and Wyoming Counties, West Virginia, for alleged property damages and personal injuries arising out of flooding on or about May 2, 2002.  These complaints covered approximately 350 plaintiffs seeking unquantified compensatory and punitive damages from approximately 35 defendants.  Of these cases two were dismissed by the court without prejudice for failure to prosecute, two were dismissed by plaintiffs voluntarily and with prejudice, and one was settled for a nominal amount.  Only the Mingo County case comprised of 4 plaintiffs and 34 defendants remains active.

Since May 2006, we and 12 of our subsidiaries have been sued in three civil actions filed in the Circuit Courts of Logan and Mingo Counties, West Virginia, for alleged property damages and personal injuries arising out of flooding between May 30 and June 4, 2004.  These complaints cover approximately 400 plaintiffs seeking unquantified compensatory and punitive damages from approximately 52 defendants.  Four of our subsidiaries have been dismissed without prejudice from one of the Logan County cases.

We believe the remaining cases will be resolved without a material adverse impact on our cash flows, results of operations or financial condition.

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        West Virginia Trucking

Since January 2003, an advocacy group and residents in Boone, Kanawha, Mingo and Raleigh Counties, West Virginia, filed 17 suits in the Circuit Courts of Kanawha and Mingo Counties, West Virginia, against 12 of our 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 compensatory and punitive damages.  The Supreme Court of Appeals of West Virginia (“WV Supreme Court”) referred the consolidated lawsuits, and similar lawsuits against other coal and transportation companies not involving our subsidiaries, to the Circuit Court of Lincoln County, West Virginia (“Circuit Court”), to be handled by a mass litigation panel judge. Plaintiffs filed motions requesting class certification. On June 7, 2007, plaintiffs voluntarily dismissed their public nuisance claims seeking monetary damages for road and bridge repairs.  Plaintiffs also agreed to an order limiting any damages for nuisance to two years prior to the filing of any suit.  A motion to dismiss any remaining public nuisance claims was resisted by plaintiffs and argued at hearings on December 14, 2007 and June 25, 2008.  No rulings on these matters have been made.  Defendants filed a motion requesting that the mass litigation panel judge recommend to the WV Supreme Court that the cases be sent back to the circuit courts of origin for resolution.  That motion was verbally denied as to those cases in which our subsidiaries are defendants, and a class certification hearing was held on October 21, 2009.  To date, no decision has been rendered by the Circuit Court on the class certification issues.  No date has been set for trial. A mediation is being scheduled in the Mingo County case.  We believe we have insurance coverage applicable to these items and that they will be resolved without a material adverse impact on our cash flows, results of operations or financial condition.

    Well Water Suits

Since September 2004, approximately 738 plaintiffs have filed approximately 400 suits against us and our subsidiary, Rawl Sales & Processing Co., in the Circuit Court of Mingo County, West Virginia (“Mingo Court”), for alleged property damage and personal injuries arising out of slurry injection and impoundment practices allegedly contaminating plaintiffs’ water wells. Plaintiffs seek injunctive relief and compensatory damages in excess of $170 million and unquantified punitive damages.  Specifically, plaintiffs are claiming that defendants’ activities during the period of 1978 through 1987 rendered their property valueless and request monetary damages to pay, inter alia, the value of their property and future water bills.  In addition, many plaintiffs are also claiming that their exposure to the contaminated well water caused neurological injury or physical injury, including cancers, kidney problems and gall stones.  Finally, all plaintiffs claimed entitlement to medical monitoring for the next 30 years and have requested unliquidated compensatory damages for pain and suffering, annoyance and inconvenience and legal fees.  On April 30, 2009, the Mingo Court held a mandatory settlement conference. At that settlement conference, all plaintiffs agreed to settle and dismiss their medical monitoring claims.  Additionally, 180 plaintiffs agreed to settle all of their remaining claims and be dismissed from the case.  All settlements to date will be funded by insurance proceeds.  Plaintiffs challenged the medical monitoring settlement. There are currently 585 plaintiffs with individual claims.  A number of motions that could impact the number of Plaintiffs and scope of the issues of these suits are pending.

The West Virginia Supreme Court issued an administrative order transferring the cases to the Mass Litigation Panel.  Mediation of all pending suits was held on February 22-23, 2011 in Charleston, West Virginia.  The mediation resulted in the final settlement of all medical monitoring claims and disposed of Plaintiffs’ earlier challenge of the prior medical monitoring settlement.  The medical monitoring claims will be paid by insurance proceeds.  No other claims were resolved.  A previous mediation conducted in November 2010 was unsuccessful.  A trial date has been set for August 2011. 

Beginning in December 2008, we and certain of our subsidiaries along with several other companies were sued in numerous actions in Boone County, West Virginia involving approximately 374 plaintiffs alleging well water contamination resulting from coal mining operations.  The claims mirror those made above in the separate action before the Mass Litigation Panel, as described above. The separate civil actions have been consolidated for discovery purposes with trial for 266 plaintiffs scheduled for October 25, 2011.  No trial date is set for the remaining approximately 108 plaintiffs.

We do not believe there was any contamination caused by our activities or that plaintiffs suffered any damage and we believe that we have strong defenses to these matters.  We plan to vigorously contest these claims.  We believe that we have insurance coverage applicable to these matters and have initiated litigation against our insurers to establish that coverage.  At this time, we believe that the litigation by the plaintiffs will be resolved without a material adverse impact on our cash flows, results of operations or financial condition.

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         Surface Mining Fills

