Alpha Natural Resources 10-K 2010 FY Annual report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 (Mark One)

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

For the fiscal year ended December 31, 2010

OR

¨ 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. 001-32331

ALPHA NATURAL RESOURCES, INC.

(Exact name of registrant as specified in its charter)

Delaware	42-1638663
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)
One Alpha Place, P.O. Box 2345, Abingdon, Virginia	24212
(Address of principal executive offices)	(Zip Code)

Registrant's telephone number, including area code:

(276) 619-4410

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

Title of Each Class	Name of Each Exchange on Which Registered
Common stock, $0.01 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  þ  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  þ

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  þ  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  þ  No  

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

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” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

The aggregate market value of the Common Stock held by non-affiliates of the registrant on June 30, 2010, was approximately $2.7 billion based on the closing price of the Company’s common stock as reported that date on the New York Stock Exchange of $33.87 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, $0.01 par value, outstanding as of February 18, 2011 – 120,483,943 shares.

DOCUMENTS INCORPORATED BY REFERENCE

 Part III incorporates certain information by reference from the registrant's definitive proxy statement for the 2011 annual meeting of stockholders (the “Proxy Statement”), which will be filed no later than 120 days after the close of the registrant's fiscal year ended December 31, 2010.

2010 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	5
Item 1A.	Risk Factors	29
Item 1B.	Unresolved Staff Comments	46
Item 2.	Properties	46
Item 3.	Legal Proceedings	51
Item 4.	Reserved	51
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	52
Item 6.	Selected Financial Data	55
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	59
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	85
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	158
Item 9A.	Controls and Procedures	158
Item 9B.	Other Information	160
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	160
Item 11.	Executive Compensation	160
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	160
Item 13.	Certain Relationships and Related Transactions, and Director Independence	160
Item 14.	Principal Accountant Fees and Services	160
PART IV
Item 15.	Exhibits and Financial Statement Schedules	161

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CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

This report includes statements of our expectations, intentions, plans and beliefs that constitute “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 and are intended to come within the safe harbor protection provided by those sections. These statements, which involve risks and uncertainties, relate to analyses and other information that are based on forecasts of future results and estimates of amounts not yet determinable and may also relate to our future prospects, developments and business strategies. We have used the words “anticipate”, “believe”, “could”, “estimate”, “expect”, “intend”, “may”, “plan”, “predict”, “ project”, “should” and similar terms and phrases, including references to assumptions, in this report to identify forward-looking statements. These forward-looking statements are made based on expectations and beliefs concerning future events affecting us and are subject to uncertainties and factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control, that could cause our actual results to differ materially from those matters expressed in or implied by these forward-looking statements.

The following factors are among those that may cause actual results to differ materially from our forward-looking statements:

· worldwide market demand for coal, electricity and steel;

· global economic, capital market or political conditions, including a prolonged economic recession in the markets in which we operate;

· decline in coal prices;

· our liquidity, results of operations and financial condition;

· regulatory and court decisions;

· competition in coal markets;

· changes in environmental laws and regulations, including those directly affecting our coal mining and production, and those affecting our customers' coal usage, including potential carbon or greenhouse gas related legislation;

· changes in safety and health laws and regulations and the ability to comply with such changes;

· availability of skilled employees and other employee workforce factors, such as labor relations;

· the inability of our third-party coal suppliers to make timely deliveries and the refusal by our customers to receive coal under agreed contract terms;

· the inability to collect payments from customers if their creditworthiness declines;

· potential instability and volatility in worldwide financial markets;

· future legislation and changes in regulations, governmental policies or taxes or changes in interpretation thereof;

· inherent risks of coal mining beyond our control;

· disruption in coal supplies;

· the geological characteristics of the Powder River Basin, Central and Northern Appalachian coal reserves;

· our production capabilities and costs;

· our ability to integrate successfully operations that we may acquire or develop in the future, including those of Massey Energy Company, or the risk that any such integration could be more difficult, time-consuming or costly than expected;

· our plans and objectives for future operations and expansion or consolidation;

· the consummation of financing transactions, acquisitions or dispositions and the related effects on our business, including financing related to our proposed acquisition of Massey Energy Company;

· the outcome of pending or potential litigation or governmental investigations;

· the ability to obtain governmental approvals of the merger with Massey Energy Company ("Massey Merger") on the proposed terms and schedule;

· the timing and completion of the Massey Merger, including the approval of the transaction at the Alpha special meeting and the Massey special meeting;

· uncertainty of the expected financial performance of Alpha following completion of the Massey Merger;

· our ability to achieve the cost savings and synergies contemplated by the Massey Merger within the expected time frame;

· disruption from the Massey Merger making it more difficult to maintain relationships with customers, employees or suppliers;

· the calculations of, and factors that may impact the calculations of, the acquisition price in connection with the Massey Merger and the allocation of such acquisition price to the net assets acquired in accordance with applicable accounting rules and methodologies;

· our relationships with, and other conditions affecting, our customers;

· reductions or increases in customer coal inventories and the timing of those changes;

· changes in and renewal or acquisition of new long-term coal supply arrangements;

· railroad, barge, truck and other transportation availability, performance and costs;

· availability of mining and processing equipment and parts;

· disruptions in delivery or changes in pricing from third party vendors of goods and services that are necessary for our operations, such as diesel fuel, steel products, explosives and tires;

· our assumptions concerning economically recoverable coal reserve estimates;

· our ability to obtain, maintain or renew any necessary permits or rights, and our ability to mine properties due to defects in title on leasehold interests;

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· our ability to negotiate new UMWA wage agreements on terms acceptable to us;

· changes in postretirement benefit obligations, pension obligations and federal and state black lung obligations;

· increased costs and obligations potentially arising from the Patient Protection and Affordable Care Act;

· fair value of derivative instruments not accounted for as hedges that are being marked to market;

· indemnification of certain obligations not being met;

· continued funding of the road construction business, related costs, and profitability estimates;

· restrictive covenants in our secured credit facility and the indentures governing the 7.25% notes due 2014 and the 2.375% convertible senior notes due 2015

· certain terms of the 7.25% notes due 2014 and the 2.375% convertible senior notes due 2015, including any conversions, that may adversely impact our liquidity;

· weather conditions or catastrophic weather-related damage; and

· other factors, including those discussed in Item 1A “Risk Factors” of this Annual Report on Form 10-K.

When considering these forward-looking statements, you should keep in mind the cautionary statements in this report and the documents incorporated by reference. We do not undertake any responsibility to release publicly any revisions to these forward-looking statements to take into account events or circumstances that occur after the date of this report. Additionally, we do not undertake any responsibility to update you on the occurrence of any unanticipated events, which may cause actual results to differ from those expressed or implied by the forward-looking statements contained in this report.

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PART I

Item 1. Business

Overview

On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings, Inc. (“Foundation”) merged (the “Foundation Merger”) with Foundation continuing as the surviving legal corporation of the Foundation Merger which was renamed Alpha Natural Resources, Inc. (“Alpha”). For financial accounting purposes, the Foundation Merger was treated as a “reverse acquisition” and Old Alpha was treated as the accounting acquirer. Accordingly, Old Alpha’s financial statements became the financial statements of Alpha and Alpha’s periodic filings subsequent to the Foundation Merger reflect Old Alpha’s historical financial condition and results of operations shown for comparative purposes. Old Alpha’s results of operations for the year ended December 3 1, 2008 do not include financial results for Foundation. For the year ended December 31, 2009, Foundation’s financial results are included for the five month period following the Foundation Merger from August 1, 2009 through December 31, 2009.

Unless we have indicated otherwise, or the context otherwise requires, references in this report to “Alpha”, “we”, “us” and “our” or similar terms are to Alpha and its consolidated subsidiaries in reference to dates subsequent to the Foundation Merger and to Old Alpha and its consolidated subsidiaries in reference to dates prior to the Foundation Merger.

We are one of America’s premier coal suppliers, ranked third largest among publicly-traded U.S. coal producers as measured by 2010 consolidated revenues of $3.9 billion. We are the nation’s leading supplier and exporter of metallurgical coal for use in the steel-making process and a major supplier of thermal coal to electric utilities and manufacturing industries across the country. We operate 66 mines and 13 coal preparation plants in Northern and Central Appalachia and the Powder River Basin, with approximately 6,500 employees.

We have two reportable segments: Eastern Coal Operations and Western Coal Operations. Eastern Coal Operations consists of the mines in Northern and Central Appalachia, our coal brokerage activities and our road construction business. Western Coal Operations consists of two Powder River Basin mines in Wyoming. Our All Other category includes an idled underground mine in Illinois; expenses associated with certain closed mines; Maxxim Rebuild and Dry Systems Technologies; revenues and royalties from the sale of coalbed methane and natural gas extraction; terminal services; the leasing of mineral rights; general corporate overhead and corporate assets and liabilities.

Steam coal, which is primarily purchased by large utilities and industrial customers as fuel for electricity generation, accounted for approximately 86% of our 2010 coal sales volume. Metallurgical coal, which is used primarily to make coke, a key component in the steel making process, accounted for approximately 14% of our 2010 coal sales volume. Metallurgical coal generally sells at a premium over steam coal because of its higher quality and its value in the steelmaking process as the raw material for coke. We believe that the volume of the coal we sell will grow when and if demand for power and steel increases.

During 2010, we sold a total of 84.8 million tons of steam and metallurgical coal and generated coal revenues of $3.5 billion, EBITDA from continuing operations of $769.1 million and income from continuing operations of $97.2 million. We define and reconcile EBITDA from continuing operations in Item 6-“Selected Financial Data.” Our coal sales during 2010 consisted of 82.6 million tons of produced and processed coal, including 0.8 million tons purchased from third parties and processed at our processing plants or loading facilities prior to resale, and 2.2 million tons of purchased coal which we resold without processing. Approximately 73% of the coal we purchased in 2010 was blended with coal produced from our mines prior to resale. Approximately 35% of our coal revenues combined with freight and hand ling revenues in 2010 was derived from sales made outside the United States, primarily in Brazil, Italy, India, Turkey and Ukraine.

As of December 31, 2010, we owned or leased approximately 2.3 billion tons of proven and probable coal reserves. Of our total proven and probable reserves, approximately 63% are low sulfur reserves, with approximately 53% having sulfur content below 1%. Approximately 64% of our total proven and probable reserves have a high Btu content which creates more energy per unit when burned compared to coals with lower Btu content. We believe that our total proven and probable reserves will support current production levels for more than 20 years.

On January 29, 2011, Alpha and Massey Energy Company (“Massey”) announced a signed definitive agreement under which we will acquire all outstanding shares of Massey common stock, subject to customary closing conditions including stockholder approval of both companies and customary regulatory approvals. Under the terms of the agreement, Massey stockholders will receive, upon consummation of the Massey Merger, 1.025 shares of Alpha common stock and $10.00 in cash for each share of Massey common stock. Upon consummation of the Massey Merger, Alpha and Massey stockholders will own approximately 54% and 46% of the combined company, respectively. The Massey Merger will bring together Alpha’s and Massey’s highly complementary assets, which will include more than 110 mines and combined coal reserves of approxima tely 5.1 billion tons, including one of the world’s largest and highest-quality metallurgical coal reserve bases.

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History

Old Alpha was formed under the laws of the State of Delaware on November 29, 2004.  On February 15, 2005, an initial public offering of Old Alpha’s common stock occurred and since then, we have grown substantially through a series of acquisitions including the Foundation Merger in 2009 discussed above. 

During 2006, Old Alpha acquired certain coal mining operations in eastern Kentucky from Progress Fuels Corp, a subsidiary of Progress Energy. These operations are adjacent to our Enterprise operations and were integrated with Enterprise.  

During 2007, Old Alpha completed the acquisition of certain coal mining assets in western West Virginia known as Mingo Logan from Arch Coal, Inc. The Mingo Logan purchase consisted of coal reserves, one active deep mine and a load-out and processing plant, which is managed by our Callaway operations.  

During 2008:

• Our subsidiary, Alpha Terminal Company, LLC, increased its equity ownership position in Dominion Terminal Associates (“DTA”) from approximately 33% to approximately 41%, effectively increasing our coal export and terminal capacity at DTA from approximately 6.5 million tons to approximately 8.0 million tons annually.  DTA is a 20 million-ton annual capacity coal export terminal located in Newport News, Virginia.

• Old Alpha sold its interest in Gallatin Materials LLC (“Gallatin”), a start-up lime manufacturing business in Verona, Kentucky, for cash in the amount of $45.0 million.  The proceeds were used in part to repay the Gallatin loan facility outstanding with NedBank Limited in the amount of $18.2 million.  Old Alpha recorded a gain on the sale of $13.6 million in the third quarter of 2008.

• Old Alpha entered into a definitive merger agreement pursuant to which, and subject to the terms and conditions thereof, Cliffs Natural Resources Inc. (formerly known as Cleveland Cliffs Inc.) (“Cliffs”) would acquire all of Old Alpha’s outstanding shares. On November 3, 2008, Old Alpha commenced litigation against Cliffs by filing an action in the Delaware Court of Chancery to obtain an order requiring Cliffs to hold its scheduled shareholder meeting. During the fourth quarter of 2008, Old Alpha and Cliffs mutually terminated the merger agreement and settled the litigation.  The terms of the settlement agreement included a $70.0 million payment from Cliffs to Old Alpha which, net of transaction costs, resulted in a gain of $56.3 million.

• Old Alpha announced the permanent closure of the Whitetail Kittanning Mine, an adjacent coal preparation plant and other ancillary facilities (“Kingwood”).  The mine stopped producing coal in early January 2009 and we ceased equipment recovery operations by the end of April 2009.  The decision resulted from adverse geologic conditions and regulatory requirements that rendered the coal seam unmineable at this location. Old Alpha recorded a charge of $30.2 million in the fourth quarter of 2008, which includes asset impairment charges of $21.2 million, write off of advance mining royalties of $3.8 million, which will not be recoverable, severance and other employee benefit costs of $3.6 million and increased reclamation obligations of $1.9 million.

• Approximately 17.6 million tons of underground coal reserves in eastern Kentucky that Old Alpha had originally acquired as part of the Progress acquisition were sold to a private coal producer for approximately $13.0 million in cash.

During 2010, we entered into a 50/50 joint venture with Rice Energy, LP through which we are developing our Marcellus Shale natural gas resource in southwestern Pennsylvania, where we control nearly 20,000 acres of one of the Marcellus’ most productive regions.

Competitive Strengths

We believe that the following competitive strengths enhance our prominent position in the United States:

We are the third largest publicly traded coal producer in the United States based on 2010 consolidated revenues and have significant coal reserves. Based on 2010 consolidated revenues of $3.9 billion, we are the third largest publicly traded coal producer in the United States. As of December 31, 2010, we controlled approximately 2.3 billion tons of proven and probable coal reserves.

We have a diverse portfolio of coal mining operations and reserves. We operate a total of 66 mines and have reserves in the three major U.S. coal producing regions: Northern and Central Appalachia and the Powder River Basin. Our mines are located in Wyoming, Pennsylvania, West Virginia, Virginia, Illinois and Kentucky. We sell coal to domestic and foreign electric utilities, steel producers and industrial users. We believe we are the only producer with significant operations and major reserve blocks in both the Powder River Basin and Northern Appalachia, two U.S. coal production regions for which future demand is expected to increase. We believe that this geographic diversity provides us with a significant competitive advantage, allowing us to source coal from mu ltiple regions to meet the needs of our customers and reduce their transportation costs.

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We are a recognized industry leader in safety and environmental performance. Our focus on safety and environmental performance results in a lower likelihood of disruption of production at our mines, which leads to higher productivity and improved financial performance. We operate some of the nation’s safest mines, with 2010 total injury incident rates, as tracked by the Mine Safety and Health Administration (“MSHA”), below industry averages.

Our ability to blend coals from our operations allows us to increase our coal revenues and gross margins while meeting our customer requirements. The strategic locations of our mines and preparation plants provide us the ability to blend coals from our operations and increase coal revenues and gross margins while meeting our customer requirements.

We have long-standing relationships and long-term contracts with many of the largest coal-burning utilities in the United States. We supply coal to numerous power plants operated by a diverse group of electricity generators across the country. We believe we have a reputation for reliability and superior customer service that has enabled us to solidify our customer relationships.

We are the largest producer of metallurgical coal in the United States and have access to international customers. We are the largest producer of metallurgical coal in the United States and have the ability to serve international customers. We have the capacity to ship approximately 8 million tons annually through our 41% ownership interest in DTA and through our access to other international shipping points.

Our management team has a track record of success. Our management team has a proven record of generating free cash flow, reducing costs, developing and maintaining long-standing customer relationships and effectively positioning us for future growth and profitability.

Business Strategy

Our objective is to increase shareholder value through sustained earnings growth and free cash flow generation. Our key strategies to achieve this objective are described below:

Maintaining our commitment to operational excellence. We seek to maintain our operational excellence with an emphasis on investing selectively in new equipment and advanced technologies. We will continue to focus on profitability and efficiency by leveraging our significant economies of scale, large fleet of mining equipment, information technology systems and coordinated purchasing and land management functions. In addition, we continue to focus on productivity through our culture of workforce involvement by leveraging our strong base of experienced, well-trained employees.

Capitalizing on industry dynamics through a balanced approach to selling our coal. Despite the volatility in coal prices over the past several years, we believe the long-term fundamentals of the U.S. coal industry are favorable. We plan to continue employing a balanced approach to selling our coal, including the use of long-term sales commitments for a portion of our future production while maintaining uncommitted planned production to capitalize on favorable future pricing environments.

Selectively expanding our production and reserves. Given our broad scope of operations and expertise in mining in major coal-producing regions in the United States, we believe that we are well-situated to capitalize on the expected continued growth in U.S. and international coal consumption by evaluating growth opportunities, including expansion of production capacity at our existing mining operations, further development of existing significant reserve blocks in Northern and Central Appalachia, and potential strategic acquisition opportunities that arise in the United States or internationally. We will prudently act to expand our reserves when appropriate. 

 Continuing to provide a mix of coal types and qualities to satisfy our customers’ needs. By having operations and reserves in three major coal producing regions, we are able to source and blend coal from multiple mines to meet the needs of our domestic and international customers. Our broad geographic scope and mix of coal qualities provide us with the opportunity to work with many leading electricity generators, steel companies and other industrial customers across the country.

Continuing to focus on excellence in safety and environmental stewardship. We intend to maintain our recognized leadership in operating some of the safest mines in the United States and in achieving environmental excellence. Our ability to minimize workplace incidents and environmental violations improves our operating efficiency, which directly improves our cost structure and financial performance.

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Coal Mining Techniques

We use four different mining techniques to extract coal from the ground: longwall mining, room-and-pillar mining, truck-and-shovel mining and truck and front-end loader mining.

Longwall Mining

We utilize longwall mining techniques at our Pennsylvania Services business unit. Longwall mining is the most productive and safest underground mining method used in the United States. A rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface. Continuous miners are used to develop access to long rectangular blocks of coal which are then mined with longwall equipment, allowing controlled subsidence behind the advancing machinery. Longwall mining is highly productive and most effective for large blocks of medium to thick coal seams. High capital costs associated with longwall mining demand large, contiguous reserves. Ultim ate seam recovery of in-place reserves using longwall mining is much higher than the room-and-pillar mining underground technique. All of the raw coal mined at our longwall mines is washed in preparation plants to remove rock and impurities.

Room-and-Pillar Mining

Our AMFIRE, Southern West Virginia, Northern West Virginia, and Virginia/Kentucky business units utilize room-and-pillar mining methods. In this type of mining, main airways and transportation entries are developed and maintained while remote-controlled continuous miners extract coal from so-called rooms by removing coal from the seam, leaving pillars to support the roof. Shuttle cars and battery coal haulers are used to transport coal to the conveyor belt for transport to the surface. This method is more flexible than longwall mining and often used to mine smaller coal blocks or thin seams. Ultimate seam recovery of in-place reserves is typically less than that achieved with longwall mining. All of this production is also washed in preparation plants before it becomes saleable clean coal.

Truck-and-Shovel Mining and Truck and Front-End Loader Mining

We utilize truck-and-shovel mining methods in both of our mines in the Powder River Basin. We utilize the truck and front-end loader method at the surface mines in our AMFIRE, Southern West Virginia, Northern West Virginia, and Virginia/Kentucky business units. These methods are similar and involve using large, electric or hydraulic-powered shovels or diesel-powered front-end loaders to remove earth and rock (overburden) covering a coal seam which is later used to refill the excavated coal pits after the coal is removed. The loading equipment places the coal into haul trucks for transportation to a preparation plant or loadout area. Ultimate seam recovery of in-place reserves on average exceeds 90%. This surface-mined coal rarely needs to be cleaned in a preparation plant before sale. Productivity depends on overburden and coal thickness (strip ratio), equipment utilized and geologic factors.

Coal Characteristics

In general, coal of all geological compositions is characterized by end use as either steam coal or metallurgical coal. Heat value, sulfur and ash content, and in the case of metallurgical coal, volatility, are the most important variables in the profitable marketing and transportation of coal. These characteristics determine the best end use of a particular type of coal. We mine, process, market and transport sub-bituminous and bituminous coal, characteristics of which are described below.

Heat Value. The heat value of coal is commonly measured in British thermal units, or “Btus.” A Btu is the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Alpha mines both sub-bituminous and bituminous coal. Bituminous coal is located primarily in Appalachia, Arizona, the Midwest, Colorado, Wyoming and Utah and is the type most commonly used for electric power generation in the United States. Sub-bituminous coal is used for industrial steam purposes, while bituminous coal, depending on its quality, can be used for both metallurgical and industrial steam purposes. Of our estimated 2.3 billion tons of proven and probable reserves, approximately 64% have a heat value above 12,500 Btus per pound, which is considered high bt u coal.

Sulfur Content. Sulfur content can vary from seam to seam and sometimes within each seam. When coal is burned, it produces sulfur dioxide, the amount of which varies depending on the chemical composition and the concentration of sulfur in the coal. Low sulfur coals have a sulfur content of 1.5% or less. Approximately 63% of our proven and probable reserves are low sulfur coal.

High sulfur coal can be burned in plants equipped with sulfur-reduction technology, such as scrubbers, which can reduce sulfur dioxide emissions by 50% to 90%. Plants without scrubbers can burn high sulfur coal by blending it with lower sulfur coal or by purchasing emission allowances on the open market, allowing the user to emit a predetermined amount of sulfur dioxide. Some older coal-fired plants have been retrofitted with scrubbers, although most have shifted to lower sulfur coals as their principal strategy for complying with Phase II of the Clean Air Act's Acid Rain regulations. We expect that any new coal-fired generation plants built in the United States will use clean coal-burning technology and will include scrubbers.

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Ash & Moisture Content. Ash is the inorganic residue remaining after the combustion of coal. As with sulfur content, ash content varies from seam to seam. Ash content is an important characteristic of coal because electric generating plants must handle and dispose of ash following combustion. The absence of ash is also important to the process by which metallurgical coal is transformed into coke for use in steel production. Moisture content of coal varies by the type of coal, the region where it is mined and the location of coal within a seam. In general, high moisture content decreases the heat value and increases the weight of the coal, thereby reducing its value and making it more expensive to transport. Moisture content in coal, as sold, can range from approximately 5% to 30% of the coal's weight.

Coking Characteristics. The coking characteristics of metallurgical coal are typically measured by the coal's fluidity, ARNU and volatility. Fluidity and ARNU tests measure the expansion and contraction of coal when it is heated under laboratory conditions to determine the strength of the coke that could be produced from a given coal. Typically, higher numbers on these tests indicate higher coke strength. Volatility refers to the loss in mass, less moisture, when coal is heated in the absence of air. The volatility of metallurgical coal determines the percentage of feed coal that actually becomes coke, known as coke yield, all other metallurgical characteristics being equal. Coal with a lower volatility produces a higher coke yield and is more highly valued than coal with a hi gher volatility.

Business Environment

Coal is an abundant, efficient and affordable natural resource used primarily to provide fuel for the generation of electric power. According to the U.S. Department of Energy's Energy Information Administration "EIA" 2010 International Energy Outlook, world-wide economically recoverable coal reserves using today’s technology are estimated to be approximately 909 billion tons. Also according to the 2010 EIA International Energy Outlook, the United States is one of the world’s largest producers of coal and has approximately 29% of global coal reserves, representing nearly 228 years of supply based on current usage rates. According to the U.S. Department of Energy, the energy content of the United States coal reserves exceeds that of all the known oil supplies in the world.

Coal Markets. Coal is primarily consumed by utilities to generate electricity. It is also used by steel companies to make steel products and by a variety of industrial users to heat and power foundries, cement plants, paper mills, chemical plants and other manufacturing and processing facilities. In general, coal is characterized by end use as either steam coal or metallurgical coal. Steam coal is used by electricity generators and by industrial facilities to produce steam, electricity or both. Metallurgical coal is refined into coke, which is used in the production of steel. Over the past forty years, total annual coal consumption in the United States (excluding exports) has more than doubled to over one billion tons in 2010. The growth in the demand for coal ha s coincided with an increased demand for coal from electric power generators.

	Actual (1)						Preliminary (1)		Projected (1)				Annual Growth
Consumption by Sector	2007		2008		2009		2010		2015		2030		2010-2015			2015-2030
	(Tons in millions)
Electric Generation		1,045		1,041		937		980		932		1,105		(5	)%		19	%
Industrial		57		54		45		48		49		48		3	%		(2	)%
Steel Production		23		22		15		21		22		19		7	%		(13	)%
Coal-to-Liquids Processes		-		-		-		-		11		65					473	%
Residential/Commercial		4		4		3		3		3		3		3	%		(3	)%
Export		59		82		59		77		70		76		(9	)%		9	%
Total		1,188		1,202		1,059		1,129		1,087		1,316		(4	)%		21	%

(1) Data sourced from the U.S. Department of Energy’s EIA’s 2010 and 2011 Annual Energy Outlook.

Much of the nation’s power generation infrastructure is coal-fired. As a result, coal has consistently maintained a 46% to 53% market share during the past 10 years according to the U.S. Department of Energy EIA's Short-Term Energy Outlook, principally because of its relatively low cost, reliability and domestic abundance. Coal is a low-cost fossil fuel used for base-load electric power generation, typically being considerably less expensive than oil and generally competitive with natural gas. Coal-fired generation is also competitive with nuclear power generation especially on a total cost per megawatt-hour basis. The production of electricity from existing hydroelectric facilities is inexpensive, but its application is limited both by geography and susceptibility to seasonal and climatic conditions. Through 2010, non-hydropower r enewable power generation accounted for only 3.5% of all the electricity generated in the United States, and wind and solar power represented only 2.4% of United States power generation according to the U.S. Department of Energy EIA's Short-Term Energy Outlook.

Coal consumption patterns are also influenced by the demand for electricity, governmental regulation impacting power generation, technological developments, transportation costs, and the location, availability and cost of other fuels such as natural gas, nuclear and hydroelectric power.

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Coal’s primary advantages are its relatively low cost and availability compared to other fuels used to generate electricity. According to the EIA, the estimated levelized cost of generation for various power generation technologies, including levelized capital costs, fixed operating and maintenance (O&M), variable O&M (including fuel) and transmission investment are as follows:

Levelized Cost of Electricity(1)
	$/MWh
	Mean		Minimum		Maximum
Supercritical Pulverized Coal	$	62.0	$	49.0	$	82.0
Integrated Gasification Combined Cycle	$	62.5	$	53.0	$	71.0
Natural Gas Combined Cycle	$	70.5	$	58.0	$	87.0
Nuclear	$	81.5	$	65.0	$	110.0
Onshore Wind	$	119.6	$	50.0	$	156.0
Offshore Wind	$	123.7	$	71.0	$	181.0
Biomass Circulating Fluidized Bed	$	146.0	$	73.0	$	180.0
Hydro	$	154.0	$	45.0	$	262.0
Solar Thermal	$	246.3	$	175.0	$	324.0
Solar Photovoltaic	$	1,017.8	$	226.0	$	2,031.0

(1) Figures represent the minimum, maximum and average values of levelized costs of electricity from multiple studies depicted in the IEA report Projected Costs of Generating Electricity, 2010 Edition, tables 11.1B and 11.2.

Coal Production. United States coal production was approximately 1.1 billion tons in 2010. The following table, derived from data prepared by the EIA, sets forth production statistics in each of the major coal producing regions for the periods indicated.

	Actual (1)						Preliminary (1)		Projected (1)				Annual Growth
Production by Region	2007		2008		2009		2010		2015		2030			2010-2015		2015-2030
	(Tons in millions)
Powder River Basin		480		452		417		434		436		559		0	%	6	%
Central Appalachia		227		234		197		193		114		103		(8	)%	(2	)%
Northern Appalachia		133		136		128		133		143		163		1	%	-
Illinois Basin		96		102		106		110		114		124		1	%	-
Other		211		248		227		228		237		298		1	%	1	%
Total		1,147		1,172		1,075		1,098		1,044		1,246		(1	)%	1	%

(1) Data sourced from the EIA’s 2010 and 2011 Annual Energy Outlook

Coal Regions. Coal is mined from coal fields throughout the United States, with the major production centers located in the Western United States, Northern and Central Appalachia and the Illinois Basin. The quality of coal varies by region. Physical and chemical characteristics of coal are very important in measuring quality and determining the best end use of particular coal types.

Competition. The coal industry is intensely competitive. With respect to our U.S. customers, we compete with numerous coal producers in the Appalachian region and with a large number of western coal producers. Competition from coal with lower production costs shipped east from western coal mines has resulted in increased competition for coal sales in the Appalachian region. In 2010, imports accounted for a relatively small percentage of total U.S coal consumption. Approximately 2% of total U.S. coal consumption in 2010 was imported. Excess industry capacity, which has occurred in the past, tends to result in reduced prices for our coal. The most important factors on which we compete are delivered coal price, coal quality and characteristics, transportat ion costs from the mine to the customer and the reliability of supply. Demand for coal and the prices that we will be able to obtain for our coal are closely linked to coal consumption patterns of the domestic electric generation industry, which has accounted for greater than 93% of 2010 domestic coal consumption. These coal consumption patterns are influenced by factors beyond our control, including the demand for electricity, which is significantly dependent upon summer and winter temperatures and commercial and industrial outputs in the United States, environmental and other government regulations, technological developments and the location, availability, quality and price of competing fuels for power such as natural gas, nuclear, fuel oil and alternative energy sources such as hydroelectric power. Demand for our low sulfur coal and the prices that we will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allow ances in order to meet Clean Air Act requirements.

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Demand for our metallurgical coal and the prices that we will be able to obtain for metallurgical coal will depend to a large extent on the demand for U.S. and international steel, which is influenced by factors beyond our control, including overall economic activity and the availability and relative cost of substitute materials. In the export metallurgical market, during 2010 and 2009, we largely competed with producers from Australia, Canada, and other international producers of metallurgical coal.

Mining Operations

We currently have six regional business units, operating in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming.  As of December 31, 2010, these business units include 13 preparation plants, each of which receive, blend, process and ship coal that is produced from one or more of our 66 active mines (some of which are operated by third parties under contracts with us), using four mining methods: longwall mining, room-and-pillar mining, truck-and-shovel mining and truck and front-end loader mining. Our underground mines generally consist of one or more single or dual continuous miner sections which are made up of the continuous miner, shuttle cars or continuous haulage, roof bolters, and various ancillary equipment. We have two large underground mines that employ a longwall mining system. Our Eastern surface mines are a c ombination of contour highwall miner, auger operations using truck/loader-excavator equipment fleets along with large production tractors and a small percentage using mountain top removal. Our Western surface mines are large open-pit operations that use the truck-and-shovel mining method. Most of our preparation plants are modern heavy media plants that generally have both coarse and fine coal cleaning circuits. We employ preventive maintenance and rebuild programs to ensure that our equipment is modern and well-maintained. During 2010, most of our preparation plants also processed coal that we purchased from third party producers before reselling it to our customers. Within each regional business unit, mines have been developed at strategic locations in close proximity to our preparation plants and rail shipping facilities. Coal is transported from our regional business units to customers by means of railroads, trucks, barge lines, and ocean-going vessels from terminal facilities.

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The following table provides location and summary information regarding our six regional business units and the preparation plants and active mines associated with these business units as of December 31, 2010:

Regional Business Units

			Number and Type of Mines as of December 31, 2010
Business Unit	Location	Preparation Plants/Shipping Points as of December 31, 2010	Underground		Surface		Total		Transportation	2010 Production of Saleable Tons (in thousands) (1)
Pennsylvania Services	Pennsylvania	Cumberland and Emerald		2		-		2	Barge, Truck, CSX, NS		10,666
AMFIRE	Pennsylvania	Clymer and Portage		5		11		16	NS, Truck		2,590
Southern West Virginia	West Virginia, Virginia	Litwar, Kepler and  Black Bear		13		3		16	NS		5,136
Northern West Virginia	West Virginia	Erbacon, Kingston, Rockspring and Pioneer		5		3		8	Barge, CSX, NS, RJCC, Truck		7,456
Virginia/Kentucky (2)	Virginia, Kentucky	Toms Creek, Roxana, McClure River and Moss #3		13		9		22	CSX, NS, Truck		7,313
Alpha Coal West	Wyoming	Belle Ayr and Eagle Butte		-		2		2	BNSF, UP, Truck		48,992
	Total from active operations			38		28		66			82,153

(1) Includes coal purchased from third-party producers that was processed at our subsidiaries' preparation plants in 2010.

(2) In November 2010, Alpha placed Moss #3 preparation plant on idle status.

BNSF = BNSF Railway

CSX = CSX Transportation

RJCC = R.J. Corman Railroad Company

NS = Norfolk Southern Railway Company

UP = Union Pacific Railroad Company

The coal production and processing capacity of our mines and processing plants is influenced by a number of factors including reserve availability, labor availability, environmental permit timing, and preparation plant capacity.

Pennsylvania Services

Our Pennsylvania Services business unit consists of our Cumberland and Emerald mining complexes, which collectively shipped 11.1 million tons in 2010. Coal is mined primarily by using longwall mining systems supported by continuous miners. We control approximately 775.3 million tons of contiguous reserves through our Pennsylvania Services business unit. Approximately 175.0 million tons are assigned to active mines and 600.3 million tons are unassigned. Both mines operate in the Pittsburgh No. 8 Seam, the dominant coal-producing seam in the region, which is six to eight feet thick in the mines. The mines sell high Btu, high sulfur coal primarily to eastern utilities. There are 1,515 salaried and hourly employees at our Pennsylvania Services business unit. The hourly work force at each mine is represented by the United Mine Workers of America (“UMWA”).

Cumberland shipped 5.8 million tons of coal in 2010. All of the coal at Cumberland is processed through a preparation plant before being loaded onto Cumberland’s owned and operated railroad for transportation to the Monongahela River dock site. At the dock site, coal is then loaded into barges for transportation to river-served utilities or to other docks for subsequent rail shipment to non-river-served utilities. The mine can also ship a portion of its production by truck.

Emerald shipped 5.3 million tons of coal in 2010. Emerald has the ability to store clean coal and blend variable sulfur products to meet customer requirements. All of Emerald’s coal is processed through a preparation plant before being loaded into unit trains operated by the Norfolk Southern Railway or CSX Transportation. The mine also has the option to ship a portion of its coal by truck.

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AMFIRE

Our AMFIRE business unit consists of five underground mines operated by AMFIRE employees and eleven surface mines, six of which are operated by independent contractors. Coal is mined primarily using continuous miners employing the room-and-pillar mining method at the underground mines and the truck and front end loader method at our surface mines. We control approximately 83.7 million tons of coal reserves through our AMFIRE business unit. Approximately 34.3 million tons are assigned to active mines and approximately 49.4 million tons are unassigned. AMFIRE employs 480 salaried and hourly employees. The mines sell high Btu, low, medium, and high sulfur coal to eastern utilities and steel companies. All of the underground mining operations at AMFIRE a re staffed and operated by AMFIRE employees. The underground coal is delivered directly by truck to the customer, or transported to the Clymer or Portage coal preparation plants or raw coal loading docks where it is cleaned, blended and loaded onto rail, belt or truck for shipment to customers. The surface mined coal is delivered directly by truck to the customer or transported to the Clymer or Portage coal preparation plants or raw coal loading docks where it is blended and loaded onto rail, belt or truck for shipment to customers. During 2010, AMFIRE shipped 2.5 million tons, which included 0.1 million tons of coal purchased from third parties that was blended with AMFIRE's coal and shipped to our customers.

Southern West Virginia

Our Southern West Virginia business unit consists of our Brooks Run South and Callaway operations, which collectively shipped 5.1 million tons in 2010. Coal is mined primarily using continuous miners employing the room-and-pillar mining method at our underground mines and the truck and front end loader method at our surface mines. We control approximately 96.3 million tons of coal reserves through our Southern West Virginia business unit. Approximately 44.7 million tons are assigned to active mines and approximately 51.6 million tons are unassigned. There are 670 salaried and hourly employees at our Southern West Virginia business unit.

Brooks Run South produces coal from twelve underground mines, four of which are underground mines operated by our employees, and eight that are operated by independent contractors. The mines sell high Btu, low sulfur coal to eastern utilities and metallurgical coal to steel companies. The coal is transported by truck or rail to the Litwar and Kepler preparation plants operated by Brooks Run South, where it is cleaned, blended and loaded onto rail for shipment to customers.  During 2010, Brooks Run South shipped 2.2 million tons, which included approximately 0.5 million tons of coal purchased from third parties that was blended with other coals and shipped to our customers.

