10-K 1 document.htm FORM 10-K 12.31.2009 document.htm
  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, 2009
OR
 
¨
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 ¨
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  ¨ 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 ¨
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 ¨
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.   ¨
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  ¨
Non-accelerated filer  ¨                             Smaller reporting company  ¨
(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  ¨ No  x   
The aggregate market value of the common stock held by non-affiliates of the registrant on June 30, 2009, was $1,670,076,824 based on the last sales price reported that date on the New York Stock Exchange of $19.54 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, 2010 — 86,545,037 shares.
 
DOCUMENTS INCORPORATED BY REFERENCE
Part III incorporates certain information by reference from the registrant’s definitive proxy statement for the 2010 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, 2009.
 
 

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:

(i)
our cash flows, results of operation or financial condition;
(ii)
the successful completion of acquisition, disposition or financing transactions and the effect thereof on our business;
(iii)
governmental policies, laws, regulatory actions and court decisions affecting the coal industry or our customers’ coal usage;
(iv)
legal and administrative proceedings, settlements, investigations and claims and the availability of insurance coverage related thereto;
(v)
inherent risks of coal mining beyond our control, including weather and geologic conditions or catastrophic weather-related damage;
(vi)
inherent complexities make it more difficult and costly to mine in Central Appalachia than in other parts of the United States;
(vii)
our production capabilities to meet market expectations and customer requirements;
(viii)
our ability to obtain coal from brokerage sources or contract miners in accordance with their contracts;
(ix)
our ability to obtain and renew permits necessary for our existing and planned operations in a timely manner;
(x)
the cost and availability of transportation for our produced coal;
(xi)
our ability to expand our mining capacity;
(xii)
our ability to manage production costs, including labor costs;
(xiii)
adjustments made in price, volume or terms to existing coal supply agreements;
(xiv)
the worldwide market demand for coal, electricity and steel;
(xv)
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;
(xvi)
competition among coal and other energy producers, in the United States and internationally;
(xvii)
our ability to timely obtain necessary supplies and equipment;
(xviii)
our reliance upon and relationships with our customers and suppliers;
(xix)
the creditworthiness of our customers and suppliers;
(xx)
our ability to attract, train and retain a skilled workforce to meet replacement or expansion needs;
(xxi)
our assumptions and projections concerning economically recoverable coal reserve estimates;
(xxii)
our failure to enter into anticipated new contracts;
(xxiii)
future economic or capital market conditions;
(xxiv)
foreign currency fluctuations;
(xxv)
the availability and costs of credit, surety bonds and letters of credit that we require;
(xxvi)
the lack of insurance against all potential operating risks;
(xxvii)
our assumptions and projections regarding pension and other post-retirement benefit liabilities;
(xxviii)
our interpretation and application of accounting literature related to mining specific issues; and
(xxix)
the successful implementation of our strategic plans and objectives for future operations and expansion or consolidation.

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.
 

i


 
2009 ANNUAL REPORT ON FORM 10-K
 
TABLE OF CONTENTS
 

   
Page
PART I
   
Item 1.
Business
1
Item 1A.
Risk Factors
24
Item 1B.
Unresolved Staff Comments
33
Item 2.
Properties
34
Item 3.
Legal Proceedings
34
 
   
PART II
   
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
35
Item 6.
Selected Financial Data
37
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
39
Item 7A.
Quantitative and Qualitative Disclosures about Market Risk
54
Item 8.
Financial Statements and Supplementary Data
55
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
92
Item 9A.
Controls and Procedures
93
Item 9B.
Other Information
94
     
PART III
   
Item 10.
Directors, Executive Officers and Corporate Governance
95
Item 11.
Executive Compensation
97
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
97
Item 13.
Certain Relationships and Related Transactions, and Director Independence
97
Item 14.
Principal Accountant Fees and Services
97
     
PART IV
   
Item 15.
Exhibits and Financial Statement Schedules
98
   
SIGNATURES
103
 

Annual Shareholders Meeting
 
Our 2010 Annual Meeting of Shareholders will be held at 9:00 a.m. EDT on Tuesday, May 18, 2010 at The Jefferson Hotel, 101 West Franklin Street, Richmond, Virginia 23220.
 
ii

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 21 at the end of Item 1. Business.
 
Item 1. Business
 
Business Overview

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 and total coal reserves in 2009.