Since September 2005, three environmental groups sued the Corps in the United States District Court for the Southern District of West Virginia (the “District Court”), asserting the Corps unlawfully issued permits to four of our surface mines to construct mining fills. The suit alleges the Corps failed to comply with the requirements of both Section 404 of the Clean Water Act and the National Environmental Policy Act, including preparing environmental impact statements for individual permits. We intervened in the suit to protect our interests. On March 23, 2007, the District Court rescinded four of our subsidiaries’ permits, resulting in the temporary suspension of mining at these surface mines. We appealed that ruling to the United States Court of Appeals for the Fourth Circuit (the “Fourth Circuit Court”). On April 17, 2007, the District Court partially stayed its ruling, permitting mining to resume in certain fills that were already under construction. On June 14, 2007, the District Court issued an additional ruling, finding the Corps improperly approved placement of sediment ponds in streams below fills on the four permits in question.  The District Court subsequently modified its ruling to allow these ponds to remain in place, as the ponds and fills have already been constructed.  The District Court’s ruling could impact the issuance of permits for the placement of sediment ponds for future operations. If the permits for the fills or sediment ponds are ultimately held to be unlawfully issued, production could be affected at these surface mines, and the process of obtaining new Corps permits for all surface mines could become more difficult. We appealed both rulings to the Fourth Circuit Court.  On February 13, 2009, the Fourth Circuit Court reversed the prior rulings of the District Court and remanded the matter for further proceedings. On March 30, 2009, the plaintiffs requested that the Fourth Circuit Court reconsider the case.  The request was denied on May 20, 2009. On August 26, 2009, the plaintiffs filed their request with the United States Supreme Court to review the Fourth Circuit Court’s decision.  Our subsidiaries’ response was due on August 5, 2010. However, on August 3, 2010, the plaintiffs moved to withdraw their petition in the wake of a new policy adopted by the Corps and the Environmental Protection Agency on July 30, 2010 for assessing “stream ecosystem structure and function” for Appalachian surface coal mining. The motion to withdraw the petition for certiorari was granted, thereby finalizing the Fourth Circuit Court’s decision.

        Customer Disputes

We have been sued by one customer who claims they did not receive, or did not timely receive, all of the coal required to be shipped to them during prior years under their sales contract. This customer filed a claim for cover damages, which damages are equal to the difference between the contract price of the coal that was not delivered and the market price of replacement coal or comparable quality coal, and for other compensatory damages, the total of which could exceed $31 million.  The customer is also seeking punitive damages.  We believe that we have strong defenses and have not recorded an accrual for this matter because we do not believe a loss is probable.  It is reasonably possible that our judgment regarding this matter could change in the near term, resulting in the recording of a material loss that would affect our operating results and financial position.

Subsequent to December 31, 2010, we received notice of a suit from a plaintiff regarding whether or not a binding contract existed for the sale of coal, which coal the plaintiff had planned to broker to a third party in 2008.  The suit asks that we reimburse plaintiff for an $18 million court judgment against plaintiff awarded to the third party.  We do not believe that a binding sales contract was reached and currently believe that we have strong defenses and, therefore, have not recorded an accrual for this matter because we do not believe a loss is probable. It is reasonably possible that our judgment regarding this matter could change in the near term, resulting in the recording of a material loss that would affect our operating results and financial position.

Separately, we are currently in litigation with one customer regarding whether or not binding contracts for the sale of coal were reached.  We maintain that this customer improperly terminated a signed, higher-priced contract; the customer argues that it was only required to purchase coal under a purported agreement reached by email. On February 12, 2010, we received a decision from an arbitration panel awarding this customer $10.5 million on the grounds that the purported agreement by email was valid and that the higher-priced contract was invalid.  We believed that the arbitration panel’s decision as to the validity of the higher-priced contract was beyond the panel’s jurisdiction of the award, which amounts to $8.2 million, and challenged that decision in federal court.  On June 2, 2010, the federal court rejected our challenge.  We are appealing this matter to the Fourth Circuit Court.  While we will vigorously pursue this appeal, we have accrued the remainder of the judgment in Other current liabilities at December 31, 2010.  We have paid $2.3 million for the award relating to the panels’ decision that the agreement by email was valid, but have not yet paid the portion of the award under appeal.

         Spartan Unfair Labor Practice Matter & Related Age Discrimination Class Action

In 2005, the UMWA filed an unfair labor practice charge with the National Labor Relations Board (“NLRB”) alleging that one of our subsidiaries, Spartan Mining Company (“Spartan”), discriminated on the basis of anti-union animus in its employment offers.  The NLRB issued a complaint and an NLRB Administrative Law Judge (“ALJ”) issued a recommended decision making detailed findings that Spartan committed a number of unfair labor practice violations and awarding, among other relief, back pay damages to union discriminatees.  On September 30, 2009, the NLRB upheld the ALJ’s recommended decision.  Spartan has appealed the NLRB’s decision to the Fourth Circuit Court. We have no insurance coverage applicable to this unfair labor practice matter; however, its resolution is not expected to have a material impact on our cash flows, results of operations or financial condition.

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        Upper Big Branch Mine

 On April 5, 2010, an accident occurred at the UBB mine, tragically resulting in the deaths of 29 miners and seriously injuring two others.  The Federal Mine Safety and Health Administration (“MSHA”) and the State of West Virginia have undertaken a joint investigation into the cause of the UBB tragedy.  We also have commenced our own investigation.  We believe these investigations will continue for the foreseeable future, and we cannot provide any assurance as to their outcome, including whether we become subject to possible criminal and civil penalties or enforcement actions. Additionally, the U.S. Attorney for the Southern District of West Virginia has commenced a grand jury investigation. In order to accommodate these investigations, the UBB mine will be closed for an extended period of time, the length of which we cannot predict at this time.  It is also possible that we may decide or be required by regulators to permanently close the UBB mine.  We self-insure the underground mining equipment, including the longwalls at the UBB mine.  We do not currently carry business interruption insurance for the UBB mine.  We have third-party general liability insurance coverage that applies to litigation risk, which coverage we believe applies to litigation stemming from the UBB tragedy.

While updated analyses will continue in future periods, we have recorded our best estimate of probable losses related to this matter.  The most significant components of these losses related to: the benefits being provided to the families of the fallen miners (see Note 15 to the Notes to Consolidated Financial Statements for more information about the significant benefits provided), costs associated with the rescue and recovery efforts, possible legal and other contingencies, and asset impairment charges (see Note 6 to the Notes to Consolidated Financial Statements for more information).  We have recorded a $78 million liability in Other current liabilities at December 31, 2010, which represents our best estimate of the probable loss related to potential future litigation settlements associated with the UBB tragedy.  Two of the families have filed wrongful death suits against us, while seven families have signed agreements to settle their claims (four of which have been finalized after receiving the required judicial approval).  Insurance recoveries related to our general liability insurance policy that are deemed probable and that are reasonably estimable have been recognized in the Consolidated Statements of Income to the extent of the related losses, less applicable deductibles.  Such recognized recoveries for litigation settlements associated with the UBB tragedy totaled $78 million and are included in Trade and other accounts receivable at December 31, 2010.