Callaway produces coal from three surface mining operations operated by our Callaway employees and one underground mine operated by our subsidiary Cobra Natural Resources, LLC (“Cobra”) using continuous miners and the room-and-pillar mining method.  The mines sell high Btu, low sulfur coal to eastern utilities and metallurgical coal to steel companies. Callaway also recovers coal from the road construction business operated by our subsidiary Nicewonder Contracting, Inc. (“NCI”). Coal from the three surface mines and NCI is transported by truck to the Black Bear preparation plant or the Ben Creek or Mate Creek loadouts operated by Cobra or the Virginia Energy loadout operated by Callaway where the coal is cleaned, blended, and loaded onto rail for shipment to customers. Coal from the underground mine is b elted to the Black Bear preparation plant where it is cleaned and then loaded into railcars at the Ben Creek loadout for shipment to our customers. During 2010, Callaway shipped 2.9 million tons, which included less than 0.1 million tons of coal purchased from third parties.

Northern West Virginia

Our Northern West Virginia business unit consists of our Brooks Run North, Kingston, Rockspring, and Pioneer operations, which collectively shipped 7.6 million tons in 2010. Coal is mined primarily using continuous miners employing the room-and-pillar mining method at our underground mines and the truck and front end loader method at our surface mines. We control approximately 258.1 million tons of coal reserves through our Northern West Virginia business unit. Approximately 70.5 million tons are assigned to active mines and approximately 187.6 million tons are unassigned. There are 1,100 salaried and hourly employees at our Northern West Virginia business unit.

Brooks Run North produces coal from two underground mines and one surface mine operated by our Brooks Run North employees. The mines sell high Btu, medium sulfur coal primarily to eastern utilities. The coal is transported by truck to the Erbacon preparation plant operated by Brooks Run North where it is cleaned, blended and loaded onto rail for shipment to customers. During 2010, Brooks Run North shipped 2.4 million tons.

Kingston produces coal from two underground mines operated by Kingston employees. Kingston sells primarily metallurgical coal. The coal is trucked to the Kanawha River for shipment by barge or to CSX Transportation or the Norfolk Southern Railway load-outs for shipment by rail. During 2010, Kingston shipped 1.1 million tons.

Rockspring operates a large multiple section mining complex called Camp Creek that produces coal from one underground mine operated by our Rockspring employees. The mine sells mid Btu, low and medium sulfur coal primarily to southeastern utilities. Rockspring has a mine site rail loadout served by Norfolk Southern Railway. The mine can also ship a portion of its production by truck. Rockspring shipped 3.1 million tons of coal in 2010.

Pioneer produces coal from two surface mines: Paynter Branch and Pax. These mines sell high Btu, low and medium sulfur steam coal primarily to eastern utilities and metallurgical coal to steel companies. The Pioneer mines shipped 1.0 million tons of steam and metallurgical coal in 2010. Coal from Paynter Branch is shipped by truck to our on-site rail loading facility on the Norfolk Southern Railway and then on to domestic utilities and exported to metallurgical coal customers. Coal from Pax is shipped to customers primarily via rail, with coal being trucked from the mine to our on-site train loading facility served by CSX Transportation and R.J. Corman Railroad. Pax coal may also be trucked to the Kanawha River for shipment by barge. In late 2010, Paynter Branch completed mining the reserves at its current mine. The equipment and em ployees were subsequently redeployed to the Pax mine.

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Virginia/Kentucky

Our Virginia/Kentucky business unit consists of our Paramont, Dickenson-Russell and Enterprise operations, which collectively shipped 7.3 million tons in 2010. Coal is mined primarily using continuous miners employing the room-and-pillar mining method at our underground mines and the truck and front end loader method at our surface mines. We control approximately 354.9 million tons of coal reserves through our Virginia/Kentucky business unit. Approximately 176.8 million tons are assigned to active mines and approximately 178.1 million tons are unassigned. There are approximately 1,385 salaried and hourly employees at our Virginia/Kentucky business unit.

Paramont produces coal from eight underground mines, four of which are operated by independent contractors. Paramont also operates seven surface mines, three of which are operated by independent contractors. These mines sell high Btu, low sulfur coal primarily to eastern utilities and metallurgical coal to steel companies. The coal produced by the underground mines is transported by truck to the Toms Creek preparation plant operated by Paramont, or the McClure River preparation plant operated by Dickenson-Russell. At the preparation plant, the coal is cleaned, blended and loaded onto rail for shipment to customers. The coal produced by the surface mines is transported to one of our preparation plants or raw coal loading docks where it is blended and loaded onto rail for shipment to customers. During 2010, Paramont shipped 4.2 million ton s, which included less than 0.1 million tons of coal purchased from third parties that was blended with Paramont's coal and shipped to our customers.

Dickenson-Russell produces coal from three underground mines. These mines sell high Btu, low sulfur coal primarily to eastern utilities and metallurgical coal to steel companies. The coal is transported by truck to the McClure River preparation plant operated by Dickenson-Russell or the Toms Creek preparation plant operated by Paramont where it is cleaned, blended and loaded on rail or truck for shipment to customers. During 2010, Dickenson-Russell shipped 0.9 million tons, which included less than 0.1 million tons of coal purchased from third parties that was blended with Dickenson-Russell's coal and shipped to our customers.

Enterprise produces coal from two underground mines. Enterprise also has two surface mines, one of which is operated by an independent contractor. These mines sell high Btu, low, medium, and high sulfur coal primarily to eastern utilities and metallurgical coal to steel companies. The coal produced by the underground mines is transported by truck to the Roxana coal preparation plant operated by Enterprise where it is cleaned, blended and loaded onto rail for shipment to customers. The coal produced by the surface mine is transported to the Roxana preparation plant and Pioneer loadout facility where it is blended and loaded onto rail for shipment to customers. During 2010, Enterprise shipped 2.2 million tons, which included less than 0.1 million tons of coal purchased from third parties that was blended with Enterprise's coal and shipped to our customers.

Alpha Coal West

Our Alpha Coal West business unit is located in the Powder River Basin. Alpha Coal West consists of our Belle Ayr and Eagle Butte operations, which collectively shipped 49.0 million tons in 2010. Coal is mined primarily using the truck and shovel mining method. We control approximately 653.2 million tons of coal reserves through our Alpha Coal West business unit and all of the coal reserves are assigned to active mines. There are approximately 660 salaried and hourly employees at our Alpha Coal West business unit.

Belle Ayr consists of one mine that produces sub-bituminous, low sulfur coal for sale primarily to utility companies. Belle Ayr extracts coal from a coal seam that is 75 feet thick. The mine sells 100% raw coal mined and no washing is necessary. Belle Ayr shipped 25.8 million tons of coal in 2010. We plan to apply to lease several hundred million tons of surface mineable federal coal reserves that adjoins Belle Ayr’s property under the lease by application (“LBA”) process. If we prevail in the bidding process and obtain these reserves, we will be able to extend the life of the mine. Belle Ayr has the advantage of shipping its coal on both of the major western railroads, the BNSF Railway and the Union Pacific Railroad, to power plants located throughout the West, Midwest and the South.

Eagle Butte consists of one mine that produces sub-bituminous, low sulfur coal for sale primarily to utility companies. Eagle Butte extracts coal from coal seams that total 100 feet thick. The mine sells 100% raw coal mined and no washing is necessary. Eagle Butte shipped 23.2 million tons of coal in 2010. Coal from Eagle Butte is shipped on the BNSF Railway to power plants located throughout the West, Midwest and the South. The mine also ships a small portion by truck.

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Other Operations

We have other operations and activities in addition to our coal production, processing and sales business, including:

Road Construction Business. NCI operates a road construction business under a contract with the State of West Virginia Department of Transportation. Pursuant to the contract, NCI is completing approximately 11 miles of rough grade road in West Virginia over approximately the next year and, in exchange, NCI will be compensated by West Virginia based on the number of cubic yards of material excavated and/or filled to create a road bed, as well as for certain other cost components. As the road is constructed, any coal recovered is sold by NCI as part of its coal operations. We also have other minor road construction projects in conjunction with other surface mining operations.

Maxxim Rebuild and Dry Systems Technologies. Our subsidiary Maxxim Rebuild Co., LLC, is a mining equipment company with facilities in Kentucky and Virginia. This business largely consists of repairing and reselling equipment and parts used in surface mining and in supporting preparation plant operations. Our subsidiary Dry Systems Technologies manufactures patented particulate scrubbers and filters for underground diesel engine applications and rebuilds underground mining equipment for external customers and our subsidiaries.

Coalbed Methane and Natural Gas Extraction. A subsidiary engages in degassing services in advance of mining in Pennsylvania. Coal bed methane is directed through pipelines and sold to third parties. We also control approximately 20,000 acres of Marcellus Shale natural gas holdings in southwest Pennsylvania in one of the Marcellus’ most productive regions. During 2010, we entered into a 50/50 joint venture with Rice Energy, LP to develop a portion of these holdings.

Dominion Terminal Associates. Through our subsidiary Alpha Terminal Company, LLC, we hold a 41% interest in Dominion Terminal Associates (“DTA”), a 20 million-ton annual capacity coal export terminal located in Newport News, Virginia. The terminal, constructed in 1984, provides the advantages of unloading/transloading equipment with ground storage capability, providing producers with the ability to custom blend export products without disrupting mining operations. During 2010, we shipped a total of 2.2 million tons of coal to our customers through the terminal. We make periodic cash payments in respect of the terminal for operating expenses, which are offset by payments we receive for transportation incentive payments and for renting our unused storage space in the terminal to third parties. In 2010, we received cash payments related to the terminal of $16.7 million, partially offset by payments we made for expenses of $8.3 million. The terminal is held in a partnership with subsidiaries of two other companies, Arch Coal, Inc. and Peabody Energy Corp.  

Coal Brokerage. Our coal brokerage group purchases and sells third party coal and serves as an agent of our coal subsidiaries.

Miscellaneous. We engage in the sale of certain non-strategic assets such as timber, gas and oil rights as well as the leasing and sale of non-strategic surface properties and reserves. We also provide coal and environmental analysis services.

Marketing, Sales and Customer Contracts

Our marketing and sales force, which is principally based in Abingdon, Virginia, included 60 employees as of December 31, 2010, and consists of sales managers, distribution/traffic managers, contract administrators and administrative personnel. In addition to marketing coal produced in our six regional business units, we are also actively involved in the purchase and resale of coal mined by others, the majority of which we blend with coal produced from our mines. We have coal supply commitments with a wide range of electric utilities, steel manufacturers, industrial customers and energy traders and brokers. Our marketing efforts are centered on customer needs and requirements.  By offering coal of both steam and metallurgical grades to provide specific qualities of heat content, sulfur and ash, and other characteristics relevan t to our customers, we are able to serve a diverse customer base. This diversity allows us to adjust to changing market conditions and provides us with the ability to sustain high sales volumes and sales prices for our coal. Many of our larger customers are well-established public utilities and steel manufacturers who have been stable long-term customers of ours and our acquired companies.

We sold a total of 84.8 million tons of coal in 2010, consisting of 82.6 million tons of produced and processed coal and 2.2 million tons of purchased coal that we resold without processing. A portion of purchased coal was blended prior to resale, meaning the coal was mixed with coal produced from our mines prior to resale, which generally allows us to realize a higher overall margin for the blended product than we would be able to achieve selling these coals separately. Approximately 0.8 million tons of our 2010 purchased coal sales were processed by us, meaning we washed, crushed or blended the coal at one of our preparation plants or loading facilities prior to resale.

We sold a total of 47.2 million tons of coal in 2009, consisting of 45.7 million tons of produced and processed coal and 1.5 million tons of purchased coal that was resold without processing. Of the total purchased coal sales of 1.9 million tons in 2009, approximately 1.5 million tons were blended prior to resale.  Approximately 0.4 million tons of 2009 purchased coal sales were processed by us.

Old Alpha sold a total of 26.9 million tons of coal in 2008, consisting of 22.0 million tons of produced and processed coal and 4.9 million tons of purchased coal that was resold without processing. Of the total purchased coal sales of 6.2 million tons in 2008, approximately 4.0 million tons were blended prior to resale. Approximately 1.3 million tons of 2008 purchased coal sales were processed by us.

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The breakdown of tons sold for 2010, 2009 and 2008 is set forth in the table below:

	Steam Coal Sales (1)					Metallurgical Coal Sales (1)
Year	Tons		% of Total Sales Volume			Tons		% of Total Sales Volume
	(In millions, except percentages)
2010		73.0		86	%		11.8		14	%
2009 (2)		39.1		83	%		8.1		17	%
2008		15.5		58	%		11.4		42	%

(1) Sales of steam coal during 2010, 2009, and 2008 were made primarily to large utilities and industrial customers throughout the United States and sales of metallurgical coal during those years were made primarily to steel companies in the Northeastern and Midwestern regions of the United States and in countries in Europe, Asia and South America.

(2) The amounts for 2009 include the results of operations for Old Alpha for the period from January 1, 2009 through July 31, 2009 and the results of operations for the combined company for the period from August 1, 2009 through December 31, 2009.

We sold coal to over 150 different customers in 2010. Our top ten customers in 2010 accounted for approximately 42% of 2010 total revenues and our largest customer during 2010 accounted for approximately 9% of 2010 total revenues. The following table provides information regarding exports in 2010, 2009 and 2008 by revenues and tons sold:

Year	Export Tons Sold		Export Tons Sold as a Percentage of Total Coal Sales Volume			Export Sales Revenues		Export Sales Revenue as a Percentage of Total Revenues
2010		9.6		11	%	$	1,351.0		34	%
2009 (1)		6.6		14	%	$	768.0		31	%
2008		8.5		31	%	$	1,292.1		52	%

(1) The amounts for 2009 include the results of operations for Old Alpha for the period from January 1, 2009 through July 31, 2009 and the results of operations for the combined company for the period from August 1, 2009 through December 31, 2009.

Export shipments during 2010, 2009 and 2008 serviced customers in 27, 19 and 20 countries, respectively, across North America, Europe, South America, Asia and Africa. Brazil was the largest export market in 2010, 2009 and 2008, with sales to Brazil accounting for approximately 11%, 23% and 15%, respectively, of total export revenues and 4%, 7% and 8%, respectively, of total revenues. All of our sales are made in U.S. dollars, which reduces foreign currency risk. A portion of our coal sales volume is subject to seasonal fluctuation, with sales to certain customers being curtailed during the winter months due to the freezing of lakes that we use to transport coal to those affected customers.

As is customary in the coal industry, when market conditions are appropriate and particularly in the steam coal market, we enter into long-term contracts (exceeding one year 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. A significant majority of our steam coal sales are shipped under long-term contracts. During 2010, approximately 87% and 78% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts and during 2009, approximately 71% and 55% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts.

Our sales backlog, including backlog subject to price reopener and/or extension provisions, was approximately 195.9 million tons as of January 26, 2011 and approximately 208.9 million tons at the beginning of 2010. Of these tons, approximately 43% and 38%, respectively, were expected to be filled within one year.

The terms of our contracts result from bidding and negotiations with customers. Consequently, the terms of these contracts typically vary significantly in many respects, including price adjustment features, provisions permitting renegotiation or modification of coal sale prices, coal quality requirements, quantity parameters, flexibility and adjustment mechanisms, permitted sources of supply, treatment of environmental constraints, options to extend and force majeure, suspension, termination and assignment provisions, and provisions regarding the allocation between the parties of the cost of complying with future governmental regulations.

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Distribution

We employ transportation specialists who negotiate freight and terminal agreements with various providers, including railroads, trucks, barge lines, and terminal facilities. Transportation specialists also coordinate with customers, mining facilities and transportation providers to establish shipping schedules that meet the customer's needs. Our produced and processed coal is loaded from our 13 preparation plants, loadout facilities, and in certain cases directly from our mines. The coal we purchase is loaded in some cases directly from mines and preparation plants operated by third parties or from an export terminal. Virtually all of our coal is transported from the mine to our preparation plants by truck or rail, and then from the preparation plant to the customer by means of railroads, trucks, barge lines, lake-going and ocean-going v essels from terminal facilities. Rail shipments constituted approximately 80% of total shipments of coal volume produced and processed from our mines to the preparation plant to the customer in 2010. The balance was shipped from our preparation plants, loadout facilities or mines via truck. In 2010, approximately 8% of our coal sales volume was delivered to our customers through transport on the Great Lakes and domestic rivers, approximately 5% was moved through the Norfolk Southern export facility at Norfolk, Virginia, approximately 3% was moved through the coal export terminal at Newport News, Virginia operated by DTA, and approximately 2% was moved through the export terminals at Baltimore, MD and New Orleans, LA. We own a 41% interest in the coal export terminal at Newport News, VA operated by DTA. See “-Other Operations.”

Transportation

Coal consumed domestically is usually sold at the mine and transportation costs are normally borne by the purchaser. Export coal is usually sold at the loading port, with purchasers responsible for further transportation. Producers usually pay shipping costs from the mine to the port.

We depend upon rail, barge, trucking and other systems to deliver coal to markets. In 2010, our produced coal was transported from the mines and to the customer primarily by rail, with the main rail carriers being CSX Transportation, Norfolk Southern Railway Company, BNSF Railway and Union Pacific Railroad Company. The majority of our sales volume is shipped by rail, but a portion of our production is shipped by barge and truck.

We have positive relationships with rail carriers and barge companies due, in part, to our modern coal-loading facilities and the experience of our transportation and logistics employees.

Suppliers

We incur a substantial amount of expenses per year to procure goods and services in support of our business activities in addition to capital expenditures. Principal goods and services include maintenance and repair parts and services, electricity, fuel, roof control and support items, explosives, tires, conveyance structure, ventilation supplies and lubricants. We use suppliers for a significant portion of our equipment rebuilds and repairs both on- and off-site, as well as construction and reclamation activities and to support computer systems.

Each of our regional mining operations has developed its own supplier base consistent with local needs. We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods, and to support the business units. The supplier base has been relatively stable for many years, but there has been some consolidation. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs. We seek suppliers who identify and concentrate on implementing continuous improvement opportunities within their area of expertise.

Employees

As of December 31, 2010, we had approximately 6,500 employees. As of December 31, 2010, the UMWA represented approximately 21% of our employees located in Virginia, West Virginia and Pennsylvania. UMWA-represented employees produced approximately 13% of our coal sales volume during the fiscal year ended December 31, 2010. Relations with organized labor are important to our success, and we believe our relations with our employees are satisfactory.

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ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Federal, state and local authorities regulate the United States coal mining and oil and gas industries with respect to matters such as: employee health and safety; permitting and licensing requirements; emissions to air and discharges to water; plant and wildlife protection; the reclamation and restoration of properties after mining or other activity has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil; protection of surface and groundwater; surface subsidence from underground mining; the effects on surface and groundwater quality and availability; noise; dust and competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, pipelines, roads and public facilities. Ordinances, regulations and legislation (and judicial or agency interpretations thereof) with respe ct to these matters have had, and will continue to have, a significant effect on our production costs and our competitive position. New laws and regulations, as well as future interpretations or different enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs and may cause delays, interruptions, or a termination of operations, the extent of which we cannot predict. We intend to respond to these regulatory requirements and interpretations thereof at the appropriate time by implementing necessary modifications to facilities or operating procedures or plans. When appropriate, we may also challenge actions in regulatory or court proceedings. Future legislation, regulations, interpretations or enforcement may also cause coal to become a less attractive fuel source for our customers due to factors such as investments in pollution control equipment necessary to meet new and more stringent air, water or solid waste requirements.  Similarly, coal may become a less attractive fuel source for our customers if federal, state or local emissions rates or caps on greenhouse gases are enacted, or a tax on carbon is imposed, such as those that may result from climate change legislation or regulations. As a result, future legislation, regulations, interpretations or enforcement may adversely affect our mining or other operations, or our cost structure or may adversely impact the ability or economic desire of our customers to use coal.

We endeavor to conduct our mining and other operations in compliance with all applicable federal, state, and local laws and regulations. However, violations occur from time to time. None of the violations identified or the monetary penalties assessed upon us have been material. It is possible that future liability under or compliance with environmental and safety requirements could have a material effect on our operations or competitive position. Under some circumstances, substantial fines and penalties, including revocation or suspension of mining or other permits or plans, may be imposed under the laws described below. Monetary sanctions and, in severe circumstances, criminal sanctions may be imposed for failure to comply with these laws.

Mine Safety and Health

The Coal Mine Health and Safety Act of 1969 and the Federal Mine Safety and Health Act of 1977 impose stringent safety and health standards on all aspects of mining operations. Also, 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 one of the most comprehensive and pervasive systems for protection of employee health and safety affecting any segment of U.S. industry. Regulation has a significant effect on our operating costs.

In recent years, legislative and regulatory bodies at the state and federal levels, including MSHA, have promulgated or proposed various statutes, regulations and policies relating to mine safety and mine emergency issues. The MINER Act passed in 2006 mandated mine rescue regulations, new and improved technologies and safety practices in the area of tracking and communication, and emergency response plans and equipment. Although some new laws, regulations and policies are in place, these legislative and regulatory efforts are still ongoing. In addition, on October 14, 2010, MSHA published a proposed rule to reduce the permissible concentration of respirable dust in underground coal mines from the current standard of 2 milligram per cubic meter of air to one milligram per cubic meter. MSHA is also likely to adopt new safety standards for proximity protection for miners that will require certain underground mining equipment to be equipped with devices that will shut the equipment down if a person is too close to the equipment to avoid injuries where individuals are caught between equipment and blocks of unmined coal. At this time, it is not possible to predict the full effect that the new or proposed statutes, regulations and policies will have on our operating costs, but it will increase our costs and those of our competitors. Some, but not all, of these additional costs may be passed on to customers.

Black Lung

Under the Black Lung Benefits Revenue Act of 1977 and the Black Lung Benefits Reform Act of 1977, as amended in 1981, each coal mine operator must secure payment of federal black lung benefits to claimants who are current and former employees and to a trust fund for the payment of benefits and medical expenses to eligible claimants. The trust fund is funded by an excise tax on production of up to $1.10 per ton for deep-mined coal and up to $0.55 per ton for surface-mined coal, neither amount to exceed 4.4% of the gross sales price.

In December 2000, the Department of Labor amended regulations implementing the federal black lung laws to, among other things, establish a presumption in favor of a claimant’s treating physician and limit a coal operator’s ability to introduce medical evidence regarding the claimant’s medical condition. Due to these changes, the number of claimants who are awarded benefits has since increased, and will continue to increase, as will the amounts of those awards. The Patient Protection and Affordable Care Act (“PPACA”), which was implemented in 2010, made two changes to the Federal Black Lung Benefits Act. First, it provided changes to the legal criteria used to assess and award claims by creating a legal presumption that miners are entitled to benefits if they have worked at least 15 years in coal mi nes and suffer from totally disabling lung disease. A coal company would have to prove that a miner did not have black lung or that the disease was not caused by the miner’s work. Second, it changed the law so black lung benefits being received by miners automatically go to their dependent survivors, regardless of the cause of the miner’s death.

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As of December 31, 2010, all of our various payment obligations for federal black lung benefits to claimants entitled to such benefits are either fully secured by insurance coverage or paid from a tax exempt trust established for that purpose. Based on actuarial reports and required funding levels, from time to time we may have to supplement the trust corpus to cover the anticipated liabilities going forward.

Coal Industry Retiree Health Benefit Act of 1992

The Coal Industry Retiree Health Benefit Act of 1992 (the “Coal Act”) provides for the funding of health benefits for certain UMWA, retirees and their spouses or dependants. The Coal Act established the Combined Benefit Fund into which employers who are “signatory operators” are obligated to pay annual premiums for beneficiaries. The Combined Benefit Fund covers a fixed group of individuals who retired before July 1, 1976, and the average age of the retirees in this fund is over 80 years of age. Premiums paid in 2010 and 2009 for our obligations to the Combined Benefit Fund were approximately $0.8 million and $0.4 million, respectively. The Coal Act also created a second benefit fund, the 1992 UMWA Benefit Plan (“the 1992 Plan”), for miners who retired between July 1, 1976 and September& #160;30, 1994, and whose former employers are no longer in business to provide them retiree medical benefits. Companies with 1992 Plan liabilities also pay premiums into this plan. Premiums paid in 2010 and 2009 for our obligation to the 1992 Plan were $0.9 million and less than $0.1 million, respectively. These per beneficiary premiums for both the Combined Benefit Fund and the 1992 Plan are adjusted annually based on various criteria such as the number of beneficiaries and the anticipated health benefit costs.

On December 20, 2006, the Tax Relief and Health Care Act of 2006 (“TRHC”) became law. The TRHC seeks to reduce or eliminate the premium obligation of companies due to the expanded transfers from the Abandoned Mine Land Fund (“AML”). The additional transfer of funds from AML will incrementally eliminate by 2010, to the extent the new transfers are adequate, the unassigned beneficiary premium under the Combined Benefit Fund effective October 1, 2007. The additional transfers will also reduce incrementally the pre-funding and assigned beneficiary premium to cover the cost of beneficiaries for which no individual company is responsible (“orphans”) under the 1992 Plan beginning January 1, 2008. For the first time, the 1993 Benefit Plan (“the 1993 Plan”) (all of the beneficiaries o f which are orphans) will begin receiving a subsidy from a new federal transfer that will ultimately cover the entire cost of the eligible population as of December 31, 2006. Under the Combined Benefit Fund, the 1992 Plan and the 1993 Plan, if the federal transfers are inadequate to cover the cost of the “orphan” component, the current or former signatories of the UMWA wage agreement will remain liable for any shortfall.

Environmental Laws

We and our customers are subject to various federal, state and local environmental laws relating to the extraction, processing and use of coal, oil and natural gas. Some of the more material of these laws and issues, discussed below, place stringent requirements on our coal mining and other operations, others apply to the ability of our customers to use coal. Federal, state and local regulations also require regular monitoring of our mines and other facilities to ensure compliance with these many laws and regulations.

Mining Permits and Necessary Approvals

Numerous governmental permits, licenses or approvals are required for mining, oil and gas operations, and related operations. When we apply for these permits and approvals, we may be required to present data to federal, state or local authorities pertaining to the effect or impact our operations may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining or other operations. These requirements may also be supplemented, modified or re-interpreted from time to time. Regulations also 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 m ining permit violations. Thus, past or ongoing violations of federal and state mining laws could provide a basis to revoke existing permits and to deny the issuance of additional permits.

In order to obtain mining permits and approvals from state regulatory authorities, we must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior or better condition, productive use or other permitted condition. Typically, we submit our necessary permit applications several months, or even years, before we plan to begin mining a new area or extend an existing area. In the past, we have generally obtained our mining permits in time so as to be able to run our operations as planned. However, we may experience difficulty or delays in obtaining mining permits or other necessary approvals in the future, or even face denials of permits altogether. In particular, issuance of Army Corps of Engineers (the “COE”) permits in Central Appalachia allowing placement of material in valleys have been slowed in recent years due to ongoing disputes over the requirements for obtaining such permits. These delays could spread to other geographic regions.

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Mountaintop removal mining is a legal but controversial method of surface mining. Certain anti-mining special interest groups are waging a public relations assault upon this mining method and are encouraging the introduction of legislation at the state and federal level to restrict or ban it and to preclude purchasing coal mined by this method. Should changes in laws, regulations or availability of permits severely restrict or ban this mining method in the future, our production and associated profitability could be adversely impacted.

Surface Mining Control and Reclamation Act

The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”), which is administered by the Office of Surface Mining Reclamation and Enforcement within the Department of the Interior (“OSM”), establishes mining, environmental protection and reclamation standards for all aspects of surface mining, as well as many aspects of deep mining that impact the surface. Where state regulatory agencies have adopted federal mining programs under SMCRA, the state becomes the regulatory authority with primacy and issues the permits, but OSM maintains oversight. SMCRA stipulates compliance with many other major environmental statutes, including the federal Clean Air Act, Clean Water Act, Resource Conservation and Recovery Act (“RCRA”) and Comprehensive Environmental Response, Compensation and Liability Act (“ CERCLA” or “Superfund”). SMCRA permit provisions include requirements for, among other actions, coal prospecting; mine plan development; topsoil removal, storage and replacement; selective handling of overburden materials; mine pit backfilling and grading; protection of the hydrologic balance; mitigation plans; subsidence control for underground mines; surface drainage control; mine drainage and mine discharge control and treatment; and re-vegetation. The permit application process is initiated by collecting baseline data to adequately characterize the pre-mine environmental condition of the permit area. This work includes surveys of cultural and historical resources, soils, vegetation, wildlife, assessment of surface and ground water hydrology, climatology, and wetlands. In conducting this work, we collect geologic data to define and model the soil and rock structures and coal that we will mine. We develop mining and reclamation plans by utilizing this geologic data and incorporating eleme nts of the environmental data. The mining and reclamation plan incorporates the provisions of SMCRA, the state programs, and the complementary environmental programs that affect coal mining. Also included in the permit application are documents defining ownership and agreements pertaining to coal, minerals, oil and gas, water rights, rights of way and surface land.

Some SMCRA mine permits take over a year to prepare, depending on the size and complexity of the mine. Once a permit application is prepared and submitted to the regulatory agency, it goes through a completeness review and technical review. Proposed permits also undergo a public notice and comment period. Some SMCRA mine permits may take several years or even longer to be issued. Regulatory authorities have considerable discretion in the timing of the permit issuance and the public and other agencies have rights to comment on and otherwise engage in the permitting process, including through intervention in the courts.

Before a SMCRA permit is issued, a mine operator must submit a bond or otherwise secure the performance of reclamation obligations. The AML, which is part of SMCRA, requires a fee on all coal produced. The proceeds are used to reclaim mine lands closed prior to 1977 when SMCRA came into effect. The current fee is $0.315 per ton on surface-mined coal and $0.135 on deep-mined coal from 2008 to 2012, with reductions to $0.28 per ton on surface-mined coal and $0.12 per ton on deep-mined coal from 2013 to 2021.

In December 2008, OSM issued revisions to its Stream Buffer Zone Rule under SMCRA. The revisions allow disposal of excess spoil within 100 feet of streams if OSM makes findings of impact minimization that overlap findings required by the COE in administration of the Clean Water Act Section 404 permit program. In April 2010, as initial steps toward issuing a new Stream Protection Rule under SMCRA, OSM commenced a pre-rulemaking information gathering process and solicited public comment on a notice of intent to conduct an environmental impact study.  OSM reports that the options under consideration for the new rule include requiring more extensive baseline data on hydrology, geology and aquatic biology in permit applications; specifically defining the “material damage” that would be prohibited outside permitted a reas; requiring additional monitoring during mining and reclamation; establishing corrective action thresholds; and limiting variances and exceptions to the “approximate original contour” requirement for reclamation.  In a settlement agreement with environmental groups that filed legal challenges seeking to invalidate the 2008 rule, OSM has agreed to issue a new proposed rule by February 2011 and a final rule by June 2012. In addition, legislation has been introduced in Congress in the past and may be introduced in the future in an attempt to preclude placing any fill material in streams. Implementation of new requirements or enactment of such legislation would negatively impact our future ability to conduct certain types of mining activities.

Surety Bonds

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations including mine closure or reclamation costs, water treatment, federal and state workers’ compensation costs, obligations under federal coal leases and other miscellaneous obligations. Many of these bonds are renewable on a yearly basis. We cannot predict the ability to obtain or the cost of bonds in the future.

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Greenhouse Gas Emissions Impact Initiatives

One major by-product of burning coal and all other fossil fuels is the release of carbon dioxide (“CO2”), which is considered by the U.S. Environmental Protection Agency (the “EPA”) as a greenhouse gas (“GHG”). CO2 is perceived by some as a major source of concern with respect to global warming. Methane, which must be expelled from our underground coal mines for mining safety reasons, also is classified as a greenhouse gas. Although our gas operations capture much of the coalbed methane in several of our operations, most is vented into the at mosphere when the coal is mined.

Considerable and increasing government attention in the United States and other countries is being paid to reducing greenhouse gas emissions, including CO2 emissions from coal-fired power plants and methane emissions from mining operations. Although the United States has not ratified the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (“UNFCCC”), which became effective for many countries in 2005 and establishes a binding set of emission targets for greenhouse gases, the United States is actively participating in various international initiatives within and outside of the UNFCCC process to negotiate developed and developing na tion commitments for greenhouse gas emission reductions and related financing. Any international greenhouse gas agreement in which the United States participates, if at all, could adversely affect the price and demand for coal.

In addition to possible future U.S. treaty obligations, regulation of greenhouse gases in the United States could occur pursuant to new or amended federal or state legislation, including but not limited to regulatory changes under the Clean Air Act, Public Utility Regulatory Policies Act, state initiatives, or otherwise. At the federal level, Congress actively considered in the past, and may consider in the future, legislation that would establish a nationwide GHG emissions cap-and-trade or other market-based program to reduce greenhouse gas emissions.  There are other types of legislative proposals that would promote clean energy that Congress has also considered in the past, and is currently considering. Many of these proposals would tend to favor fuels that have a lower carbon content than coal, but such proposals also incen t the construction and development of carbon capture and sequestration plants as well as other advanced coal technologies.  We cannot predict the financial impact of future greenhouse gas or clean energy legislation on our operations or our customers at this time.

The EPA also is implementing plans to regulate carbon dioxide emissions. In October 2009, the EPA published its final Mandatory Greenhouse Gas Reporting Rule, which requires power plants and other large sources of greenhouse gases to commence data collection in January 2010 and to file their first annual reports disclosing greenhouse gas emissions in 2011. In July 2010, the EPA issued amendments that would require underground coal mines and certain other source categories to file their first annual reports disclosing greenhouse gas emissions in 2012, covering calendar year 2011.

More generally, in April 2007, the U.S. Supreme Court ruled in Massachusetts v. Environmental Protection Agency that the Clean Air Act gives the EPA the authority to regulate vehicle tailpipe emissions of greenhouse gases and that the EPA had not yet articulated a reasonable basis for not issuing such regulations. Accordingly, in December 2009, the EPA issued a Final Endangerment and Cause or Contribute Findings for Greenhouse Gases under Section 202(a) of the Clean Air Act, wherein the EPA concluded that GHGs endanger the public health and welfare. In April 2010, the EPA issued, along with the Department of Transportation, a rule to regulate GHG emissions from new cars and trucks.  This rule took effect in January 2011, and according to EPA, established GHG emissions as “regulated pollutants” under the Clean Air Act.  As a consequence, and in conjunction with an EPA Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, will require new and modified emission sources to meet Best Available Control Technology for GHG emissions beginning in 2011.  The EPA has announced plans to begin issuing GHG performance standards for new and existing power plants and some other source categories. In particular, in December 2010, the EPA announced a proposed schedule for establishing greenhouse gas emissions limits for fossil fuel fired electric generation facilities calling for proposed regulations by July 2011 and final regulations by May 2012. Federal legislation that would variously suspend or eliminate EPA’s regulatory authority over GHGs has been introduced in both the House and Senate.

In addition to federal GHG regulations, there are several new state programs to limit greenhouse gas emissions and others have been proposed. State and regional climate change initiatives are taking effect before federal action. Beginning January 1, 2009 the Regional Greenhouse Gas Initiative (“RGGI”), a regional GHG cap-and-trade program calling for a ten percent reduction of emissions by 2018, was established by ten Northeastern states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont). The RGGI program has had several emission allowances auctions and will enter its second three-year control period in 2012.

On December 17, 2010, the California Air Resources Board (“ARB”) issued a final rule approving a state-wide GHG cap-and-trade program to be implemented pursuant to the California Global Warming Solutions Act of 2006 (known as “AB 32”).  The California AB 32 program is set by ARB to commence its first compliance period in 2012.  Many other greenhouse gas initiatives, including the Western Climate Initiative and the Midwestern Greenhouse Gas Reduction Accord, are in various stages of development. Also, numerous state public service commissions have revised or are revising air quality programs so as to limit greenhouse gas emissions such as Kansas, Colorado, and Texas.

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Considerable uncertainty is associated with these greenhouse gas emissions impact initiatives. The content of new treaties or legislation is not yet determined and many of the new regulatory initiatives remain subject to review by the agencies or the courts. In addition to the timing for implementing any new legislation, open issues include matters such as the applicable baseline of emissions to be permitted, initial allocations of any emission allowances, required emissions reductions, availability of offsets to emissions such as planting trees or capturing methane emitted during mining, the extent to which additional states will adopt the programs, and whether they will be linked with programs in other states or countries.

Predicting the economic effects of greenhouse gas emissions impact legislation is difficult given the various alternatives proposed and the complexities of the interactions between economic and environmental issues. Coal-fired generators could switch to other fuels that generate less of these emissions, possibly reducing the construction of coal-fired power plants or causing some users of our coal to switch to a lower CO2 generating fuel, or more generally reducing the demand for coal-fired electricity generation. This could result in an indeterminate decrease in demand for coal nationally, and various mechanisms proposed to limit greenhouse gas emissions could impact the price of coal and the cost of coal-fired generation. The majority of our c oal 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 to comply with applicable ambient air quality standards. In addition, if regulation of greenhouse gas emissions does not exempt the release of coalbed methane, we may have to curtail coal production, pay higher taxes, or incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines.