We produce, process and sell bituminous coal of various steam and metallurgical grades, primarily of a low sulfur content, through our 23 processing and shipping centers (“Resource Groups”), many of which receive coal from multiple mines. At January 31, 2010, we operated 56 mines, including 42 underground mines (two of which employ both room and pillar and longwall mining) and 14 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.
 
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 (the “Spin-Off”) which separated Fluor Corporation into two entities:  the “new” Fluor Corporation (“New Fluor”) and Fluor Corporation which retained our coal-related businesses and was subsequently renamed Massey Energy Company.  Massey Energy Company has been a separate, publicly traded company since December 1, 2000.

Industry Overview
 
Coal accounted for 25% 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 2008, according to the BP Statistical Review of World Energy (“BP”). In 2008, coal was the fuel source of 49% 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 2008, the United States was the second largest coal producer in the world, exceeded only by China. Other leading coal producers include Australia, India, South Africa, the Russian Federation and Indonesia. 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 2009, 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
    46%  
Central Appalachia
    19%  
Northern Appalachia
    12%  
West (other than Powder River Basin)
    11%  
Midwest
    10%  
All other
    2%  
Total
    100%  

1

The EIA estimated that approximately 69% of United States coal was produced by surface mining methods in 2008. 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”).
 
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 ten months of 2009 as estimated by EIA is as follows:

End Use
 
% of Total
 
Electric Power
    94%  
Other Industrial
    4%  
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 the first 10 months of 2009 was as follows:

Electricity Generation Source
 
Average Cost per million BTU
Petroleum Liquids
 
$9.92
Natural Gas
 
$4.65
Coal
 
$2.22
Petroleum Coke
 
$1.59


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 10 months of 2009, as estimated by EIA, is as follows:

Electricity Generation Source
 
% of Total Electricity Generation
 
Coal
    44%  
Natural Gas
    24%  
Nuclear
    20%  
Hydroelectric
    7%  
Oil and other (solar, wind, etc.)
    5%  
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 10 months of 2009, electricity consumption in the United States decreased 4.4% from the same period in 2008, but the average growth rate in the past decade was approximately 1.3% 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 Institute (“WCI”), in 2008, the United States ranked fourth among worldwide exporters of coal. Australia was the largest exporter, with other major exporters including Indonesia, the Russian Federation, Columbia, South Africa and China. According to Energy Ventures Analysis, Inc. ("EVA"), United States exports decreased by 28% from 2008 to 2009. The usage breakdown for 2009 United States coal exports of 59 million tons was 39% for electricity generation and 61% for steel production. In 2009, United States coal exports were shipped to more than 40 countries. The largest purchaser of United States exported utility coal in 2009 continued to be Canada, which took 8.2 million tons or 36% of total utility coal exports. This was down 57% compared to the 19.1 million tons exported to Canada in 2008. Overall steam coal exports decreased 41% in 2009 compared to 2008. The largest purchaser of United States exported metallurgical coal was Brazil, which
 
2

imported approximately 8.1 million tons from the United States, or 22% of total United States metallurgical coal exports. In total, metallurgical coal exports decreased 16% in 2009, compared to 2008.

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.
 
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 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.  Since mid-2008, the United States and world economies have been in an economic recession and financial credit crisis, reducing the demand for coal.
 
Metallurgical grade coal is distinguished by special quality characteristics that include high carbon content, volatile matter, low expansion pressure, low sulfur content, and various other chemical attributes. High vol met coal is also high in heat content (as measured in Btus), and therefore is desirable to utilities as fuel for electricity generation. Consequently, high vol met coal producers have the ongoing opportunity to select the market that provides maximum revenue and profitability. The premium price offered by steel makers for the metallurgical quality attributes is typically higher than the price offered by utility coal buyers that value only the heat content. The primary concentration of United States metallurgical coal reserves is located in the Central Appalachian region. EVA estimates that the Central Appalachian region supplied 88% of domestic metallurgical coal and 70% of United States exported metallurgical coal during 2008.

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 WCI. 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.
 
3

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 draglines, 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.
 
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 45% of our 2009 coal production. Production from underground longwall mining operations constituted approximately 3% of our 2009 production. Surface mining represented approximately 44% of our 2009 coal production. Highwall mining represented approximately 8% of our 2009 coal production.
 
Mining Operations
 
We currently have 23 distinct Resource Groups, including seventeen in West Virginia, five in Kentucky and one in Virginia. These complexes blend, process and ship coal that is produced from one or more mines, with a single complex handling the coal production of as many as ten 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 19% of 2009 United States coal production according to EIA.