Given the uncertainty of the outcome of current investigations, including whether we become subject to possible civil penalties or enforcement actions, it is possible that the total costs incurred related to this tragedy could exceed our current estimates.  As of December 31, 2010, we believe that the reasonably possible aggregate loss related to these claims in excess of amounts currently recorded cannot be estimated.  It is possible, however, that the ultimate liabilities in the future with respect to these claims, in the aggregate, may be material.  We will continue to review the amount of any necessary accruals, potential asset impairments, or other related expenses and record the charges in the period in which the determination is made and an adjustment is required.

        Clean Water Act Citizens’ Suits

The Sierra Club and others have filed two citizens’ suits against several of our subsidiaries in federal court in the Southern District of West Virginia (“Southern District Court”) alleging violations of the terms of our water discharge permits. One of the cases is limited to allegations that two of our subsidiaries, Independence Coal Company and Jacks Branch Coal Company, are violating limits on the allowable concentrations of selenium in their discharges of storm water from several surface mines. The other action is limited to claims that several of our subsidiaries are violating discharge limits on substances other than selenium, such as aluminum. The plaintiffs in these cases seek both a civil penalty and injunctive relief.

In the non-selenium case, we have argued that the alleged violations are contemplated by an existing consent decree with the United States government and should not be the subject of a new lawsuit, but the Southern District Court has allowed the case to progress.  In the selenium case, we have argued that the limits on selenium concentrations in our discharges have been stayed by an order of the West Virginia Environmental Quality Board and therefore cannot be the subject of a Clean Water Act case until after those limits become effective. The plaintiffs have nonetheless filed a motion for summary judgment in the selenium case, arguing that we are in violation of our permit limits despite the stays. The plaintiffs have also filed reports of experts contending that our subsidiaries should have commenced construction on selenium treatment units in October 2008.  They claim that the failure to do so has saved our subsidiaries over $100 million, and that the Southern District Court should impose a penalty which recoups all of the “savings” realized by the alleged non-compliance.  We strongly disagrees with plaintiffs’ position and do not expect the resolution of this matter to have a material impact on our cash flows, results of operations or financial condition.

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         Other Legal Proceedings

We are parties to a number of other legal proceedings, incident to our normal business activities.  These include, for example, contract disputes, personal injury claims, property damage claims, environmental issues, and employment and safety matters.While we cannot predict the outcome of any of these proceedings, based on our current estimates we do not believe that any liability arising from these matters individually or in the aggregate should have a material adverse impact upon our consolidated cash flows, results of operations or financial condition.  It is possible, however, that the ultimate liabilities in the future with respect to these lawsuits and claims, in the aggregate, may be materially adverse to our cash flows, results of operations or financial condition.

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23. Quarterly Information (Unaudited)

The table below details our quarterly financial information for the previous two fiscal years.

	Three Months Ended
	March 31,  2010 (1)		June 30,  2010 (2)			September 30,  2010 (3)			December 31,  2010 (4)
	(In Thousands, Except Per Share Amounts)
Total revenue	$	688,639	$	810,148		$	810,164		$	730,023
Income (loss) before interest and taxes		66,795		(110,805	)		(30,457	)		(63,842	)
Income (loss) before taxes		46,822		(135,750	)		(55,056	)		(89,613	)
Net income (loss)		33,626		(88,714	)		(41,424	)		(70,075	)
Net income (loss) per share:
Basic	$	0.39	$	(0.88	)	$	(0.41	)	$	(0.69	)
Diluted	$	0.39	$	(0.88	)	$	(0.41	)	$	(0.69	)

	Three Months Ended
	March 31,  2009 (5)		June 30,  2009		September 30, 2009 (6)		December 31, 2009 (7)
	(In Thousands, Except Per Share Amounts)
Total revenue	$	768,088	$	697,627	$	641,560	$	583,884
Income before interest and taxes		72,750		48,705		45,783		59,738
Income before taxes		56,391		26,059		20,880		33,935
Net income		43,426		20,192		16,458		24,357
Net income per share:
Basic	$	0.51	$	0.24	$	0.19	$	0.29
Diluted	$	0.51	$	0.24	$	0.19	$	0.28

(1) Net income in the first quarter of 2010 includes $9.1 million in insurance proceeds, resulting in a $5.8 million pre-tax gain on insurance recovery related to the Bandmill preparation plant fire.

(2) The results of the second quarter of 2010 were negatively impacted by the following pre-tax items: $128.9 million estimated expense related to the UBB mine tragedy (see Notes 6, 15 and 22 to the Notes to Consolidated Financial Statements for further discussion), $8.5 million charge recorded in relation to a customer pricing dispute and a $5.0 million bad debt reserve related to a note receivable from a supplier.  The results of the second quarter of 2010 were favorably impacted by the following pre-tax items: $9.7 million from the settlement of certain claims against a service provider, $7.2 million related to the sale of a claim in a customer bankruptcy proceeding, and a gain of $3.6 million on exchanges of coal reserves.

(3) The results of the third quarter of 2010 were negatively impacted by a $14.5 million pre-tax expense for ongoing investigation costs related to the UBB mine tragedy (see Notes 6, 15, and 22 to the Notes to Consolidated Financial Statements for further discussion)

(4) The results of the fourth quarter of 2010 were negatively impacted by a $17.8 million pre-tax charge for impairments of idled mines, a $12.0 million pre-tax expense for benefits provided to our former Chairman and CEO in accordance with his retirement agreement, and by a $23.1 million pre-tax expense for ongoing investigation cost related to the UBB mine tragedy (see Notes 6, 15, and 22). The results of the fourth quarter of 2010 were favorably impacted by a $12.6 million pre-tax gain on insurance recovery related to the Bandmill preparation plant fire.

(5) Net income for the first quarter of 2009 included the recognition of $12.2 million in pre-tax income ($5.1 million benefit recorded in Cost of purchased coal revenue and $7.1 million in interest income) from the receipt of black lung excise tax refunds as authorized by federal legislation passed in October 2008. Additionally, during the first quarter of 2009, we sold our interest in certain coal reserves to a third party, recognizing a pre-tax gain of $7.1 million in Other revenue.

(6) Net income for the third quarter of 2009 includes a $24.9 million pre-tax gain on the exchange of coal reserves.

(7) The results for the fourth quarter of 2009 included the impact of a $6.0 million pre-tax reserve for bad debt related to a note receivable from a supplier.