Other Clean Air Act Regulations

The federal Clean Air Act and corresponding state laws that regulate the emissions of materials into the air affect coal mining operations both directly and indirectly. Direct impacts on coal mining and processing operations arise primarily from permitting requirements and/or emission control requirements relating to particulate matter, such as fugitive dust, including regulation of fine particulate matter measuring 2.5 micrometers in diameter or smaller, however, new regulations on GHG emissions could also impact permit requirements. Our customers also are subject to extensive air emissions requirements, including those applicable to the air emissions of sulfur dioxide, nitrogen oxides, particulates, mercury and other compounds from coal-fueled electricity generating plants and industrial facilities that burn coal. These requirements ar e complex, lengthy and becoming increasingly stringent as new regulations or amendments to existing regulations are adopted. In addition, legal challenges to regulations may impact their content and the timing of their implementation.

More stringent air emissions regulations in future years may increase the cost of producing and consuming coal and impact the demand for coal. Initially, we believe that such regulations will result in an upward pressure on the price of lower sulfur eastern coals, and more demand for western coals, as coal-fired power plants continue to comply with the more stringent restrictions initially focused on sulfur dioxide emissions. As utilities continue to invest the capital to add scrubbers and other devices to address emissions of nitrogen oxides, mercury and other hazardous air pollutants, demand for lower sulfur coals may drop. However, we cannot predict these impacts with certainty. Some of the more material Clean Air Act requirements that may directly or indirectly affect our operations include the following:

• New National Ambient Air Quality Standards.  The Clean Air Act requires the EPA to set standards, referred to as National Ambient Air Quality Standards (“NAAQS”), for certain pollutants. Areas that are not in compliance (referred to as “non-attainment areas”) with these standards must take steps to reduce emissions levels. In 2010, EPA established a new 1-hour NAAQS for sulfur dioxide (“SO2”), and a new 1-hour NAAQS for nitrogen dioxide (“NO2”).

• Fine Particulate Matter.  In 1997, the EPA revised the NAAQS for particulate matter, retaining the existing standard for particulate matter with an aerodynamic diameter less than or equal to 10 microns (“PM10”), and adding a new standard for fine particulate matter with an aerodynamic diameter less than or equal to 2.5 microns (“PM2.5” or “fine particulate matter”). In April 2005, the EPA issued final non-attainment designations for 39 areas not achieving the 1997 PM2.5 standards, and in April 2007, the EPA issued its fine particle implementation rule establishing rules and guidance for state implementation plans to meet the standards. Under the Clean Air Act, state implementation plans were due in April 2008, establishing a regulatory program to meet the 1997 PM2.5 standards either by April 2010 or, if the EPA gr anted an extension, as expeditiously as practicable, but no later than April 2015. Moreover, in October 2006, the EPA issued a revised, more stringent 24-hour PM2.5 standard, triggering another round of non-attainment designations and ultimately regulation. In October 2009, the EPA designated 31 areas as non-attainment for the 2006 PM2.5 standard. Under the EPA’s current timeline, state implementation plans are due by December 2012 and attainment is required by December 2014, or December 2019 if the EPA grants an extension. Meeting the new PM2.5 standard also may require reductions of nitrogen oxide and sulfur dioxide emissions.

• Acid Rain. Title IV of the Clean Air Act required a two-phase reduction of sulfur dioxide emissions by electric utilities. Phase II became effective in 2000 and applies to all coal-fired power plants generating greater than 25 megawatts. The affected electricity generators have sought to meet these requirements mainly by, among other compliance methods, switching to lower sulfur fuels, installing pollution control devices, reducing electricity generating levels or purchasing sulfur dioxide emission allowances.

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• Ozone. In 1997, the EPA revised the NAAQS for ozone. Although legal challenges delayed implementation, in April 2004, the EPA announced that counties in 31 states and the District of Columbia failed to meet the new eight-hour standard for ozone and the EPA issued implementation rules in April 2004 and November 2005. At present, the 1997 ozone standard is gradually phasing in. In addition, the EPA proposed a more stringent ozone NAAQS on January 25, 2010. Accordingly, emissions control requirements for new and expanded coal-fired power plants and industrial boilers may continue to become more demanding in the years ahead.

• Clean Air Interstate Rule/Transport Rule. In 2005, the EPA issued its final Clean Air Interstate Rule (“CAIR”) for further reducing emissions of sulfur dioxide and NOx to deal with the interstate transport component of nonattainment with NAAQS. CAIR calls for Texas and 27 states bordering or east of the Mississippi River, and the District of Columbia, to cap their emission levels of sulfur dioxide and NOx through an allowance trading program or other system. At full implementation, the EPA projected that CAIR would cut regional sulfur dioxide emissions by more than 70% from the 2003 levels, and cut NOx emissions by more than 60% from 2003 levels. Although a July 2008 court decision requires the EPA to modify CAIR, it currently remains in effect except in Minnesota, where a stay applies. In July 2010, in response to the court order on CAIR, th e EPA proposed a new rule to replace CAIR, called the Transport Rule. As proposed, the Transport Rule would require additional reductions in SO2 and NOx emissions from power plants in 31 eastern states and the District of Columbia. As well, the Transport Rule, as proposed, would severely limit interstate emissions trading as a compliance option. The Transport Rule, which the EPA plans to finalize by June 2011, may ultimately require many coal-fired sources to install additional pollution control equipment for NOx and SO2.

• Clean Air Mercury Rule. In March 2005, the EPA issued its final Clean Air Mercury Rule (“CAMR”) to set a mandatory, declining cap on the total mercury emissions allowed from coal-fired power plants nationwide pursuant to section 111 of the Clean Air Act. This “cap-and-trade” approach is similar to the approach under the CAIR rule discussed above. If implemented, the CAMR approach, which allows mercury emissions trading, when combined with the CAIR regulations, was forecast to reduce mercury emissions by nearly 70% from current levels once facilities reach a final mercury cap that was to take effect in 2018. However, in February 2008, CAMR was overturned in court, and in December 2009 the EPA announced that it plans to promulgate a rule under Section 112 of the Clean Air Act that will establish limits for power plants based on Maxi mum Available Control Technology (“MACT”) for mercury and other hazardous air pollutants. The EPA currently plans to issue a proposed rule by March 2010, and a final rule by November 2011. Once completed, the new MACT standard could require power plants to install significant additional controls.

• Regional Haze. In 1999, the EPA promulgated a regional haze rule designed to protect and to improve visibility at and around national parks, national wilderness areas and international parks. The original regional haze rule required designated facilities to install Best Available Retrofit Technology (“BART”) to reduce emissions that contribute to visibility problems. In December 2006, the EPA modified the regional haze rule to allow states the flexibility to evaluate the use of cap-and-trade programs when such programs would result in greater progress toward the EPA’s visibility goals. States were to submit Regional Haze State Implementation Plan ("SIP") by December 2007. Most states failed to do so and the EPA promulgated a Federal Implementation Plan (“FIP”) that affects states with no SIP. The regional haze program primarily a ffects the construction of new coal-fired power plants whose operation may impair visibility at and around federally protected areas. It is expected that emission reductions required under other rules will address many, but perhaps not all, of the emission reduction requirements of the regional haze rule.

Clean Water Act

The Clean Water Act of 1972 (the “CWA”) and corresponding state laws affect coal mining operations by imposing restrictions on the discharge of certain pollutants into water and on dredging and filling wetlands. The CWA establishes in-stream water quality standards and treatment standards for wastewater discharge through the National Pollutant Discharge Elimination System (“NPDES”). Regular monitoring, as well as compliance with reporting requirements and performance standards, are preconditions for the issuance and renewal of NPDES permits that govern the discharge of pollutants into water. These requirements are complex, lengthy and becoming increasingly stringent as new regulations or amendments to existing regulations are adopted. In addition, legal challenges to regulations may impact their content and the ti ming of their implementation.

Some of the more material CWA issues that may directly or indirectly affect our operations are discussed below.

Section 404 Permitting

Permits under Section 404 of the CWA are required for coal companies to conduct dredging or filling activities in jurisdictional waters for the purpose of creating slurry ponds, water impoundments, refuse disposal areas, valley fills or other mining activities. Jurisdictional waters typically include ephemeral, intermittent, and perennial streams and may in certain instances include man-made conveyances that have a hydrologic connection to a stream or wetland. The COE only has jurisdiction over the “navigable waters” of the United States, and outside these waters there is arguably no need to procure a 404 permit. The United States Supreme Court ruled in Rapanos v. United States in 2006 that upper reaches of streams which are intermittent or do not flow might not be jurisdictional waters requiring 404 permits. The case did not involve disposal of mining refuse, but has implications for the mining industry. Subsequently, in June 2007 the COE and EPA issued a joint guidance document to attempt to develop a policy that will apply the jurisdictional standards imposed by the Supreme Court. The guidance requires a case-by-case analysis of whether the area to be filled has a sufficient nexus to downstream navigable waters so as to require 404 permits. Review and implementation of this guidance by the COE field offices remains inconsistent; the extent to which decisions made pursuant to this guidance will be challenged remains an open question.

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The COE issuance of 404 permits is subject to the National Environmental Policy Act (“NEPA”). NEPA defines the procedures by which a federal agency must administer its permitting programs. The law requires that a federal agency must take a “hard look” at any activity that may “significantly affect the quality of the human environment”. This “hard look” is accomplished through an Environmental Impact Statement (“EIS”), a very lengthy data collection and review process. After the EIS is complete, only then can the 404 permit application be considered. However, the law also allows an initial Environmental Assessment (“EA”) to be completed to determine if a project will have a significant impact on the environment. To date, the COE has typically used the less detailed EA process to determine the impacts from impoundments, fills and other activities associated with coal mining, however, in some cases the full EIS process is being required for mining projects. In general, the preliminary findings show that these types of mining related activities will not have a significant effect on the environment, and as such a full EIS is not required. Should a full EIS be required for every permit, significant permitting delays could affect mining costs or cause operations not to be opened in the first instance, or to be idled or closed.

In March 2007, the U.S. District Court for the Southern District of West Virginia issued a decision concerning 404 permitting for fills. The court held that widely used pre-mining assessments of areas to be impacted required by the COE and conducted by the permit applicants are inadequate and do not accurately assess the nature of the headwater areas being filled. As such, the court found the COE erred in its finding of no significant impact from this activity. Based on this conclusion, the court went on to find that proposed mitigation to offset the adverse impacts of the area to be filled also are not supported by adequate data. Due to this decision, the COE is assessing the protocol for evaluating the pre-mining stream conditions, as well as procedures used in the measurement of the success of mitigation. That effort to revise the pro tocol and associated findings is ongoing and may be challenged as it is applied to newly issued permits. Until this process is completed, preparing and submitting new permit applications is somewhat hindered. The March 2007 decision was appealed to the Fourth Circuit Court of Appeals. In June 2007, the same federal district court also effectively prohibited mine operators from impounding streams below their valley fills for the purpose of constructing sediment ponds. Mine operators are required to route drainage from valley fills to sediment control structures and to meet NPDES permit limits for discharges from those structures. In the steep sloped areas of Central Appalachia, often the only practicable location for those structures is in the stream channel itself downstream of the valley fills. The COE and EPA had both considered such ponds to be “treatment systems” excluded from the definition of “waters of the United States” to which the Clean Water Act applies. The court’s J une 2007 opinion, though, held that these ponds remain “waters of the United States” and that mine operators must meet effluent limits for discharges into the ponds as well as from the ponds. Meeting these limits at the point where water first leaves a valley fill or enters the stream or pond would be difficult. This decision was also appealed to the Fourth Circuit Court of Appeals. In February 2009, the Fourth Circuit Court of Appeals overturned these lower court decisions. The plaintiffs have a pending petition before the United States Supreme Court seeking review of the Fourth Circuit’s ruling. Legislation also may be introduced at the state or federal level in order to override this decision by the Court of Appeals. An outcome that prevents the placement of mining spoil or refuse into valleys could have a material adverse impact on the ability to maintain current operations and to permit new operations.

The COE is empowered to issue nationwide permits for specific categories of filling activity that are determined to have minimal environmental adverse effects in order to save the cost and time of issuing individual permits under Section 404. Nationwide Permit 21 (“NWP 21”) authorizes the disposal of dredge-and-fill material from mining activities into the waters of the United States. On October 23, 2003, several citizens groups sued the COE in the United States District Court for the Southern District of West Virginia seeking to invalidate nationwide permits utilized by the COE and the coal industry for permitting most in-stream disturbances associated with coal mining, including excess spoil valley fills and refuse impoundments. The plaintiffs sought to enjoin the prospective approval of these nationwide permits a nd to enjoin some coal operators from additional use of existing nationwide permit approvals until they obtain more detailed individual permits. On July 8, 2004, the court issued an order enjoining the further issuance of NWP 21 permits and rescinded certain listed permits where construction of valley fills and surface impoundments had not commenced. On August 13, 2004, the court extended the ruling to all NWP 21 permits within the Southern District of West Virginia. The COE appealed the decision to the United States Court of Appeals for the Fourth Circuit. In November 2005, the Fourth Circuit Court of Appeals overturned the July 2004 decision, thereby allowing the continued use of the NWP 21 permitting process, but remanded remaining challenges to the NWP 21 permits to the district court. Resolution of those additional challenges is still pending before that court. A similar challenge to the NWP 21 and related permit processes was filed in Kentucky. In addition, in July 2009, the COE pub lished a proposal to suspend and modify the NWP 21 to eliminate its use within a six state region, including Kentucky, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia. Although work under existing NWP 21 permits will be allowed to continue, no new authorizations will be issued under this permit and it will not be renewed when it expires in March 2012.

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In September 2009, the EPA announced it had identified 79 pending permit applications for Appalachian surface coal mining, under an enhanced coordination process with the COE and the United States Department of the Interior entered into in June 2009, that the EPA believes warrant further review because of its continuing concerns about water quality and/or regulatory compliance issues. These included five of our permit applications, two of which were already withdrawn when the EPA issued its list. While the EPA has stated that its identification of these 79 permit applications does not constitute a determination that the mining involved cannot be permitted under the CWA and does not constitute a final recommendation from the EPA to the COE on these projects, it is uncertain how long the further review will take for our three subject permi t applications, what types of conditions or restrictions will be imposed or what the final outcome will be.

Further, the EPA has begun to apply its enhanced permitting coordination process, called the Surface Coal Mining Pending Permit Coordination Procedures issued by EPA and the COE on June 11, 2009 (the “ECP”), and guidance contained in an document, April 1, 2010 Memorandum entitled “Detailed Guidance: Improving EPA Review of Appalachian Surface Coal Mining Operations Under the Clean Water Act, National Environmental Policy Act, and the Environmental Justice Executive Order” (“Detailed Guidance”) (75 Fed. Reg. 18,500) in their review of new surface and underground mining permits. Application of the ECP and the Detained Guidance has the potential to delay issuance of permits for the company, or to change the conditions or restrictions imposed in those permits. Use of this guidance by EPA without going through formal rulemaking procedures has been challenged in court by the National Mining Association and by several states.

In March 2010, the U.S. Environmental Protection Agency (“EPA”) proposed a veto of a federal Clean Water Act permit held by another coal mining company for a surface mine in Appalachia. In explaining its position, the EPA cited significant and irreversible damage to wildlife and fishery resources and severe degradation of water quality caused by mining pollution. If the EPA’s proposed action is finalized, the permit will be invalidated. While our operations are not directly impacted, this could be a further indication that other surface mining water permits could be subject to more substantial review in the future.

National Pollutant Discharge Elimination Permits

The Clean Water Act (“CWA”) requires that all of our operations obtain NPDES permits for discharges of water from all of our mining operations. All NPDES permits require regular monitoring and reporting of one or more parameters on all discharges from permitted outfalls. Additional parameters, including selenium, aluminum, total dissolved solids and conductivity, stemming in part from application of the Detailed Guidance discussed above and increasingly more restrictive limits are being added to NPDES permits in all states which potentially could create requirements for treatment systems and higher costs to comply with permit conditions. In particular, the Detailed Guidance establishes threshold conductivity levels to be used as a basis for evaluating compliance with narrative water quality standards. Conductivity is a measur e that reflects levels of various salts present in water. In order to obtain federal Clean Water Act new permits and renewals for coal mining in Appalachia, as defined in the guidance, applicants must perform an evaluation to determine if a reasonable potential exists that the proposed mining would cause a violation of water quality standards, including narrative standards. The EPA Administrator has stated that these water quality standards may be difficult for most mining operations to meet. Additionally, the Detailed Guidance contains requirements for avoidance and minimization of environmental impacts, mitigation of mining impacts, consideration of the full range of potential impacts on the environment, human health, and communities, including low-income or minority populations, and provision of meaningful opportunities for public participation in the permit process. In the future, to obtain necessary new permits and renewals, we and other mining companies will be required to meet these requirements. We h ave begun to incorporate these new requirements into some of our current permitting actions, however there can be no guarantee that we will be able to meet these or any other new standards with respect to our future permit applications or renewals.

When a water discharge occurs and one or more parameters are outside the approved limits permitted in an NPDES permit, these exceedances of permit limits are self-reported to the pertinent agency. The agency may impose penalties for each such release in excess of permitted amounts. If factors such as heavy rains or geologic conditions cause persistent releases in excess of amounts allowed under NPDES permits, costs of compliance can be material, fines may be imposed, or operations may have to be idled until remedial actions are possible. Additionally, the CWA has citizen suit provisions which allow individuals or organized groups to file suit against permit holders or the EPA or state agencies for failure to enforce all aspects of the CWA. Although we are aware of potential citizen suit actions against a small number of our permits, it i s not clear if these actions will proceed. Similar actions have recently been filed against other companies.

Recently, there have been renewed efforts by the EPA to examine the coal industry’s record of compliance with these limits. This enhanced scrutiny recently resulted in an agreement by Massey to pay a $20 million penalty for over 4,000 alleged NPDES permit violations. Subsequently, each of our operating subsidiaries conducted an assessment of their NPDES monitoring and reporting practices, which identified some exceedances of permit limits. In 2009 and 2008, each of our West Virginia subsidiaries entered into Consent Orders with the West Virginia Department of Environmental Protection on this matter.  Future exceedances of permit limits may be unavoidable and future fines may be imposed.

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The Clean Water Act has specialized sections that address NPDES permit conditions for discharges to waters in which state-issued water quality standards are violated and where the quality exceeds the levels established by those standards. For those waters where conditions violate state water quality standards, states or the EPA are required to prepare a Total Maximum Daily Load (“TMDL”) by which new discharge limits are imposed on existing and future discharges in an effort to restore the water quality of the receiving streams. Likewise, when water quality in a receiving stream is better than required, states are required to adopt an “anti-degradation policy” by which further “degradation” of the existing water quality is reviewed and possibly limited. In the case of both the TMDL and anti-degradation review, the limits in our NPDES discharge permits could become more stringent, thereby potentially increasing our treatment costs and making it more difficult to obtain new surface mining permits. New standards may also require us to install expensive water treatment facilities or otherwise modify mining practices and thereby substantially increase mining costs. These increased costs may render some operations unprofitable.

Other Regulations on Steam Impacts

Federal and state laws and regulations can also impose measures to be taken to minimize and/or avoid altogether stream impacts caused by both surface and underground mining. Temporary stream impacts from mining are not uncommon, but when such impacts occur there are procedures we follow to mitigate or remedy any such impacts. These procedures have generally been effective and we work closely with applicable agencies to implement them. Our inability to mitigate or remedy any temporary stream impacts in the future, and the application of existing or new laws and regulations to disallow any stream impacts, could adversely affect our operating and financial results.

Endangered Species Act

The Federal Endangered Species Act and counterpart state legislation protect species threatened with possible extinction. Protection of threatened and 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 or their habitats. A number of species indigenous to our properties are protected under the Endangered Species Act. Based on the species that have been identified to date and the current application of applicable laws and regulations, however, 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.

Resource Conservation and Recovery Act

The Resource Conservation and Recovery Act (“RCRA”) affects coal mining operations by establishing requirements for the treatment, storage, and disposal of hazardous wastes. Certain coal mine wastes, such as overburden and coal cleaning wastes, are exempted from hazardous waste management requirements.

Subtitle C of RCRA exempted fossil fuel combustion wastes from hazardous waste regulation until the EPA completed a report to Congress and made a determination on whether the wastes should be regulated as hazardous. In a 1993 regulatory determination, the EPA addressed some high volume-low toxicity coal combustion wastes generated at electric utility and independent power producing facilities, such as coal ash. In May 2000, the EPA concluded that coal combustion wastes do not warrant regulation as hazardous under RCRA. The EPA is retaining the hazardous waste exemption for these wastes. However, the EPA has determined that national non-hazardous waste regulations under RCRA Subtitle D are needed for coal combustion wastes disposed in surface impoundments and landfills and used as mine-fill. The EPA also concluded beneficial uses of these wastes, other than for mine-filling, pose no significant risk and no additional national regulations are needed. As long as this exemption remains in effect, it is not anticipated that regulation of coal combustion waste will have any material effect on the amount of coal used by electricity generators. However, the recent failure of an ash disposal dam in Tennessee has focused attention on this issue and many environmental groups continue to push for classification of ash as a hazardous waste. In May 2010, the EPA issued proposed regulations governing management and disposal of coal ash from coal-fired power plants. The EPA sought public comment on two regulatory options. Under the more stringent option, the EPA would regulate coal ash as a “special waste” subject to hazardous waste standards when disposed in landfills or surface impoundments, which would be subject to stringent design, permitting, closure and corrective action requirements.  Alternatively, coal ash would be regu lated as non-hazardous waste under RCRA subtitle D, with national minimum criteria for disposal but no federal permitting or enforcement. Under both options, the EPA would establish dam safety requirements to address the structural integrity of surface impoundments to prevent catastrophic releases. The EPA is expected to issue a final decision by the end of 2011. We currently cannot predict whether these rules, once finalized, with have a significant impact on coal used by electricity generators.

Federal and State Superfund Statutes

Superfund and similar state laws affect coal mining and hard rock operations by creating liability for investigation and remediation in response to releases of hazardous substances into the environment and for damages to natural resources. Under Superfund, joint and several liability may be imposed on waste generators, site owners or operators and others, regardless of fault. In addition, mining operations may have reporting obligations under the Emergency Planning and Community Right to Know Act and the Superfund Amendments and Reauthorization Act.

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GLOSSARY OF SELECTED TERMS

Ash. Impurities consisting of iron, alumina 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.

Assigned reserves. Coal that is planned to be mined at an operation that is currently operating, currently idled, or for which permits have been submitted and plans are eventually to develop the operation.

Bituminous coal. A common type of coal with moisture content less than 20% by weight and heating value of 9,500 to 14,000 Btus per pound. It is dense and black and often has well-defined bands of bright and dull material.

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

Central Appalachia. Coal producing area in eastern Kentucky, Virginia, southern West Virginia and a portion of eastern Tennessee.

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. Coal which, when burned, emits 1.2 pounds or less of sulfur dioxide per million Btu, as required by Phase II of the Clean Air Act.

Continuous miner. A machine which constantly extracts coal while loading. This is to be distinguished from a conventional mining unit which must stop the extraction process in order for loading to commence.

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

High Btu coal. Coal which has an average heat content of 12,500 Btus per pound or greater.

Illinois Basin. Coal producing area in Illinois, Indiana and western Kentucky.

Lignite. The lowest rank of coal with a high moisture content of up to 15% by weight and heat value of 6,500 to 8,300 Btus per pound. It is brownish black and tends to oxidize and disintegrate when exposed to air.

Longwall mining. The most productive underground mining method in the United States. A rotating drum is trammed mechanically across the face of coal, and a hydraulic system supports the roof of the mine while the drum advances through the coal. Chain conveyors then move the loosened coal to a standard underground mine conveyor system for delivery to the surface.

Low Btu coal. Coal which has an average heat content of 9,500 Btus per pound or less.

Low sulfur coal. Coal which, when burned, emits 1.6 pounds or less of sulfur dioxide per million Btu.

Medium sulfur coal. Coal which, when burned, emits between 1.6 and 4.5 pounds of sulfur dioxide per million Btu.

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

Mid Btu coal. Coal which has an average heat content of between 9,500 and 12,500 Btus per pound.

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

Northern Appalachia. Coal producing area in Maryland, Ohio, Pennsylvania and northern West Virginia.

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

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

Powder River Basin. Coal producing area in northeastern Wyoming and southeastern Montana. This is the largest known source of coal reserves and the largest producing region in the United States.

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

Probable reserves. Reserves for which quantity and grade and/or quality are computed from information similar to that used for proven 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 reserves, is high enough to assume continuity between points of observation.

Proven reserves. Reserves for which 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 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.

Reclamation. The process of restoring land and the environment to their 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. That part of a mineral deposit that could be economically and legally extracted or produced at the time of the reserve determination.

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

Room-and-Pillar Mining. Method of underground mining in which the mine roof is supported mainly by coal pillars left at regular intervals. Rooms are placed where the coal is mined.

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

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

Sub-bituminous coal. Dull coal that ranks between lignite and bituminous coal. Its moisture content is between 20% and 30% by weight and its heat content ranges from 7,800 to 9,500 Btus per pound of coal.

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

Surface mine. A mine in which the coal lies near the surface and can be extracted by removing the covering layer of soil (see “Overburden”). About 67% of total U.S. coal production comes from surface mines.

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

Truck-and-Shovel Mining and Truck and Front-End Loader Mining. Similar forms of mining where large shovels or front-end loaders are used to remove overburden, which is used to backfill pits after the coal is removed. Smaller shovels load coal in haul trucks for transportation to the preparation plant or rail loadout.

Unassigned reserves. Coal that is likely to be mined in the future, but which is not considered Assigned reserves.

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 and conveyor to the surface. Underground mines account for about 33% of annual U.S. coal production.

Unit train. A train of 100 or more cars carrying a single product. A typical coal unit train can carry at least 10,000 tons of coal in a single shipment.

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Item 1A. Risk Factors

Investment in our common stock is subject to various risks, including risks and uncertainties inherent in our business. The following sets forth factors related to our business, operations, financial position or future financial performance or cash flows which could cause an investment in our securities to decline and result in a loss

Any change in coal consumption patterns by steel producers or North American electric power generators resulting in a decrease in the use of coal by those consumers could result in less demand and lower prices for our coal, which would reduce our revenues and adversely impact our earnings and the value of our coal reserves.

Steam coal accounted for approximately 86% and 83% of our coal sales volume during 2010 and 2009, respectively. The majority of our sales of steam coal were to U.S. and Canadian electric power generators. The amount of coal consumed for U.S. and Canadian electric power generation is affected primarily by the overall demand for electricity, the location, availability, quality and price of competing fuels for power such as natural gas, nuclear fuel, oil and alternative energy sources such as hydroelectric power, technological developments, and environmental and other governmental regulations. We expect many new power plants will be built to produce electricity during peak periods of demand, when the demand for electricity rises above the “base load demand,” or minimum amount of electricity required if consumption occurred at a steady rate. However, we also expect that many of these new power plants will be fired by natural gas because they are cheaper to construct than coal-fired plants and because natural gas is a cleaner burning fuel with plentiful supplies and low cost at the current time. In addition, the increasingly stringent requirements of the Clean Air Act may result in more electric power generators shifting from coal to natural gas-fired power plants. Any reduction in the amount of coal consumed by North American electric power generators could reduce the price of steam coal that we mine and sell, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

We produce metallurgical coal that is used in both the U.S. and foreign steel industries. Metallurgical coal accounted for approximately 14% and 17% of our coal sales volume during 2010 and 2009, respectively.  Any deterioration in conditions in the U.S. steel industry would reduce the demand for our metallurgical coal and could impact the collectability of our accounts receivable from U.S. steel industry customers. In addition, the U.S. steel industry increasingly relies on electric arc furnaces or pulverized coal processes to make steel. These processes do not use coke. If this trend continues, the amount of metallurgical coal that we sell and the prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves. If the demand and pricing for metallurgical coal in international markets decreases in the future, the amount of metallurgical coal that we sell and the prices that we receive for it could decrease, thereby reducing our revenues and adversely impacting our earnings and the value of our coal reserves.

A substantial or extended decline in coal prices could reduce our revenues and the value of our coal reserves.

Our results of operations are substantially dependent upon the prices we receive for our coal. The prices we receive for coal depend upon factors beyond our control, including:

· the supply of and demand for domestic and foreign coal;

· the demand for electricity;

· domestic and foreign demand for steel and the continued financial viability of the domestic and foreign steel industry;

· interruptions due to transportation delays;

· domestic and foreign governmental regulations and taxes;

· air emission standards for coal-fired power plants;

· regulatory, administrative, and judicial decisions;

· the price and availability of alternative fuels, including the effects of technological developments;

· the effect of worldwide energy conservation measures; and

· the proximity to, capacity of, and cost of transportation and port facilities.

Declines in the prices we receive for our coal could adversely affect our operating results and our ability to generate the cash flows we require to improve our productivity and invest in our operations.

Our mining operations are extensively regulated, which imposes significant costs on us, and future regulations or violations of regulations could increase those costs or limit our ability to produce coal.

Our operations are subject to a variety of federal, state and local environmental, health and safety, transportation, labor and other laws and regulations. Examples include those relating to employee health and safety; emissions to air and discharges to water; plant and wildlife protection; the reclamation and restoration of properties after mining or other activity has been completed; the storage, treatment and disposal of wastes; remediation of contaminated soil, surface and groundwater; surface subsidence from underground mining; noise; and the effects of operations on surface water and groundwater quality and availability. In addition, we are subject to significant legislation mandating certain benefits for current and retired coal miners. We incur substantial costs to comply with the laws and regulations that apply to our mining and other operations. Because of extensive and comprehensive regulatory requirements, violations of laws, regulations and permits occur at our operations from time to time and may result in significant costs to us to correct such violations, as well as civil or criminal penalties and limitations or shutdowns of our operations.

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Federal and state authorities inspect our operations, and given a recent incident at a Massey subsidiary’s underground mine in Central Appalachia and related announcements by government authorities, we anticipate additional requirements may be imposed and heightened inspection intensity. In response to the incident, federal and West Virginia authorities have announced special inspections of coal mines for, among other safety concerns, the accumulation of coal dust and the proper ventilation of gases such as methane. Certain of these inspections have already occurred. In addition, both the federal government and the state of West Virginia have announced that they are considering changes to mine safety rules and regulations, which could potentially result in or require additional or enhanced safety features, more frequent mine inspec tions, stricter enforcement practices and enhanced reporting requirements.

The costs, liabilities and requirements associated with addressing the outcome of inspections and complying with these environmental, health and safety requirements are often significant and time-consuming and may delay commencement or continuation of exploration or production. Additionally, the Mine Safety and Health Administration (“MSHA”) may further utilize the temporary closure provisions at mines in the event of certain violations of safety rules. These factors could have a material adverse effect on our results of operations, cash flows and financial condition.

In addition, these laws and regulations require us to obtain numerous governmental permits. Many of our permits are subject to renewal from time to time, and renewed permits may contain more restrictive conditions than our existing permits. Many of our permits governing discharges to or impacts upon surface streams and groundwater will be subject to new and more stringent conditions to address various new water quality requirements that permitting authorities are now required to address when those permits are renewed over the next several years. To obtain new permits, we may have to petition to have stream quality designations changed based on available data, and if we are unsuccessful, we may not be able to operate the facility as planned or at all. Although we have no estimates at this time, our costs to satisfy such conditions could b e substantial. We may also be required under certain permits to provide authorities data pertaining to the effect or impact that a proposed exploration for or production of coal may have on the environment.

In recent years, the permitting required for coal mining, particularly under the Surface Mining Control and Reclamation Act and the Clean Water Act to address filling ephemeral and intermittent streams and other valleys with materials from mountaintop coal mining operations and preparation plant refuse disposal has been the subject of increasingly stringent regulatory and administrative requirements and extensive litigation by environmental groups against coal mining companies and environmental regulatory authorities. Congress has also considered legislation to impose additional limitations on surface mining. It is unclear at this time how the issues will ultimately be resolved, but for this as well as other issues that may arise involving permits necessary for coal mining and other operation, such requirements could prove costly and tim e-consuming, and could delay commencing or continuing exploration or production operations. New laws and regulations, as well as future interpretations or different enforcement of existing laws and regulations, may require substantial increases in equipment and operating costs to us and delays, interruptions or a termination of operations, the extent of which we cannot predict.

Extensive regulation of these matters has had and will continue to have a significant effect on our costs of production and competitive position. Further legislation, regulations or enforcement may also cause our sales or profitability to decline by hindering our ability to continue our mining operations, by increasing our costs or by causing coal to become a less attractive fuel source. See Item I “Business—Environmental and Other Regulatory Matters.”

Climate change initiatives could significantly reduce the demand for coal, increase our costs and reduce the value of our coal and gas assets.

Global climate change continues to attract considerable public and scientific attention with widespread concern about the impacts of human activity, especially the emissions of greenhouse gases (“GHG”), such as carbon dioxide and methane. Combustion of fossil fuels, such as the coal and gas we produce, results in the creation of carbon dioxide that is currently emitted into the atmosphere by coal and gas end users, such as coal-fired electric generation power plants. Our underground mines emit methane, which must be expelled for safety reasons.

Considerable and increasing government attention in the United States and other countries is being paid to reducing greenhouse gas emissions, including CO2 emissions from coal-fired power plants and methane emissions from mining operations. Although the United States has not ratified the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change (“UNFCCC”), which became effective for many countries in 2005 and establishes a binding set of emission targets for greenhouse gases, the United States is actively participating in various international initiatives within and outside of the UNFCCC process to negotiate developed and developing nation commitments for greenhouse gas emission reductions and related financing . Any international greenhouse gas agreement in which the United States participates, if at all, could adversely affect the price and demand for coal.

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U.S. legislative and regulatory action also may address greenhouse gas emissions. At the federal level, Congress actively considered in the past, and may consider in the future, legislation that would establish a nationwide GHG emissions cap-and-trade or other market-based program to reduce greenhouse gas emissions. The EPA also has commenced regulatory action that could lead to controls on carbon dioxide from larger emitters such as coal-fired power plants and industrial sources. In advance of federal action, state and regional climate change initiatives, such as the Regional Greenhouse Gas Initiative of eastern states, the Western Regional Climate Action Initiative, and recently enacted legislation in California and other states are taking effect before federal action. In addition, some states and municipalities in the United States ha ve adopted or may adopt in the future regulations on greenhouse gas emissions. Some states and municipal entities have commenced litigation in different jurisdictions seeking to have certain utilities, including some of our customers, reduce their emission of carbon dioxide. Apart from governmental regulation, in February 2008, three of Wall Street’s largest investment banks announced that they had adopted climate change guidelines for lenders. The guidelines require the evaluation of carbon risks in the financing of utility power plants which may make it more difficult for utilities to obtain financing for coal-fired plants.

Considerable uncertainty is associated with these climate change initiatives. The content of new treaties, legislation or regulation is not yet determined, and many of the new regulatory initiatives remain subject to review by the agencies or the courts. Predicting the economic effects of climate change legislation is difficult given the various alternatives proposed and the complexities of the interactions between economic and environmental issues. Any regulations on greenhouse gas emissions, however, are likely to impose significant emissions control expenditures on many coal-fired power plants and industrial boilers and could have the effect of making them unprofitable. As a result, these generators may switch to other fuels that generate less of these emissions, possibly reducing future demand for coal and the construction of coal-fi red power plants. In this regard, many 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 to comply with applicable ambient air quality standards. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material adverse effect on demand for and prices received for our coal and a material adverse effect on our results of operations, cash flows and financial condition. In addition, if regulation of greenhouse gas emissions does not exempt the release of coalbed methane, we may have to curtail coal production, pay higher taxes, or incur costs to purchase credits that permit us to continue operations as they now exist at our underground coal mines.

Other extensive environmental regulations also could affect our customers and could reduce the demand for coal as a fuel source and cause our sales to decline.

The operations of our customers are subject to extensive laws and regulations relating to emissions to air and discharges to water, plant and wildlife protection, the storage, treatment and disposal of wastes, and permitting of operations. These requirements are a significant part of the costs of their respective businesses, and their costs are increasing as environmental requirements become more stringent.  These requirements could adversely affect our sales by causing coal to become a less attractive fuel source of energy.

In particular, the Clean Air Act and similar state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides, mercury and other compounds emitted into the air from electric power plants, which are the largest end-users of our coal. See Item I “Business—Environmental and Other Regulatory Matters.” A series of more stringent requirements are expected to become effective in coming years. These requirements include implementation of the current and more stringent proposed ambient air quality standards for particulate matter and ozone, implementation of and forthcoming revisions to the Clean Air Interstate rule governing emission levels of sulfur dioxide and nitrogen oxides, and the EPA’s projected rule to limit emissions of mercury and other hazardous air pollutants fro m power plants.  Such requirements may require significant emissions control expenditures for coal-fired power plants. Any switching of fuel sources away from coal, closure of existing coal-fired plants, or reduced construction of new plants could have a material effect on demand for and prices received for our coal.

MSHA and state regulators may order certain of our mines to be temporarily closed or operations therein modified, which would adversely affect our ability to meet our contracts or projected costs.

MSHA and state regulators may order certain of our mines to be temporarily closed due to investigations of accidents resulting in property damage or injuries, or due to other incidents such as fires, roof falls, water flow and equipment failure or ventilation concerns. In addition, regulators may order changes to mine plans or operations due to their interpretation or application of existing or new laws or regulations. Any required changes to mine plans or operations may result in temporary idling of production or addition of costs.