4



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

map
 
 
 
 
 
 
 
 
 
5

The following table provides key operational information on our Resource Groups in 2009:

Resource Group Name
Location (County)
Active/ Inactive
 
Mine Type
   
Active Mine Count (1)
 
Mining Equipment
Transportation
 
2009 Production (2)
   
2009 Shipments (3)
   
Year Established or Acquired
 
                           
(Thousands of Tons)
       
West Virgina Resource Groups
                                   
   
Black Castle
Boone
Active
    S       1  
HW
truck, barge
    2,680       1,843       1987  
   
Delbarton
Mingo
Active
    U       1    
NS
    476       893       1999  
   
Edwight
Raleigh
Active
    S       1    
CSX
    1,482       2,159       2003  
   
Elk Run
Boone
Active
    U       5    
CSX
    2,033       3,292       1978  
   
Endurance
Boone
Inactive
                 
CSX
    483       194       2001  
   
Green Valley
Nicholas
Active
    U       3    
CSX
    847       807       1996  
   
Guyandotte
Wyoming
Active
    U       1    
NS
    228       208       2006  
   
Independence
Boone
Active
    U       3  
LW
CSX
    1,490       2,811       1994  
   
Inman
Boone
Active
    U       1    
CSX
    536       -       2008  
   
Logan County
Logan
Active
    S/U       2  
HW
CSX
    3,738       3,233       1998  
   
Mammoth
Kanawha
Active
    U       4    
barge/NS
    1,688       4,465       2004  
   
Marfork
Raleigh
Active
    S/U       9  
LW/HW
CSX
    4,244       3,925       1993  
   
Nicholas Energy
Nicholas
Active
    S/U       3  
HW
NS
    2,211       2,043       1997  
   
Progress
Boone
Active
    S       1  
HW/DL
CSX
    4,954       3,149       1998  
   
Rawl
Mingo
Active
    U       2    
NS
    999       -       1974  
   
Republic Energy
Raleigh
Active
    S       2  
HW
truck
    3,367       260       2004  
   
Stirrat
Logan
Active
                 
CSX
    450       1.068       1993  
                                                     
Kentucky Resource Groups
                                             
   
Coalgood Energy
Harlan
Active
    S/U       2  
HW
CSX
    348       310       2005  
   
Long Fork
Pike
Active
                 
NS
    -       1,513       1991  
   
Martin County
Martin
Active
    S/U       4  
HW
NS
    1,691       1,394       1969  
   
New Ridge
Pike
Active
                 
CSX
    -       315       1992  
   
Sidney
Pike
Active
    S/U       9  
HW
NS
    3,447       2,219       1984  
                                                     
Virginia Resource Group
                                             
   
Knox Creek
Tazewell
Active
    S/U       2  
HW
NS
    562       551       1997  
                                                     
   
Total
                56           37,954       36,652          
                                                     
                                                     
                                                     
(1)    Active mine count as of January 31, 2010
(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
DL    -dragline
NS     -Norfolk Southern Railway Company
CSX - CSX Transportation

6

The following descriptions of the Resource Groups are current as of January 31, 2010:
 
West Virginia Resource Groups
 
Black Castle. The Black Castle complex includes a large surface mine, two highwall miners, the Homer III direct-ship 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 800 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 2009.
 
Delbarton. The Delbarton complex includes one underground room and pillar mine and a preparation plant. Production from the mine is transported to the Delbarton preparation plant via overland conveyor. 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 trucked to Marfork Resource Group’s preparation plant where it is loaded and shipped to customers via the CSX rail system in unit trains of up to 150 railcars.

Logan County. The Logan County complex includes a surface mine, a highwall miner and an underground room and pillar mine. Production from the underground mine is transported via truck to the preparation plant of the Stirrat Resource Group.  The surface mine and highwall miner production 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 Logan County Resource Group preparation plant (“Bandmill preparation plant”) was destroyed by fire in August 2009. A new plant is expected to be completed in fall of 2010, at which time the production from
 
7

the underground room and pillar mine will go to this new plant. Additionally, upon completion of the new plant, three surface mines that are currently idle are expected to be re-started.