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24. Subsequent Events

On January 28, 2011, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Alpha Natural Resources, Inc., a Delaware corporation (“Alpha”), and Mountain Merger Sub, Inc., a Delaware corporation and a wholly owned subsidiary of Alpha (“Merger Sub”), providing for the acquisition of Massey Energy Company (“Massey”) by Alpha.  Subject to the terms and conditions of the Merger Agreement, Massey will be merged with and into Merger Sub (the “Merger”), with Massey surviving the Merger as a wholly owned subsidiary of Alpha.

At the effective time of the Merger, each share of Common Stock issued and outstanding immediately prior to the effective time (other than shares owned by (i) Alpha, us or Merger Sub or their respective subsidiaries (which will be cancelled) or (ii) stockholders who have properly exercised and perfected appraisal rights under Delaware law) will be converted into the right to receive 1.025 shares of Alpha common stock and $10.00 in cash, without interest (the “Massey Merger Consideration”).  No fractional shares of Alpha common stock will be issued in the Merger, and Massey stockholders will receive cash in lieu of fractional shares, if any, of Common Stock. Immediately upon completion of the Merger, Massey stockholders will own approximately 46% of the combined company.

The consummation of the Merger is subject to certain conditions, including (i) the adoption by Massey stockholders of the Merger Agreement and (ii) the approval by the Alpha stockholders of (x) an amendment to Alpha’s certificate of incorporation to increase the number of shares of Alpha common stock that Alpha is authorized to issue in order to permit issuance of the Alpha common stock in connection with the Merger and (y) the issuance of Alpha common stock in connection with the Merger.  In addition, the Merger is subject to clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, as well as other customary closing conditions.

The Merger Agreement contains customary covenants, including covenants providing for each of the parties: (i) to conduct its operations in all material respects according to the ordinary and usual course of business consistent with past practice during the period between the execution of the Merger Agreement and the closing of the Merger; (ii) to use reasonable best efforts to cause the transaction to be consummated; (iii) not to initiate, solicit or knowingly encourage inquiries, proposals or offers relating to alternate transactions or, subject to certain exceptions, engage in any discussions or negotiations with respect thereto; and (iv) to call and hold a special stockholders’ meeting and, subject to certain exceptions, recommend adoption of the Merger Agreement, in our case, and amendment of the Alpha certificate of incorporation and issuance of Alpha common stock in connection with the Merger, in the case of Alpha.

The Merger Agreement also contains certain termination rights and provides that, (i) upon termination of the Merger Agreement under specified circumstances, including, but not limited to, a change in the recommendation of the Massey board of directors or termination of the Merger Agreement to enter into a written definitive agreement for a “superior proposal”, Massey will owe Alpha a cash termination fee of $251 million; (ii) upon the termination of the Merger Agreement under specified circumstances, including, but not limited to, a change in the recommendation of the board of directors of Alpha or termination of the Merger Agreement to enter into a written definitive agreement for a “superior proposal”, Alpha will owe Massey a cash termination fee of $252 million; and (iii) upon the termination of the Merger Agreement due to Alpha’s failure to obtain the required stockholder approval at the Alpha stockholders’ meeting in the absence of a competing proposal, Alpha will owe Massey a cash termination fee of $72 million. In addition, Alpha is obligated to pay a cash termination fee of $360 million to us if all the conditions to closing have been met and the Merger is not consummated because of a breach by Alpha’s lenders of their obligations to finance the Merger.

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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

We have established disclosure controls and procedures to ensure that information relating to us, including our consolidated subsidiaries, required to be disclosed in the reports that we file or submit under the Exchange Act, is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of the end of the period covered by this report.

Based on our evaluation as of December 31, 2010, the principal executive officer and principal financial officer have concluded that the disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed in reports that we file or furnish under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There has been no change in our internal control over financial reporting during the quarter ended December 31, 2010, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. The completion of the Cumberland Acquisition will expand the Company’s internal control over financial reporting.

In reliance on guidance set forth in Question 3 of a “Frequently Asked Questions” interpretative release issued by the Staff of the SEC’s Office of the Chief Accountant and the Division of Corporation Finance in September 2004, as revised on September 24, 2007, regarding Securities Exchange Act Release No. 34-47986, Management’s Report on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, our management determined that it would exclude the business of Cumberland from the scope of its assessment of changes in internal control over financial reporting for the year ended December 31, 2010.  The reason for this exclusion is that we acquired Cumberland in April 2010 and it was not possible for management to conduct an assessment of internal control over financial reporting in the period between the date the acquisition was completed and the date of management’s assessment.  Accordingly, management excluded Cumberland from its assessment of changes to internal control over financial reporting during the year ended December 31, 2010.  Cumberland’s total assets represent 22% of the Company’s total assets and total revenues represent 14% of the Company’s total revenues as reflected in the Company’s Consolidated Financial Statements as of and for the year ended December 31, 2010. Cumberland will be included in management’s assessment of internal control over financial reporting starting no later than our annual assessment for the fiscal year beginning January 1, 2011.

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 Annual Report on 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.

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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, 2010. 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, 2010, internal control over financial reporting is effective.

In reliance on guidance set forth in Question 3 of a “Frequently Asked Questions” interpretative release issued by the Staff of the SEC’s Office of the Chief Accountant and the Division of Corporation Finance in September 2004, as revised on September 24, 2007, regarding Securities Exchange Act Release No. 34-47986, Management’s Report on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, our management determined that it would exclude the business of Cumberland Resources Corporation and certain affiliated entities ("Cumberland") from the scope of its assessment of the effectiveness of internal control over financial reporting for the year ended December 31, 2010.  The reason for this exclusion is that we acquired Cumberland in April 2010 and it was not possible for management to conduct an assessment of internal control over financial reporting in the period between the date the acquisition was completed and the date of management’s assessment.  Accordingly, management excluded Cumberland from its assessment of the effectiveness of internal control over financial reporting during the year ended December 31, 2010.  Cumberland’s total assets represent 22% of the Company’s total assets and total revenues represent 14% of the Company’s total revenues as reflected in the Company’s Consolidated Financial Statements as of and for the year ended December 31, 2010. Cumberland will be included in management’s assessment of the effectiveness of internal control over financial reporting starting no later than our annual assessment for the fiscal year beginning January 1, 2011.

The effectiveness of our internal control over financial reporting as of December 31, 2010, has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report, which follows immediately hereafter.

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of Massey Energy Company

We have audited Massey Energy Company’s internal control over financial reporting as of December 31, 2010 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 included in the accompanying Management Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, 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.

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.