Our coal mining production and delivery is subject to conditions and events beyond our control, which could result in higher operating expenses and decreased production and sales and adversely affect our operating results and could result in impairments to our assets.

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A majority of our coal mining operations are conducted in underground mines and the balance of our operations is at surface mines. Our coal production at these mines is subject to operating conditions and events beyond our control that could disrupt operations, affect production and the cost of mining for varying lengths of time and have a significant impact on our operating results. Adverse operating conditions and events that we have experienced in the past and may experience in the future include:

· the termination of material contracts by state or other governmental authorities;

· changes or variations in geologic conditions, such as the thickness of the coal deposits and the amount of rock embedded in or overlying the coal deposit;

· mining, processing and loading equipment failures and unexpected maintenance problems;

· limited availability of mining, processing and loading equipment and parts from suppliers;

· the proximity to, capacity of, and cost of transportation facilities;

· adverse weather and natural disasters, such as heavy snows, heavy rains and flooding or hurricanes;

· accidental mine water discharges;

· the unavailability of qualified labor;

· strikes and other labor-related interruptions; and

· unexpected mine safety accidents, including fires and explosions from methane and other sources.

If any of these conditions or events occur in the future at any of our mines or affect deliveries of our coal to customers, they may increase our cost of mining and delay or halt production or sales to our customers either permanently or for varying lengths of time, which could adversely affect our operating results and could result in impairments to our assets.

We may be unable to obtain and renew permits necessary for our operations, which would reduce our production, cash flows and profitability.

Mining companies must obtain numerous permits that impose strict conditions on various environmental and safety matters in connection with coal mining. These include permits issued by various federal and state agencies and regulatory bodies. The permitting rules are complex and may change over time, making our ability to comply with the applicable requirements more difficult or impractical, possibly precluding the continuance of ongoing operations or the development of future mining operations. The public, including special interest groups and individuals, have certain rights under various statutes to comment upon, submit objections to, and otherwise engage in the permitting process, including bringing citizens’ lawsuits to challenge such permits or mining activities.  Accordingly, required permits may not be issued or re newed in a timely fashion (or at all), or permits issued or renewed may be conditioned in a manner that may restrict our ability to efficiently conduct our mining activities.  Such inefficiencies would likely reduce our production, cash flows, and profitability.

In particular, certain of our activities involving valley fills, ponds or impoundments, refuse, road building, placement of excess material, and other mine development activities require a Section 404 dredge and fill permit from the Army Corps of Engineers (“COE”) and a Section 401 certification or its equivalent from the state in which the mining activities are proposed.  In recent years, the Section 404 permitting process has faced increasingly stringent regulatory and administrative requirements and a series of court challenges that have resulted in increased costs and delays in the permitting process. In September 2009, the U.S. Environmental Protection Agency (“EPA”) announced it had identified 79 pending permit applications for Appalachian surface coal mining, under a coordination process with the COE and the United States Department of the Interior entered into in June 2009, that the EPA believes warrant further review because of its continuing concerns about water quality and/or regulatory compliance issues. These included five of our permit applications, two of which we have withdrawn. While the EPA has stated that its identification of these 79 permit applications does not constitute a determination that the mining involved cannot be permitted under the Clean Water Act and does not constitute a final recommendation from the EPA to the COE on these projects, it is uncertain how long the further review will take for our three subject permit applications or what the final outcome will be.  It is also unclear what impact this process may have on the types of conditions or restrictions that will be imposed on our future applications for surface coal mining permits and surface facilities at underground mines. Increasingly stringent requirements governing coal mining also are being conside red or implemented under the Surface Mining Control and Reclamation Act, the National Pollution Discharge Elimination System permit process, and various other environmental programs. Future changes or challenges to the permitting process could cause additional increases in the costs, time, and difficulty associated with obtaining and complying with the permits, and could, as a result, adversely affect our coal production, cash flows and profitability.

Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.

Our operations, including our acquired companies, currently use and have used in the past, hazardous materials, and from time to time we generate and have generated in the past, limited quantities of hazardous wastes. We may be subject to claims under federal or state statutes or common law doctrines for toxic torts, natural resource damages and other damages as well as for the investigation and clean up of soil, surface water, sediments, groundwater, and other natural resources. Such claims may arise out of current or former conditions at sites that we own or operate currently, as well as at sites that we and our acquired companies owned or operated in the past, and at contaminated sites that have always been owned or operated by third parties. Our liability for such claims may be joint and several, so that we may be held responsible fo r more than our share of the contamination or other damages, or even for the entire share.

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We maintain extensive coal slurry impoundments at a number of our mines. Such impoundments are subject to extensive regulation. Slurry impoundments maintained by other coal mining operations have been known to fail, causing extensive damage to the environment and natural resources, as well as liability for related personal injuries and property damages. Some of our impoundments overlie mined out areas, which can pose a heightened risk of failure and of damages arising out of failure. If one of our impoundments were to fail, we could be subject to substantial claims for the resulting environmental contamination and associated liability, as well as for fines and penalties. The failure of the fly ash impoundment at the Tennessee Valley Authority’s Kingston Power Plant, which is not regulated in the same manner as our slurry impoundmen ts, could result in additional scrutiny of our impoundments.

These and other unforeseen environmental impacts that our operations may have, as well as exposures to hazardous substances or wastes associated with our operations, could result in costs and liabilities that could materially and adversely affect our business.

Also, see Item 1 “Business-Environmental and Other Regulatory Matters” for discussion related to “Superfund” and “RCRA.”

Mining in Central and Northern 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 Northern and 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 the Powder River Basin, 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 Northern and Central Appalachia.

Competition within the coal industry may adversely affect our ability to sell coal, and excess production capacity in the industry could put downward pressure on coal prices.

We compete with numerous other coal producers in various regions of the United States for domestic and international sales. Recent increases in coal prices has and could continue to encourage the development of expanded capacity by new or existing coal producers. Any resulting overcapacity could reduce coal prices and therefore reduce our revenues.

Demand for our higher sulfur coal and the price that we can obtain for it is impacted by, among other things, the changing laws with respect to allowable emissions and the price of emission allowances. Significant increases in the price of those allowances could reduce the competitiveness of higher sulfur coal at plants not equipped to reduce sulfur dioxide emissions. Competition from low sulfur coal and possibly natural gas could result in a decrease in the higher-sulfur coal market share and revenues from some of our operations.

Demand for our low sulfur coal and the prices that we can obtain for it are also affected by, among other things, the price of emissions allowances. Decreases in the prices of these emissions allowances could make low sulfur coal less attractive to our customers. In addition, more widespread installation by electric utilities of technology that reduces sulfur emissions (which could be accelerated by increases in the prices of emissions allowances), may make high sulfur coal more competitive with our low sulfur coal. This competition could adversely affect our business and results of operations.

We also compete in international markets against coal produced in other countries. Measured by tons sold, exports accounted for approximately 11% of our sales in 2010. The demand for U.S. coal exports is dependent upon a number of factors outside of our control, including the overall demand for electricity in foreign markets, currency exchange rates, the demand for foreign-produced steel both in foreign markets and in the U.S. market (which is dependent in part on tariff rates on steel), general economic conditions in foreign countries, technological developments, and environmental and other governmental regulations. For example, if the value of the U.S. dollar were to rise against other currencies in the future, our coal would become relatively more expensive and less competitive in international markets, which could redu ce our foreign sales and negatively impact our revenues and net income. In addition, if the amount of coal exported from the United States were to decline, this decline could cause competition among coal producers in the United States to intensify, potentially resulting in additional downward pressure on domestic coal prices.

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Overcapacity in the coal industry, both domestically and internationally, may affect the price we receive for our coal. For example, in the past, increased demand for coal and attractive pricing brought new investors to the coal industry and promoted the development of new mines. These factors resulted in added production capacity throughout the industry, which led to increased competition and lower coal prices.

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

We base our reserve information on engineering, economic and geological data assembled and analyzed by our staff, which includes various engineers and geologists, and which is occasionally reviewed by outside firms. The reserve estimates as to both quantity and quality are annually updated to reflect production of coal from the reserves and new drilling, engineering or other data received. There are numerous uncertainties inherent in estimating quantities and qualities of and costs to mine recoverable reserves, including many factors beyond our control. Estimates of economically recoverable coal reserves and net cash flows necessarily depend upon a number of variable factors and assumptions, such as geological and mining conditions which may not be fully identified by available exploration data or which may differ from experience in curr ent operations, historical production from the area compared with production from other similar producing areas, the assumed effects of regulation and taxes by governmental agencies and assumptions concerning coal prices, operating costs, mining technology improvements, severance and excise tax, development costs and reclamation costs, all of which may vary considerably from actual results.

For these reasons, estimates of the economically recoverable quantities and qualities attributable to any particular group of properties, classifications of reserves based on risk of recovery and estimates of net cash flows expected from particular reserves prepared by different engineers or by the same engineers at different times may vary substantially. Actual coal tonnage recovered from identified reserve areas or properties and revenues and expenditures with respect to our reserves may vary materially from estimates. These estimates thus may not accurately reflect our actual reserves. Any inaccuracy in our estimates related to our reserves could result in lower than expected revenues, higher than expected costs or decreased profitability.

Our ability to operate our company effectively could be impaired if we fail to attract and retain key personnel.

Our ability to operate our business and implement our strategies depends, in part, on the efforts of our executive officers and other key employees.  In addition, our future success will depend on, among other factors, our ability to attract and retain other qualified personnel.  The loss of the services of any of our executive officers or other key employees or the inability to attract or retain other qualified personnel in the future could have a material adverse effect on our business or business prospects.

Due to our participation in multi-employer pension plans, we may have exposure under those plans that extend beyond what our obligation would be with respect to our employees.

We contribute to a multi-employer defined benefit pension plan (the "Plan") administered by the UMWA. In 2010, our total contributions to the plan and other contractual payments under our UMWA wage agreement were approximately $19.9 million.

In the event of a partial or complete withdrawal by us from any plan which is underfunded, we would be liable for a proportionate share of such plan’s unfunded vested benefits. Based on the information available from plan administrators, we believe that our portion of the contingent liability in the case of a full withdrawal or termination would be material to our financial position and results of operations. In the event that any other contributing employer withdraws from any plan which is underfunded, and such employer (or any member in its controlled group) cannot satisfy its obligations under the plan at the time of withdrawal, then we, along with the other remaining contributing employers, would be liable for our proportionate share of such plan’s unfunded vested benefits.

The Pension Protection Act of 2006 (“PPA”) requires a minimum funding ratio of 80% be maintained for this multi-employer pension plan and if the plan is determined to have a funding ratio of less than 80%, it will be deemed to be “seriously endangered”, and if less than 65% it will deemed to be “critical”, and in either case will be subject to additional funding requirements. In October 2010, we received notice that the plan is considered to be in seriously endangered status for the July 1, 2010 plan year because the actuary determined that the plan’s funding percentage is less than 80% and the plan is projected to have an accumulated funding deficiency by the plan year beginning July 1, 2017. The PPA requires the plan to adopt a funding improvement plan that may include increased contributions. Such increased contributions could have a material effect on our financial condition, results of operations and cash flows.

Our defined benefit 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 defined benefit pension plans in the United States for certain salaried and non-union hourly employees. For these plans, the PPA generally establishes a funding target of 100% of the present value of accrued benefits. The PPA includes a funding target phase-in provision such that the funding target is 92% in 2008, 94% in 2009, 96% in 2010 and 100% thereafter. Generally, a plan with a funding ratio below the prescribed target is subject to additional contributions requirements (amortization of funding shortfalls). Furthermore, any such plan with a funding ratio of less than 80% will be deemed at risk and will be subject to even higher funding requirements under the PPA. In addition, the value of existing assets held in our pension trust is affected by changes in the economic environment. As a result, we may be required to make significant cash contributions into the pension trust in order to comply with the funding requirements of the PPA. In 2010 we contributed $43.5 million to our pension plans. We currently expect to make contributions in 2011 in the range of $40 million for our defined benefit retirement plans to maintain at least an 80% funding ratio.

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As of December 31, 2010, our annual measurement date, our salaried and hourly pension plans were underfunded by $37.6 million. These pension plans are subject to the Employee Retirement Income Security Act of 1974 (“ERISA”). Under ERISA, the Pension Benefit Guaranty Corporation, (“PBGC”), has the authority to terminate an underfunded pension plan under limited circumstances. In the event our U.S. pension plans are terminated for any reason while the plans are underfunded, we may incur a liability to the PBGC that could exceed the entire amount of the underfunding.

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

In March 2010, the Patient Protection and Affordable Care Act (“PPACA”) was enacted, potentially impacting our costs to provide healthcare benefits to our eligible active and certain retired employees and workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (black lung disease). The PPACA has both short-term and long-term implications on benefit plan standards. Implementation of this legislation is planned to occur in phases, with plan standard changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018.

In the short term, our healthcare costs could increase due to raising the maximum age for covered dependents to receive benefits, changes to benefits for occupational disease related illnesses, the elimination of lifetime dollar limits per covered individual and restrictions of annual dollar limits per covered individual, among other standard requirements. In the long term, our healthcare costs could increase due to an excise tax on “high cost” plans and the elimination of annual dollar limits per covered individual, among other standard requirements.

The healthcare benefits that we provide to our represented employees and retirees are stipulated by law and by labor agreements. Healthcare benefit changes required by the healthcare legislation will be included in any new labor agreements. Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds certain dollar thresholds. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. We re-measured our retiree welfare plan obligations during 2010 in order to account for the estimated impact of the excise tax and updated other assumptions related to anticipated retirement ages and health care cost trend rates. The re-measurement resulted in an additional $27.1 million i ncrease to the retiree welfare plan obligation. We anticipate that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. We will need to continue to evaluate the impact of the PPACA in future periods, and when these regulations or interpretations are published, we will evaluate its assumptions in light of the new information.

Our work force could become increasingly unionized in the future and our unionized or union-free hourly work force could strike, which could adversely affect the stability of our production and reduce our profitability.

Approximately 87% of our 2010 coal production came from mines operated by union-free employees. As of December 31, 2010, approximately 79% of our workforce is union-free. However, employees have the right at any time under the National Labor Relations Act to form or affiliate with a union. Any further unionization of our employees, or the employees of third-party contractors who mine coal for us, could adversely affect the stability of our production and reduce our profitability.

Two of our Pennsylvania subsidiaries have separate wage agreements with the UMWA. Their existing wage agreements cover 1,138 (559 and 579, respectively) employees, and both wage agreements will expire at the end of the fourth quarter of 2011. Additionally, there is an agreement between Emerald Coal Resources, LP (“Emerald”) and the UMWA on behalf of the five employees working at the warehouse for Emerald, which expires at the end of the fourth quarter of 2011. Another Pennsylvania subsidiary has a wage agreement with the International Brotherhood of Electrical Workers (“IBEW”) covering 6 employees. This agreement expires in August 2013.

One of our Virginia subsidiaries has two contracts with the UMWA that cover 193 employees.   Two new collective bargaining agreements were ratified by those covered employees in May 2010.  Those agreements will expire in December 2014.

One of our West Virginia subsidiaries has a wage agreement with the UMWA, covering 18 employees. That collective bargaining agreement will expire in December 2011. Also, another West Virginia subsidiary, which is idle, has a wage agreement with the UMWA that could be terminated by our subsidiary or the UMWA with notice but since it is idle, no employees are affected at this time. However, if the operation becomes active again, these employees could be affected.

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The hourly workforce at the Wabash mine in southern Illinois was represented by the UMWA prior to its idling in 2007. The effects of the idling were the subject of an agreement with the UMWA signed in April 2007.

As is the case with our union-free operations, the UMWA and IBEW represented employees could strike, which would disrupt our production, increase our costs, and disrupt shipments of coal to our customers, or result in the closure of affected mines due to a strike by the workers or a lockout by mine management, which could reduce our profitability.

We could be negatively affected if we do not negotiate a new agreement with the UMWA, if we enter into a new wage agreement which significantly increases our labor costs or if we otherwise fail to maintain satisfactory labor relations.

Approximately 21% of our employees are represented by the UMWA. The current wage agreements for employees at two of our Pennsylvania subsidiaries and one of our West Virginia subsidiaries are set to expire in 2011. If we do not negotiate new collective bargaining agreements with the UMWA at these locations, we may incur prolonged strikes and other work stoppages at our union mines which would adversely affect our results of operations and cash flows. If we enter into a new agreement with the UMWA which significantly increases our labor costs relative to the existing agreements or other coal companies, our ability to compete with other coal companies may be materially adversely affected.

A shortage of skilled labor in the mining industry could pose a risk to achieving improved labor productivity and competitive costs and could adversely affect our profitability.

Efficient coal mining using modern techniques and equipment requires skilled laborers, preferably with at least a year of experience and proficiency in multiple mining tasks. In recent years, a shortage of trained coal miners has caused us to operate certain units without full staff, which decreases our productivity and increases our costs. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our coal, which could adversely affect our profitability.

Acquisitions that we have completed since our formation, as well as acquisitions that we may undertake in the future, involve a number of risks, any of which could cause us not to realize the anticipated benefits.

We continually seek to expand our operations and coal reserves through acquisitions. In the past five years, we have completed significant acquisitions and several smaller acquisitions and investments. Our ability to complete acquisitions is subject to availability of attractive targets on terms acceptable to us and general market conditions, among other things. If we are unable to successfully integrate the companies, businesses or properties that we acquire, our profitability may decline and we could experience a material adverse effect on our business, financial condition or results of operations. Acquisition transactions, including the proposed acquisition of Massey Energy Company, involve various inherent risks, including:

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

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

· the ability to achieve identified operating and financial synergies from an acquisition in the amounts and on the timeframe;

· problems that could arise from the integration of the acquired business, including the application of our internal control processes to the acquired business; and

· unanticipated changes in business, industry, market, or general economic conditions that differ from the assumptions underlying our rationale for pursuing the acquisition.

Any one or more of these factors could cause us not to realize the benefits anticipated from an acquisition.

Moreover, any acquisition opportunities we pursue could materially affect our liquidity and capital resources and may require us to incur indebtedness, seek equity capital or both. Future acquisitions could also result in our assuming more long-term liabilities relative to the value of the acquired assets than we have assumed in our previous acquisitions. Further, acquisition accounting rules require changes in certain assumptions made subsequent to the measurement period as defined in current accounting standards, to be recorded in current period earnings, which could affect our results of operations.

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

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The Massey Merger is subject to customary closing conditions.  These closing conditions include, among others, the receipt of required approvals of the stockholders of Alpha and Massey, the effectiveness of the registration statement and the expiration or termination of all waiting periods under applicable antitrust laws, including the applicable waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, ("HSR Act") and foreign antitrust laws.

 

The governmental agencies from which the parties will seek these approvals have broad discretion in administering the governing regulations.  As a condition to their approval of the Massey Merger, agencies may impose requirements, limitations or costs or require divestitures or place restrictions on the conduct of our business after consummation of the Massey Merger.  These requirements, limitations, costs, divestitures or restrictions could jeopardize or delay the consummation of the Massey Merger or may reduce the anticipated benefits of the business combination.  Neither Alpha nor Massey has any obligation to complete the Massey Merger if, as a condition to their approval, regulators require any sale, divestiture or disposition of, or prohibition or limitation on the ownership or operation by us of any po rtion of our respective business, properties or assets if such actions would have a material adverse effect on Alpha and its subsidiaries, taken as a whole, or Massey and its subsidiaries, taken as a whole.  Further, no assurance can be given that the required stockholder approvals will be obtained, that the related Registration Statement on Form S-4 will be declared effective or that the required closing conditions will be satisfied, and, if all required consents and approvals are obtained and the closing conditions are satisfied, no assurance can be given as to the terms, conditions and timing of the approvals.  If Alpha and Massey agree to any material requirements, limitations, costs, divestitures or restrictions in order to obtain any approvals required to consummate the Massey Merger, these requirements, limitations, costs, divestitures or restrictions could adversely affect our ability to integrate our operations with Massey’s operations or reduce the anticipated benefits of the Massey Merger.  This could result in a failure to consummate the Massey Merger or have a material adverse effect on our business and results of operations after consummation of the Massey Merger.  Alpha and Massey will also be obligated to pay certain transaction-related fees and expenses in connection with the Massey Merger, whether or not the Massey Merger is completed.

Alpha may fail to realize the cost savings estimated as a result of the Massey Merger.

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

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

Massey and Massey’s directors and officers are named parties to a number of actions, including various actions relating to the Upper Big Branch mine and safety conditions at Massey mines, and further actions may be filed against Massey, including by the U.S. Attorney’s Office.

A number of actions are pending in Delaware and Virginia state courts and federal courts relating to safety conditions at Massey’s mines, the April 2010 incident at the Upper Big Branch mine ("UBB") and other related matters.  These include derivative actions against current and former Massey directors and officers.  Massey and its officers and directors may be subject to future claims, including from families of the 29 miners that died in the UBB incident.  In addition, the U.S. Attorney’s Office and the federal MSHA in conjunction with the State of West Virginia are currently investigating the UBB incident.  The outcomes of these pending and potential claims and investigations are uncertain.  Depending on the outcome, these actions could have adverse financial effects o r cause reputational harm to us.  Alpha may not resolve these claims favorably or may not successfully implement remedial safety measures imposed as a result of some of these actions and investigations.  In addition, if the Massey Merger is consummated, plaintiffs in the pending derivative actions against current and former Massey directors and officers, which we refer to as the derivative plaintiffs, and other plaintiffs who have filed suit challenging the Massey Merger have asserted that, if the Massey Merger is completed the derivative plaintiffs may lose standing to assert those claims.

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Changes in purchasing patterns in the coal industry may make it difficult for us to extend existing supply contracts or enter into new long-term supply contracts with customers, which could adversely affect the capability and profitability of our operations.

We sell a significant portion of our coal under long-term coal supply agreements, which are contracts with a term greater than 12 months. The execution of a satisfactory long-term coal supply agreement is frequently the basis on which we undertake the development of coal reserves required to be supplied under the contract.   During 2010, approximately 87% and 78% of our steam and metallurgical coal sales volume, respectively, was delivered pursuant to long-term contracts. At December 31, 2010, our long-term coal supply agreements had remaining terms of up to ten years and an average remaining term of approximately two years. When our current contracts with customers expire or are otherwise renegotiated, our customers may decide to purchase fewer tons of coal than in the past or on different terms, including pricing te rms less favorable to us. For additional information relating to our long-term coal supply contracts, see “Business -- Marketing, Sales and Customer Contracts.”

As of January 26, 2011, approximately 6% and 59%, respectively, of our planned production for 2011 and 2012 was uncommitted. We may not be able to enter into coal supply agreements to sell this production on terms, including pricing terms, as favorable to us as our existing agreements.

As electric utilities continue to adjust to frequently changing regulations, including the Acid Rain regulations of the Clean Air Act, the Clean Air Mercury Rule, the Clean Air Interstate Rule and the possible deregulation of their industry, they are becoming increasingly less willing to enter into long-term coal supply contracts and instead are purchasing higher percentages of coal under short-term supply contracts. The industry shift away from long-term supply contracts could adversely affect us and the level of our revenues. For example, fewer electric utilities would have a contractual obligation to purchase coal from us, thereby increasing the risk that we will not have a market for our production. The prices we receive in the spot market may be less than the contractual price an electric utility is willing to pay for a committed su pply. Furthermore, spot market prices tend to be more volatile than contractual prices, which could result in decreased revenues.

Certain provisions in our long-term supply contracts may reduce the protection these contracts provide us during adverse economic conditions or may result in economic penalties upon our failure to meet specifications.

Price adjustment, “price reopener” and other similar provisions in long-term supply contracts may reduce the protection from short-term coal price volatility traditionally provided by these contracts. Price reopener provisions are particularly common in international metallurgical coal sales contracts. Some of our coal supply contracts contain provisions that allow for the price to be renegotiated at periodic intervals. Generally, price reopener provisions require the parties to agree on a new price based on the prevailing market price, however, some contracts provide that the new price is set between a pre-set “floor” and “ceiling.” In some circumstances, failure of the parties to agree on a price under a price reopener provision can lead to termination of the contract or litigation, the outcome of wh ich is uncertain. Any adjustment or renegotiation leading to a significantly lower contract price could result in decreased revenues. Accordingly, supply contracts with terms of one year or more may provide only limited protection during adverse market conditions.

Coal supply agreements also typically contain force majeure provisions allowing temporary suspension of performance by us or the customer during specified events beyond the control of the affected party. Most of our 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. In addition, some of these contracts allow our customers to terminate their contracts in the event of changes in regulations affecting our industry that increase the price of coal beyond specified limits.

As a result of the economic slowdown that has resulted in deep cuts in worldwide steel production in late 2008 and the first half of 2009 and the application of such price adjustment and other similar provisions in our long-term supply contracts, we had to restructure certain agreements under mutually acceptable terms with steel customers starting in late 2008 and continuing through 2009. A slowing in the current economic recovery would likely result in an increase in the number of restructured agreements.

Due to the risks mentioned above with respect to long-term supply contracts, we may not achieve the revenue or profit we expect to achieve from these sales commitments.

The loss of, or significant reduction in, purchases by our largest customers could adversely affect our revenues and profitability.

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Our largest customer during 2010 accounted for approximately 9% of our total revenues. We derived approximately 42% of our 2010 total revenues from sales to our ten largest customers. These customers may not continue to purchase coal from us under our current coal supply agreements, or at all. If these customers were to reduce their purchases of coal from us significantly or if we were unable to sell coal to them on terms as favorable to us as the terms under our current agreements, our revenues and profitability could suffer materially.

 

A decline in demand for metallurgical coal would limit our ability to sell our high quality steam coal as higher-priced metallurgical coal and could affect the economic viability of certain of our mines that have higher operating costs.

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 metallurgical and steam coal markets. We decide whether to mine, process and market these coals as metallurgical or steam coal based on management's assessment as to which market is likely to provide us with a higher margin. We consider a number of factors when making this assessment, including the difference between the current and anticipated future market prices of steam coal and metallurgical coal, the lower volume of saleable tons that results from producing a given quantity of reserves for sale in the metallurgical market instead of the steam market, the increased costs incurred in producing coal for sale in the metallurgi cal market instead of the steam market, the likelihood of being able to secure a longer-term sales commitment by selling coal into the steam market and our contractual commitments to deliver different types of coals to our customers. 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, thereby reducing our revenues and profitability. 

Most of our metallurgical coal reserves possess quality characteristics that enable us to mine, process and market them as high quality steam coal. However, some of our mines operate profitably only if all or a portion of their production is sold as metallurgical coal to the steel market. If demand for metallurgical coal declined to the point where all the production from these mines had to be sold as steam coal, theses mines may not be economically viable and subject to closure. Such closures could lead to asset impairment charges, accelerated reclamation costs, as well as reduced revenue and profitability.

Disruption in supplies of coal produced by contractors and other third parties could temporarily impair our ability to fill customers' orders or increase our costs.

In addition to marketing coal that is produced by our subsidiaries' employees, we utilize contractors to operate some of our mines. Operational difficulties at contractor-operated mines, changes in demand for contract miners from other coal producers, and other factors beyond our control could affect the availability, pricing, and quality of coal produced for us by contractors. The majority of the coal that we purchase from third parties is blended with coal produced from our mines prior to resale, and we also process (which includes washing, crushing or blending coal at our preparation plants or loading facilities) a portion of the coal that we purchase from third parties prior to resale. We sold 2.2 million tons of coal purchased from third parties during 2010, representing approximately 3% of our total coal sales volume during 20 10. Approximately 73% of our purchased coal sales volume in 2010 was blended with coal produced from our mines prior to resale, and approximately 1% of our total coal sales volume in 2010 consisted of coal purchased from third parties that we processed before resale. The availability of specified qualities of this purchased coal may decrease and prices may increase as a result of, among other things, changes in overall coal supply and demand levels, consolidation in the coal industry and new laws or regulations. Disruption in our supply of contractor-produced coal and purchased coal could temporarily impair our ability to fill our customers' orders or require us to pay higher prices in order to obtain the required coal from other sources. Any increase in the prices we pay for contractor-produced coal or purchased coal could increase our costs and therefore lower our earnings.

Our ability to collect payments from our customers could be impaired if their creditworthiness deteriorates.

Our ability to receive payment for coal sold and delivered depends on the continued creditworthiness of our customers. Our customer base is changing with deregulation as utilities sell their power plants to their non-regulated affiliates or third parties that may be less creditworthy, thereby increasing the risk we bear on payment default. These new power plant owners may have credit ratings that are below investment grade. In addition, competition with other coal suppliers could force us to extend credit to customers and on terms that could increase the risk we bear on payment default.

We have contracts to supply coal to energy trading and brokering companies under which those companies sell coal to end users. If the creditworthiness of the energy trading and brokering companies declines, this would increase the risk that we may not be able to collect payment for all coal sold and delivered to or on behalf of these energy trading and brokering companies.

Global financial markets experienced extreme disruption in recent years, which, among other things, severely limited liquidity and credit availability. While conditions improved in 2010 and liquidity has become available in the financial markets, we continue to closely monitor economic conditions and credit availability and the resulting impacts on our business and our suppliers and customers. If the current economic recovery proves to be only temporary, the current economic conditions worsens or a prolonged global, national or regional economic recession or other similar events occur, it is likely to significantly impact the creditworthiness of our customers and could increase the risk we bear on payment default.

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Fluctuations in transportation costs and the availability or reliability of transportation could affect the demand for our coal or temporarily impair our ability to supply coal to our customers.

Transportation costs represent a significant portion of the total cost of coal for our customers. Increases in transportation costs could make coal a less competitive source of energy or make our coal production less competitive than coal produced from other sources.  

We depend upon railroads, trucks, beltlines, ocean vessels and barges to deliver coal to our customers. Disruption of these transportation services due to weather-related problems, mechanical difficulties, strikes, lockouts, bottlenecks, terrorist attacks, and other events could temporarily impair our ability to supply coal to our customers, resulting in decreased shipments.   Decreased shipment performance levels over longer periods of time could cause our customers to look to other sources for their coal needs, negatively affecting our revenues and profitability.

In 2010, 80% of our produced and processed coal volume was transported from the load-out or preparation plant to the customer by rail. From time to time in the past, we have experienced deterioration in the reliability of the service provided by rail carriers, which increased our internal coal handling costs. If there is future deterioration of the transportation services provided by the railroad companies we use and we are unable to find alternative transportation providers to ship our coal, our business could be adversely affected.

We have investments in mines, loading facilities, and ports that in most cases are serviced by a single rail carrier. Our operations that are serviced by a single rail carrier are particularly at risk to disruptions in the transportation services provided by that rail carrier, due to the difficulty in arranging alternative transportation. If a single rail carrier servicing our operations does not provide sufficient capacity, revenue from these operations and our return on investment could be adversely impacted.  In addition, much of our eastern coal is transported from our mines to our loading facilities by trucks owned and operated by third parties. An increase in transportation costs could have an adverse effect on our ability to increase or to maintain production on a profit-making basis and could therefore adversely affect our r evenues and earnings.

Our mining operations consume significant quantities of commodities. If commodity prices increase significantly or rapidly, it could impact our cost of production.

Coal mines consume large quantities of commodities such as steel, copper, rubber products, explosives and liquid fuels, such as diesel fuel. Some commodities, such as steel, are needed to comply with roof control plans required by regulation. The prices we pay for these products are strongly impacted by the global commodities market. A rapid or significant increase in cost of these commodities could impact our mining costs because we have limited ability to negotiate lower prices, and, in some cases, do not have a ready substitute for these commodities.

Fair value of derivative instruments that are not accounted for as a hedge could cause volatility in our earnings.

Derivative financial instruments are recognized as either assets or liabilities and are measured at fair value. Changes in fair value are recognized either in earnings or equity, depending on whether the transaction qualifies for cash flow hedge accounting, and if so, how effective the derivatives are at offsetting price movements in the underlying exposure. We account for certain of our coal forward purchase and sales agreements that do not qualify for the “normal purchase and normal sales” exception available under existing accounting rules as derivative instruments. We use significant quantities of diesel fuel and explosives in our operations and enter into commodity swap and option agreements for a portion of our diesel fuel and explosive needs to reduce the risk that changes in the market price of diesel fuel and explosi ves can have on our operations. A portion of our commodity swap agreements have not been designated as qualifying cash flow hedges and therefore, we are required to record changes in fair value of these derivative instruments in our Consolidated Statements of Operations.

We also have outstanding debt that includes a variable interest rate component.  We entered into an interest rate swap to reduce the risk that changing interest rates could have on our operations. The swap initially qualified for cash flow hedge accounting and changes in fair value were recorded as a component of equity; however, the debt instrument was subsequently paid and the swap no longer qualified for cash flow hedge accounting. Subsequent changes in fair value of the interest rate swap will be recorded in earnings. During 2010 we recorded a loss of $11.3 million related to changes in the fair value of our derivative instruments. Future changes in the fair value of derivative instruments that do not qualify for hedge accounting could require us to record additional losses.

Our hedging activities for diesel fuel and explosives may prevent us from benefiting from price decreases

We enter into hedging arrangements, primarily financial swap contracts, for a portion of our anticipated diesel fuel and explosive needs.  As of December 31, 2010, we had financial swap contracts to fix approximately 68% and 39% of our calendar year 2011 and 2012 expected diesel fuel needs, respectively, and 28% of our calendar year 2011 expected explosive needs.  While our hedging strategy provides us protection in the event of price increases to our diesel fuel and explosives, it may also prevent us from the benefits of price decreases.  If prices for diesel fuel and explosives decreased significantly below our swap prices, it could have a material effect on our financial condition, the result of operations and cash flows.

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Our business will be adversely affected if we are unable to develop or acquire additional coal reserves that are economically recoverable.

Our profitability depends substantially on our ability to mine coal reserves possessing quality characteristics desired by our customers in a cost-effective manner. As of December 31, 2010, we owned or leased 2.3 billion tons of proven and probable coal reserves that we believe will support current production levels for more than 20 years. We have not yet applied for the permits required, or developed the mines necessary, to mine all of our reserves. Permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen. In addition, we may not be able to mine all of our reserves as profitably as we do at our current operations.

Because our reserves are depleted as we mine our coal, our future success and growth depend, in part, upon our ability to acquire additional coal reserves that are economically recoverable. If we are unable to replace or increase our coal reserves on acceptable terms, our production and revenues will decline as our reserves are depleted. Additionally, our goodwill will also become impaired. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to acquire additional coal reserves through business combinations in the future also could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, or the lack of su itable acquisition candidates.

Because our profitability is substantially dependent on the availability of an adequate supply of coal reserves that can be mined at competitive costs, the unavailability of these types of reserves would cause our profitability to decline.

We have not yet applied for all of the permits required, or developed the mines necessary, to use all of our reserves. Furthermore, we may not be able to mine all of our reserves as profitably as we do at our current operations. Our planned development projects and acquisition activities may not result in significant additional reserves and we may not have continuing success developing new mines or expanding existing mines beyond our existing reserves. Most of our mining operations are conducted on properties owned or leased by us. Because title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, our right to mine some of our reserves may be materially adversely affected if defects in title or boundaries exist. In addition, in order to develop our reserves, we mu st receive various governmental permits. We may be unable to obtain the permits necessary for us to operate profitably in the future. Some of these permits are becoming increasingly more difficult and expensive to obtain and the review process continues to lengthen.

Our profitability depends substantially on our ability to mine coal reserves that have the geological characteristics that enable them to be mined at competitive costs and to meet the quality needed by our customers. 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. We may not be able to accurately assess the geological characteristics of any reserves that we now own or subsequently acquire, which may adversely affect our profitability and financial condition. Exhaustion of reserves at particular mines also may have an adverse effect on our operating results that is disproportionate to the percentage of overall production represented by such mines. Our ability to obtain other reserves through business combinations in the future could be limited by restrictions under our existing or future debt agreements, competition from other coal companies for attractive properties, the lack of suitable acquisition candidates or the inability to acquire coal properties on commercially reasonable terms.

Failure to obtain or renew surety bonds on acceptable terms or maintain self bonding status could affect our ability to secure reclamation and coal lease obligations, which could adversely affect our ability to mine or lease coal.

Federal and state laws require us to obtain surety bonds to secure payment of certain long-term obligations such as mine closure or reclamation costs, federal and state workers' compensation costs, coal leases and other obligations. These bonds are typically renewable annually. Surety bond issuers and holders may not continue to renew the bonds or may demand additional collateral or other less favorable terms upon those renewals. We also maintain self bonding in certain states. Our failure to maintain our self bonding status, or our inability to acquire surety bonds that are required by state and federal law would affect our ability to secure reclamation and coal lease obligations and increase our costs and collateral requirements, which could adversely affect our ability to mine or lease coal and our results of operations. That failure could result from a variety of factors including, without limitation:

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

· restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our credit facility or the indentures governing our 7.25% senior notes due 2014 and our 2.375% convertible notes due 2015; and

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

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In addition, due to the current instability and volatility of the financial markets, our current surety bond providers may experience difficulties in providing new surety bonds to us, maintaining existing surety bonds, or satisfying liquidity requirements under existing surety bond contracts.  In that event, we would be required to find alternative sources of funding to satisfy our payment obligations, which may require greater use of our credit facility.