Mammoth. The Mammoth complex operates four 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 seven underground room and pillar mines, a longwall mine, a surface mine, a highwall miner and a preparation plant. Production from the longwall mine and six 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 mine and the highwall miner is trucked to either the Marfork preparation plant or the Elk Run Resource Group’s preparation plant. 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, two highwall miners and a preparation plant. Coal from the underground mine is transported to the preparation plant for processing via conveyor system. Coal from the highwall miners 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 MTR surface mine and a highwall miner. A dragline is also utilized at the Twilight MTR surface mine. Production from the Twilight MTR surface mine is transported via underground conveyor to the Elk Run Resource Group for processing and rail shipment.
 
Rawl. The Rawl complex includes two underground room and pillar mines and a preparation plant. Production from the mines is transported via truck to the preparation plant of the Stirrat Resource Group. The Rawl plant, which was idled in December 2006, has a throughput capacity of 1,450 tons per hour. Customers can be served by the Rawl 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. 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 Group and one underground room and pillar mine of the Logan County Resource Group. 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 underground room and pillar mine, 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 underground mine and 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 two 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.
 
Martin County. The Martin County complex includes two underground room and pillar mines, two surface mines, a highwall miner and a preparation plant.  Direct-ship coal production from the surface mines is shipped to river docks via truck. Surface mine and highwall miner coal requiring processing and production from the underground mines is transported
 
8

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 2010 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 eight 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 underground conveyor system or truck to Sidney’s preparation plant. A portion of the coal from Sidney’s preparation plant and coal from the surface mines 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.  

 
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.
 
Coal Reserves
 
We estimate that, as of December 31, 2009, we had total recoverable reserves of approximately 2.4 billion tons consisting of both proven and probable reserves. “Reserves” are defined by the SEC Industry Guide 7 as that part of a mineral deposit, which could be economically and legally extracted or produced at the time of the reserve determination. “Recoverable” reserves means coal that is economically recoverable using existing equipment and methods under federal and state laws currently in effect. Approximately 1.5 billion tons of 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 0.9 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.
 
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 18% 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 4.4% of Produced coal revenue for the year ended December 31, 2009.

9

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, 2009:

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
    83,440       57,364       26,076       39,297       44,143       538       82,902  
     Delbarton
Mingo County
    285,761       120,440       165,321       140,263       145,498       25       285,736  
     Edwight
Raleigh County
    4,851       4,851       -       4,851       -       -       4,851  
     Elk Run
Boone County
    106,756       73,963       32,793       80,734       26,022       4,660       102,096  
     Endurance
Boone County
    20,871       20,871       -       20,871       -       20,831       40  
     Green Valley
Nicholas County
    11,360       11,360       -       10,417       943       -       11,360  
     Guyandotte
Wyoming County
    45,336       17,366       27,970       2,100       43,236       330       45,006  
     Independence
Boone County
    42,881       41,571       1,310       30,293       12,588       9,482       33,399  
     Inman
Boone County
    45,501       43,986       1,515       -       45,501       -       45,501  
     Logan County
Logan County
    102,302       84,718       17,584       75,134       27,168       2,388       99,914  
     Mammoth
Kanawha County
    131,628       100,705       30,923       73,881       57,747       42,596       89,032  
     Marfork
Raleigh County
    128,977       100,849       28,128       70,759       58,218       815       128,162  
     Nicholas Energy
Nicholas County
    86,161       48,258       37,903       43,745       42,416       33,554       52,607  
     Progress
Boone County
    21,860       21,860       -       21,860       -       -       21,860  
     Rawl
Mingo County
    107,853       80,623       27,230       73,985       33,868       1,333       106,520  
     Republic Energy
Raleigh County
    77,211       65,626       11,585       77,211       -       -       77,211  
     Stirrat
Logan County
    9,512       7,330       2,182       4,631       4,881       -       9,512  
Kentucky
                                                         
     Coalgood Energy
Harlan County
    20,906       12,939       7,967       3,361       17,545       2,704       18,202  
     Long Fork
Pike County
    4,964       2,764       2,200       264       4,700       -       4,964  
     Martin County
Martin County
    46,967       30,278       16,689       1,905       45,062       1,336       45,631  
     New Ridge
Pike County
    -       -       -       -       -       -       -  
     Sidney
Pike County
    120,685       70,173       50,512       120,685       -       7,028       113,657  
Virginia
                                                         
     Knox Creek
Tazewell County
    62,307       46,756       15,551       34,776       27,531       4,552       57,755  
                                                           
  Subtotal
      1,568,090       1,064,651       503,439       931,023       637,067       132,172       1,435,918  
Land Management Companies: (4)
                                                       