As indicated in the accompanying Management Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Cumberland Resources Corporation and certain affiliated entities ("Cumberland"), which is included in the 2010 consolidated financial statements of Massey Energy Company and constituted 22% of total assets as of December 31, 2010 and 14% of revenues for the year then ended.  Our audit of internal control over financial reporting of Massey Energy Company also did not include an evaluation of the internal control over financial reporting of Cumberland.

In our opinion, Massey Energy Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based onthe COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2010 consolidated financial statements of Massey Energy Company and our report dated March 1, 2011 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Richmond, Virginia

March 1, 2011

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Part III

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant

Baxter F. Phillips, Jr., Age 64

Mr. Phillips has been a director since 2007.  He has been Chief Executive Officer since December 2010. He has been President since November 2008. Mr. Phillips previously served as Executive Vice President and Chief Administrative Officer from November 2004 to November 2008, as Senior Vice President and Chief Financial Officer from September 2003 to November 2004 and as Vice President and Treasurer from 2000 to August 2003. Mr. Phillips joined us in 1981 and has also served in the roles of Corporate Treasurer, Manager of Export Sales and Corporate Human Resources Manager, among others.

J. Christopher Adkins, Age 47

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

Mark A. Clemens, Age 44

Mr. Clemens has been Senior Vice President, Group Operations since July 2007. From January 2003 to July 2007, Mr. Clemens was President of Massey Coal Services, Inc. Mr. Clemens was formerly President of Independence Coal Company, Inc., one of our operating subsidiaries, from 2000 through December 2002 and our Corporate Controller from 1997 to 1999. Mr. Clemens has held a number of other accounting positions and has been with us since 1989. 

Michael K. Snelling, Age 54

Mr. Snelling has been Vice President, Surface Operations of our subsidiary, Massey Coal Services, Inc. since June 2005. Mr. Snelling was formerly Director of Surface Mining of Massey Coal Services, Inc. from July 2003 until May 2005. Mr. Snelling joined us in 2000 and has served us in a variety of capacities, including President of our subsidiary, Nicholas Energy Co. Prior to joining us, Mr. Snelling held various positions in the coal industry including engineer, production supervisor, plant supervisor, general foreman, manager of contract mining, superintendent, mine manager and vice president of operations.

Jeffrey M. Gillenwater, Age 46

Mr. Gillenwater has been Vice President, Human Resources since January 2009. In October 1999, Mr. Gillenwater became Director of Human Resources at our Massey Coal Services, Inc. subsidiary, and held the position of Director of External Affairs & Administration from October 2002 until January 2009. Prior to October 2002 he held the position of Human Resources Manager at several of our subsidiaries

Richard R. Grinnan, Age 42

Mr. Grinnan has been Vice President and Corporate Secretary since May 2006. He served as Senior Corporate Counsel from July 2004 until May 2006. Prior to joining us, Mr. Grinnan was a corporate and securities attorney at the law firm of McGuireWoods LLP in Richmond, Virginia from August 2000 until July 2004.

Andrew B. Hampton, Age 33

            Mr. Hampton has been Vice President, Corporate Development since August 2010.  He served as Senior Corporate Counsel from October 2008 until August 2010.  Prior to joining us, Mr. Hampton was an attorney serving in the legal department of Circuit City Stores, Inc. from November 2004 until October 2008.  Prior to joining Circuit City, Mr. Hampton was a corporate and securities attorney at the law firm of Williams Mullen from August 2002 until November 2004. 

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M. Shane Harvey, Age 41

Mr. Harvey has been Vice President and General Counsel since January 2008. He served as Vice President and Assistant General Counsel from November 2006 until January 2008 and as Corporate Counsel and Senior Corporate Counsel from April 2000 until November 2006. Prior to joining us, Mr. Harvey was an attorney at the law firm of Jackson Kelly PLLC in Charleston, West Virginia from May 1994 until April 2000.

Jeffrey M. Jarosinski, Age 51

Mr. Jarosinski was appointed Vice President, Treasurer and Chief Compliance Officer in February 2009. Prior to that he served as Vice President, Finance since 1998 and Chief Compliance Officer since December 2002. From 1998 through December 2002, Mr. Jarosinski was Chief Financial Officer. Mr. Jarosinski was formerly Vice President, Taxation from 1997 to 1998 and Assistant Vice President, Taxation from 1993 to 1997. Mr. Jarosinski joined us in 1988.

John M. Poma, Age 46

Mr. Poma has been Vice President and Chief Administrative Officer since January 2009.  Mr. Poma previously served as Vice President, Human Resources from April 2003 to January 2009. Mr. Poma served as Corporate Counsel from 1996 until 2000 and as Senior Corporate Counsel from 2000 through March 2003. Prior to joining us in 1996, Mr. Poma was an employment attorney with the law firms of Midkiff & Hiner in Richmond, Virginia and Jenkins, Fenstermaker, Krieger, Kayes & Farrell in Huntington, West Virginia.

Steve E. Sears, Age 62

Mr. Sears has been Vice President, Sales and Marketing, and President of our subsidiary Massey Coal Sales Company, Inc. since December 2008.  Mr. Sears served as President of Massey Industrial and Utility Sales, a division of Massey Coal Sales Company, Inc., from December 2006 to December 2008.  Mr. Sears has held various positions within the sales department.  He joined us in 1981.

Eric B. Tolbert, Age 43

Mr. Tolbert has been Vice President and Chief Financial Officer since November 2004. Mr. Tolbert served as Corporate Controller from 1999 to 2004. He joined us in 1992 as a financial analyst and subsequently served as Director of Financial Reporting.  Prior to joining us, Mr. Tolbert worked for the public accounting firm Arthur Andersen from 1990 to 1992.

David W. Owings, Age 37

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

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The following information is incorporated by reference from our 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, 2010:

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

● Information regarding our 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 our Code of Ethics required by this item is found under the heading Code of Ethics.

Because Common Stock is listed on the NYSE, ourchief 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 us of the corporate governance listing standards of the NYSE. Our former chief executive officer made his annual certification to that effect to the NYSE as of June 3, 2010 . In addition, we have filed, as exhibits to this annual report on Form 10-K, the certifications of our principal executive officer and principal financial officer required under Section 302 of the Sarbanes Oxley Act of 2002 to be filed with the SECregarding the quality of our public disclosure.

Item 11. Executive Compensation

Information required by this item is included in the Compensation Discussion and Analysis, Compensation of Named Executive Officers, Compensation Committee Interlocks and Insider Participation, and Compensation Committee Report on Executive Compensation 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 our fiscal year ended December 31, 2010.