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

The SMCRA establishes operational, reclamation and closure standards for all aspects of surface mining as well as deep mining. We accrue for the costs of current mine disturbance and final mine closure, including the cost of treating mine water discharge where necessary. Estimates of our total reclamation and mine-closing liabilities are based upon permit requirements and our experience. The amounts recorded are dependent upon a number of variables, including the estimated future asset retirement costs, estimated proven reserves, assumptions involving profit margins of third party contractors, inflation rates, discount rates and the assumed credit-adjusted risk-free interest rates. Furthermore, these obligations are unfunded. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, o ur future operating results could be adversely affected.

Defects in title in our mine properties could limit our ability to recover coal from these properties or result in significant unanticipated costs.

We conduct a significant part of our mining operations on properties that we lease. Title to most of our leased properties and mineral rights is not thoroughly verified until a permit to mine the property is obtained, and in some cases title with respect to leased properties is not verified at all. Our right to mine some of our reserves may be materially adversely affected by actual or alleged defects in title or boundaries. In order to obtain leases or mining contracts to conduct our mining operations on property where these defects exist, we may in the future have to incur unanticipated costs or could even lose our right to mine on that property, which could adversely affect our profitability.  In addition, from time to time the rights of third parties for competing uses of adjacent, overlying or underlying lands such as for oil and gas activity, coalbed methane, production, pipelines, roads, easements and public facilities may affect our ability to operate as planned if our title is not superior or arrangements cannot be negotiated.

Expenditures for benefits for non-active employees could be materially higher than we have anticipated, which could increase our costs and adversely affect our financial results.

We are responsible for certain long-term liabilities under a variety of benefit plans and other arrangements with active and inactive employees. The unfunded status (the excess of projected benefit obligation over plan assets) of these obligations as of December 31, 2010, as reflected in Note 15 to our Consolidated Financial Statements, included $706.3 million of postretirement obligations, $41.3 million of defined benefit pension and supplemental employee retirement plan obligations, $51.7 million of workers’ compensation obligations and $45.0 million of self-insured black lung obligations. These obligations have been estimated based on assumptions including actuarial estimates, discount rates, estimates of mine lives, expected returns on pension plan assets and changes in health care costs. We could be re quired to expend greater amounts than anticipated. 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 affect on our financial results. Several states in which we operate consider changes in workers’ compensation laws from time to time, which, if enacted, could adversely affect us.

Our indebtedness could harm our business by limiting our available cash and our access to additional capital and could force us to sell material assets or take other actions to attempt to reduce our indebtedness.

At December 31, 2010, we had $821.5 million of indebtedness outstanding before discounts applied for financial reporting, representing 24% of our total capitalization. This indebtedness consisted of $287.5 million principal of our 2.375% convertible notes due 2015, $298.3 million principal of our 7.25% senior notes due 2014, $227.9 million term loan due 2014 under our credit facility and $7.8 million of other debt. In addition, at December 31, 2010, we had $7.7 million of letters of credit outstanding under our credit facility and $63.8 million of letters of credit outstanding under our accounts receivable securitization facility.

This level of indebtedness could have important consequences to our business. For example, it could:

· require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions and other general corporate activities;

· limit our ability to obtain additional financing to fund future working capital, capital expenditures, research and development, debt service requirements or other general corporate requirements;

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· increase our vulnerability to general adverse economic and industry conditions and limit our flexibility in planning for, or reacting to, changes in our business and in the coal industry;

· make it more difficult to self-insure and obtain surety bonds or letters of credit;

· limit our ability to enter into new long-term sales contracts; and

· place us at a competitive disadvantage compared to less leveraged competitors.

If our cash flows and capital resources are insufficient to fund our debt service obligations or our requirements under our other long-term liabilities, we may be forced to sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations or our requirements under our other long term liabilities. In the absence of sufficient cash flows and resources, we could face substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. Our credit facility restricts our ability to sell assets and use the proceeds from the sales. We may not be able to consummate any such sales or to obtain the proceeds which we could realiz e from them and these proceeds may not be adequate to meet any debt service obligations then due. Furthermore, substantially all of our material assets secure our indebtedness under our credit facility.

We may also be able to incur substantially more debt which could further exacerbate the risks associated with our significant indebtedness.

We may be able to incur substantial additional indebtedness in the future under the terms of our credit facility and the indentures governing our 7.25% senior notes due 2014 and our 2.375% convertible notes due 2015. Our credit facility provides for a revolving line of credit of up to $854.4 million, of which $846.7 million was available as of December 31, 2010. The addition of new debt to our current debt levels could increase the related risks that we now face. For example, the spread over the variable interest rate applicable to loans under our revolving line of credit is dependent on our leverage ratio, and it would increase if our leverage ratio increases. Additional drawings under our revolving line of credit could also limit the amount available for letters of credit in support of our bonding obligations, which we w ill require as we develop and acquire new mines.

The terms of our credit facility and the indentures governing our 7.25% senior notes due 2014 and 2.375% convertible notes due 2015 limit our and our subsidiaries’ ability to take certain actions, which may limit our operating and financial flexibility and adversely affect our business.

Our credit facility and the indentures governing our 7.25% senior notes due 2014 and 2.375% convertible notes due 2015contain a number of significant restrictions and covenants that limit our ability and our subsidiaries’ ability to, among other things, incur additional indebtedness, enter into sale and leaseback transactions, pay dividends, make redemptions and repurchases of certain capital stock, make loans and investments, create liens, engage in transactions with affiliates, and merge or consolidate with other companies or sell substantially all of our assets.  These covenants could adversely affect our ability to finance our future operations or capital needs or to execute preferred business strategies.  In addition, complyin g with these covenants may make it more difficult for us to successfully execute our business strategy and compete against companies who are not subject to such restrictions.

Operating results below current levels or other adverse factors, including a significant increase in interest rates, could result in our being unable to comply with our covenants and payment obligations contained in our credit facility and the indentures governing our 7.25% senior notes due 2014 and 2.375% convertible notes due 2015. If we violate these covenants or obligations under any of these agreements and are unable to obtain waivers from our lenders, our debt under all of these agreements would be in default and could be accelerated by our lenders. If our indebtedness is accelerated, we may not be able to repay our debt or borrow sufficient funds to refinance it. Even if we were 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 reas on, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Failure to maintain capacity for required letters of credit could limit our available borrowing capacity under our credit facility, limit our ability to provide financial assurance for self-insured obligations and negatively impact our ability to obtain additional financing to fund future working capital, capital expenditure or other general corporate requirements.

At December 31, 2010, we had $71.5 million of letters of credit in place, of which $7.7 million was outstanding under our credit facility and $63.8 million was outstanding under our accounts receivable securitization facility. These outstanding letters of credit supported workers’ compensation bonds, coal mining reclamation obligations, UMWA retiree health care obligations, and other miscellaneous obligations. Our credit facility provides for revolving commitments of up to $854.4 million, all of which can be used to issue letters of credit, and our accounts receivable securitization facility provides for the issuance of up to $150.0 million in letters of credit. Obligations secured by letters of credit may increase in the future. Any such increase would limit our available borrowing capacity under our current or future cr edit facilities and could negatively impact our ability to obtain additional financing to fund future working capital, capital expenditures or other general corporate requirements. Moreover, if we do not maintain sufficient borrowing capacity under our revolving credit facility and accounts receivable securitization facility for additional letters of credit, we may be unable to provide financial assurance for our mining operations.

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Certain terms of our 2.375% convertible notes due 2015 may adversely impact our liquidity.

Upon conversion of our 2.375% convertible notes due 2015, we will be required to pay in cash the lesser of the principal amount of the converted notes and the sum of a calculated daily conversion value over an averaging period. As a result, the conversion of the convertible notes may significantly reduce our liquidity.

The inability of the sellers of the companies that we have acquired to fulfill their indemnification obligations to us under our acquisition agreements could increase our liabilities and adversely affect our results of operations and financial position.

In the acquisition agreements entered into with the sellers of the companies that we have acquired, including the acquisition agreements entered into related to the Coastal Coal Company, Nicewonder and Progress acquisitions, the respective sellers and, in some of the acquisitions, their parent companies, agreed to retain responsibility for and indemnify Old Alpha against damages resulting from certain third-party claims or other liabilities, such as workers' compensation liabilities, black lung liabilities, postretirement medical liabilities and certain environmental or mine safety liabilities. The failure of any seller and, if applicable, its parent company, to satisfy their obligations with respect to claims and retained liabilities covered by the acquisition agreements could have an adverse effect on our results of operations and fina ncial position if claimants successfully assert that we are liable for those claims and/or retained liabilities. The obligations of the sellers and, in some instances, their parent companies, to indemnify us with respect to their retained liabilities will continue for a substantial period of time, and in some cases indefinitely. The sellers' indemnification obligations with respect to breaches of their representations and warranties in the acquisition agreements will terminate upon expiration of the applicable indemnification period (generally 18-24 months from the acquisition date for most representations and warranties, and from two to five years from the acquisition date for environmental representations and warranties), are subject to deductible amounts and will not cover damages in excess of the applicable coverage limit. The assertion of third-party claims after the expiration of the applicable indemnification period or in excess of the applicable coverage limit, or the failure of any seller to sa tisfy its indemnification obligations with respect to breaches of its representations and warranties, could have an adverse effect on our results of operations and financial position.

If we are unable to accurately estimate the overall risks or costs when we bid on a road construction contract that is ultimately awarded to us, we may achieve a lower than anticipated profit or incur a loss on the contract.

A large percentage of our road construction revenues and contract backlog is typically derived from fixed unit price contracts. Fixed unit price contracts require us to perform the contract for a fixed unit price irrespective of our actual costs. As a result, we realize a profit on these contracts only if we successfully estimate our costs and then successfully control actual costs and avoid cost overruns. If our cost estimates for a contract are inaccurate, or if we do not execute the contract within our cost estimates, then cost overruns may cause us to incur losses or cause the contract not to be as profitable as we expected. Also, if we do not recover the amounts of coal estimated on our construction projects, profitability on our construction contracts could be less than projected. This, in turn, could negatively affect our cash flo w, earnings and financial position. During 2010, we recorded an additional loss of approximately $5.3 million due to a change in estimated costs to complete the current project.

The costs incurred and gross profit realized on those contracts can vary, sometimes substantially, from the original projections due to a variety of factors, including, but not limited to:

· onsite conditions that differ from those assumed in the original bid;

· delays caused by weather conditions;

· contract modifications creating unanticipated costs not covered by change orders;

· changes in availability, proximity and costs of materials, including diesel fuel, explosives, and parts and supplies for our equipment;

· coal recovery which impacts the allocation of cost to road construction;

· availability and skill level of workers in the geographic location of a project;

· our suppliers' or subcontractors' failure to perform;

· mechanical problems with our machinery or equipment;

· citations issued by a governmental authority, including the Occupational Safety and Health Administration and the Mine Safety and Health Administration;

· difficulties in obtaining required governmental permits or approvals;

· changes in applicable laws and regulations; and

· claims or demands from third parties alleging damages arising from our work.

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Sales of additional shares of our common stock, the exercise or granting of additional equity securities or conversion of our convertible notes could cause the price of our common stock to decline.

Sales of substantial amounts of our common stock in the open market and the availability of those shares for sale could adversely affect the price of our common stock. In addition, future issuances of equity securities, including issuances pursuant to outstanding stock-based awards under our long-term incentive plans or the conversion of our convertible bonds, could dilute the interests of our existing stockholders and could cause the market price for our common stock to decline. We may issue equity securities in the future for a number of reasons, including to finance our operations and business strategy, to adjust our ratio of debt to equity, to satisfy our obligations upon the exercise or vesting of outstanding stock-based awards or for other reasons.

As of December 31, 2010, there were:

· 595,966 shares of common stock issuable upon the exercise of stock options with a weighted-average exercise price of $10.60; and

· 2,487,399 restricted share unit awards issued to directors, officers and key employees to be converted to common stock upon the satisfaction of future service and performance conditions (assuming performance at the maximum level).

The price of our common stock could also be affected by hedging or arbitrage trading activity that may exist or develop involving our common stock and our convertible notes.

Ongoing instability and volatility in the worldwide financial markets have created uncertainty, which could adversely affect our business and the price of our common shares.

In recent years, financial markets in the United States, Europe and Asia experienced extreme disruptions including, among other things, extreme volatility in security prices, severely diminished liquidity and credit availability, rating downgrades of certain investments and declining valuations of others, including real estate. The tightening of credit in financial markets adversely affected our customers’ ability to obtain financing for operations and resulted in a temporary decrease in demand, the cancellation of some orders for our coal products and the restructuring of agreements with certain of our coal customers. Beginning in the second half of 2009, economic conditions started to improve and most economies are now regarded as recovering from a deep recession. Although global industrial activity and the financial markets reco vered in 2010 from 2009 levels, reversal of the current economic recovery, a prolonged global, national or regional economic recession or other similar events could have a material adverse effect on the demand for coal and on our sales, margins, and profitability. We continue to monitor economic developments and the resulting impact on our business and other suppliers and customers closely.  However, we are unable to predict the timing, duration and severity of potential future disruptions in financial markets and potential future adverse economic conditions in the U.S. and other countries and the impact these events may have on our operations and the industry in general.

We do not intend to pay cash dividends on our common stock in the foreseeable future.

We have never declared or paid a cash dividend, and our Board of Directors periodically evaluates commencing a dividend policy.  If we were to decide in the future to pay dividends, our ability to do so would be dependent on the ability of our subsidiaries to make cash available to us, by dividend, debt repayment or otherwise. Our ability to pay dividends is limited by restrictions in our credit facility.

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

Terrorist attacks and threats, escalation of military activity in response to such attacks or acts of war may negatively affect our business, financial condition, and results of operations. 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 U.S. targets, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions affecting our customers may materially adversely affect our operations and those of our customers. As a result, there could be delays or losses in transportation and deliveries of coal to our customers, decreased sales of our coal and extensi on of time for payment of accounts receivable from our 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, disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.

Provisions in our certificate of incorporation and bylaws and the indentures governing our 2.375% convertible notes due 2015 and our 7.25% senior notes due 2014 may discourage a takeover attempt even if doing so might be beneficial to our stockholders.

Provisions contained in our certificate of incorporation and bylaws could impose impediments to the ability of a third party to acquire us even if a change of control would be beneficial to our stockholders. Provisions of our certificate of incorporation and bylaws impose various procedural and other requirements, which could make it more difficult for stockholders to effect certain corporate actions. For example, our 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 our common stock. These provis ions 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 our common stock.

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If a “fundamental change” (as defined in the indenture governing our convertible notes) occurs, holders of the convertible notes will have the right, at their option, either to convert their convertible notes or require us to repurchase all or a portion of their convertible notes. In the event of a “make-whole fundamental change” (as defined in the indenture governing the convertible notes), we also may be required to increase the conversion rate applicable to any convertible notes surrendered for conversion. If a “change in control” (as defined in the indenture governing the 7.25% senior notes) occurs, holders of the 7.25% senior notes will have the right to require us to repurchase all or a portion of their 7.25% senior notes. In addition, each indenture prohibits 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 applicable notes. Our credit facility imposes 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 our stockholders.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Coal Reserves

We periodically retain outside experts to independently verify our estimates of our coal reserves. “Reserves” are defined by the Securities and Exchange Commission (“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. “Proven (Measured) Reserves” are defined by SEC Industry Guide 7 as reserves for which (1) 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 (2) 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. “Probabl e reserves” are defined by 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, as well as third party consultants retained by us. We periodically update our reserve estimates to reflect past coal production, new drilling information and other geological or mining data, and acquisitions or sales of coal properties. Coal tonnages are categorized according to coal quality, mining method, permit status, mineability and location relative to existing mines and infrastructure. 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.

Prior to Old Alpha’s initial public offering in 2005, a third party consultant was retained to perform reserve estimates in November 2004. Since November 2004, a third party consultant has been retained to verify reserves for our major acquisitions, which include the Callaway, Progress Fuels, Mingo Logan Ben’s Creek Complex, and Foundation acquisitions, as well as to conduct ongoing reserve updates, on an annual basis, for specific properties that have undergone substantial modification to the reserve base. Properties that have undergone insignificant or no changes since the original assessment in November 2004 have been carried forward without re-evaluation.  These reviews include the preparation of reserve maps and the development of estimates by certified professional geologists based on data supplied by us and u sing standards accepted by government and industry, including the methodology outlined in U.S. Circular 891. Reserve estimates were developed using criteria to assure that the basic geologic characteristics of the reserve (such as minimum coal thickness and wash recovery, interval between deep mineable seams and mineable area tonnage for economic extraction) were in reasonable conformity with existing and recently completed operation capabilities on our properties.

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We estimate that, as of December 31, 2010, we owned or leased total proven and probable coal reserves of approximately 2,253.5 million tons. We believe that we have sufficient reserves to replace capacity from depleting mines for the foreseeable future and that our current reserves are one of our strengths. We believe that the current level of production at our major mines is sustainable for the foreseeable future.

Of the 2,253.5 million tons, approximately 1,155.0 million tons were assigned reserves that we expect to be mined in future operations. Approximately 1,098.5 million tons were unassigned reserves that we are holding for future development. All of our reserves in Wyoming are assigned. As of December 31, 2010, we had unassigned reserves in Pennsylvania, West Virginia, Virginia/Kentucky and Illinois of 649.7 million tons, 242.1 million tons, 178.1 million tons and 28.6 million tons, respectively.

Approximately 64% of our reserves are classified as high Btu coal (coal delivered with an average heat value of 12,500 Btu per pound or greater) and are located in Pennsylvania, West Virginia, and Virginia/Kentucky. Approximately 64% of our reserves are classified as compliance coal which meets the 1.2 lb SO 2 /mm Btu standard of Phase II of the Clean Air Act. Our compliance coal reserves are located in Pennsylvania, Wyoming, West Virginia, and Virginia/Kentucky.

As with most coal-producing companies that operate in Appalachia, which include our operations in Pennsylvania, West Virginia, and Virginia/Kentucky, the great majority of our Appalachian reserves are subject to leases from third-party landowners. These leases convey mining rights to the coal producer in exchange for a percentage of gross sales in the form of a royalty payment to the lessor, subject to minimum payments. Of our Appalachian reserve holdings at December 31, 2010, 410.9 million tons of reserves were owned and required no royalty or per-ton payment to other parties. Our remaining Appalachian reserve holdings at December 31, 2010, of 1,160.9 million tons were leased and require minimum royalty and/or per-ton payments.

Our mines in Wyoming are subject to federal coal leases that are administered by the U.S. Department of Interior under the Federal Coal Leasing Amendment Act of 1976. Each lease requires diligent development of the lease within ten years of the lease award with a required coal extraction of 1.0% of the reserves within that 10-year period. At the end of the 10-year development period, the mines are required to maintain continuous operations, as defined in the applicable leasing regulations. All of our federal leases are in full compliance with these regulations. We pay to the federal government an annual rent of $3.00 per acre and production royalties of 12.5% of gross proceeds on surface mined coal. Effective October 1, 2008, the Federal Government remits 48% of royalties, rentals and any lease bonus payments to the state of Wyoming . Of our Wyoming reserve holdings at December 31, 2010, 23.5 million tons of reserves are owned and require no royalty or per-ton payments. Our remaining Wyoming reserve holdings at December 31, 2010, of 629.7 million tons were leased and were subject to the terms described above.

Our idled mine in Illinois (“Wabash”) is subject to coal leases and requires payments of minimum royalties, payable in periodic installments. We expect to continue leasing these reserves until future development is feasible. Our reserve holdings attributable to Wabash at December 31, 2010 were 28.6 million tons.

Although our coal leases have varying renewal terms and conditions, they generally last for the economic life of the reserves. According to our current mine plans, any leased reserves assigned to a currently active operation will be mined during the tenure of the applicable lease. Because the great majority of our leased or owned properties and mineral rights are covered by detailed title abstracts prepared when the respective properties were acquired by predecessors in title to us and our current lessors, we generally do not thoroughly verify title to, or maintain title insurance policies on, our leased or owned properties and mineral rights.

The following table provides the “quality” (sulfur content and average Btu content per pound) of our proven and probable coal reserves as of December 31, 2010.

			Recoverable Reserves		Sulfur Content									Average BTU
Reportable Segment	Regional Business Unit	State	Proven & Probable (1)		<1%			1.0% - 1.5%			>1.5%			>12,500			<12,500
East	Pennsylvania Services	Pennsylvania		775.3		73.6			-			701.7			775.3			-
East	AMFIRE	Pennsylvania		83.7		19.3			27.3			37.1			55.3			28.4
East	Southern West Virginia	West Virginia		96.3		94.8			1.5			-			92.5			3.8
East	Northern West Virginia	West Virginia		258.1		123.3			130.0			4.8			194.2			63.9
East	Virginia/Kentucky	Virginia, Kentucky		354.9		219.8			77.4			57.7			320.2			34.7
West	Alpha Coal West	Wyoming		653.2		653.2			-			-			-			653.2
	Totals from active operations			2,221.5		1,184.0			236.2			801.3			1,437.5			784.0
	Percentages from active operations					53	%		11	%		36	%		65	%		35	%
N/A	Kingwood (4)	West Virginia		3.4		-			0.5			2.9			3.4			-
N/A	Wabash (5)	Illinois		28.6		-			-			28.6			-			28.6
	Totals from all operations			2,253.5		1,184.0			236.7			832.8			1,440.9			812.6
	Percentages from all operations					53	%		10	%		37	%		64	%		36	%

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The following table summarizes, by regional business unit, the tonnage of our coal reserves that is assigned to our operating mines, our property interest in those reserves and whether the reserves consist of steam or metallurgical coal, as of December 31, 2010.

			Recoverable Reserves		Total Tons						Total Tons
Reportable Segment	Regional Business Unit	State	Proven & Probable (1)		Assigned (2)			Unassigned (2)			Owned			Leased			Coal Type (3)
			(In millions of tons)
East	Pennsylvania Services	Pennsylvania		775.3		175.0			600.3			403.1			372.2		Steam and Metallurgical
East	AMFIRE	Pennsylvania		83.7		34.3			49.4			3.0			80.7		Steam and Metallurgical
East	Southern West Virginia	West Virginia		96.3		44.7			51.6			0.6			95.7		Steam and Metallurgical
East	Northern West Virginia	West Virginia		258.1		70.5			187.6			1.5			256.6		Steam and Metallurgical
East	Virginia/Kentucky	Virginia, Kentucky		354.9		176.8			178.1			2.6			352.3		Steam and Metallurgical
West	Alpha Coal West	Wyoming		653.2		653.2			-			23.5			629.7		Steam
	Totals from active operations			2,221.5		1,154.5			1,067.0			434.3			1,787.2
	Percentages from active operations					52	%		48	%		20	%		80	%
N/A	Kingwood (4)	West Virginia		3.4		0.5			2.9			-			3.4		Steam and Metallurgical
N/A	Wabash (5)	Illinois		28.6		-			28.6			-			28.6		Steam and Metallurgical
	Totals from all operations			2,253.5		1,155.0			1,098.5			434.3			1,819.2
	Percentages from all operations					51	%		49	%		19	%		81	%

(1) Recoverable reserves represent the amount of proven and probable reserves that can actually be recovered taking into account all mining and preparation losses involved in producing a saleable product using existing methods under current law. The reserve numbers set forth in the table exclude reserves for which we have leased our mining rights to third parties. Reserve information reflects a coal moisture factor on an “as received” basis, which means measuring coal in its natural state and not after it has dried in a laboratory setting. We have measured all reserves on an “as received” basis. This moisture factor on our delivered coal can vary depending on the quality of coal and the processing requirements.

(2) Assigned reserves represent recoverable coal reserves that can be mined without a significant capital expenditure for mine development, whereas unassigned reserves will require significant capital expenditures to mine the reserves.

(3) Almost all of our reserves that we currently market as metallurgical coal also possess quality characteristics that would enable us to market them as steam coal.

(4) On December 3, 2008, Old Alpha announced the permanent closure of Kingwood and the mine stopped producing coal in early January 2009. Unmineable reserves were written off at December 31, 2008.

(5) The Wabash mine, an idled room-and-pillar operation, located in Wabash County, Illinois, has been on long-term idled status since April 2007. Idled facilities include a preparation plant and rail loading facility on the Norfolk Southern Railway. If conditions warrant, the mine could be re-opened with less capital investment than would be required to develop a new underground mine.

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The following map shows the locations of Alpha's properties as of December 31, 2010:

49

The following map shows the locations of Alpha's shipping points as of December 31, 2010:

See Item 1, “Business”, for additional information regarding our coal operations and properties.

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Item 3. Legal Proceedings

We are a party to a number of legal proceedings incident to our normal business activities.  While we cannot predict the outcome of these proceedings, 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.

Nicewonder Litigation

In December 2004, prior to Old Alpha’s Nicewonder acquisition in October 2005, the Affiliated Construction Trades Foundation brought an action against the West Virginia Department of Transportation, Division of Highways (“WVDOH”) and Nicewonder Contracting, Inc. ("NCI"), which became our wholly-owned indirect subsidiary as a result of the Nicewonder acquisition, in the United States District Court in the Southern District of West Virginia. The plaintiff sought a declaration that the contract between NCI and the State of West Virginia related to NCI's road construction project was illegal as a violation of applicable West Virginia and federal competitive bidding and prevailing wage laws. The plaintiff also sought an injunction prohibiting performance of the contract but has not sought monetary damages.

In September 2007, the Court ruled that the WVDOH and the Federal Highway Administration (which is now a party to the suit) could not, under the circumstances of this case, enter into a contract that did not require the contractor to pay the prevailing wages as required by the Davis-Bacon Act. In anticipation of a potential Court directive that the contract be renegotiated for such payment, for which the WVDOH had committed to reimburse NCI, we recorded a $9.0 million long-term liability for the potential obligations under the ruling and an offsetting $9.0 million long-term receivable for the recovery of these costs from the WVDOH.

On September 30, 2009, the Court issued an order that dismissed or denied for lack of standing all of the plaintiff’s claims under federal law and remanded the remaining state claims to circuit court in Kanawha County, WV for resolution. The Court also vacated portions of its September 2007 order, and held that the plaintiff lacked standing to pursue the Davis-Bacon Act claim and further concluded that no private right of action exists to challenge the absence of a provision in a contract for highway construction requiring payment of prevailing wages established by the Davis-Bacon Act. As a result of the September 30, 2009 ruling, our previously established long-term liability and offsetting long-term receivable of $9.0 million have been reversed.

On May 7, 2010, the Circuit Court of Kanawha County entered Summary Judgment in favor of NCI.  The plaintiffs filed a petition for appeal with the West Virginia Supreme Court of Appeals and the Court of Appeals accepted the appeal by order dated November 17, 2010.  A final decision on the appeal is not expected until later in 2011.

Massey Litigation

On January 29, 2011, Alpha and Massey Energy Company entered into an Agreement and Plan of Merger. Since the date of the announcement, actions have been filed in the U.S. District Court for the Eastern District of Virginia and the Delaware Court of Chancery challenging the Massey Merger. The complaints, which we believe are without merit and which we are challenging vigorously, allege, among other things, that Massey’s directors violated their fiduciary duty to Massey’s stockholders by agreeing to a price to be paid for Massey that was too low, and that Alpha aided and abetted that breach.  The complaints seek to enjoin the consumation of the Massey Merger.

Item 4. Reserved

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PART II

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

The initial public offering of Old Alpha’s common stock occurred on February 15, 2005, and its common stock was then listed on the New York Stock Exchange under the symbol “ANR.”  There was no public market for the common stock of Old Alpha prior to this date.  On July 31, 2009, after the Foundation Merger, the common stock of Foundation, the surviving company of the Foundation Merger, which was renamed Alpha Natural Resources, Inc., replaced the common stock of Old Alpha on the New York Stock Exchange listing under the symbol "ANR", and the Company's common stock has since continued to trade under the symbol "ANR".

Price range of our common stock

The following table sets forth, for the periods indicated, the high and low sales prices per share of our common stock reported in the New York Stock Exchange consolidated tape.

2010	High		Low
First Quarter	$	53.92	$	38.70
Second Quarter	$	55.70	$	32.01
Third Quarter	$	44.39	$	32.48
Fourth Quarter	$	61.07	$	41.07

2009	High		Low
First Quarter	$	22.67	$	14.73
Second Quarter	$	30.19	$	16.24
Third Quarter	$	39.46	$	22.79
Fourth Quarter	$	46.07	$	33.44

As of December 31, 2010, there were 2,158 registered holders of record of our common stock, including 173 unvested restricted stock positions. The transfer agent and registrar for our common stock is Computershare Trust Company, N.A.

Dividend Policy

We do not presently pay dividends on our common stock. Our Board of Directors periodically evaluates the initiation of dividends.

Equity Compensation Plan Information

The section of our Proxy Statement entitled “Equity Compensation Plan Information” is incorporated herein by reference.

Stock Performance Graph

The following stock performance graph compares the cumulative total return to stockholders on an annual basis on our common stock with the cumulative total return to stockholders on an annual basis on three indices, the S&P 500 Index, the Russell 3000 Index and the Russell 3000 Coal Index. In addition, the stock performance graph includes the date of the Foundation Merger.

The graph assumes that:

· you invested $100 in Old Alpha common stock and in each index at the closing price on February 15, 2005;

· all dividends were reinvested; and

· you continued to hold your investment through December 31, 2010.

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You are cautioned against drawing any conclusions from the data contained in this graph, as past results are not necessarily indicative of future performance.  The indices used are included for comparative purposes only and do not indicate an opinion of management that such indices are necessarily an appropriate measure of the relative performance of our stock.

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Repurchase of Common Stock

On May 19, 2010, the Board of Directors authorized a share repurchase program, which permits us to repurchase up to $125 million of our outstanding common stock, par value $0.01 per share (“Shares”).  The program enables us to repurchase Shares from time to time, as market conditions warrant.

The following table summarizes information about shares of common stock that were repurchased during the fourth quarter of 2010.

	Total Number of Shares Purchased (1)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Program (2)		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (000's omitted) (3)
October 1, 2010 through October 31, 2010		-	$	-		-	$	100,001
November 1, 2010 through November 30, 2010		-	$	-		-	$	100,001
December 1, 2010 through December 31, 2010		1,531	$	55.16		-	$	100,001
		1,531	$	55.16		-	$	100,001

(1) In November 2008, the Board of Directors authorized us to repurchase common shares from employees to satisfy the employees’ minimum statutory tax withholdings upon the vesting of restricted stock and performance shares. During the three months ended December 31, 2010, we repurchased 1,531 shares of common stock to satisfy the employees' minimum statutory tax withholdings.

(2)  On May 19, 2010, the Board of Directors authorized us to repurchase up to $125 million of common shares.

(3) We cannot estimate the number of shares that will be repurchased because decisions to purchase are based on company outlook, business conditions and current investment opportunity.

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Item 6. Selected Financial Data

The following table presents selected financial and other data for the most recent five fiscal periods. The selected financial data as of December 31, 2010 and 2009, and for the years ended December 31, 2010, 2009 and 2008 have been derived from the audited Consolidated Financial Statements and related Notes thereto of Alpha Natural Resources, Inc. and subsidiaries included in this Annual Report on Form 10-K. You should read the following table in conjunction with the Consolidated Financial Statements and related Notes thereto included elsewhere in this Annual Report on Form 10-K and “Management's Discussion and Analysis of Financial Condition and Results of Operations”.

On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings, Inc. (“Foundation”) merged (the “Foundation Merger”) with Foundation continuing as the surviving legal corporation of the Foundation Merger which was renamed Alpha Natural Resources, Inc. (“Alpha”). For financial accounting purposes, the Foundation Merger was treated as a “reverse acquisition” and Old Alpha was treated as the accounting acquirer. Accordingly, Old Alpha’s financial statements became the financial statements of Alpha and Alpha’s periodic filings subsequent to the Foundation Merger reflect Old Alpha’s historical financial condition and results of operations shown for comparative purposes. Old Alpha’s results of operations for the years ended December 31, 2008, 2007 and 2006 do not include financial results for Foundation. For the year ended December 31, 2009, Foundation’s financial results are included for the five month period from August 1, 2009 through December 31, 2009.

The results of operations for the historical periods included in the following table are not necessarily indicative of the results to be expected for future periods. In addition, see Item 1A “Risk Factors” of this Annual Report on Form 10-K for a discussion of risk factors that could impact our future results of operations.

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	Alpha Natural Resources, Inc. and Subsidiaries
	Years Ended December 31,
	2010			2009			2008			2007			2006
	(In thousands)
Statements of Operations Data:
Revenues:
Coal revenues	$	3,497,847		$	2,210,629		$	2,140,367		$	1,558,665		$	1,608,170
Freight and handling revenues		332,559			189,874			279,853			205,086			188,366
Other revenues (1)		86,750			95,004			48,533			42,403			37,889
Total revenues		3,917,156			2,495,507			2,468,753			1,806,154			1,834,425
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)		2,566,825			1,616,905			1,627,960			1,284,840			1,269,910
Gain on sale of coal reserves		-			-			(12,936	)		-			-
Freight and handling costs		332,559			189,874			279,853			205,086			188,366
Other expenses		65,498			21,016			91,461			22,725			23,011
Depreciation, depletion and amortization		370,895			252,395			164,969			153,987			135,878
Amortization of acquired coal supply agreements, net		226,793			127,608			-			-			-
Selling, general, and administrative expenses (exclusive of depreciation and amortization shown separately above)		180,975			170,414			71,923			58,485			67,952
Total costs and expenses		3,743,545			2,378,212			2,223,230			1,725,123			1,685,117
Income from operations		173,611			117,295			245,523			81,031			149,308
Other income (expense):
Interest expense		(73,463	)		(82,825	)		(39,812	)		(40,366	)		(41,774	)
Interest income		3,458			1,769			7,351			2,266			839
Loss on early extinguishment of debt		(1,349	)		(5,641	)		(14,702	)		-			-
Gain on termination of Cliffs' merger, net		-			-			56,315			-			-
Miscellaneous (expense) income, net		(821	)		3,186			(3,834	)		(93	)		522
Total other (expense) income, net		(72,175	)		(83,511	)		5,318			(38,193	)		(40,413	)
Income from continuing operations before income taxes		101,436			33,784			250,841			42,838			108,895
Income tax (expense) benefit		(4,218	)		33,023			(52,242	)		(9,965	)		21,705
Income from continuing operations (2)	$	97,218		$	66,807		$	198,599		$	32,873		$	130,600

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	Years Ended December 31,
	2010			2009			2008			2007			2006
Earnings Per Share Data:
Basic earnings (loss) per common share:
Income from continuing operations attributable to Alpha Natural Resources, Inc.	$	0.81		$	0.74		$	2.90		$	0.51		$	2.04
Loss from discontinued operations attributable to Alpha Natural Resources, Inc.		(0.01	)		(0.10	)		(0.48	)		(0.08	)		(0.04	)
Net income per basic share attributable to Alpha Natural Resources, Inc.	$	0.80		$	0.64		$	2.42		$	0.43		$	2.00
Diluted earnings (loss) per common share:
Income from continuing operations attributable to Alpha Natural Resources, Inc.	$	0.80		$	0.73		$	2.83		$	0.51		$	2.04
Loss from discontinued operations attributable to Alpha Natural Resources, Inc.		(0.01	)		(0.10	)		(0.47	)		(0.08	)		(0.04	)
Net income per diluted share attributable to Alpha Natural Resources, Inc.	$	0.79		$	0.63		$	2.36		$	0.43		$	2.00

	Years Ended December 31,
	2010			2009			2008			2007			2006
	(In thousands)
Balance sheet data (at period end):
Cash and cash equivalents	$	554,772		$	465,869		$	676,190		$	54,365		$	33,256
Working capital	$	928,691		$	592,403		$	729,829		$	157,147		$	116,464
Total assets (3)	$	5,179,283		$	5,120,343		$	1,709,838		$	1,210,914		$	1,145,793
Notes payable and long-term debt, including current portion, net (4)	$	754,151		$	790,253		$	451,315		$	446,913		$	445,651
Stockholders' equity (5)	$	2,656,036		$	2,591,289		$	795,692		$	380,836		$	344,049
Statement of cash flows data:
Net cash provided by (used in):
Operating activities	$	693,601		$	356,220		$	458,043		$	225,741		$	210,081
Investing activities	$	(508,497	)	$	(281,810	)	$	(77,625	)	$	(165,203	)	$	(160,046	)
Financing activities	$	(96,201	)	$	(284,731	)	$	241,407		$	(39,429	)	$	(56,401	)
Capital expenditures	$	(308,864	)	$	(187,093	)	$	(137,751	)	$	(126,381	)	$	(131,943	)

EBITDA from continuing operations is calculated as follows (unaudited, in thousands):

	Years Ended December 31,
	2010			2009			2008			2007			2006
	(In thousands)
Income from continuing operations	$	97,218		$	66,807		$	198,599		$	32,873		$	130,600
Interest expense		73,463			82,825			39,812			40,366			41,774
Interest income		(3,458	)		(1,769	)		(7,351	)		(2,266	)		(839	)
Income tax expense (benefit)		4,218			(33,023	)		52,242			9,965			(21,705	)
Depreciation, depletion, and amortization		370,895			252,395			164,969			153,987			135,878
Amortization of acquired coal supply agreements, net		226,793			127,608			-			-			-
EBITDA from continuing operations (6)	$	769,129		$	494,843		$	448,271		$	234,925		$	285,708

(1) Other revenues for 2009 include $18.1 million for the modification of a coal supply agreement.