Black King
Boone County, WV
    53,536       40,804       12,732       734       52,802       -       53,536  
                   Raleigh County, WV                                                        
Boone East
Boone County, WV
    138,741       101,268       37,473       4,340       134,401       61,218       77,523  
                   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
    33,351       24,220       9,131       -       33,351       -       33,351  
Rostraver Energy
Various counties, PA
    94,086       44,449       49,637       -       94,086       65,728       28,358  
Lauren Land
Mingo County, WV
    171,028       104,814       66,214       11,175       159,853       17,669       153,359  
                   Logan County, WV                                                        
                   Various counties, KY                                                        
New Market Land
Wyoming County, WV
    5,884       2,690       3,194       -       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
    784,485       430,756       353,729       26,745       757,740       234,324       550,161  
Other               
N/A
    57,733       29,680       28,053       12,740       44,993       3,112       54,621  
Total
      2,410,308       1,525,087       885,221       970,508       1,439,800       369,608       2,040,700  
                                                           
                                                           
(1)  Recoverable reserves represents 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:
 
         
Recoverable Reserves (1)
             
   
Recoverable
         
Sulfur Content
         
Avg. Btu as
       
Resource Group
 
Reserves
      +1% (2)       -1% (2)    
Compliance (2)
   
Received (3)
   
Coal Type (4)
 
   
(In Thousands of Tons Except Average Btu as Received)
       
West Virginia
                                       
     Black Castle
    83,440       33,978       49,462       22,093       12,700    
Utility
 
     Delbarton
    285,761       111,954       173,807       127,073       13,350    
High Vol Met and Utility
 
     Edwight
    4,851       1,225       3,626       3,512       12,550    
High Vol Met and Utility
 
     Elk Run
    106,756       46,795       59,961       50,058       13,700    
High Vol Met and Utility
 
     Endurance
    20,871       6,443       14,428       6,381       11,850    
Utility
 
     Green Valley
    11,360       2,550       8,810       9,750       13,100    
High Vol Met, Mid Vol Met, and Industrial
 
     Guyandotte
    45,336       -       45,336       45,336       13,850    
Low Vol Met
 
     Independence
    42,881       16,725       26,156       -       12,650    
High Vol Met and Utility
 
     Inman
    45,501       26,672       18,829       19,549       12,650    
High Vol Met and Utility
 
     Logan County
    102,302       34,899       67,403       44,840       12,050    
High Vol Met, Utility, and Industrial
 
     Mammoth
    131,628       22,391       109,237       41,073       12,150    
High Vol Met and Utility
 
     Marfork
    128,977       51,797       77,180       38,606       14,050    
High Vol Met and Utility
 
     Nicholas Energy
    86,161       38,466       47,695       28,000       12,450    
High Vol Met and Utility
 
     Progress
    21,860       9,038       12,822       12,836       12,350    
High Vol Met and Utility
 
     Rawl
    107,853       27,658       80,195       59,378       12,350    
High Vol Met and Utility
 
     Republic
    77,211       16,576       60,635       36,980       12,450    
High Vol Met and Utility
 
     Stirrat
    9,512       204       9,308       7,492       12,300    
High Vol Met and Utility
 
Kentucky
                                             
     Coalgood Energy
    20,906       4,708       16,198       11,680       13,100    
Utility and Industrial
 
     Long Fork
    4,964       3,500       1,464       -       12,850    
Utility
 
     Martin County
    46,967       33,900       13,067       4,888       12,500    
Utility
 
     New Ridge
    -       -       -       -       -     N/A    
     Sidney
    120,685       47,878       72,807       52,545       13,200    
Utility
 
Virginia
                                               
     Knox Creek
    62,307       9,193       53,114       38,491       12,350    
High Vol Met and Utility
 
  Subtotal
    1,568,090       546,550       1,021,540       660,561                  
                                                 
Land Management Companies:
                                         
     Black King
    53,536       99       53,437       36,858       12,150    
Low Vol Met, High Vol Met and Utility
 
     Boone East
    138,741       34,939       103,802       36,789       12,500    
Low Vol Met, High Vol Met and Utility
 
     Boone West
    241,974       130,063       111,911       79,369       13,350    
High Vol Met and Utility
 
     Ceres Land
    33,351       5,991       27,360       12,740       12,700    
High Vol Met and Utility
 
     Rostraver Energy
    94,086       94,086       -       -       14,050    
High Vol Met, Utility, and Industrial
 