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 and Stock Ownership of Certain Beneficial Owners 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 our fiscal year ended December 31, 2010.

The following table sets forth as of December 31, 2010, the number of shares of Common Stock authorized for issuance under our equity compensation plan. 

Plan Category	(a) Number of securities to be issued upon exercise of outstanding options, warrants and rights (1), (2)		(b) Weighted-average per share exercise price of outstanding options, warrants and rights (2)		(c) Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by shareholders		1,428,611	$	30.12		2,499,217
Equity compensation plans not approved by shareholders (3)		—		—		—
Total		1,428,611	$	30.12		2,499,217

(1) There are no outstanding warrants or rights.

(2) These amounts do not include shares to be issued upon vesting of restricted stock because they have no exercise price.

(3) We do not have any equity compensation plans that have not been approved by our stockholders.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information required by this item is included in the Certain Relationships and Related Transactions and Director Independence 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 our fiscal year ended December 31, 2010.

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Item 14. Principal Accountant Fees and Services

Information concerning principal accountant 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 our fiscal year ended December 31, 2010.

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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, 2010, 2009 and 2008

Consolidated Balance Sheets at December 31, 2010 and 2009

Consolidated Statements of Cash Flows for the Fiscal Years Ended December 31, 2010, 2009, and 2008

Consolidated Statements of Shareholders’ Equity for the Fiscal Years Ended December 31, 2010, 2009, and 2008

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
2.1	Agreement and Plan of Merger, dated as of January 28, 2011, among Mountain Merger Sub, Inc., Alpha Natural Resources, Inc. and Massey Energy Company [filed as Exhibit 2.1 to Massey’s current report on Form 8-K filed January 31, 2010 and incorporated by reference]
3.1	Amended and Restated Certificate of Incorporation of Massey Energy Company, effective October 6, 2010 [filed as Exhibit 3.1 to Massey’s current report on Form 8-K filed October 6, 2010 and incorporated by reference]
3.2	Amended and Restated Bylaws of the Company, effective as of December 3, 2010 [filed as Exhibit 3.2 to Massey’s current report on Form 8-K filed December 7, 2010 and incorporated by reference]
4.1	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, [filed as Exhibit 4.1 to Massey’s current report on Form 8-K filed May 30, 2003 and incorporated by reference]
4.2	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]
4.3	Third Supplemental Indenture, dated July 20, 2009, 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 2.25% Senior Notes [filed as Exhibit 4.1 to Massey’s quarterly report on Form 10-Q filed August 10, 2009 and incorporated by reference].
4.4	Fourth Supplemental Indenture, dated August 28, 2009, 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 2.25% Senior Notes [filed as Exhibit 4.1 to Massey’s quarterly report on Form 10-Q filed October 28, 2009 and incorporated by reference].
4.5	Fifth Supplemental Indenture, dated April 30, 2010, 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 2.25% convertible senior notes [filed as Exhibit 4.1 to Massey’s quarterly report on Form 10-Q filed August 9, 2010 and incorporated by reference]
4.6	Sixth Supplemental Indenture, dated June 29, 2010, 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 2.25% convertible senior notes [filed as Exhibit 4.4 to Massey’s quarterly report on Form 10-Q filed August 9, 2010 and incorporated by reference]

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4.7	Indenture, dated as of December 21, 2005,  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 6.875% Senior Notes [filed as Exhibit 4.1 to Massey’s current report on Form 8-K filed December 21, 2005, and incorporated by reference]
4.8	First Supplemental Indenture, dated July 20, 2009, 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 6.875% Senior Notes [filed as Exhibit 4.3 to Massey’s quarterly report on Form 10-Q filed August 10, 2009 and incorporated by reference].
4.9	Second Supplemental Indenture, dated August 28, 2009, 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 6.875% Senior Notes [filed as Exhibit 4.3 to Massey’s quarterly report on Form 10-Q filed October 28, 2009 and incorporated by reference].
4.10	Third Supplemental Indenture, dated April 30, 2010, 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 6.875% senior notes [filed as Exhibit 4.2 to Massey’s quarterly report on Form 10-Q filed August 9, 2010 and incorporated by reference]
4.11	Fourth Supplemental Indenture, dated June 29, 2010, 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 6.875% senior notes [filed as Exhibit 4.5 to Massey’s quarterly report on Form 10-Q filed August 9, 2010 and incorporated by reference]
4.12	Senior Indenture, dated as of August 12, 2008, 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 3.25% Senior Notes [filed as Exhibit 4.1 to Massey’s current report on Form 8-K filed August 12, 2008, and incorporated by reference]
4.13	First Supplemental Indenture, dated as of August 12, 2008,  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 3.25% Senior Notes [filed as Exhibit 4.2 to Massey’s current report on Form 8–K filed August 12, 2008, and incorporated by reference]
4.14	Second Supplemental Indenture, dated as of July 20, 2009,  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 3.25% Senior Notes [filed as Exhibit 4.4 to Massey’s quarterly report on Form 10-Q filed August 10, 2009, and incorporated by reference]
4.15	Third Supplemental Indenture, dated as of August 28, 2009,  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 3.25% Senior Notes [filed as Exhibit 4.4 to Massey’s quarterly report on Form 10-Q filed October 28, 2009, and incorporated by reference]
4.16	Fourth Supplemental Indenture, dated as of April 30, 2010, 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 3.25 % convertible senior notes [filed as Exhibit 4.3 to Massey’s quarterly report on Form 10-Q filed August 9, 2010 and incorporated by reference]
4.17	Fifth Supplemental Indenture, dated as of June 29, 2010, 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 3.25 % convertible senior notes [filed as Exhibit 4.6 to Massey’s quarterly report on Form 10-Q filed August 9, 2010 and incorporated by reference]
10.1	Second Amended and Restated Credit Agreement dated as of November 8, 2010 among A.T. Massey Coal Company, Inc. and certain of its subsidiaries, as Borrowers, Massey Energy Company and certain of its subsidiaries, as Guarantors, Deutsche Bank Securities Inc. as Co-Syndication Agent, Capital One Leverage Finance Corporation, as Documentation Agent, The CIT Group/Business Credit, Inc., as Collateral Agent and Co-Syndication Agent, UBS Securities LLC, as Sole Arranger, UBS AG Stamford Branch, as Administrative Agents and UBS Loan Finance LLC, as Swingline Lender [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed November 9, 2010 and incorporated by reference].
10.2	Limited Consent and Second Amendment to Amended and Restated Credit Agreement dated July 19, 2007 [filed as Exhibit 10.1 to Massey’s quarterly report on Form 10-Q filed August 9, 2007 and incorporated by reference]