(2) Income from continuing operations for 2009 includes the following significant amounts from the Foundation Merger: Total revenues-$716.8 million; Cost of coal sales-$467.5 million; Depreciation, depletion and amortization-$101.4 million; Amortization of acquired coal supply agreements-$127.6 million; Selling, general and administrative expenses-$34.7 million; and Interest expense-$21.4 million. See Note 19 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

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(3) Total assets as of December 31, 2009 included the addition of the following significant assets acquired in the Foundation Merger: $1.8 billion of owned and leased mineral rights; $716.7 million of property and equipment, $529.5 million of coal supply agreements and $361.9 million of goodwill. See Note 19 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

(4) Long-term debt, including current portion and debt discount as of December 31, 2009 includes $595.8 million, net of debt discount, assumed in the Foundation Merger. See Note 19 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

(5) Stockholders’ equity as of December 31, 2009, includes approximately $1.7 billion related to the issuance of common shares and other equity consideration for the acquisition of Foundation. See Note 19 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K.

(6) EBITDA from continuing operations is defined as income from continuing operations attributable plus interest expense, income tax expense (benefit), depreciation, depletion and amortization and amortization of acquired coal supply agreements, net, less interest income. EBITDA from continuing operations is a non-GAAP measure used by management to measure operating performance, and management also believes it is a useful indicator of our ability to meet debt service and capital expenditure requirements. Because EBITDA from continuing operations is not calculated identically by all companies, our calculation may not be comparable to similarly titled measures of other companies.

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

The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and related Notes thereto included elsewhere in this Annual Report on Form 10-K.

Explanatory Note

On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings, Inc. (“Foundation”) merged (the “Foundation Merger”) with Foundation continuing as the surviving legal corporation of the Foundation Merger which was renamed Alpha Natural Resources, Inc. (“Alpha”). For financial accounting purposes, the Foundation Merger was treated as a “reverse acquisition” and Old Alpha was treated as the accounting acquirer.  Accordingly, Old Alpha’s financial statements became the financial statements of Alpha and Alpha’s periodic filings subsequent to the Foundation Merger reflect Old Alpha’s historical financial condition and results of operations shown for comparative purposes.  Old Alpha’s results of operations for the year ended December 31, 2008 do not include financial results for Foundation. For the year ended December 31, 2009, Foundation’s financial results are included for the five month period from August 1, 2009 through December 31, 2009.

Unless we have indicated otherwise, or the context otherwise requires, references in this report to “Alpha,” “we,” “us” and “our” or similar terms are to Alpha and its consolidated subsidiaries in reference to dates subsequent to the Foundation Merger and to Old Alpha and its consolidated subsidiaries in reference to dates prior to the Foundation Merger.

Overview

We are one of America’s premier coal suppliers, ranked third largest among publicly-traded U.S. coal producers as measured by consolidated 2010 revenues of $3.9 billion. We are the nation’s leading supplier and exporter of metallurgical coal for use in the steel-making process and a major supplier of thermal coal to electric utilities and manufacturing industries across the country. We operate 66 mines and 13 coal preparation facilities in Northern and Central Appalachia and the Powder River Basin, with approximately 6,500 employees.

We produce, process, and sell steam and metallurgical coal from six business units located throughout Virginia, West Virginia, Kentucky, Pennsylvania, and Wyoming. We also sell coal produced by others, the majority of which we process and/or blend with coal produced from our mines prior to resale, providing us with a higher overall margin for the blended product than if we had sold the coals separately. Our sales of steam coal in 2010 and 2009 accounted for approximately 86% and 83%, respectively, of our annual coal sales volume, and our sales of metallurgical coal in 2010 and 2009, which generally sells at a premium over steam coal, accounted for approximately 14% and 17%, respectively, of our annual coal sales volume.

Our sales of steam coal during 2010 and 2009 were made primarily to large utilities and industrial customers throughout the United States, and our sales of metallurgical coal during 2010 and 2009 were made primarily to steel companies in the Northeastern and Midwestern regions of the United States and in several countries in Europe, Asia and South America. Approximately 34% and 31% of our total revenues in 2010 and 2009, respectively, were derived from sales made outside the United States, primarily in Brazil, India, Italy, Belgium and Turkey.

In addition, we generate other revenues from equipment and parts sales and repair, Dry Systems Technologies equipment and filters, road construction, rentals, commissions, coal handling, terminal and processing fees, coal and environmental analysis fees, royalties, override royalty payments from a coal supply agreement now fulfilled by another producer, fees to transload coal through our Rivereagle facility on the Big Sandy River and the sale of coalbed methane and natural gas. We also record revenue for freight and handling charges incurred in delivering coal to certain customers, for which we are reimbursed by our customers. As such, freight and handling revenues are offset by equivalent freight and handling costs and do not contribute to our profitability.

Our primary expenses are for operating supply costs, repair and maintenance expenditures, cost of purchased coal, royalties, current wages and benefits, postretirement and post employment benefits, freight and handling costs, and taxes incurred in selling our coal. Historically, our cost of coal sales per ton is lower for sales of our produced and processed coal than for sales of purchased coal that we do not process prior to resale.

We have two reportable segments, Eastern Coal Operations and Western Coal Operations. Eastern Coal Operations consists of our operations in Northern and Central Appalachia, our coal brokerage activities and our road construction business. Western Coal Operations consists of two Powder River Basin mines in Wyoming. Our All Other category includes an idled underground mine in Illinois; expenses associated with certain closed mines; Dry Systems Technologies; revenues and royalties from the sale of coalbed methane and natural gas extraction; equipment sales and repair operations; terminal services; the leasing of mineral rights; general corporate overhead and corporate assets and liabilities.

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On January 1, 2009, Old Alpha retrospectively applied accounting guidance to separately account for the liability and equity components of its 2.375% convertible notes due 2015 in a manner reflective of its nonconvertible debt borrowing rate. The deferred loan fees and debt discount are being amortized and accreted, respectively, over the term of the convertible notes. Interest expense of $12.7 million and $11.7 million was recorded for the years ended December 31, 2010 and 2009, respectively, related to amortization of the deferred loan fees and accretion of the debt discount.

Business Developments

In addition to the Foundation Merger completed on July 31, 2009, recent business developments included the following:

On January 29, 2011, Alpha and Massey Energy Company (“Massey”) announced that they signed a definitive agreement under which we will acquire all outstanding shares of Massey common stock, subject to customary closing conditions including stockholder approval of both companies and customary regulatory approvals (the “Massey Merger”). Under the terms of the agreement, Massey stockholders will receive, upon the consummation of the Massey Merger, 1.025 shares of Alpha common stock and $10.00 in cash for each share of Massey common stock. Upon consummation of the Massey Merger, Alpha and Massey stockholders will own approximately 54% and 46% of the combined company, respectively. The Massey Merger will bring together Alpha’s and Massey’s highly complementary assets, which include more than 110 mines a nd combined coal reserves of approximately 5 billion tons, including one of the world’s largest and highest-quality metallurgical coal reserve bases.

We control approximately 20,000 acres of Marcellus Shale natural gas holdings in southwest Pennsylvania in one of the Marcellus’ most productive regions. During 2010, we entered into a 50/50 joint venture with Rice Energy, LP to develop a portion of these holdings.

In November, 2010, we announced the idling of the Moss #3 preparation plant and recorded charges of approximately $2.1 million and $0.6 million for asset impairments and estimated severance and medical benefit continuation costs, respectively.

Excelven Pty Ltd. During 2008, Old Alpha recorded an impairment charge of $4.5 million to write off the total remaining value of our 24.5% interest in Excelven Pty Ltd. (“Excelven”) because it had exhausted all reasonable efforts to obtain a mining permit from the Venezuelan government and concluded that it is no longer reasonable to assume that a permit will be granted. Excelven, through its subsidiaries, controls the rights to the Las Carmelitas mining venture in Venezuela.

Kingwood Mining Company, LLC. During 2008, Old Alpha announced the permanent closure of the Whitetail Kittanning Mine, an adjacent coal preparation plant and other ancillary facilities. The mine stopped producing coal in early January 2009 and Kingwood ceased equipment recovery operations in April 2009. The decision resulted from adverse geologic conditions and regulatory requirements that rendered the coal seam unmineable at this location. During 2008, Old Alpha recorded a charge of $30.2 million, which includes asset impairment charges of $21.2 million, write-off of advance mining royalties that were deemed unrecoverable of $3.8 million, severance and other employee benefit costs of $3.6 million and increased reclamation obligations of $1.9 million. The results of operations for Kingwood have been reported as discontinued operations for all periods presented.

Cliffs Natural Resources, Inc. Proposed Merger. During 2008, Old Alpha entered into a definitive merger agreement pursuant to which, and subject to the terms and conditions thereof, Cliffs Natural Resources Inc. (formerly known as Cleveland Cliffs Inc.) (“Cliffs”) would acquire all of its outstanding shares. On November 3, 2008, Old Alpha commenced litigation against Cliffs by filing an action in the Delaware Court of Chancery to obtain an order requiring Cliffs to hold its shareholder meeting as scheduled. On November 17, 2008, Old Alpha and Cliffs mutually terminated the merger agreement and settled the litigation. The terms of the settlement agreement included a $70.0 million payment from Cliffs to Old Alpha which, net of transaction costs, resulted in a ga in of $56.3 million in 2008.

Sale of Mineral Reserves. During 2008, Old Alpha sold approximately 17.6 million tons of underground coal reserves at its Enterprise operations to a private coal producer for approximately $13.0 million in cash. Old Alpha recognized a gain of $12.9 million from the sale in 2008.

Gallatin Materials LLC.During 2008, Old Alpha sold its interest in Gallatin for cash in the amount of $45.0 million and recorded a gain on the sale of $13.6 million.  The proceeds were used in part to repay the Gallatin loan facility outstanding with NedBank Limited in the amount of $18.2 million. An escrow balance of $4.5 million was established and Old Alpha agreed to indemnify and guarantee the buyer against breaches of representations and warranties in the sale agreement and contingencies that may have existed at closing and materialize within one year from the date of the sale.  As of December 31, 2009, all outstanding obligations had been satisfied and the balance of the escrow account had been released. The results of operations for Gallatin have been reported as discontinued operations for all periods presented.

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Dominion Terminal Associates (DTA). During 2008, Old Alpha’s subsidiary, Alpha Terminal Company, LLC, increased its equity ownership position in DTA from approximately 33% to approximately 41% by making an additional investment of $2.8 million.  DTA is a 20 million-ton annual capacity coal export terminal located in Newport News, Virginia. Our coal export and terminal capacity through DTA is approximately 8.0 million tons annually.

Coal Pricing Trends, Uncertainties and Outlook

Our long-term outlook for the coal markets in the U.S. remains positive. The Energy Information Administration (“EIA”) in its 2011 Annual Energy Outlook forecasts that coal-fired electrical generation will decrease by an average annual rate of 0.6% through 2015. In 2010, however, the EIA estimates that electric power generation from coal increased by 5% compared to 2009 as overall U.S. demand for electricity began to recover from recession lows experienced in 2009. Long-term demand for coal and coal-based electricity generation in the U.S. will likely be driven by various factors such as the economy, increasing population, increasing demand to power residential electronics and plug-in hybrid electric vehicles, public demands for affordable electricity, the inability of renewable energy sources such as wind and solar to become the base load source of electric power, geopolitical risks associated with importing large quantities of global oil and natural gas resources, increasing demand for coal outside the U.S. resulting in increased exports and the relatively abundant steam coal reserves located within the United States. As the U.S. and global economies emerge from the recent economic downturn, the International Monetary Fund’s October 2010 World Economic Outlook forecasts U.S. annual GDP to grow 2.3% and 3.0% in 2011 and 2012, respectively.

According to the National Energy Technology Laboratory’s (“NETL”) January 2011 report on new coal-fired power plants, there are 13,755 megawatts of new coal-fired electrical generation under construction in the United States and 320 megawatts of new coal-fired electrical generation capacity near construction in the United States. This total expected capacity will increase the annual coal consumption for electrical generation by an estimated forty to fifty million tons, much of which is expected to be supplied from the Powder River Basin in Wyoming. Additionally, approximately 3,280 megawatts of coal-fired electrical generation are in the permitting phase and 26,233 megawatts of coal-fired electrical generation have been announced and are in the early stages of permitting and development.

Coal exports from the U.S. increased from approximately 59 million tons in 2009 to approximately 80 million tons in 2010 in response to the worldwide economic recovery. Export volumes were similar to the historic levels experienced in 2008. According to the EIA’s 2010 International Energy Outlook (“IEO”), global primary energy demand is expected to grow by 49% between 2007 and 2035, with coal demand rising most in absolute terms and fossil fuels accounting for most of the increase in demand between now and 2035. The IEO estimates that 86% of the increase in total energy demand will come from non-OECD (Organisation for Economic Co-operation and Development) nations. In total, coal use is expected to grow by 56% by 2035 with China and India accounting for 85% of the increase. The IEO has reached a general conclusion that dependence on coal for power rises strongly in countries with emerging economies and relatively large coal reserves, while it stagnates in the more developed nations and nations with smaller coal reserves.

Ultimately, the global demand for and use of coal may be limited by any global treaties which place restrictions on carbon dioxide emissions. As part of the United Nations Framework Convention on Climate Change, representatives from 187 nations, including the U.S., met in Bali, Indonesia in December 2007 to discuss a program to limit greenhouse gas emissions after 2012. The convention adopted the “Bali Road Map” that detailed a two-year process to finalizing a binding agreement in Copenhagen in 2009. In December 2009 participants gathered in Copenhagen to develop a framework for climate change mitigation beyond 2012. The principal output of the Copenhagen summit was the Copenhagen Accord, a document that is neither legally binding nor voted upon nor signed, but was simply “noted” by the 194 participating countries . The ensuing UN Framework Convention on Climate Change held in Cancun in December 2010 resulted in an agreement that pushes most of the important decisions to future negotiations. Although the results from the Copenhagen and Cancun summits were considered modest by many participants, the ultimate outcome of future summits, and any treaty or other arrangement ultimately adopted by the United States or other countries, may have a material adverse impact on the global demand for and supply of coal. This is particularly true if cost effective technology for the capture and storage of carbon dioxide is not sufficiently developed.

Proposed coal-fired electric generating facilities that do not include technologies to capture and store carbon dioxide are facing increasing opposition from environmental groups as well as state and local governments, which are concerned with global climate change and uncertain financial impacts of potential greenhouse gas regulations. Coal-fired generating plants incorporating carbon dioxide capture and storage technologies will be more expensive to build than conventional pulverized coal generating plants and the technologies are still in the developmental stages. This dynamic may cause power generating companies to cut back on plans to build coal-fired plants in the near term. Nevertheless, the desire to attain U.S. energy independence suggests the construction of new coal-fired generating facilities is likely to remain a viable opti on. This desire, coupled with heightened interest in coal gasification and coal liquefaction, is a potential indicator of increasing demand for coal in the United States.

Based on weekly coal production reporting through December 31, 2010 from the EIA, year-over-year Appalachian production declined by approximately 0.9% due to regulatory impacts on mining and increased costs. Compared to 2009, Western coal production decreased by approximately 1.3% in 2010. In Central Appalachia, delays with respect to permits to construct valley fills at surface mines are likely to slow the permitting process for surface mining in that region with resultant uncertainties for producers. Increased MSHA mine inspection activity may also impact production levels. Average spot market prices for 2010 for Central Appalachian and Northern Appalachian coals increased by approximately 25% and 21%, respectively, compared to 2009 prices. Average spot market prices for Powder River Basin coal increased by approximately 34% from the p revious year, with the Basin offering the least expensive fossil fuel on a dollar per Btu basis. Long-term, the delicate balance of coal supply and increasing coal demand is expected to result in strong, but potentially volatile fundamentals for the U.S. coal industry.

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Our revenues depend on the price at which we are able to sell our coal and the cost of mining the coal. The pricing environment for U.S. steam coal production in 2010 has recovered significantly from the low levels experienced in 2009. Recent steam coal market conditions indicate that supply and demand have largely come into balance and the forecasted upswing in demand may result in improved prices for suppliers. Prices for high quality metallurgical coal, used to manufacture coke for steelmaking, strengthened in 2010 in response to increased worldwide demand for steel. Continued strong global demand for steel, particularly in China, and limited metallurgical coal supply, have created market conditions that we believe may signal increasing prices in 2011.

The worldwide economic slowdown and the volatility and uncertainty in the credit markets seen through much of the past two years began to ease in 2010. Global energy fundamentals, including the return of electricity demand and increased steel production have supported increased spot prices for coal in the marketplace. Steel manufacturers had shut-in significant capacity in 2009 due to the lack of near-term visibility but have since added back significant production capacity to meet increased global demand for steel for construction, automobile manufacturing and other down-stream products. We believe continued recovery from the global recession, increased steel plant utilization and supply disruptions due to adverse weather in Australia may contribute to a strong global market for metallurgical coal in 2011. However, depressed natural gas prices are placing competitive pressure on steam coal. A weak economic recovery could slacken demand for metallurgical and steam coals and could negatively influence pricing in the near-term. Longer-term, coal industry fundamentals remain intact and significant additional growth is expected worldwide. Seaborne coal is expected to grow significantly as developing nations rely heavily on coal for their power needs. U.S. exports will be needed to help meet the anticipated increase in worldwide coal demand. We believe these factors should lead to stronger demand for coal, both globally and in the United States, in the coming years.

Our results of operations are dependent upon the prices we obtain for our coal as well as our ability to improve productivity and control costs. Principal goods and services we use in our operations include maintenance and repair parts and services, electricity, fuel, roof control and support items, explosives, tires, conveyance structure, ventilation supplies and lubricants.

Our management continues to aggressively control costs and strives to improve operating performance to mitigate external cost pressures. We have experienced volatility in operating costs related to fuel, explosives, steel, tires, contract services and healthcare and have taken measures to mitigate the increases in these costs at all operations. We have a centralized sourcing group for major supplier contract negotiation and administration, for the negotiation and purchase of major capital goods, and to support the business units. The supplier base has been relatively stable for many years, but there has been some consolidation. We are not dependent on any one supplier in any region. We promote competition between suppliers and seek to develop relationships with suppliers that focus on lowering our costs. We seek suppliers who identify an d concentrate on implementing continuous improvement opportunities within their area of expertise. To the extent upward pressure on costs exceeds our ability to realize sales increases, or if we experience unanticipated operating or transportation difficulties, our operating margins would be negatively impacted. Employee labor costs have historically increased primarily due to the demands associated with attracting and retaining a workforce; however, recent stability in the marketplace has helped ease this situation. We may also continue to experience difficult geologic conditions, delays in obtaining permits, labor shortages, unforeseen equipment problems and shortages of critical materials such as tires and explosives that may result in adverse cost increases and limit our ability to produce at forecasted levels.

For additional information regarding some of the risks and uncertainties that affect our business, see Item 1A “Risk Factors.”

Results of Operations

As noted previously, the financial results for the year ended December 31, 2009 include only five months of operations related to the acquired operations of Foundation due to the timing of the closing of the Foundation Merger on July 31, 2009 and therefore, the year-over-year results are not comparable. To help understand the operating results for the full year, the term “Foundation operations” refers to the results of Foundation on a stand-alone basis for the year ended December 31, 2010 and for the five month period from August 1, 2009 through December 31, 2009 and the term “legacy Alpha operations” refers to the results of Old Alpha on a stand-alone basis for the years ended December 31, 2010 and 2009. Additionally, the Foundation operations and legacy Alpha operations stand-alone results presented herein are n ot necessarily the results that would have been achieved as separate entities due to certain intercompany allocations of the combined company and the overall integration of the two companies since the Foundation Merger. Unless specifically indicated otherwise, all amounts discussed in the following analysis of results of operations relate to amounts from continuing operations.

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EBITDA from continuing operations is calculated as follows:

	Years Ended December 31,
	2010			2009			2008
	(In thousands)
Income from continuing operations	$	97,218		$	66,807		$	198,599
Interest expense		73,463			82,825			39,812
Interest income		(3,458	)		(1,769	)		(7,351	)
Income tax expense (benefit)		4,218			(33,023	)		52,242
Depreciation, depletion, and amortization		370,895			252,395			164,969
Amortization of acquired coal supply agreements, net		226,793			127,608			-
EBITDA from continuing operations	$	769,129		$	494,843		$	448,271

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

Summary

Total revenues increased $1,421.6 million, or 57%, for the year ended December 31, 2010 compared to the prior year period. The increase in total revenues was due to increased coal revenues of $1,287.2 million and increased freight and handling revenues of $142.7 million, partially offset by decreased other revenues of $8.3 million. The increase in coal revenues consisted of an increase of $1,198.4 million, or 175%, from the Foundation operations as a result of their inclusion for the full year in 2010 and an increase of $88.8 million, or 6%, from the legacy Alpha operations. The increase in freight and handling revenues consisted of an increase of $137.9 million from the legacy Alpha operations and an increase of $4.8 million from the Foundation operations. The decrease in other revenues consisted of a decrease of $16 .8 million from the legacy Alpha operations, partially offset by an increase of $8.5 million from the Foundation operations.

Income from continuing operations increased $30.4 million, or 46%, for the year ended December 31, 2010 compared to the prior year period. The increase was largely due to increased coal revenues of $1,287.2 million and a decrease in other income (expense), net, of $11.3 million, partially offset by increased certain operating costs and expenses of $1,222.6 million, a $37.2 million increase in income tax expense and decreased other revenues of $8.3 million.

The increase in certain operating costs and expenses of $1,222.6 million was due to increased cost of coal sales of $949.9 million, increased depreciation, depletion and amortization expenses of $118.5 million, increased amortization of acquired coal supply agreements of $99.2 million, increased other expenses of $44.5 million and increased selling, general and administrative expenses of $10.5 million. The increase in cost of coal sales consisted of an increase of $722.9 million, or 155%, from the former Foundation operations and an increase of $227.0 million, or 20%, from the legacy Alpha operations. The increase in depreciation, depletion and amortization expenses consisted of an increase of $130.1 million from the Foundation operations, partially offset by an $11.6 million decrease from the legacy Alpha operations. The increase in oth er expenses consisted of an increase of $18.4 million from the Foundation operations and an increase of $26.1 million from the legacy Alpha operations. The increase in selling, general and administrative expenses consisted of an increase of $61.1 million from the Foundation operations partially offset by a decrease of $50.6 million from the legacy Alpha operations.

We sold 84.8 million tons of coal during the year ended December 31, 2010 compared to 47.2 million tons in the prior year period, an increase of 37.6 million tons, or 80%. The 84.8 million tons consisted of 24.0 million tons of steam coal and 11.9 million tons of metallurgical coal from our Eastern Coal Operations and 48.9 million tons of steam coal from our Western Coal Operations. The 47.2 million tons consisted of 18.3 million tons of steam coal and 8.1 million tons of metallurgical coal from our Eastern Coal Operations and 20.8 million tons of steam coal from our Western Coal Operations.

The increase in coal sales volumes of 37.6 million tons was due to increases of 28.2 million, 7.5 million and 1.3 million tons of western steam, eastern steam and metallurgical coal, respectively, from the Foundation operations and an increase of 2.4 million tons of metallurgical coal partially offset by a decrease of 1.8 million tons of eastern steam coal from the legacy Alpha operations.

The consolidated average coal sales realization per ton for the year ended December 31, 2010 was $41.22 compared to $46.84 in the prior year period. The decrease was largely attributable to the inclusion of coal sales for the full year 2010 from our Western Coal Operations, which has a substantially lower coal sales realization per ton due to the difference in pricing between coal in the Powder River Basin and coal in the eastern coal basins. The average coal sales realization per ton for metallurgical coal and eastern steam coal was $113.89 and $67.07, respectively, for the year ended December 31, 2010 compared to $98.08 and $65.30, respectively, in the prior year period. The average coal sales realization per ton for western steam coal was $10.95 for the year ended December 31, 2010 compared to $10.47 in the prior year period.

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Consolidated coal margin percentage, calculated as consolidated coal revenues less consolidated cost of coal sales (excluding cost of coal sales in our All Other segment), divided by consolidated coal revenues, was 27% for the years ended December 31, 2010 and 2009. Coal margin percentage for our Eastern and Western Coal Operations was 28% and 22%, respectively, for the year ended December 31, 2010 compared to 28% and 21%, respectively, in the prior year period. Consolidated coal margin per ton, calculated as consolidated coal sales realization per ton less consolidated cost of coal sales per ton, was $11.14 for the year ended December 31, 2010 compared to $12.65 in the prior year period. Coal margin per ton for our Eastern and Western Coal Operations was $23.09 and $2.39, respectively, for the year ended December 31, 2010 compared to $2 0.87 and $2.17, respectively, in the prior year period.

Revenues

	Year Ended				Increase
	December 31,				(Decrease)
	2010		2009		$ or Tons			%
	(Amounts in thousands, except per ton data)
Coal revenues:
Eastern steam	$	1,609,832	$	1,196,121	$	413,711			35	%
Western steam		536,064		217,187		318,877			147	%
Metallurgical		1,351,951		797,321		554,630			70	%
Freight and handling revenues		332,559		189,874		142,685			75	%
Other revenues		86,750		95,004		(8,254	)		(9	)%
Total revenues	$	3,917,156	$	2,495,507	$	1,421,649			57	%
Tons sold:
Eastern steam		24,001		18,318		5,683			31	%
Western steam		48,977		20,752		28,225			136	%
Metallurgical		11,871		8,130		3,741			46	%
Total		84,849		47,200		37,649			80	%
Coal sales realization per ton:
Eastern steam	$	67.07	$	65.30	$	1.77			3	%
Western steam	$	10.95	$	10.47	$	0.48			5	%
Metallurgical	$	113.89	$	98.08	$	15.81			16	%
Average	$	41.22	$	46.84	$	(5.62	)		(12	)%

Coal revenues. Coal revenues increased $1,287.2 million, or 58%, for the year ended December 31, 2010 compared to the prior year period. The increase in coal revenues consisted of an increase in metallurgical coal revenues of $554.6 million, an increase in eastern steam coal revenues of $413.7 million and an increase in western steam coal revenues of $318.9 million.

The increase in metallurgical coal revenues was largely due to an increase in tons shipped and coal sales realization per ton. Metallurgical tons shipped increased 3.7 million, or 46%, compared to the prior year period and consisted of an increase of 1.3 million tons from the Foundation operations and an increase of 2.4 million tons from the legacy Alpha operations. The increase in metallurgical tons shipped reflects an increase in demand for coking coal from steel producers in the year ended December 31, 2010 compared to the prior year period and the inclusion of the Foundation operations for the full year 2010. Coal sales realization per ton for metallurgical coal increased $15.81, or 16%, compared to the prior year period as a result of increased pricing due to stronger demand.

The increase in eastern steam coal revenues was largely due to an increase in tons shipped and a 3% increase in average coal sales realization. Eastern steam tons shipped increased 5.7 million, or 31%, compared to the prior year period and consisted of an increase of 7.5 million tons from the Foundation operations partially offset by a decrease of 1.8 million tons from the legacy Alpha operations. The increase from the Foundation operations reflects the inclusion of the Foundation operations for the full year 2010. The decrease from the legacy Alpha operations was due primarily to a mix shift of mining additional metallurgical tons in response to the increase in demand for those tons.

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The increase in western steam coal revenues was due to an increase in tons shipped and average coal sales realization per ton. Tons shipped increased 28.2 million primarily due to the inclusion of the Foundation operations for the full year 2010. Coal sales realization per ton increased $0.48, or 5%, compared to the prior year period as a result of increased pricing on contracted tons shipped.

Our sales mix of metallurgical coal and steam coal based on volume for the year ended December 31, 2010 was 14% and 86%, respectively, compared with 17% and 83% in the prior year period. Our sales mix of metallurgical coal and steam coal based on coal revenues for the year ended December 31, 2010 was 39% and 61%, respectively, compared with 36% and 64% in the prior year period.

Freight and handling revenues. Freight and handling revenues were $332.6 million for the year ended December 31, 2010, an increase of $142.7 million, or 75%, compared to the prior year period. The increase was due to higher export and domestic shipments combined with higher shipping rates compared to the prior year period. These revenues are offset by equivalent costs and do not contribute to our profitability.

Other revenues. Other revenues decreased $8.3 million, or 9%, for the year ended December 31, 2010 compared to the prior year period. The decrease consisted of a decrease of $16.8 million from the legacy Alpha operations partially offset by an increase of $8.5 million from the Foundation operations. The decrease from the legacy Alpha operations was due to a decrease in road construction revenues of approximately $24.2 million due to a loss on a construction contract and decreased revenues related to mark-to-market adjustments to coal sales contracts that are reported at fair value, partially offset by increases in royalties, coal processing and other miscellaneous revenues. The increase from the Foundation operations was largely due to the inclusion of the Foundation operations for the full year 2010 and consisted of increased revenues related to Dry Systems Technologies, increased revenues and royalties related to our coalbed methane and natural gas extraction activities, partially offset by decreased other miscellaneous revenues of $18.1 million related to a coal supply agreement modification in 2009.

Costs and Expenses

	Year Ended				Increase
	December 31,				(Decrease)
	2010		2009		$			%
	(Amounts in thousands, except per ton data)
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	$	2,566,825	$	1,616,905	$	949,920			59	%
Freight and handling costs		332,559		189,874		142,685			75	%
Other expenses		65,498		21,016		44,482			212	%
Depreciation, depletion and amortization		370,895		252,395		118,500			47	%
Amortization of acquired coal supply agreements, net		226,793		127,608		99,185			78	%
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)		180,975		170,414		10,561			6	%
Total costs and expenses	$	3,743,545	$	2,378,212	$	1,365,333			57	%
Cost of coal sales per ton:
Eastern coal operations	$	59.47	$	54.50	$	4.97			9	%
Western coal operations	$	8.56	$	8.30	$	0.26			3	%
Average	$	30.08	$	34.19	$	(4.11	)		(12	)%

Cost of coal sales. Cost of coal sales increased $949.9 million, or 59%, for the year ended December 31, 2010 compared to the prior year period. The increase consisted primarily of increases in wages and employee benefits, operating supplies, maintenance and repair, purchased coal expenses, outside services, royalties and production and severance taxes. These increases were largely due to the inclusion of the Foundation operations for the full year 2010, which increased by $722.9 million. Additionally, cost of coal sales included non-recurring charges of approximately $15.5 million related to aligning vacation and retirement benefits company-wide and asset impairment charges of approximately $2.7 million related to the idling of the Moss #3 preparation plant. The legacy Alpha opera tions increased $227.0 million compared to the prior year period. The consolidated average cost of coal sales per ton was $30.08 compared to $34.19 in the prior year period. The average cost of coal sales per ton for Eastern and Western Coal Operations was $59.47 and $8.56, respectively, compared to $54.50 and $8.30, respectively, in the prior year period. The increase in cost of coal sales per ton at our Eastern Operations was largely due to an increase in production of higher cost metallurgical tons as a result of responding to the increase in demand for metallurgical coal and a decrease in production from our lower cost longwall mines due to difficult geological conditions, the impact of our miner vacation schedule, which impacted the current year period more as a result of the inclusion of the Foundation operations for the full year 2010, and a longwall move that began in August 2010. Additionally, we experienced certain weather-related delays and railroad performance issues in the later part of the year that contributed to the increase in cost per ton in the East. An increase in purchased coal volumes also contributed to the increase in cost of coal sales per ton for the Eastern Coal Operations.

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Freight and handling costs. Freight and handling costs increased $142.7 million, or 75%, compared to the prior year period. The increase was due to higher export and domestic shipments combined with higher shipping rates compared to the prior year period. These costs are offset by equivalent revenues and do not contribute to our profitability.

Other expenses. Other expenses increased $44.5 million, or 212%, for the year ended December 31, 2010 compared to the prior year period. The increase was due to increased other expenses of $18.4 million from the Foundation operations and $26.1 million from the legacy Alpha operations. Other expenses generally consist of mark-to-market gains and losses on derivatives swap contracts that are not designated as cash flow hedges and expenses associated with our road construction, Dry Systems Technologies and coalbed methane and natural gas extraction activities. The increase in other expenses from the legacy Alpha operations was largely due to mark-to-market gains recorded in earnings during 2009 for derivative instruments that have since been designated as cash flow hedges and for whic h changes in fair value are now recorded as a part of accumulated other comprehensive (loss) income. The increase in other expenses from the Foundation operations was due to increases in costs related to Dry Systems Technologies and our coalbed methane and natural gas extraction activities, primarily as a result of the inclusion of these costs for the full year 2010.

Depreciation, depletion and amortization. Depreciation, depletion, and amortization increased $118.5 million, or 47%, for the year ended December 31, 2010 compared to the prior year period. The increase consisted of increased depreciation and amortization of $76.4 million primarily related to capital expenditures during the previous twelve months and increased depletion expense of $42.1 million related to increased production compared to the prior year period. These increases were largely due to the inclusion of the Foundation operations for the full year 2010 and the increase in metallurgical production which carries a higher depletion rate. Depreciation, depletion, and amortization for the Foundation operations was $231.6 million for the year ended December 31, 2010.

Amortization of acquired coal supply agreements, net. Application of acquisition accounting in connection with the Foundation Merger resulted in the recognition of a significant asset for above market-priced coal supply agreements and a liability for below market-priced coal supply agreements on the date of the acquisition. The coal supply agreement assets and liabilities are being amortized over the actual amount of tons shipped under each contract. Amortization of acquired coal supply agreements, net was $226.8 million for the year ended December 31, 2010 compared to $127.6 million in the prior year period. Amortization of acquired coal supply agreements, net for future periods is expected to be $119.5 million in 2011, $31.7 million in 2012 and a credit to expense of ($1.7 millio n) in 2013.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $10.6 million, or 6%, for the year ended December 31, 2010 compared to the prior year period. The increase in selling, general and administrative expenses consisted of an increase of $61.2 million from the Foundation operations partially offset by a decrease of $50.6 million from the legacy Alpha operations. The increase was primarily due to increased employee wages and benefits, increased severance and relocation charges, and increased other miscellaneous overhead expenses due to the inclusion of the Foundation operations for the full year 2010, partially offset by decreased merger related expenses related to legal and other outside services costs incurred for the Foundation Merger , lower expenses recorded for share-based compensation and a portion of a curtailment gain recorded during the year associated with a re-measurement of  our defined-benefit pension plan obligations as a result of a plan change due to the alignment of employee benefits company-wide. Consolidated selling, general and administrative expenses included approximately $10.2 million of expenses related to the Foundation Merger.

Interest expense. Interest expense decreased $9.4 million, or 11%, during the year ended December 31, 2010 compared to the prior year period. The decrease in interest expense was primarily related to the decreased interest expense and amortization of deferred loan fees associated with the legacy Alpha term loan that was paid off subsequent to the Foundation Merger, and a decrease in interest expense associated with the realized and unrealized losses due to the changes in fair value of the legacy Alpha interest rate swap that was de-designated as a cash flow hedge as a result of paying off the legacy Alpha term loan in July 2009, partially offset by increased interest expense associated with the long term debt assumed in the Foundation Merger that was included for the full year 2010 .

Interest income. Interest income increased by $1.7 million for the year ended December 31, 2010 compared to the prior year period primarily due to a higher average cash balance invested in marketable securities.

Loss on early extinguishment of debt. During the year ended December 31, 2010, we amended our credit facility and prepaid approximately $39.6 million of the outstanding term loan. As a result, we wrote off a portion of the deferred financing costs and recorded a loss of $1.3 million. During the year ended December 31, 2009, we paid off the legacy Alpha term loan and wrote off the remaining deferred loan fees and recorded a loss of $5.6 million.

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Income tax expense (benefit). Income tax expense from continuing operations of $4.2 million was recorded for the year ended December 31, 2010 on income from continuing operations before income taxes of $101.4 million, which equates to an effective tax rate of 4.2%. This rate is lower than the federal statutory rate of 35% due primarily to the tax benefits associated with percentage depletion and the reversal of certain tax reserves of approximately $14.0 million, partially offset by the impact of a state rate and net operating loss change and a $25.6 million deferred tax charge required for the legislative change related to the deductibility of retiree prescription drug expenses (Medicare Part D).

Income tax benefit from continuing operations of $33.0 million was recorded for year ended December 31, 2009 on income from continuing operations before income taxes of $33.8 million. The income tax benefit for 2009 was due primarily to the tax benefits associated with percentage depletion and the reversal of $22.2 million of valuation allowance that was triggered by our movement from a net deferred tax asset position to a net deferred tax liability position on our consolidated balance sheet as a result of the Foundation Merger, partially offset by non-deductible transaction costs and the impact from the interest rate swap.

Discontinued operations. Loss from discontinued operations for the year ended December 31, 2010 was $1.7 million, net of tax, compared to a loss from discontinued operations of $8.8 million, net of tax, for the year ended December 31, 2009. The loss from discontinued operations in 2010 and 2009 was related to expenses incurred for Kingwood.

Segment Analysis

The price of coal is influenced by many factors that vary by region. Such factors include, but are not limited to: (1) coal quality, which includes energy (heat content), sulfur, ash, volatile matter and moisture content; (2) transportation costs; (3) regional supply and demand; (4) available competitive fuel sources such as natural gas, nuclear or hydro; and (5) production costs, which vary by mine type, available technology and equipment utilization, productivity, geological conditions, and mine operating expenses.

The energy content or heat value of coal is a significant factor influencing coal prices as higher energy coal is more desirable to consumers and typically commands a higher price in the market. The heat value of coal is commonly measured in British thermal units or the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal from the Eastern and Midwest regions of the United States tends to have a higher heat value than coal found in the Western United States.