     Lauren Land
    171,028       88,195       82,833       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 Volume Met, Utility, and Industrial
 
  Subtotal Land Management
    784,485       381,175       403,310       240,111                  
                                                 
Other
    57,733       6,638       51,095       45,948       12,800    
Various
 
                                                 
Total
    2,410,308       934,363       1,475,945       946,620                  
                                                 
                                                 
(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 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 will meet the power plant emission standard of 1.2 pounds of sulfur dioxide per million Btu’s of fuel consumed. At December 31, 2009, approximately 0.9 billion tons, or 39%, 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 2009 shipments of 36.7 million tons were loaded from 23 mining complexes. Rail shipments constituted 89% of total shipments, with 28% loaded on Norfolk Southern trains and 61% loaded on CSX trains. The balance was shipped from mining complexes via truck or barge.

Approximately 21% 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 5% of our production to Great Lakes’ ports for transport to various United States and Canadian customers.
  
Customers and Coal Contracts
 
We have coal supply commitments with a wide range of electric utilities, steel manufacturers, industrial customers and energy traders and brokers. By offering coal of both steam and metallurgical grades, we are able to serve a diverse customer base. This market diversity allows us to adjust to changing market conditions and sustain high sales volumes. 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, 2009, approximately 61%, 19% and 20% of Trade receivables represents amounts due from utility customers, metallurgical customers and industrial customers, respectively, compared with 75%, 13% and 12%, respectively, as of December 31, 2008. During 2009, we had 27 separate, active coal purchase agreements with Constellation Energy Commodities Group, Inc. (“Constellation”), with terms ranging from one month to two years which, in the aggregate accounted for approximately 19% of our fiscal year 2009 Produced coal revenue. The largest of the 27 agreements represented less than 2% of our fiscal year 2009 Produced coal revenue. As a result, we do not consider our business to be substantially dependent upon any of these agreements, individually or in the aggregate. No other customer accounted for 10% or more of fiscal year 2009 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, 2009, approximately 99% of coal sales volume was pursuant to long-term contracts. We anticipate that in 2010, coal sales volume percentage pursuant to long-term arrangements will be comparable to 2009. As of February 17, 2010, we had contractual sales commitments of approximately 100 million tons, including commitments subject to price reopener and/or optional tonnage provisions. Remaining contractual terms of our sales commitments range from one to ten years with an average volume-weighted remaining term of approximately 2.1 years. Seventy percent of our total contracted sales tons are priced. As of February 17, 2010, we have committed most of our expected 2010
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production. In addition, we purchase coal from third-party coal producers from time to time to supplement production and resell this coal to customers.

 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 2008 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 2008, exceeded by Peabody Energy Corporation (“Peabody”), Rio Tinto Energy America, Inc., Arch Coal, Inc. (“Arch”), Foundation Coal Holdings Inc. (“Foundation”) and CONSOL Energy Inc. (“CONSOL”).
  
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, capacity expansion has been somewhat limited by the increased costs of mining, high capital requirements, coal seam degradation, reserve depletion, 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. 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.
  
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 southern West Virginia operations control approximately 27,000 acres of 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 2009 average daily production, from the 228 wells owned or controlled, was 2.0 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, 2009, we sold 36.7 million tons of produced coal for total Produced coal revenue of $2.3 billion. The breakdown of produced tons sold by market served was 62% utility, 30% metallurgical and 8% industrial. Sales were concluded with over 100 customers. Export shipment revenue totaled approximately $472.1 million, representing approximately 20% of 2009 Produced coal revenue. In 2009, we exported shipments to customers in 13 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, 2009, we had 5,851 employees, including 76 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.
 
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
 
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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, 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 2009, we spent approximately $14.1 million to comply with environmental laws and regulations, of which $6.2 million was for reclamation, including $5.3 million for final reclamation. None of these expenditures were capitalized. We anticipate spending approximately $50.1 million and $29.9 million in such non-capital expenditures in 2010 and 2011, respectively. Of these expenditures, $41.2 million and $20.8 million for 2010 and 2011, 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 action 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. The bituminous coal mining industry was actively engaged throughout 2009 in activities to achieve compliance with these new requirements. These compliance efforts will continue into 2010.

           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.

All of the states in which we operate have state programs for mine safety and health regulation and enforcement. Collectively, federal and state safety and health regulation in the coal mining industry is perhaps the most comprehensive and pervasive system for protection of employee health and safety affecting any segment of 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.