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10.3	Third Amendment to Amended and Restated Credit Agreement dated March 10, 2008 [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed March 14, 2008 and incorporated by reference]
10.4	Fourth Amendment to Amended and Restated Credit Agreement dated October 10, 2008 [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed October 16, 2008 and incorporated by reference]
10.5	Equity Distribution Agreement dated February 3, 2009 between Massey Energy Company and UBS Securities LLC [filed as Exhibit 1.1 to Massey’s current report on Form 8-K filed February 4, 2009 and incorporated by reference]
10.6	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]
10.7	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]
10.8	Massey Energy Company 1996 Executive Stock Plan (as amended and restated, effective January 1, 2009) [filed as Exhibit 10.14 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.9	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]
10.10	Massey Energy Company 1999 Executive Performance Incentive Plan (as amended and restated, effective January 1, 2009) [filed as Exhibit 10.15 to Massey’s current report on Form 8-K  filed December 24, 2008 and incorporated by reference]
10.11	Massey Energy Company 2006 Stock and Incentive Compensation Plan (as amended and restated, effective August 18, 2009) [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed August 21, 2009 and incorporated by reference]
10.12	Form of Non-Employee Director Initial Restricted Stock Award Agreement under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed December 31, 2008 and incorporated by reference]
10.13	Form of Non-Employee Director Initial Restricted Unit Award Agreement under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.3 to Massey’s current report on Form 8-K filed December 31, 2008 and incorporated by reference]
10.14	Form of Non-Employee Director Annual Restricted Stock Award Agreement under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed February 22. 2010 and incorporated by reference]
10.15	Form of Non-Employee Director Annual Stock Option Award Agreement under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed February 22, 2010 and incorporated by reference]
10.16	Form of stock option agreement under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed November 16, 2009 and incorporated by reference]
10.17	Form of restricted stock agreement under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.3 to Massey’s current report on Form 8-K filed November 16, 2009 and incorporated by reference]
10.18	Form of restricted unit agreement under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.4 to Massey’s current report on Form 8-K filed November 16, 2009 and incorporated by reference]
10.19	Form of cash incentive award agreement based on earnings before taxes under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.6 to Massey’s current report on Form 8-K filed November 14, 2008 and incorporated by reference]
10.20	Form of amended cash incentive award agreement based on earnings before taxes under the Massey Energy Company 2006  Stock and Incentive Compensation Plan [filed as Exhibit 10.2 to Massey’s current report in Form 8-K filed January 6, 2010 and incorporated by reference.
10.21	Form of cash incentive award agreement based on earnings before interest and taxes under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.6 to Massey’s current report on Form 8-K filed November 14, 2008 and incorporated by reference]

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10.22	Form of cash incentive award agreement based on earnings before interest, taxes, depreciation and amortization under the Massey Energy Company 2006 Stock and Incentive Compensation Plan [filed as Exhibit 10.7 to Massey’s current report on Form 8-K filed November 14, 2008 and incorporated by reference]
10.23	A.T. Massey Coal Company, Inc. Supplemental Benefit Plan (as amended and restated as of January 1, 2009) [filed as Exhibit 10.20 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.24	Amendment to A.T. Massey Coal Company, Inc. Supplemental Benefit Plan (as amended and restated as of January 1, 2009) [filed as Exhibit 10.6 to Massey’s current report on Form 8-K filed November 30, 2010 and incorporated by reference]
10.25	A.T. Massey Coal Company, Inc. Executive Deferred Compensation Plan (as amended and restated as of January 1, 2009) [filed as Exhibit 10.19 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.26	Massey Executive Deferred Compensation Program (as amended and restated as of January 1, 2009) [filed as Exhibit 10.17 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.27	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]
10.28	Massey Executives’ Supplemental Benefit Plan (as amended and restated effective January 1, 2009) [filed as Exhibit 10.13 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.29	Retention and Employment Agreement between Massey Energy Company and John Christopher Adkins, effective as of November 10, 2010 [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed November 17, 2010 and incorporated by reference]
10.30	Employment Agreement dated May 28, 2009 between Massey Energy Company and Michael K. Snelling [filed as Exhibit 10.1 to Massey’s quarterly report on Form 10-Q filed August 10, 2009 and incorporated by reference]
10.31	Amendment to Employment Agreement with Michael K. Snelling, effective October 22, 2010 [filed as Exhibit 10.5 to Massey’s current report on Form 8-K filed October 22, 2010 and incorporated by reference]
10.32	Employment and Change in Control Agreement dated November 10, 2008 between Massey Energy Company and Baxter F. Phillips, Jr. [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed November 14, 2008 and incorporated by reference]
10.33	Amendment to Employment and Change in Control Agreement between Massey Energy Company and Baxter F. Phillips, Jr. effective January 1, 2010 [filed as Exhibit 10.3 to Massey’s current report on Form 8-K filed January 6, 2010 and incorporated by reference]
10.34	Amendment to the Employment and Change in Control Agreement with Baxter F. Phillips, Jr., dated May 18, 2010 [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed May 21, 2010 and incorporated by reference]
10.35	Amendment to Employment and Change in Control Agreement with Baxter F. Phillips, Jr., effective October 22, 2010 [filed as Exhibit 10.3 to Massey’s current report on Form 8-K filed October 22, 2010 and incorporated by reference]
10.36	Amendment to Employment and Change in Control Agreement with Baxter F. Phillips, Jr., effective December 3, 2010 [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed December 7, 2010 and incorporated by reference]
10.37	Form of Amended and Restated Change in Control Severance Agreement for Tier 1 Participants [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed October 22, 2010 and incorporated by reference]
10.38	Form of Change in Control Severance Agreement for Tier 2 Participants [filed Exhibit 10.37 to Massey’s annual report on Form 10-K filed March 2, 2009 and incorporated by reference]
10.39	Form of Change in Control Severance Agreement for Tier 3 Participants [filed Exhibit 10.38 to Massey’s annual report on Form 10-K filed March 2, 2009 and incorporated by reference]
10.40	Change in Control Severance Agreement (as amended and restated) dated as of December 23, 2008 between Massey Energy Company and J. Christopher Adkins [filed as Exhibit 10.25 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.41	Amendment to Change in Control Severance Agreement, dated as of February 16, 2010 between Massey Energy Company and John Christopher Adkins [filed as Exhibit 10.2 to Massey’s current report on Form 8-K filed April 30, 2010 and incorporated by reference]