Powder River Basin coal, with its lower energy content, lower production cost and often greater distance to travel to the consumer, typically sells at a lower price than Northern and Central Appalachian coal that has a higher energy content and is often located closer to the end user.

	Year Ended December 31,				Increase (Decrease)
	2010		2009		Tons/$		Percent
	(In thousands, except per ton data)
Western Coal Operations
Steam tons sold		48,977		20,752		28,225		136	%
Steam coal sales realization per ton	$	10.95	$	10.47	$	0.48		5	%
Total revenues	$	544,058	$	218,613	$	325,445		149	%
EBITDA from continuing operations	$	97,583	$	39,278	$	58,305		148	%
Eastern Coal Operations
Steam tons sold		24,001		18,318		5,683		31	%
Metallurgical tons sold		11,871		8,130		3,741		46	%
Steam coal sales realization per ton	$	67.07	$	65.30	$	1.77		3	%
Metallurgical coal sales realization per ton	$	113.89	$	98.08	$	15.81		16	%
Total revenues	$	3,324,548	$	2,249,027	$	1,075,521		48	%
EBITDA from continuing operations	$	678,339	$	524,042	$	154,297		29	%

Western Coal Operations –EBITDA from continuing operations for our Western Coal Operations increased $58.3 million, or 148%, compared to the prior year period. The increase was due to increased total revenues of $325.5 million, partially offset by increased certain operating expenses of $267.2 million. The increase in total revenues consisted of increased coal and other revenues of $318.9 million and $6.6 million, respectively. The increase in coal revenues was largely due to increased tons shipped of 28.2 million, or 136%, and increased average sales realization per ton of $0.48, or 5%. The increase in certain operating expenses consisted of increased cost of coal sales of $246.8 million and a $20.4 million increase in other operating expenses. These incre ases were primarily due to the inclusion of the Western Coal Operations for the full year 2010. Cost of coal sales per ton increased $0.26, or 3%.

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Eastern Coal Operations –EBITDA from continuing operations increased $154.3 million, or 29%, compared to the prior year period. The increase was due to increased coal revenues of $968.3 million, partially offset by increased certain operating expenses of $773.3 million, decreased other revenues of $35.4 million, increased other miscellaneous expense, net of $3.9 million and a loss on early extinguishment of debt of $1.4 million. The increase in coal revenues was due to increased metallurgical and steam coal revenues of $554.6 million and $413.7 million, respectively. The increase in certain operating expenses consisted of increased cost of coal sales of $692.2 million and increased other operating expenses of $81.1 million.

The increase in metallurgical coal revenues was largely due to an increase in tons shipped and coal sales realization per ton. Metallurgical tons shipped increased 3.7 million, or 46%, compared to the prior year period and consisted of an increase of 1.3 million tons from the Foundation operations and an increase of 2.4 million tons from the legacy Alpha operations. The increase in metallurgical tons shipped reflects an increase in demand for coking coal from steel producers during 2010 compared to the prior year period and the inclusion of the Foundation operations for the full year 2010. Coal sales realization per ton for metallurgical coal increased $15.81, or 16%, compared to the prior year period as a result of increased pricing due to stronger global demand.

The increase in eastern steam coal revenues was largely due to an increase in tons shipped and a 3% increase in average sales realization per ton. Eastern steam tons shipped increased 5.7 million, or 31%, compared to the prior year period and consisted of an increase of 7.5 million tons from the Foundation operations and a decrease of 1.8 million tons from the legacy Alpha operations. The increase from the Foundation operations reflects the inclusion of the Foundation operations for the full year 2010. The decrease from the legacy Alpha operations was due to a mix shift of mining additional metallurgical tons in response to the increase in demand for those tons during the year.

The increase in cost of coal sales was due to increases in wages and employee benefits, operating supplies, maintenance and repair, purchased coal expenses, outside services, royalties and production and severance taxes, all of which experienced increases due in part to the inclusion of the Foundation operations for the full year 2010. Additionally, cost of coal sales in the East included non-recurring charges of approximately $15.3 million related to aligning vacation and retirement benefits company-wide and asset impairment charges of approximately $2.7 million related to the idling of the Moss #3 preparation plant. Cost of coal sales per ton increased $4.97, or 9%, compared to the prior year period largely due to an increase in production of higher cost metallurgical tons as a result of responding to the increase in demand for metallu rgical coal and a decrease in production from our lower cost longwall mines due to difficult geological conditions, the impact of our miner vacation schedule, which impacted the current year period more as a result of the inclusion of the Foundation operations for the full year 2010, and a longwall move that began in August of 2010. Additionally, we experienced certain weather-related delays and railroad performance issues in the later part of the year that contributed to the increase in cost per ton in the East. An increase in purchased coal volumes also contributed to the increase in cost of coal sales per ton for the Eastern Coal Operations.

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

Summary

Total revenues increased $26.8 million, or 1%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in total revenues consisted of the addition of $716.8 million in revenues from the Foundation operations, largely offset by a decrease of $690.0 million in revenues from the legacy Alpha operations. The decrease in revenues from the legacy Alpha operations was due to a decrease in coal revenues of $614.6 million, or 29%, and a $90.2 million decrease in freight and handling revenues, which are offset by an equivalent decrease in freight and handling costs, partially offset by an increase in other revenues of $14.8 million, or 31%.

Coal revenues increased $70.3 million, or 3%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in coal revenues consisted of the addition of $684.9 million in coal revenues from the Foundation operations, largely offset by a decrease in coal revenues of $614.6 million from the legacy Alpha operations. The decrease in coal revenues of $614.6 million from the legacy Alpha operations was a result of lower metallurgical coal sales volumes in addition to lower metallurgical coal sales realization per ton due to lower demand and lower contract pricing as a result of the economic recession experienced through much of 2009, partially offset by higher average steam coal sales realization per ton.

Income from continuing operations decreased $131.8 million, or 66%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The decrease was primarily due to an increase in operating costs and expenses of $155.0 million and other non-operating expenses of $88.9 million, partially offset by an increase in revenues as explained above of $26.8 million and a decrease in income tax expense of $85.3 million. The increase in operating costs and expenses of $155.0 million consisted of the addition of $737.1 million in operating costs and expenses from the Foundation operations, partially offset by a decrease of $582.1 million in operating costs and expenses related to the legacy Alpha operations. The decrease in operating costs and expenses of $582.1 million related to the legacy Alpha operations was due to decreased c ost of coal sales of $478.6 million, decreased freight and handling expenses of $90.1 million which are offset by an equivalent decrease in freight and handling revenue, decreased other expenses of $63.2 million and decreased depreciation, depletion and amortization expenses of $14.0 million, partially offset by increased selling, general and administrative expenses of $63.8 million. Operating costs and expenses related to the Foundation operations consisted of $467.5 million of cost of coal sales, $127.6 million of amortization of acquired coal supply agreements, $101.4 million of depreciation, depletion and amortization expenses, $34.7 million of selling, general and administrative expenses, $5.7 million of other miscellaneous expenses and $0.2 million of freight and handling expenses.

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We sold 47.2 million tons of coal during the year ended December 31, 2009 compared to 26.9 million tons during the year ended December 31, 2008, an increase of 20.3 million tons, or 75%. The 47.2 million tons sold during the year ended December 31, 2009 consisted of 28.2 million tons from the Foundation operations and 19.0 million tons from the legacy Alpha operations. Total coal sales volume from the legacy Alpha operations decreased 7.9 million tons, or 29%, during the year ended December 31, 2009 compared to the year ended December 31, 2008. The decrease in coal sales volume from the legacy Alpha operations consisted of a decrease in steam coal sales volume of 4.0 million tons, or 26%, and a decrease in metallurgical coal sales volume of 3.9 million tons, or 34%. The 28.2 million tons sold by the Foundation operations included 20 .8 million tons of steam coal from our Western Coal Operations and 6.8 million tons of steam coal and 0.6 million tons of metallurgical coal from our Eastern Coal Operations.

The consolidated weighted average coal sales realization per ton for the year ended December 31, 2009 was $46.84 compared to $79.58 for the year ended December 31, 2008. The decrease was largely attributable to the inclusion of the Foundation operations. The weighted average coal sales realization per ton for the legacy Alpha operations was $80.35 for the year ended December 31, 2009 compared to $79.58 for the year ended December 31, 2008. The increase in average coal sales realization per ton for the legacy Alpha operations reflected higher sales prices on steam coal sales volumes, $70.22 per ton for 2009 compared to $51.80 per ton for 2008, which were mostly offset by lower sales prices on metallurgical coal sales volumes, $95.83 per ton for 2009 compared to $117.50 per ton for 2008. The weighted average coal sales realization per ton for the year ended December 31, 2009 for the Foundation operations was $24.28, which reflects a high proportion of coal sales volumes from the Western Coal Operations at an average coal sales realization per ton of $10.47. Coal sales realization per ton for eastern steam coal was $57.06 and coal sales realization per ton for eastern metallurgical coal was $125.57 for the Foundation operations for the year ended December 31, 2009.

Consolidated coal margin percentage, calculated as consolidated coal revenues less consolidated cost of coal sales, divided by consolidated coal revenues, was 27% for the year ended December 31, 2009 compared to 24% for the year ended December 31, 2008. Coal margin percentage for the Foundation operations was 32% and coal margin percentage for the legacy Alpha operations was 25% for the year ended December 31, 2009. Consolidated coal margin per ton, calculated as consolidated coal sales realization per ton less consolidated cost of coal sales per ton, was $12.58 for the year ended December 31, 2009 compared to $19.05 for the year ended December 31, 2008. Coal margin per ton for the Foundation operations was $7.71 per ton and coal margin per ton for the legacy Alpha operations was $19.82 per ton for the year ended December 31, 2009.

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Revenues

	Years Ended				Increase
	December 31,				(Decrease)
	2009		2008		$ or Tons			%
	(in thousands, except per ton data)
Revenues:
Coal revenues:
Eastern steam	$	1,196,121	$	804,188	$	391,933			49	%
Western steam		217,187		-		217,187		NM
Metallurgical		797,321		1,336,179		(538,858	)		(40	)%
Freight and handling revenues		189,874		279,853		(89,979	)		(32	)%
Other revenues		95,004		48,533		46,471			96	%
Total revenues	$	2,495,507	$	2,468,753	$	26,754			1	%
Tons sold:
Eastern steam		18,318		15,525		2,793			18	%
Western steam		20,752		-		20,752		NM
Metallurgical		8,130		11,372		(3,242	)		(29	)%
Total		47,200		26,897		20,303			75	%
Coal sales realization per ton:
Eastern steam	$	65.30	$	51.80	$	13.50			26	%
Western steam	$	10.47		-		10.47		NM
Metallurgical	$	98.08	$	117.50	$	(19.42	)		(17	)%
Average	$	46.84	$	79.58	$	(32.74	)		(41	)%

Coal revenues. Coal revenues increased $70.3 million, or 3%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in coal revenues consisted of the addition of $684.9 million related to the Foundation operations, largely offset by a decrease of $614.6 million related to the legacy Alpha operations. The decrease of $614.6 million, or 29%, in coal revenues related to the legacy Alpha operations was due to a $615.9 million decrease in metallurgical coal revenue partially offset by a $1.3 million increase in eastern steam coal revenue. The decrease in metallurgical coal revenue related to the legacy Alpha operations was due to a decline in metallurgical coal sales volumes of 3.8 million tons and an 18% decrease in metallurgical coal sales real ization per ton, reflecting lower market pricing and lower demand for metallurgical coal from steel producers due to the economic recession experienced through much of 2009 compared to 2008. Eastern steam coal revenues related to legacy Alpha operations increased $1.3 million despite a 4.0 million ton decrease in eastern steam coal sales volumes due to a 36% increase in coal sales realization per ton related to shipments on higher priced contracts that were executed in 2008. The $684.9 million in coal revenues from the Foundation operations included $390.6 million in eastern steam coal revenues, $217.2 million in western steam coal revenues and $77.1 million in metallurgical coal revenues. Our sales mix of metallurgical coal and steam coal based on volume for the year ended December 31, 2009 was 17% and 83%, respectively, compared with 42% and 58%, respectively, for the year ended December 31, 2008. The sales mix of metallurgical coal and steam coal for the legacy Alpha operations in 2009 was 40% and 60%, re spectively, and 2% and 98%, respectively, for the Foundation operations. In 2009, approximately 36% of coal revenues were derived from the sale of metallurgical coal compared with 62% in 2008.

Freight and handling revenues. Freight and handling revenues were $189.9 million for the year ended December 31, 2009, a decrease of $90.0 million compared to the year ended December 31, 2008 due to lower export shipments combined with lower rates. These revenues are primarily related to the legacy Alpha operations and are offset by equivalent costs and do not contribute to our profitability.

Other revenue. Other revenue increased $46.5 million, or 96%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in other revenue consisted of the addition of $31.7 million from the Foundation operations and an increase of $14.8 million from the legacy Alpha operations. The increase of $14.8 million from the legacy Alpha operations was due to increased terminal fees, mark-to-market gains on derivative coal contracts and increased revenues related to our road construction business, partially offset by lower coal processing fees, lower parts and equipment sales from our Maxxim Rebuild business and lower royalty income. Other revenues of $31.7 million from the Foundation operations co nsisted of revenues related to our Dry Systems Technologies and Coal Gas Recovery businesses and $18.1 million related to a coal supply agreement modification.

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Costs and expenses

	Year Ended					Increase
	December 31,					(Decrease)
	2009		2008			$			%
	(in thousands, except per ton data)
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)	$	1,616,905	$	1,627,960		$	(11,055	)		(1	)%
Gain on sale of coal reserves		-		(12,936	)		12,936		NM
Freight and handling costs		189,874		279,853			(89,979	)		(32	)%
Other expenses		21,016		91,461			(70,445	)		(77	)%
Depreciation, depletion and amortization		252,395		164,969			87,426			53	%
Amortization of acquired coal supply agreements, net		127,608		-			127,608		NM
Selling, general and administrative expenses (exclusive of depreciation and amortization shown separately above)		170,414		71,923			98,491			137	%
Total costs and expenses	$	2,378,212	$	2,223,230		$	154,982			7	%
Cost of coal sales per ton:
Eastern coal operations	$	54.50	$	60.53		$	(6.03	)		(10	)%
Western coal operations	$	8.30	$	-		$	8.30		NM
Average	$	34.19	$	60.53		$	(26.34	)		(44	)%

Cost of coal sales. Cost of coal sales decreased $11.1 million, or 1%, in the year ended December 31, 2009 compared to the year ended December 31, 2008. The decrease in cost of coal sales in 2009 compared to 2008 consisted of a decrease of $478.6 million from the legacy Alpha operations, largely offset by the inclusion of $467.5 million from the Foundation operations. The decrease of $478.6 million in cost of coal sales related to the legacy Alpha operations was primarily due to a decrease in purchased coal expense related to 3.4 million fewer tons purchased, lower repairs and maintenance, lower operating supplies and a decrease in other variable expenses due to lower coal production as a result of the global recession experienced during most of 2009. The weighted average total cos t of coal sales per ton was $34.19 for the year ended December 31, 2009, a decrease of 44% compared to $60.53 for the year ended December 31, 2008. Cost of coal sales per ton for the legacy Alpha operations remained virtually unchanged at $60.54 despite the 7.9 million ton decrease in coal sales volumes. This is primarily due to fixed operating costs being spread over a lower amount of tons produced, which offset the reduction in variable production expenses.

The weighted average cost of coal sales per ton for the year ended December 31, 2009 for the Foundation operations was $16.29, which reflects a high proportion of coal sales volumes from the Western Coal Operations, which had an average cost of coal sales per ton of $8.30. Cost of coal sales per ton for the Eastern Coal Operations related to the Foundation operations was $38.53 for the year ended December 31, 2009.

Gain on sale of coal reserves. Gain on sale of coal reserves of $12.9 million for the year ended December 31, 2008 related to the sale of a portion of our Kentucky May underground coal reserves.

Freight and handling costs. Freight and handling costs were $189.9 million for the year ended December 31, 2009, a decrease of $90.0 million compared to the year ended December 31, 2008, due to lower export shipments combined with lower rates. These costs are primarily related to the legacy Alpha operations and are offset by equivalent revenue and do not contribute to our profitability.

Other expenses. Other expenses decreased $70.4 million, or 77%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The decrease consisted of a $76.1 million decrease in other expenses related to the legacy Alpha operations, partially offset by the addition of $5.7 million of other expenses from the Foundation operations. The decrease in other expenses related to the legacy Alpha operations was primarily due to decreased expenses related to coal contract buy-out transactions and net mark-to-market gains on derivative swap contracts recorded during the year ended December 31, 2009 compared to net mark-to-market losses recorded during the year ended December 31, 2008. Other expenses of $5.7 million related to the Foundation operations consisted of mark- to-market gains on our derivative swap agreements and expenses for our Dry Systems Technologies and coalbed methane and natural gas extraction activities.

Depreciation, depletion and amortization. Depreciation, depletion, and amortization increased $87.4 million, or 53%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase consisted of $101.4 million of depreciation, depletion and amortization expense from the Foundation operations, partially offset by a $14.0 million decrease in depreciation, depletion and amortization expense from the legacy Alpha operations. The decrease of $14.0 million from the legacy Alpha operations was due to decreased depletion expense due to lower tons produced, partially offset by a decreased credit to amortization expense related to the amortization of miscellaneous intangibles. Depreciation, depletion, and amortization of $101.4 million related to the Foundation operations consisted of $61.5 million of depreciation and amortization of property, equipment and mine development costs and $39.9 million of depletion expense.

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Amortization of acquired coal supply agreements, net. Application of acquisition accounting in connection with the Foundation Merger resulted in the recognition of a significant asset for above market-priced coal supply agreements and a liability for below market-priced coal supply agreements on the date of the acquisition. The coal supply agreement assets and liabilities are being amortized over the actual amount of tons shipped under each contract. Amortization of acquired coal supply agreements, net was $127.6 million for the year ended December 31, 2009.

Selling, general and administrative expenses. Selling, general and administrative expenses increased $98.5 million, or 137%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in selling, general and administrative expenses consisted of $34.7 million in expenses from the Foundation operations and an increase of $63.8 million related to the legacy Alpha operations. The increase of $63.8 million related to the legacy Alpha operations was due to legal and professional fees of $43.1 million primarily related to transaction, consulting and integration costs related to the Foundation Merger, increased employee compensation of $18.3 million, including a $15.7 million increase in non-cash stock-based compensation and $2.4 million of other miscel laneous expenses. Consolidated selling, general and administrative expenses for 2009 included approximately $59.0 million of expenses related to the Foundation Merger.

Interest expense. Interest expense increased $43.0 million, or 108%, during the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in interest expense consisted of the addition of $21.4 million from the Foundation operations and an increase of $21.6 million from the legacy Alpha operations. The increase of $21.6 million from the legacy Alpha operations was primarily due to $24.2 million of interest expense related to the reclassification of unrealized losses into interest expense from accumulated other comprehensive income (loss) and subsequent changes in fair value related to an interest rate swap that was de-designated as a cash flow hedge as a result of paying off a term loan related to the legacy Alpha operations shortly after the Foundation Merger. Interest expense related to the Foundation operations consisted of interest expense from the outstanding term loan due 2011, the outstanding 7.25% notes due 2014 and accretion of debt discount.

Interest income. Interest income decreased by $5.6 million, or 76%, for the year ended December 31, 2009 compared to the twelve months ended December 31, 2008 primarily due to lower interest rates realized on our invested cash as well as a lower average cash balance for the comparable period.

Loss on early extinguishment of debt. Loss on early extinguishment of debt was $5.6 million for the year ended December 31, 2009 and was related to the write-off of unamortized deferred debt issuance costs for a term loan related to the legacy Alpha operations that was paid off shortly after the Foundation Merger. Loss on early extinguishment of debt was $14.7 million for the year ended December 31, 2008 and  consisted of $10.7 million in tender offer consideration payment for the repurchase of  Old Alpha’s $175.0 million 10% senior notes and the write-off of the related unamortized deferred debt issuance costs of $4.0 million.

Net gain on termination of Cliffs’ merger. Net gain on termination of Cliffs’ merger was $56.3 million for the year ended December 31, 2008 and consisted of a $70.0 million fee Old Alpha received from Cliffs upon termination of the planned merger less $13.7 million in transaction costs, including fees paid for financial, legal and other professional fees.

Miscellaneous income (expense), net. Miscellaneous income (expense), net was $3.2 million for the year ended December 31, 2009 and ($3.8 million) for the year ended December 31, 2008. Miscellaneous expense in 2008 was primarily related to the impairment charge of $4.5 million related to Old Alpha’s equity investment in the Excelven joint venture in Venezuela.

Income tax expense (benefit). Income tax benefit from continuing operations for the year ended December 31, 2009 was $33.0 million as compared to income tax expense of $52.2 million for the year ended December 31, 2008. The income tax benefit for 2009 was due primarily to the tax benefits associated with percentage depletion and the reversal of $22.2 million of valuation allowance that was triggered by our movement from a net deferred tax asset position to a net deferred tax liability position on our consolidated balance sheet as a result of the Foundation Merger, partially offset by non-deductible transaction costs and the impact from the interest rate swap.

Our effective tax rate of 20.8% for 2008 was lower than the statutory federal tax rate due primarily to the tax benefits associated with percentage depletion, the domestic production activities deduction, and the change in the valuation allowance, partially offset by state income taxes.

The effective tax rate for 2009 was lower than the effective tax rate for 2008 mainly due to the benefits of the valuation allowance reversal and percentage depletion being larger in relation to pre-tax income. As a result of the Foundation Merger, a significant amount of the book depreciation, depletion and amortization expense does not impact the percentage depletion calculation.  Due to being in a net liability position, no valuation allowances were established against the minimum tax credit carryforwards and the federal net operating loss, much of which is created from the percentage depletion deduction.

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Discontinued operations. Loss from discontinued operations for the year ended December 31, 2009 was $8.8 million, net of tax, compared to a loss from discontinued operations of $32.9 million, net of tax, for the year ended December 31, 2008. The loss from discontinued operations of $8.8 million in 2009 was primarily related to expenses incurred for Kingwood. The $32.9 million loss in 2008 consists of losses from Kingwood of $37.1 million and income from Gallatin of $4.2 million. The $37.1 million loss from Kingwood consists of loss from operations of $49.8 million including $30.2 million in mine closure and asset impairment charges, partially offset by an income tax benefit of $12.7 million. The $4.2 million of income from Gallatin consists of a gain on the sale of Gallatin of $13.6 million, offset by losses from the operation of Gallatin of $7.8 million, net of non-controlling interest and income tax expense of $1.6 million.

Segment Analysis

The price of coal is influenced by many factors that vary by region. Such factors include, but are not limited to: (1) coal quality, which includes energy (heat content), sulfur, ash, volatile matter and moisture content; (2) transportation costs; (3) regional supply and demand; (4) available competitive fuel sources such as natural gas, nuclear or hydro; and (5) production costs, which vary by mine type, available technology and equipment utilization, productivity, geological conditions, and mine operating expenses.

The energy content or heat value of coal is a significant factor influencing coal prices as higher energy coal is more desirable to consumers and typically commands a higher price in the market. The heat value of coal is commonly measured in British thermal units or the amount of heat needed to raise the temperature of one pound of water by one degree Fahrenheit. Coal from the Eastern and Midwest regions of the United States tends to have a higher heat value than coal found in the Western United States.

Powder River Basin coal, with its lower energy content, lower production cost and often greater distance to travel to the consumer, typically sells at a lower price than Northern and Central Appalachian coal that has a higher energy content and is often located closer to the end user.

	Year Ended
	December 31,				Increase (Decrease)
	2009		2008		Tons/$			Percent
	(In thousands, except per ton data)
Western Coal Operations
Steam tons sold		20,752		-		20,752		NM
Steam coal sales realization per ton	$	10.47	$	-		10.47		NM
Total revenues	$	218,613	$	-		218,613		NM
EBITDA from continuing operations	$	39,278	$	-		39,278		NM
Eastern Coal Operations
Steam tons sold		18,318		15,525		2,793			18	%
Metallurgical tons sold		8,130		11,372		(3,242	)		(29	)%
Steam coal sales realization per ton	$	65.30	$	51.80	$	13.50			26	%
Metallurgical coal sales realization per ton	$	98.08	$	117.50	$	(19.42	)		(17	)%
Total revenues	$	2,249,027	$	2,454,702	$	(205,675	)		(8	)%
EBITDA from continuing operations	$	524,042	$	421,572	$	102,470			24	%

Western Coal Operations - Our Western Coal Operations are located in the southern Powder River Basin of Wyoming and were acquired in the Foundation Merger and therefore, we do not have reported comparative results. We operate two large open-pit mines at Belle Ayr and Eagle Butte and produce steam coal for shipment primarily to utilities. EBITDA from continuing operations for our Western Coal Operations was $39.3 million for the year ended December 31, 2009, which included $217.2 million in coal revenues and $172.2 million in cost of coal sales. Coal sales realization per ton was $10.47 and coal sales volumes were 20.8 million tons. Coal revenues and tons shipped from the Western Coal Operations have been generally affected in 2009 by weak demand in the marke tplace and transportation delays in the region.

Eastern Coal Operations – Our Eastern Coal Operations are located in Pennsylvania, West Virginia, Virginia and Kentucky and produce steam coal that is sold primarily to electric utilities and industrial customers. Our Eastern Coal Operations also produces metallurgical coal that is sold primarily to steel producers. Steam coal sales volumes from our Eastern Coal Operations increased 2.8 million tons, or 18%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in steam coal sales volumes consisted of 6.8 million tons from the Foundation operations, partially offset by a decrease of 4.0 million tons from the legacy Alpha operations. The 4.0 million decrease in steam coal sales volumes from the legacy Alpha operation s is primarily due to lower brokered coal activity and lower production due to the economic recession experienced during 2009 and to a lesser extent, severe weather conditions experienced in the fourth quarter of 2009. The Foundation operations shipped 6.8 million tons of steam coal for the year ended December 31, 2009, which included 5.4 million tons from our Pennsylvania Services business unit and 1.4 million tons from the Foundation mines included in our Northern West Virginia business unit.

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Steam coal sales realization per ton at our Eastern Coal Operations increased $13.50, or 26%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase was primarily due to an increase in steam coal sales realization per ton for the legacy Alpha operations, partially offset by lower relative steam coal sales realization per ton from the Foundation operations. Steam coal sales realization per ton for the legacy Alpha operations was $70.22, an increase of $18.42 per ton, or 36%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase was due to shipments on higher priced contracts that were executed primarily during a period in 2008 when market prices for steam coal were more favorable as compared to the pricing in the contracts included in the 2008 coal sales vo lumes. The average coal sales realization per ton for the Foundation operations was $57.06 per ton, which included coal sales realization per ton of $53.24 from our Pennsylvania Services business unit and $72.17 from the Foundation mines included in our Northern West Virginia business unit.

Metallurgical coal sales volumes from our Eastern Coal Operations decreased 3.2 million tons, or 29%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The decrease in metallurgical coal sales volumes consisted of a decrease of 3.8 million tons from the legacy Alpha operations, partially offset by 0.6 million tons shipped from the Foundation operations. The 3.8 million decrease in metallurgical coal sales volumes from the legacy Alpha operations is due primarily to lower demand for coking coal from steel producers due to the economic recession experienced during 2009. The Foundation operations shipped 0.6 million tons for the year ended December 31, 2009, all of which was shipped from Foundation mines included in our Northern West Virginia business unit.

Metallurgical coal sales realization per ton at our Eastern Coal Operations decreased $19.42, or 17%, for the year ending December 31, 2009 compared to the year ending December 31, 2008. The decrease was due to a decrease in coal sales realization per ton for the legacy Alpha operations, partially offset by higher relative coal sales realization per ton from the Foundation operations. Coal sales realization per ton for the legacy Alpha operations was $95.83, a decrease of $21.67 per ton, or 18%, for the year ended December 31, 2009 compared to the year ended December 31, 2008. The decrease was due to lower market prices realized on coal sales volumes as a result of reduced demand for coking coal from steel producers experienced for the year ending December 31, 2009 compared to the year ending December 31, 2008. The average coal sales rea lization per ton for the Foundation operations was $125.57 per ton.

EBITDA from continuing operations for our Eastern Coal Operations increased $102.5 million, or 24%, compared to the prior year period. The increase was primarily due to lower total costs and expenses of $306.0 million and higher miscellaneous income of $2.2 million, which were partially offset by lower total revenues of $205.7 million. The decrease in total costs and expenses was largely attributable to a $189.1 million decrease in cost of coal sales related to lower purchased coal volumes and lower variable production costs, a decrease in other expenses of $70.5 million primarily related to net mark-to-market gains on derivative swap contracts and lower expenses associated with coal contract settlements, decreased freight and handling costs that are offset by a corresponding decrease in freight and handling revenues of $90.0 million, hi gher selling, general and administrative expenses of $28.1 million and lower gains on asset sales of $15.0 million.

The decrease in total revenues of $205.7 million was the result of lower metallurgical coal sales revenues of $538.9 million that were partially offset by higher steam coal sales revenues of $391.9 million. The decrease in metallurgical coal sales revenues consisted of a decrease of $615.9 million related to the legacy Alpha operations as a result of the factors described above, which was partially offset by the addition of $77.0 million of metallurgical coal sales revenue from the Foundation operations.

Liquidity and Capital Resources

Our primary sources of cash have been from sales of our coal production, borrowings under our credit facility (see “—Credit Agreement and Long-Term Debt”), sales of our common stock, and to a much lesser extent, sales of purchased coal to customers, sales of non-core assets and miscellaneous revenues.

Our primary uses of cash have been our cash production costs, capital expenditures, interest costs, cash payments for employee benefit obligations such as retiree health care benefits, cash payments related to our reclamation obligations and support of working capital requirements such as trade accounts receivable, coal inventories and trade accounts payable.  Our ability to service debt and acquire new productive assets for use in our operations has been and will be dependent upon our ability to generate cash from our operations.  We generally fund all of our capital expenditure requirements with cash generated from operations.  Historically, we have engaged in minimal financing of assets such as through operating leases.

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We believe that cash on hand, cash generated from our operations and borrowings available under our credit facility will be sufficient to meet our working capital requirements, anticipated capital expenditures, debt service requirements and reclamation obligations for at least the next twelve months.

At December 31, 2010, we had available liquidity of $1,765.1 million, including cash and cash equivalents of $554.8 million, marketable securities of $277.4 million and $932.9 million of unused revolving credit facility commitments available under the Alpha Credit Facility (the “Facility”) and our accounts receivable securitization facility (the “A/R Facility”), after giving effect to $7.7 million and $63.8 million of letters of credit outstanding, respectively, as of December 31, 2010, subject to limitations described in the Facility. Our total long-term debt, including current portion, was $821.5 million at December 31, 2010, see “—Credit Agreement and Long-Term Debt”.

We sponsor pension plans in the United States for salaried and non-union hourly employees. For these plans, the Pension Protection Act of 2006 (“PPA”) requires a funding target of 100% of the present value of accrued benefits. The PPA includes a funding target phase-in provision that establishes a funding target of 92% in 2008, 94% in 2009, 96% in 2010 and 100% thereafter for defined benefit pension plans. Generally, any such plan with a funding ratio of less than 80% will be deemed at risk and will be subject to additional funding requirements under the PPA. Annual funding contributions to the plans are made as recommended by consulting actuaries based upon the ERISA funding standards. Plan assets consist of equity and fixed income funds, real estate funds, private equity funds and alternative investment funds. We are requir ed to measure plan assets and benefit obligations as of the date of our fiscal year-end balance sheet and recognize the overfunded or underfunded status of our defined benefit pension and other postretirement plans (other than a multi-employer plan) as an asset or liability on our balance sheet and recognize changes in that funded status in the year in which the changes occur through other comprehensive (loss) income. Global economic conditions have caused investment income and the value of investment assets held in our pension trust to lose value in the past. As a result, we may be required to increase the amount of cash contributions into the pension trust in order to comply with the funding requirements of the PPA. We currently expect to make contributions in 2011 of approximately $40 million for our defined benefit pension plans.

We have obligations for a federal coal lease, which contains an estimated 224.0 million tons of proven and probable coal reserves in the Powder River Basin. The original lease bonus bid was $180.5 million, payable in five equal annual installments of $36.1 million. We paid the third installment in 2010.  The two remaining annual installments of $36.1 million each are due on May 1, 2011 and 2012.

With respect to global economic events, there continues to be uncertainty in the financial markets and this uncertainty brings potential liquidity risks for us. Such risks include declines in our stock value, less availability and higher costs of additional credit, potential counterparty defaults and further commercial bank failures.  The credit worthiness of our customers is constantly monitored by us. We believe that our current group of customers is sound and represents no abnormal business risk.

In March 2010, we filed a shelf registration statement on Form S-3 with the Securities and Exchange Commission that provides us the flexibility to raise additional debt and/or equity capital through the sale or issuance of a number of different classes of securities.  Any such transaction would be accompanied by the filing of a prospectus supplement and other documents describing the material terms of the offering as required by the rules and regulations of the Securities and Exchange Commission.

       A portion of the purchase price of the Massey Merger will be paid in cash.  We anticipate funding the cash portion and any re-financing of Massey's debt through a combination of new debt proceeds that we intend to raise in 2011 and cash on hand.  We also expect to incur between $123.0 million and $128.0 million of fees in connection with the issuance of new debt and between $47.0 million and $56.0 million for professional services in connection with the Massey Merger.

Accounts Receivable Securitization

Alpha and certain of our subsidiaries are parties to a $150.0 million A/R Facility with a third party financial institution. We formed ANR Receivables Funding, LLC (the “SPE”), a special-purpose, bankruptcy-remote wholly-owned subsidiary to purchase trade receivables generated by certain of our operating and sales subsidiaries, without recourse (other than customary indemnification obligations for breaches of specific representations and warranties), and then transfer senior undivided interests in up to $150.0 million of those accounts receivable to a financial institution for the issuance of letters of credit or for cash borrowings for our ultimate benefit.

The SPE is consolidated into our financial statements, and therefore the purchase and sale of trade receivables by the SPE from our operating and sales receivables has no impact on our consolidated financial statements. The assets of the SPE, however, are not available to the creditors of us or any other subsidiary. Available borrowing capacity is based on the amount of eligible accounts receivable as defined under the terms of the definitive agreements for the A/R Facility and varies over time. Unless extended by the parties, the receivables purchase agreement supporting the borrowings under the A/R Facility expires on December 9, 2015, or earlier upon the occurrence of certain events customary for facilities of this type, including the failure for any reason by liquidity providers to the A/R Facility’s financial institutions to r enew their commitments not less often than annually.

As of December 31, 2010, letters of credit in the amount $63.8 million were outstanding under the A/R Facility and no cash borrowing transactions had taken place.  If outstanding letters of credit exceed borrowing capacity, we are required to provide additional collateral in the form of restricted cash to secure outstanding letters of credit. Under the A/R Facility, the SPE is subject to certain affirmative, negative and financial covenants customary for financings of this type, including restrictions related to, among other things, liens, payments, merger or consolidation and amendments to the agreements underlying the receivables pool. Alpha Natural Resources, Inc. has agreed to guarantee the performance by its subsidiaries, other than the SPE, of their obligations under the A/R Facility. We do not guarantee repayment of the SPE’s debt under the A/R Facility. The financial institution, which is the administrator, may terminate the A/R Facility upon the occurrence of certain events that are customary for facilities of this type (with customary grace periods, if applicable), including, among other things, breaches of covenants, inaccuracies of representations and warranties, bankruptcy and insolvency events, changes in the rate of default or delinquency of the receivables above specified levels, a change of control and material judgments. A termination event would permit the administrator to terminate the program and enforce any and all rights and remedies, subject to cure provisions, where applicable.

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Cash Flows

Cash and cash equivalents increased by $88.9 million for the year ended December 31, 2010, and decreased $210.3 million for the year ended December 31, 2009. The net change in cash and cash equivalents was attributable to the following:

	Year Ended December 31,
	2010				2009				2008
Cash Flows
(in thousands)
Net cash provided by operating activities		$	693,601			$	356,220		$	458,043
Net cash used in investing activities			(508,497	)			(281,810	)		(77,625	)
Net cash (used in) provided by financing activities			(96,201	)			(284,731	)		241,407
Net change in cash and cash equivalents		$	88,903			$	(210,321	)	$	621,825

Net cash provided by operating activities, including discontinued operations, during 2010 was $693.6 million, an increase of $337.4 million from the $356.2 million of net cash provided by operations during 2009. This increase was driven by an increase in our net income and by changes in operating assets and liabilities. The cash generated (used) by changes in operating assets and liabilities was primarily related to the increase in accounts receivable, net of $48.5 million, the increase in inventories, net of $21.9 million, the decrease in prepaid expenses and other current assets of $59.1 million, the decrease in accounts payable of $21.8 million, the increase in accrued expenses and other current liabilities of $42.7 million and the decrease in pension and postretirement medical benefit obligations of $70.8 million.

Net cash used in investing activities, including discontinued operations, during 2010 was $508.5 million, an increase of $226.7 million from the $281.8 million of net cash used in investing activities during 2009.  The increase in 2010 was primarily due to an increase in capital expenditures of $121.8 million, an increase in net purchases of marketable securities of $39.1 million, and the acquisition of mineral rights under federal lease of $36.1 million.