We measure our success in this area primarily through the use of occupational injury and illness frequency rates. We believe that a superior safety and health regime is inherently tied to achieving productivity and financial goals, with overarching benefits for our shareholders, the community and the environment.
 
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
 
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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.
 
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 will pay 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 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 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 7-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, 2009, our pension plan was underfunded by $55.6 million.  We currently expect to make voluntary contributions in 2010 of approximately $20 million. The funded status at the end of fiscal year 2010, 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.
 
   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 principals generally accepted in the United States (“GAAP”). See Note 9 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
 
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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 United States Environmental Protection Agency (“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.  

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 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 EPA. In 2006, 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 EPA had inadequately explained its decision regarding several aspects of the NAAQS and remanded those to EPA for reconsideration, a process that could lead to more stringent NAAQS for fine particulate matter. EPA also adopted a more stringent ozone NAAQS on March 27, 2008. In addition, in 2009 and early 2010, 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. 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 EPA by December 17, 2007. Many states did not meet the December 17, 2007, deadline and we are unable to predict the impact on the coal market of the failure to submit Regional Haze SIPs by the deadline or of any subsequent submissions deadlines.
 
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, 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, 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, by allowing utilities to buy and sell credits to assist in achieving compliance with the
 
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NAAQS for 8-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 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 EPA for reconsideration on December 23, 2008. EPA is preparing its response to the remand, but the court did not impose a response date. Regardless of the outcome of litigation on either rule, stricter controls on emissions of SO2, NOX and mercury are likely in some form. Any such controls may have an impact on the demand for our coal. The EPA Administrator announced in December 2009 that EPA will propose a new air toxics Maximum Achievable Control Technology (MACT) standard for power plants in 2010 and finalize it in 2011. 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 power plants. Such rules and controls may have a significant, but undetermined, impact on the demand for coal.
 
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. These findings do not themselves impose any requirements on industry or other entities.  However, this action is a prerequisite to finalizing the EPA’s proposed greenhouse gas emission standards for light-duty vehicles, which were jointly proposed by EPA and the Department of Transportation’s National Highway Safety Administration on September 15, 2009. In addition, these findings may trigger permitting and other requirements for stationary sources regarding CO2 and other greenhouse gasses. Such 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 percent 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 percent below 2005 levels by 2020, 42 percent below 2005 levels by 2030, and 83 percent 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 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, 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.
 
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. The expiration dates of the permits are largely immaterial as the law provides for a right of successive renewal. The cost of obtaining surface mining, clean water and air permits can vary widely depending on the scientific and technical demonstrations that must be made to obtain the permits. However, 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 9 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 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 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, and Safety, 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.
 
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 of coal at the mine, which is influenced by mine operating costs and coal quality, and the cost of transporting coal from the mine to the point of use. The cost of mining the coal is influenced by geologic characteristics such as seam thickness, overburden ratios and depth of underground reserves. Underground mining is generally more expensive than surface mining as a result of 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, 2010, we operated 42 active underground mines, including two which employ both room and pillar and longwall mining, and 14 active surface mines, with 12 highwall miners.

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
 
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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. 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, 2009, 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, 2009, 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.

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, 2009, we had $1,319.1 million of total indebtedness outstanding, which represented 51.2% 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 indebtedness 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 indebtedness in the future under the terms of our $175 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 $175.0 million, of which $98.4 million was available as of December 31, 2009. 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
 
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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 certain covenants contained in the ABL Facility, which become operative only when our Average Excess Availability (as defined in the ABL Facility) is less than $30 million. These financial covenants include a Minimum Consolidated Fixed Charge Ratio of 1.00 to 1.00 and a minimum Consolidated Net Worth of $550 million under the terms of the ABL Facility (currently approximately $400 million as adjusted for Accounting Changes).

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 shareholders 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.

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.

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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.

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.

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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 dependant 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. We continue to experience rail service delays and disruptions in service which are negatively impacting our ability to deliver coal to customers and which may adversely affect our results of operations.

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.

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 United States Environmental Protection Agency (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.

Concerns about the environmental impacts of coal combustion, including perceived impacts on global climate change, are resulting in increased regulation of coal combustion in many jurisdictions, and interest in further regulation, which could significantly affect demand for our products.

The Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. Such regulation may require significant emissions control expenditures for many coal-fired power plants. As a result, the generators may switch to other fuels that generate less of these emissions or install more effective pollution control equipment, possibly reducing future demand for coal and the construction of coal-fired power plants. The majority of our coal supply agreements contain provisions that allow a purchaser to terminate its contract if legislation is passed that either restricts the use or type of coal permissible at the purchaser’s plant or results in specified increases in the cost of coal or its use.

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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 United States Supreme Court’s 2007 decision in Massachusetts v. Environmental Protection Agency ruled that EPA improperly declined to address carbon dioxide impacts on climate change in a rulemaking related to new motor vehicles. The reasoning of the court decision could affect other federal regulatory programs, including those that directly relate to coal use. In July 2008, EPA published an Advanced Notice of Proposed Rulemaking (ANPR) seeking comments regarding the regulation of greenhouse gas emissions; and in February 2009 the newly appointed administrator of EPA granted a petition by environmental advocacy groups to reconsider an interpretive memorandum by her predecessor in December 2008 that concluded the Clean Air Act’s Prevention of Significant Deterioration program does not extend to carbon dioxide emissions, a decision that could lead to carbon dioxide emissions from coal-fired power plants being a consideration in permitting decisions. In addition, a growing number of states in the United States are taking steps to require greenhouse gas emissions reductions from coal-fired power plants. Enactment of laws and promulgation 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.

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 percent 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 percent below 2005 levels by 2020, 42 percent below 2005 levels by 2030, and 83 percent 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 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, 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.

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.

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 share.
 
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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.

The Mine Safety and Health Administration (“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 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 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.

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 (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. 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
 
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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, 2009, approximately 1.3% of our total workforce was represented by the United Mine Workers of America (the “UMWA”). Our unionized workforce is spread out amongst five of our coal preparation plants. In 2009, these preparation plants handled approximately 15.8% of our coal production. We are currently in the process of negotiating successor collective bargaining agreements for ones that have expired. 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.

Legislation has been proposed to the United States Congress to enact a law allowing for workers to choose union representation solely by signing election cards (“Card Check”), which would eliminate the use of secret ballots to elect union representation. While the impact is uncertain, if Card Check legislation is enacted into law, it will be administratively easier for the UMWA to unionize coal mines and may lead to more coal mines becoming unionized.

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.

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

We are parties 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. 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 18 of the Notes to Consolidated Financial Statements.

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 5, 10 and 11 of the Notes to Consolidated Financial Statements for further discussion.

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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 voluntary contributions in 2010 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 has been adversely affected by the recent disruptions in the financial markets, 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, 2009, our annual measurement date, our pension plan was underfunded by $55.6 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, or 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 shareholders. 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.

If a “fundamental change” (as defined in the indenture governing the 3.25% convertible senior notes due 2015 (“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% convertible senior notes due 2024 (“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;

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§  
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 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 and acts of war. Future terrorist attacks against United States targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting customers may materially adversely affect 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 disruption may lead to significant increases in energy prices that could result in government-imposed price controls. It is possible that any, or a combination, of these occurrences could have a material impact on cash flows, results of operations or financial condition.

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 longwalls. We do not currently carry business interruption insurance.
 
Item 1B. Unresolved Staff Comments

None.

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Item 2. Properties
 
We own and lease properties totaling approximately 1 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

We are parties to a number of legal proceedings, incident to our normal business activities. These matters include, but are not limited to, contract disputes, personal injury, property damage and employment 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 may be material to our cash flows, results of operations or financial condition.
 
We are also party to lawsuits and other legal proceedings related to the non-coal businesses previously conducted by Fluor Corporation (renamed Massey Energy Company) but now conducted by New Fluor. Under the terms of the Distribution Agreement entered into by New Fluor and us as of November 30, 2000, in connection with the Spin-Off of New Fluor, New Fluor agreed to indemnify us with respect to all such legal proceedings and has assumed their defense.

Additional legal proceedings required by this Item 3 are contained in Note 18, “Contingencies” to the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K, which is incorporated herein by reference.
 
 
 
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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, 2010, there were 86,545,037 shares outstanding and approximately 6,189 shareholders 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 2008
                 
Quarter ended March 31, 2008
  $ 44.00     $ 26.22     $ 0.05  
Quarter ended June 30, 2008
  $ 95.70     $ 35.33     $ 0.05  
Quarter ended September 30, 2008
  $ 94.09     $ 31.15     $ 0.05  
Quarter ended December 31, 2008
  $ 35.00     $ 10.05     $ 0.06