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10.42	Change in Control Severance Agreement (as amended and restated) dated as of December 23, 2008 between Massey Energy Company and Eric B. Tolbert [filed as Exhibit 10.26 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.43	Amendment to Change in Control Severance Agreement, dated as of February 16, 2010 between Massey Energy Company and Eric B. Tolbert [filed as Exhibit 10.4 to Massey’s current report on Form 8-K filed April 30, 2010 and incorporated by reference]
10.44	Change in Control Severance Agreement (as amended and restated) dated as of December 23, 2008 between Massey Energy Company and Michael K. Snelling [filed as Exhibit 10.27 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.45	Amendment to Change in Control Severance Agreement, dated as of February 16, 2010 between Massey Energy Company and Michael K. Snelling [filed as Exhibit 10.3 to Massey’s current report on Form 8-K filed April 30, 2010 and incorporated by reference]
10.46	Retirement Agreement with Don L. Blankenship, effective December 3, 2010 [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed December 7, 2010 and incorporated by reference]
10.47	Massey Energy Company 2011 - 2013 Long Term Incentive Award Program as reported on Massey’s current report on Form 8-K [filed November 30, 2010 and incorporated by reference]
10.48	Massey Energy Company 2010 Bonus Program as reported on Massey’s current report on Form 8-K [filed November 30, 2010 and incorporated by reference]
10.49	Base salary amounts set for Massey’s named executive officers as reported on Massey’s current reports on Form 8-K [filed January 6, 2010 and November 30, 2010 and incorporated by reference]
10.50	Massey Energy Company Non-Employee Directors Compensation Summary (as amended and restated effective November 9, 2009) [filed as Exhibit 10.1 to Massey’s current report on Form 8-K filed November 30, 2010 and incorporated by reference]
10.51	Massey Energy Company Stock Plan for Non-Employee Directors (as amended and restated, effective January 1, 2009) [filed as Exhibit 10.21 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.52	Massey Energy Company 1997 Restricted Stock Plan for Non-Employee Directors (as amended and restated, effective January 1, 2009) [filed as Exhibit 10.22 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.53	Massey Energy Company Deferred Directors’ Fees Program (amended and restated, effective January 1, 2009) [filed as Exhibit 10.18 to Massey’s current report on Form 8-K filed December 24, 2008 and incorporated by reference]
10.54	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]
10.55	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]
21	Massey Energy Company Subsidiaries [filed herewith]
23.1	Consent of Independent Registered Public Accounting Firm [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]
99.1	Dodd-Frank Act Disclosure of Mine Safety and Health Administration Safety Data [filed herewith]
101	Interactive Data File (Annual Report on Form 10-K, for the fiscal year ended December 31, 2010, furnished in XBRL (eXtensible Business Reporting Language)).
	Attached as Exhibit 101 to this report are the following documents formatted in XBRL: (i) the Consolidated Statements of Income for each of the three years ended December 31, 2010, 2009 and 2008, (ii) the Consolidated Balance Sheets at December 31, 2010 and 2009, (iii) the Consolidated Statement of Cash Flows for each of the three years ended December 31, 2010, 2009 and 2008, (iv) the Consolidated Statement of Shareholders’ Equity for each of the three years ended December 31, 2010, 2009 and 2008, (v) the Notes to Consolidated Financial Statements, tagged as blocks of text and (vi) Schedule II - Valuation and Qualifying Accounts, tagged as blocks of text. Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities and Exchange Act of 1934, and otherwise is not subject to liability under these sections.

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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 1, 2011
	By:	/s/ Eric 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.

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Signature		Title	Date
Principal Executive Officer:
/s/ Baxter F. Phillips, Jr.		Director, Chief Executive Officer & President	March 1, 2011
Baxter F. Phillips, Jr.
Principal Financial Officer:
/s/ Eric B. Tolbert		Vice President and Chief Financial Officer	March 1, 2011
Eric B. Tolbert
Principal Accounting Officer:
/s/ David W. Owings		Controller	March 1, 2011
David W. Owings
Other Directors:
*		Director	March 1, 2011
James B. Crawford
*		Director	March 1, 2011
Robert H. Foglesong
*		Director	March 1, 2011
Richard M. Gabrys
*		Director	March 1, 2011
Robert B. Holland, III
*		Chairman of the Board	March 1, 2011
Bobby R. Inman
*		Director	March 1, 2011
Dan R. Moore
*		Director	March 1, 2011
Stanley C. Suboleski
*		Director	March 1, 2011
Linda J. Welty
By:	/s/ Richard R. Grinnan		March 1, 2011
Richard R. Grinnan
Attorney-in-fact

*  Manually signed Powers of Attorney authorizing Eric B. Tolbert, Richard R. Grinnan, M. Shane Harvey and Jeffrey M. Jarosinski, and each of them, to sign the annual report on Form 10-K for the fiscal year ended December 31, 2010 and any amendments thereto as attorneys-in-fact for certain directors and officers of the registrant are included herein as Exhibits 24.

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MASSEY ENERGY COMPANY

SCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

(In Thousands)

Description	Balance at Beginning of Period		Amounts Charged to Costs and Expenses			Deductions (1)			Other		Balance at End of Period
YEAR ENDED DECEMBER 31, 2010
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable	$	7,303	$	5,465	(3)	$	(11,862	)(3)	$	—	$	906
YEAR ENDED DECEMBER 31, 2009
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable	$	873	$	6,430	(2)	$	—		$	—	$	7,303
YEAR ENDED DECEMBER 31, 2008
Reserves deducted from asset accounts:
Allowance for accounts and notes receivable	$	444	$	429		$	—		$	—	$	873

(1)	Reserves utilized, unless otherwise indicated.
(2)	Allowance for accounts and notes receivable for the year ended December 31, 2009 includes a $6 million reserve for bad debt related to a note receivable from a supplier, which was recorded in Other noncurrent assets at December 31, 2009.

(3) Expense for the year ended December 31, 2010 includes a $5 million charge for bad debt related to a note receivable from a supplier, which was subsequently utilized in 2010.

134