Net cash used in financing activities, including discontinued operations, during 2010 was $96.2 million, compared to $284.7 million of net cash used in financing activities in 2009. The primary uses of cash for financing activities included $41.7 million of common stock repurchases under our stock repurchase program and to satisfy employees’ minimum statutory tax withholdings upon the vesting of restricted stock and restricted stock units. In addition, we made $56.9 million of principal payments on our long-term debt.

Net cash provided by operating activities, including discontinued operations, during 2009 was $356.2 million, a decrease of $101.8 million from the $458.0 million of net cash provided by operations during 2008. This decrease was driven by a decrease in our net income and a decrease in operating assets and liabilities in 2009 as compared to 2008 primarily related to the $40.0 million increase in prepaid expenses and other current assets, the decrease in trade accounts payable of $26.7 million, pension and postretirement medical benefit obligations of $37.5 million, and accrued expenses and other current liabilities of $22.4 million.

Net cash used in investing activities, including discontinued operations, during 2009 was $281.8 million, an increase of $204.2 million from the $77.6 million of net cash used in investing activities during 2008.  The increase in 2009 was primarily due to the purchases of marketable securities of $119.4 million, an increase in capital expenditures of $49.3 million, and the absence of $45.0 million of proceeds in 2009 that occurred in 2008 from the sale of Gallatin.  The increase in net cash used in investing activities was partially offset by the $23.5 million of cash acquired from the Foundation Merger.

Net cash used in financing activities, including discontinued operations, during 2009 was $284.7 million, compared to $241.4 million of net cash provided by financing activities in 2008. This decrease was primarily due to the concurrent offerings in April 2008 of our common stock and the convertible notes, offset by principal payments on our long-term debt and principal repayments of our note payable. In 2009, shortly after the Foundation Merger, we voluntarily repaid our term loan in the amount of $233.1 million.

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Credit Agreement and Long-term Debt

As of December 31, 2010 and 2009, our total long-term indebtedness consisted of the following (in thousands):

	December 31, 2010			December 31, 2009
Term loan due 2014	$	227,896		$	284,750
7.25% senior notes due 2014		298,285			298,285
2.375% convertible senior note due 2015		287,500			287,500
Other		7,819			-
Debt discount		(67,349	)		(80,282	)
Total long-term debt		754,151			790,253
Less current portion		11,839			33,500
Long-term debt, net of current portion	$	742,312		$	756,753

Alpha Credit Facility

On April 15, 2010, we and our lenders amended and restated (the “Amend and Extend”) the Alpha Credit Facility (the “Facility”). The Amend and Extend, among other things, extended the maturity of $236.8 million of the then-outstanding term loans and $554.0 million of existing revolving credit facility (the “Revolver”) commitments from July 7, 2011 to July 31, 2014. The Amend and Extend added $300.4 million of additional borrowing capacity with a maturity of July 31, 2014, to increase the aggregate principal amount available to be drawn under the Revolver to $950.4 million. Subsequently, we terminated $96.0 million of commitments under the Revolver and prepaid $39.6 million of the term loans, both of which related to lenders that chose not to extend their commitments beyond the original expiration date o f July 7, 2011. Additionally, the Amend and Extend (1) increased the amount of the “accordion” feature of the Facility to $400.0 million, all of which was available for us to exercise following the closing of the Amend and Extend; and, (2) also made other changes to the Facility, including amendments to certain of the negative covenants in the Facility to provide us greater financial and operating flexibility.

As of December 31, 2010, the total borrowing capacity under the Revolver was $854.4 million and the amount available was $846.7 million, after giving effect to outstanding letters of credit of $7.7 million. Borrowings under the Revolver bear interest at a base rate plus an applicable margin or at an adjusted London interbank offered rate (“LIBOR”) plus an applicable margin. The applicable margin is subject to adjustment based on leverage ratios. There were no borrowings outstanding under the Revolver at December 31, 2010 or December 31, 2009. Additionally, we are required to pay a commitment fee of 0.5% on unused borrowings.

The Facility’s secured term loan bears interest at a base rate plus an applicable margin or at an adjusted LIBOR rate plus an applicable margin.  The interest rate approximated 3.56% and 3.50% at December 31, 2010 and December 31, 2009, respectively. As of December 31, 2010, our secured term loan had a carrying value of $226.7 million, net of debt discount of $1.2 million, with $11.8 million classified as current portion of long-term debt. As of December 31, 2009, our secured term loan had a carrying value of $282.7 million, net of debt discount of $2.0 million, with $33.5 million classified as current portion of long-term debt.

The Facility places certain restrictions on us. See “—Analysis of Material Debt Covenants.”

7.25% Senior Notes Due August 1, 2014

Foundation PA Coal Company, LLC (“Foundation PA”), one of our subsidiaries, has senior unsecured notes outstanding that mature on August 1, 2014, unless previously redeemed (the “2014 Notes”) with an aggregate principal amount of $298.3 million at both December 31, 2010 and December 31, 2009. The 2014 Notes are guaranteed on a senior unsecured basis by Alpha Natural Resources, Inc. and all of our subsidiaries other than Foundation PA and ANR Receivables Funding LLC.  The 2014 Notes pay interest semi-annually and are redeemable at Foundation PA’s option at a redemption price equal to 102.417%, 101.208%, and 100% of the principal amount if redeemed during the twelve month periods beginning August 1, 2010, 2011 and 2012, respectively, plus accrued interest. As of December 31, 2010, the carrying value of the 2014 Notes was $297.3 million, net of debt discount of $1.0 million.  As of December 31, 2009, the carrying value of the 2014 Notes was $297.0 million, net of debt discount of $1.3 million.

The indenture governing the 2014 Notes places certain restrictions on Alpha. See “—Analysis of Material Debt Covenants.”

2.375% Convertible Senior Notes Due April 15, 2015

As of December 31, 2010 and December 31, 2009, we had $287.5 million aggregate principal amount of 2.375% convertible senior notes due April 15, 2015 (the “Convertible Notes”). The Convertible Notes bear interest at a rate of 2.375% per annum, payable semi-annually in arrears on April 15 and October 15 of each year, and will mature on April 15, 2015, unless previously repurchased by us or converted. We separately account for the liability and equity components of our Convertible Notes in a manner reflective of our nonconvertible debt borrowing rate. The related deferred loan costs and discount are being amortized and accreted, respectively, over the seven-year term of the Convertible Notes, and provide for an effective interest rate of 8.64%. As of December 31, 2010 and December 31, 2009, the carrying amounts of the debt comp onent were $222.4 million and $210.5 million, respectively. As of December 31, 2010 and December 31, 2009, the unamortized debt discount was $65.1 million and $77.0 million, respectively.  As of December 31, 2010 and 2009, the carrying amount of the equity component was $69.9 million.

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The Convertible Notes are our senior unsecured obligations and rank equally with all of our existing and future senior unsecured indebtedness. The Convertible Notes are effectively subordinated to all of our existing and future secured indebtedness and all existing and future liabilities of our subsidiaries, including trade payables. The Convertible Notes are convertible in certain circumstances and in specified periods at an initial conversion rate of 18.2962 shares of common stock per $1,000 principal amount of Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the Indenture. Upon conversion of the Convertible Notes, holders will receive cash up to the principal amount of the notes to be converted, and any excess conversion value will be delivered in cash, shares of common stock, or a combinatio n thereof, at our election.

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

As a result of the Foundation Merger, the Convertible Notes became convertible at the option of the holders beginning on June 18, 2009, and remained convertible through the 30th day after the effective date of the Foundation Merger, which was July 31, 2009. No notes were converted during the conversion period. The Convertible Notes were not convertible as of December 31, 2010 and 2009 and are classified as long-term debt.

Other

In 2010, we entered into certain agreements to develop, build and subsequently lease our new corporate headquarters. We have provided certain financial guarantees in connection with the development and construction of the building and are considered the owner of the building from an accounting perspective. We have recorded $7.8 million as a liability and corresponding asset in our consolidated financial statements for amounts expended and guaranteed by us through December 31, 2010. We expect to record an additional $12.5 million in 2011 for additional amounts anticipated to be expended for the construction of the building and guaranteed by us. The building is expected to be completed at the end of 2011.

Analysis of Material Debt Covenants

We were in compliance with all covenants under the Alpha Credit Facility and the indenture governing the 2014 Notes as of December 31, 2010. A breach of the covenants in the Facility or the 2014 Notes indenture, including the financial covenants under the Facility that measure ratios based on Adjusted EBITDA, could result in a default under the Facility or the 2014 Notes indenture and the respective lenders and note holders could elect to declare all amounts borrowed due and payable.  Any acceleration under either the Facility or the 2014 Notes indenture would also result in a default under the indenture governing our Convertible Notes. Additionally, under the Facility and the 2014 Notes indenture, our ability to engage in activities such as incurring additional indebtedness, making investments and paying dividends is also tied to ratios based on Adjusted EBITDA.

Covenants and required levels set forth in the Alpha Credit Facility are:

	Actual Covenant Levels; Period Ended December 31, 2010	Required Covenant Levels
Minimum adjusted EBITDA to cash interest ratio	19.5x	2.5x
Maximum total debt less unrestricted cash to adjusted EBITDA ratio	0.3x	3.5x

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Adjusted EBITDA is defined as EBITDA further adjusted to exclude certain non-cash items, non-recurring items, and other adjustments permitted in calculating covenant compliance under the Facility. EBITDA, a measure used by management to evaluate its ongoing operations for internal planning and forecasting purposes, is defined as net income (loss) from operations plus interest expense, income tax expense, amortization of acquired coal supply agreements and depreciation, depletion and amortization, less interest income and income tax benefit. EBITDA is not a financial measure recognized under United States generally accepted accounting principles and does not purport to be an alternative to net income as a measure of operating performance or to cash flows from operating activities as a measure of liquidity. The amounts shown for EBITDA as presented may differ from amounts calculated and may not be comparable to other similarly titled measures used by other companies.

Certain non-cash items that may adjust EBITDA in the compliance calculation are: (a) accretion on asset retirement obligations; (b) amortization of intangibles; (c) any long-term incentive plan accruals or any non-cash compensation expense recorded from grants of stock appreciation or similar rights, stock options or other rights to officers, directors and employees; and (d) gains or losses associated with the change in fair value of derivative instruments. Certain non-recurring items that may adjust EBITDA in the compliance calculation are: (a) business optimization expenses or other restructuring charges; (b) non-cash impairment charges; (c) certain non-cash expenses or charges arising as a result of the application of acquisition accounting; (d) non-cash charges associated with loss on early extinguishment of debt; and (e) charges associated with litigation, arbitration, or contract settlements. Certain other items that may adjust EBITDA in the compliance calculation are: (a) after-tax gains or losses from discontinued operations; (b) franchise taxes; and (c) other non-cash expenses that do not represent an accrual or reserve for future cash expense.

The calculation of adjusted EBITDA shown below is based on our results of operations in accordance with the Facility and therefore, is different from EBITDA presented elsewhere in this Annual Report on Form 10-K.

	Three Months Ended													Twelve Months Ended
		March 31, 2010			June 30, 2010			September 30, 2010			December 31, 2010			December 31, 2010
	(In thousands)
Net income		$	14,041		$	38,797		$	31,874		$	10,839		$	95,551
Interest expense			22,120			18,504			17,834			15,005			73,463
Interest income			(680	)		(848	)		(967	)		(963	)		(3,458	)
Income tax expense (benefit)			20,860			(5,159	)		1,236			(13,771	)		3,166
Amortization of acquired coal supply agreements, net			65,957			55,633			52,398			52,805			226,793
Depreciation, depletion and amortization			95,137			91,049			94,202			90,715			371,103
EBITDA			217,435			197,976			196,577			154,630			766,618
Non-cash charges (1)			12,177			14,069			10,003			18,578			54,827
Extraordinary or non-recurring items (1)			273			279			388			599			1,539
Other adjustments (1)			3,048			(1,359	)		608			(149	)		2,148
Adjusted EBITDA		$	232,933		$	210,965		$	207,576		$	173,658		$	825,132
(1) Calculated in accordance with the Facility
Adjusted EBITDA to cash interest ratio															19.5
Total debt less unrestricted cash to adjusted EBITDA ratio															0.3

Cash interest is calculated in accordance with the Facility and is equal to interest expense less interest income and non-cash interest expense. Cash interest for the twelve months ended December 31, 2010 is calculated as follows (in thousands):

Interest expense	$	73,463
Less interest income		(3,458	)
Less non-cash interest expense		(24,861	)
Less other adjustments		(2,916	)
Net cash interest expense (1)	$	42,228

(1) Calculated in accordance with the Facility

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If certain circumstances exist where all of our $287.5 million aggregate principal amount of Convertible Notes were converted at the option of the holders, we believe we would have adequate liquidity to satisfy the obligations for the Convertible Notes and remain in compliance with any required covenants

Off-Balance Sheet Arrangements

In the normal course of business, we are a party to certain off-balance sheet arrangements. These arrangements include guarantees, operating leases, indemnifications and financial instruments with off-balance sheet risk, such as bank letters of credit and performance or surety bonds. Liabilities related to these arrangements are not reflected in our Consolidated Balance Sheets. However, the underlying obligations that they secure, such as asset retirement obligations, self-insured workers’ compensation liabilities, royalty obligations and certain retiree medical obligations, are reflected in our Consolidated Balance Sheets.

We are required to provide financial assurance in order to perform the post-mining reclamation required by our mining permits, pay our federal production royalties, pay workers’ compensation claims under self-insured workers’ compensation laws in various states, pay federal black lung benefits, pay retiree health care benefits to certain retired United Mine Workers of America (“UMWA”) employees and perform certain other obligations.  In order to provide the required financial assurance, we generally use surety bonds and self bonding for post-mining reclamation and bank letters of credit for self-insured workers’ compensation obligations and UMWA retiree health care obligations. Federal black lung benefits are paid from a dedicated trust fund to which future contributions will be required. Bank lett ers of credit are also used to collateralize a portion of the surety bonds.

We had outstanding surety bonds with a total face amount of $518.6 million as of December 31, 2010 to secure various obligations and commitments. In addition, we had $71.5 million of letters of credit in place, of which $7.7 million was outstanding under the Alpha Credit Facility, and $63.8 million was outstanding under our A/R Facility. These outstanding letters of credit served as collateral for workers’ compensation bonds, reclamation surety bonds, secured UMWA retiree health care obligations, secured workers’ compensation obligations and other miscellaneous obligations. In the event that additional surety bonds or self bonding capacity become unavailable, we would seek to secure our obligations with letters of credit, cash deposits or other suitable forms of collateral.

Other

As a regular part of our business, we review opportunities for, and engage in discussions and negotiations concerning, the acquisition of coal mining assets and interests in coal mining companies, and acquisitions of, or combinations with, coal mining companies. When we believe that these opportunities are consistent with our growth plans and our acquisition criteria, we will make bids or proposals and/or enter into letters of intent and other similar agreements. These bids or proposals, which may be binding or nonbinding, are customarily subject to a variety of conditions and usually permit us to terminate the discussions and any related agreement if, among other things, we are not satisfied with the results of our due diligence investigation. Any acquisition opportunities we pursue could materially affect our liquidity and capital reso urces and may require us to incur indebtedness, seek equity capital or both. There can be no assurance that additional financing will be available on terms acceptable to us, or at all.

Contractual Obligations

The following is a summary of our significant contractual obligations as of December 31, 2010 (in thousands):

	2011			2012-2013		2014-2015	After 2015		Total
Long-term debt (1)	$	11,839	$	44,395	$	757,447	$	-	$	813,681
Other debt (2)		-		90		110		7,619		7,819
Equipment purchase commitments		88,436		200		-		-		88,636
Operating leases		5,857		5,585		2,131		1,226		14,799
Minimum royalties		16,676		31,804		18,650		40,797		107,927
Federal coal lease		36,108		36,108		-		-		72,216
Coal purchase commitments		227,195		8,280		-		-		235,475
Total	$	386,111	$	126,462	$	778,338	$	49,642	$	1,340,553

(1) Long-term debt includes principal amounts due in the years shown. Cash interest payable on these obligations, with interest rates ranging between 2.375% and 7.25% on our loans, would be approximately $36.4 million in 2011, $71.0 million in 2012 to 2013, and $24.9 million in 2014 to 2015.

 

(2) Other debt includes principal amounts due in the years shown.  Cash interest payable on this obligation, with an interest rate approximating 13.86%, would be approximately $2.3 million in 2012 to 2013, $2.1 million in 2014 to 2015, and $15.7 million after 2015.

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Additionally, we have long-term liabilities relating to asset retirement obligations, postretirement, pension, workers' compensation and black lung benefits. The table below reflects the estimated undiscounted cash flows for these obligations (in thousands):

	2011			2012-2013		2014-2015	After 2015		Total
Asset retirement obligation	$	12,934	$	20,293	$	26,002	$	340,517	$	399,746
Postretirement benefit obligation		33,042		75,880		88,528		269,929		467,379
Pension benefit obligation		13,814		30,262		32,832		83,495		160,403
Workers' compensation benefit and black lung benefit obligations		11,098		12,646		10,299		39,507		73,550
Total	$	70,888	$	139,081	$	157,661	$	733,448	$	1,101,078

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition, results of operations, liquidity and capital resources is based upon our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”). GAAP requires that we make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and on various other factors and assumptions, including the current economic environment that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We evaluate our estimates and assumptions on an ongoing basis and adjust such estimates and assumptions as facts and circumstances require. Illiquid credit markets, volatile equity, foreign currency and energy markets, and declines in demand for steel products have combined to increase the uncertainty inherent in such estimates and assumptions. As future events and their effects cannot be determined with precision, actual results may differ significantly from these estimates. Changes in these estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Derivatives Instruments and Hedging Activities. We are subject to the risk of price volatility for certain of the materials and supplies used in production, such as diesel fuel and explosives and for the amount we receive for the sale of natural gas. As a part of our risk management strategy, we enter into pay fixed, receive variable and pay variable, receive fixed swap agreements with financial institutions to mitigate the risk of price volatility for both diesel fuel and explosives and sales of natural gas, respectively. Swap agreements are derivative instruments that we are required to recognize as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The accounting requirements for derivatives are complex and judgment i s required in certain areas such as cash flow hedge accounting and hedge effectiveness testing. We assess each swap agreement to determine whether or not it qualifies for special cash flow hedge accounting. In performing the assessment, we make estimates and assumptions about the timing and amounts of future cash flows related to the forecasted purchases of diesel fuel and explosives and sales of natural gas. We update our assessments at least on a quarterly basis.

Reclamation. Our asset retirement obligations arise from the federal Surface Mining Control and Reclamation Act of 1977 and similar state statutes, which require that mine property be restored in accordance with specified standards and an approved reclamation plan. Significant reclamation activities include reclaiming refuse and slurry ponds, reclaiming the pit and support acreage at surface mines, and sealing portals at deep mines. We determine the future cash flows necessary to satisfy our reclamation obligations on a mine-by-mine basis based upon current permit requirements and various estimates and assumptions, including estimates of disturbed acreage, cost estimates, and assumptions regarding productivity. Estimates of disturbed acreage are determined based on approved mining plans and related engineering data. Cost estimates are based upon third-party costs. Productivity assumptions are based on historical experience with the equipment that is expected to be utilized in the reclamation activities. Our asset retirement obligations are initially recorded at fair value. In order to determine fair value, we use assumptions including a discount rate and third-party margin. Each is discussed further below:

· Discount Rate. Asset retirement obligations are initially recorded at fair value. We utilize discounted cash flow techniques to estimate the fair value of our obligations. We base our discount rate on the rates of treasury bonds with maturities similar to expected mine lives, adjusted for our credit standing.

· Third-Party Margin. The measurement of an obligation is based upon the amount a third party would demand to assume the obligation. Because we plan to perform a significant amount of the reclamation activities with internal resources, a third-party margin was added to the estimated costs of these activities. This margin was estimated based upon our historical experience with contractors performing similar types of reclamation activities. The inclusion of this margin will result in a recorded obligation that is greater than our estimates of our cost to perform the reclamation activities. If our cost estimates are accurate, the excess of the recorded obligation over the cost incurred to perform the work will be recorded as a gain at the time that reclamation work is completed.

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On at least an annual basis, we review our entire reclamation liability and make necessary adjustments for permit changes as granted by state authorities, additional costs resulting from accelerated mine closures, and revisions to cost estimates and productivity assumptions, to reflect current experience. At December 31, 2010, we had recorded asset retirement obligation liabilities of $223.0 million, including amounts reported as current. While the precise amount of these future costs cannot be determined with certainty, as of December 31, 2010, we estimate that the aggregate undiscounted cost of final mine closures is approximately $399.7 million.

Coal Reserves. There are numerous uncertainties inherent in estimating quantities of economically recoverable coal reserves, many of which are beyond our control. As a result, estimates of economically recoverable coal reserves are by their nature uncertain. Information about our reserves consists of estimates based on engineering, economic and geological data assembled by our internal engineers and geologists and reviewed by a third party consultant. Some of the factors and assumptions that impact economically recoverable reserve estimates include:

· geological conditions;

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

· the assumed effects of regulations and taxes by governmental agencies;

· assumptions governing future prices; and

· future operating costs.

Each of these factors may vary considerably from the assumptions used in estimating reserves. For these reasons, estimates of the economically recoverable quantities of coal attributable to a particular group of properties, and classifications of these reserves based on risk of recovery and estimates of future net cash flows, may vary substantially. Actual production, revenues and expenditures with respect to reserves will likely vary from estimates, and these variances may be material. Variances could affect our projected future revenues and expenditures, as well as the valuation of coal reserves and depletion rates.  At December 31, 2010, we had 1,154.5 million tons of proven and probable coal reserves assigned to our active operations.

Postretirement Medical Benefits. We have long-term liabilities for postretirement medical benefit cost obligations. Detailed information related to these liabilities is included in Note 15 to the Consolidated Financial Statements included elsewhere in this Annual Report on Form 10-K. Liabilities for postretirement medical benefit costs are not funded. The liability is actuarially determined, and we use various actuarial assumptions, including the discount rate and future health care cost trends, to estimate the costs and obligations for postretirement medical benefit costs. The discount rates used to determine the net periodic benefit cost for postretirement medical benefits ranged from 4.59% to 5.88% for the various plans for the year ended December 31, 2010. At December 31, 2010, we had total postretirement medical benefit obligations of $706.3 million.

The estimated impact of changes to the healthcare cost trend rate and discount rate is as follows:

Health care cost trend rate	One-Percentage Point Increase			One-Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components		$	5,753		$	(4,667	)
Effect on accumulated postretirement benefit obligation		$	84,506		$	(70,355	)

Discount rate	One-Half Percentage Point Increase				One-Half Percentage Point Decrease
	(In thousands)
Effect on total service and interest cost components		$	149			$	(165	)
Effect on accumulated postretirement benefit obligation		$	(1,698	)		$	1,707

Retirement Plans. We have two non-contributory defined benefit retirement plans (the “Pension Plans”) covering certain of our salaried and non-union hourly employees. We also have an unfunded non-qualified Supplemental Executive Retirement Plan (“SERP”) covering certain eligible employees. Benefits are based on either the employee’s compensation prior to retirement or stated amounts for each year of service with us. Funding of the defined benefit retirement plans is in accordance with the requirements of ERISA, which can be deducted for federal income tax purposes. We contributed $43.5 million to our defined benefit retirement plans for the year ended December 31, 2010.  For the year ended December 31, 2010, we recorded net periodic benefit expense of $3.1 million for our Pension Plans and SERP and have recorded obligations of $41.3 million.

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The calculation of the net periodic benefit expense and projected benefit obligation associated with our Pension Plans and SERP requires the use of a number of assumptions that we deem to be “critical accounting estimates.” These assumptions are used by our independent actuaries to make the underlying calculations. Changes in these assumptions can result in different net periodic benefit expense and liability amounts, and actual experience can differ from the assumptions.

· The expected long-term rate of return on plan assets is an assumption of the rate of return on plan assets reflecting the average rate of earnings expected on the funds invested or to be invested to provide for the benefits included in the projected benefit obligation. We establish the expected long-term rate of return at the beginning of each fiscal year based upon historical returns and projected returns on the underlying mix of invested assets. The Pension Plans investment targets are 64.5% equity funds and 35.5% fixed income funds. Investments are rebalanced on a periodic basis to stay within these targeted guidelines. The long-term rate of return assumption used to determine net periodic benefit expense was 7.92% for the year ended December 31, 2010. Any difference between the actual experience and the assumed experience is deferred as an unrecognized actuari al gain or loss and amortized into expense in future periods.

· The discount rate represents our estimate of the interest rate at which pension benefits could be effectively settled. Assumed discount rates are used in the measurement of the projected, accumulated and vested benefit obligations and the service and interest cost components of the net periodic benefit expense. In estimating that rate, we use rates of return on high quality, fixed income investments. The discount rate used to determine pension expense was 5.39% for the year ended December 31, 2010. The differences resulting from actual versus assumed discount rates are amortized into pension expense over the remaining average service life of the active plan participants. A one half percentage-point increase in the discount rate would increase the net periodic pension cost for the year ended December 31, 2010 by less than $0.1 million and decrease the projected ben efit obligation as of December 31, 2010 by approximately $13.6 million. The corresponding effects of a one half of one percentage-point decrease in the discount rate would be less than a $0.2 million increase in the net periodic pension cost and approximately a $14.4 million increase in the projected benefit obligation.

Workers' Compensation. Workers' compensation is a system by which individuals who sustain personal injuries due to job-related accidents are compensated for their disabilities, medical costs, and on some occasions, for the costs of their rehabilitation, and by which the survivors of workers who suffer fatal injuries receive compensation for lost financial support. The workers' compensation laws are administered by state agencies with each state having its own set of rules and regulations regarding compensation that is owed to an employee who is injured in the course of employment. Our obligations are covered through a combination of a self-insurance program and third party insurance policies. We accrue for any self-insured liability by recognizing costs when it is probable that a c overed liability has been incurred and the cost can be reasonably estimated. Our estimates of these costs are adjusted based upon actuarial studies. Actual losses may differ from these estimates, which could increase or decrease our costs.  At December 31, 2010, we had workers’ compensation obligations of $51.7 million.

Coal Workers' Pneumoconiosis. We are required by federal and state statutes to provide benefits to employees for awards related to coal workers' pneumoconiosis disease (black lung). Certain of our subsidiaries are insured for workers’ compensation and black lung obligations by a third-party insurance provider.  Certain subsidiaries in West Virginia are self-insured for workers’ compensation and state black lung obligations. Certain other subsidiaries are self-insured for black lung benefits and fund benefit payments through a Section 501(c)(21) tax-exempt trust fund.  Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries.  In addition, for our subsidiaries in Wyoming, we participate in a co mpulsory state-run fund.

Charges are made to operations for self-insured black lung claims, as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee's applicable term of service. As of December 31, 2010, we had black lung obligations of $45.0 million, which are net of assets of $1.1 million that are held in a tax exempt trust fund.

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

Income Taxes. We recognize deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In evaluating the need for a valuation allowance, we analyze both positive and negative evidence. Such evidence includes objective evidence obtained from our historical earnings, future sales commitments, outlooks on the coal industry by us and third parties, expected level of future earnings (with sensitivities on expectations considered), timing of temporary difference reversals, ability or inability to meet forecasted earnings, un settled industry circumstances, ability to carry back and utilize a future tax loss (if a loss were to occur), available tax planning strategies, limitations on deductibility of temporary differences, and the impact the alternative minimum tax has on utilization of deferred tax assets. The valuation allowance is monitored and reviewed quarterly. If our conclusions change in the future regarding the realization of a portion or all of our net deferred tax assets, we may record a change to the valuation allowance through income tax expense in the period the determination is made, which may have a material impact on our results. As of December 31, 2010, we were in a net deferred tax liability position with tax computed at regular tax rates on the gross temporary differences. Federal tax attributes related to minimum tax credit carry-forwards and federal and state net operating losses offset the tax effect of the temporary differences somewhat. A valuation allowance of $11.0 million has been provided on certain s tate net operating losses not expected to provide future tax benefits.

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Goodwill.  Goodwill represents the excess of purchase price over the fair value of the net assets of acquired companies. We estimate the fair value of goodwill using a number of factors, including the application of multiples and discounted cash flow estimates. Goodwill is not amortized; instead, it is tested for impairment annually or more frequently if indicators of impairment exist. On an ongoing basis, absent any impairment indicators, we perform our goodwill impairment testing as of October 31 of each year.

We test consolidated goodwill for impairment using a fair value approach at the reporting unit level. We perform our goodwill impairment test in two steps. Step one compares the fair value of each reporting unit to its carrying amount. If step one indicates that an impairment potentially exists, the second step is performed to measure the amount of impairment, if any. Goodwill impairment exists when the estimated fair value of goodwill is less than its carrying value.

For purposes of our step one analysis, our estimate of fair value for each reporting unit is based on discounted cash flows (the income approach). Under the income approach, the fair value of each reporting unit is based on the present value of estimated future cash flows. The income approach is dependent on a number of significant management assumptions including markets, sales volumes and prices, costs to produce, capital spending, working capital changes and the discount rate. The discount rate is commensurate with the risk inherent in the projected cash flows and reflects the rate of return required by an investor in the current economic conditions.

Goodwill was $382.4 million as of December 31, 2010. The Company’s annual goodwill impairment review performed on October 31, 2010 supported the carrying value of the Company’s goodwill.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

We manage our commodity price risk for coal sales through the use of long-term coal supply agreements. As of January 26, 2011, we had sales commitments for approximately 94% of planned shipments for 2011. Uncommitted and unpriced tonnage was 6%, 59% and 76% for 2011, 2012 and 2013, respectively. The discussion below presents the sensitivity of the market value of selected financial instruments to selected changes in market rates and prices. The range of changes reflects our view of changes that are reasonably possible over a one-year period. Market values are the present value of projected future cash flows based on the market rates and prices chosen.

We have exposure to price risk for supplies that are used directly or indirectly in the normal course of production such as diesel fuel, steel and other items such as explosives. We manage our risk for these items through strategic sourcing contracts in normal quantities with our suppliers and may use derivative instruments from time to time, primarily swap contracts with financial institutions, for a certain percentage of our monthly requirements. Swap agreements essentially fix the price paid for our diesel fuel and explosives by requiring us to pay a fixed price and receive a floating price.

We expect to use approximately 41,000 tons of explosives in 2011. Through our derivative swap contracts, we have fixed prices for approximately 28% of our expected explosive needs in 2011. If the price of natural gas were to decrease in 2011, our expense resulting from our natural gas derivatives would increase, which would be largely offset by a decrease in the cost of our physical explosive purchases.

We expect to use approximately 50,400,000 gallons and 48,100,000 gallons of diesel fuel in 2011 and 2012, respectively. Through our derivative swap contracts, we have fixed prices for approximately 68% and 39% of our expected diesel fuel needs for 2011 and 2012, respectively. If the price of diesel fuel were to decrease in 2011, our expense resulting from our diesel fuel derivative swap contracts would increase, which would be offset by a decrease in the cost of our physical diesel fuel purchases.

Credit Risk

Our credit risk is primarily with electric power generators and steel producers. Our policy is to independently evaluate each customer’s creditworthiness prior to entering into transactions and to constantly monitor outstanding accounts receivable against established credit limits. When appropriate (as determined by our credit management function), we have taken steps to reduce our credit exposure to customers that do not meet our credit standards or whose credit has deteriorated. These steps include obtaining letters of credit or cash collateral, requiring prepayments for shipments or establishing customer trust accounts held for our benefit in the event of a failure to pay.

Interest Rate Risk

Our objectives in managing exposure to interest rate changes are to limit the impact of interest rate changes on earnings and cash flows and to lower overall borrowing costs. As we continue to monitor the interest rate environment in concert with our risk mitigation objectives, consideration is being given to future interest rate risk reduction strategies.

We have exposure to changes in interest rates through our Alpha Credit Facility, which has a variable interest rate of 3.25 percentage points over the London interbank offered rate (“LIBOR”), subject, in the case of the revolving credit line, to adjustment based on leverage ratios. As of December 31, 2010, our term loan due 2014 under the Alpha Credit Facility had an outstanding balance of $226.7 million, net of debt discount of $1.2 million. The current portion of the term loan due in the next twelve months was $11.8 million. A 50 basis point increase or decrease in interest rates would increase or decrease our interest expense by $0.3 million, which would be partially offset by our interest rate swap.

To achieve risk mitigation objectives, we have in the past managed our interest rate exposure through the use of interest rate swaps. To reduce our exposure to rising interest rates, effective May 22, 2006 we entered into an interest rate swap to reduce the risk that changing interest rates could have on our operations. The swap initially qualified for cash flow hedge accounting and changes in fair value were recorded as a component of equity; however, the underlying debt instrument was subsequently paid in 2009 and the swap no longer qualified for cash flow hedge accounting. The amounts that were previously recorded in equity of $17.7 million, net of tax, were recognized in our Consolidated Statements of Operations in 2009. Subsequent changes in fair value of the interest rate swaps are recorded in earnings. If interest rates were to de crease in 2011, our expense resulting from our interest rate swap would increase, which would be partially offset by a decrease in the amount of actual interest paid on our Facility.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Alpha Natural Resources, Inc.:

We have audited the accompanying consolidated balance sheets of Alpha Natural Resources, Inc. and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Alpha Natural Resources, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 25, 2011 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Roanoke, Virginia

February 25, 2011

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ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Amounts in thousands, except share and per share data)

	Years Ended December 31,
	2010			2009			2008
Revenues:
Coal revenues	$	3,497,847		$	2,210,629		$	2,140,367
Freight and handling revenues		332,559			189,874			279,853
Other revenues		86,750			95,004			48,533
Total revenues		3,917,156			2,495,507			2,468,753
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)		2,566,825			1,616,905			1,627,960
Gain on sale of coal reserves		-			-			(12,936	)
Freight and handling costs		332,559			189,874			279,853
Other expenses		65,498			21,016			91,461
Depreciation, depletion and amortization		370,895			252,395			164,969
Amortization of acquired coal supply agreements, net		226,793			127,608			-
Selling, general and administrative expenses (exclusive of depreciation, depletion and amortization shown separately above)		180,975			170,414			71,923
Total costs and expenses		3,743,545			2,378,212			2,223,230
Income from operations		173,611			117,295			245,523
Other income (expense):
Interest expense		(73,463	)		(82,825	)		(39,812	)
Interest income		3,458			1,769			7,351
Loss on early extinguishment of debt		(1,349	)		(5,641	)		(14,702	)
Gain on termination of Cliffs' merger, net		-			-			56,315
Miscellaneous income (expense), net		(821	)		3,186			(3,834	)
Total other income (expense), net		(72,175	)		(83,511	)		5,318
Income from continuing operations before income taxes		101,436			33,784			250,841
Income tax (expense) benefit		(4,218	)		33,023			(52,242	)
Income from continuing operations		97,218			66,807			198,599
Discontinued operations:
Loss from discontinued operations before income taxes		(2,719	)		(14,278	)		(27,873	)
Mine closure/asset impairment charges		-			-			(30,172	)
Gain on sale of discontinued operations		-			-			13,622
Income tax benefit		1,052			5,476			11,035
Loss from discontinued operations		(1,667	)		(8,802	)		(33,388	)
Net income		95,551			58,005			165,211
Less : Net loss from discontinued operations attributable to noncontrolling interest		-			-			(490	)
Net income attributable to Alpha Natural Resources, Inc.	$	95,551		$	58,005		$	165,701
Amounts attributable to Alpha Natural Resources, Inc.
Income from continuing operations, net of tax	$	97,218		$	66,807		$	198,599
Loss from discontinued operations, net of tax		(1,667	)		(8,802	)		(32,898	)
Net income attributable to Alpha Natural Resources, Inc.	$	95,551		$	58,005		$	165,701
Basic earnings (loss) per common share:
Income from continuing operations	$	0.81		$	0.74		$	2.90
Loss from discontinued operations		(0.01	)		(0.10	)		(0.48	)
Net income	$	0.80		$	0.64		$	2.42
Diluted earnings (loss) per common share:
Income from continuing operations	$	0.80		$	0.73		$	2.83
Loss from discontinued operations		(0.01	)		(0.10	)		(0.47	)
Net income	$	0.79		$	0.63		$	2.36
Weighted average shares - basic		119,808,514			90,662,718			68,453,724
Weighted average shares - diluted		121,757,949			91,702,628			70,259,735

See accompanying Notes to Consolidated Financial Statements.

87

ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Amounts in thousands, except share and per share data)

	December 31,			December 31,
	2010			2009
Assets
Current assets:
Cash and cash equivalents	$	554,772		$	465,869
Trade accounts receivable, net		281,138			232,631
Inventories, net		198,172			176,372
Prepaid expenses and other current assets		341,755			176,953
Total current assets		1,375,837			1,051,825
Property, equipment and mine development costs (net of accumulated depreciation and amortization of $869,881 and $615,163, respectively)		1,131,987			1,082,446
Owned and leased mineral rights (net of accumulated depletion of $333,970 and $222,047, respectively)		1,884,169			1,958,855
Owned lands		98,727			91,262
Goodwill		382,440			382,440
Acquired coal supply agreements (net of accumulated amortization of $367,110 and $133,016, respectively)		162,397			396,491
Other non-current assets		143,726			157,024
Total assets	$	5,179,283		$	5,120,343
Liabilities and Stockholders' Equity
Current liabilities:
Current portion of long-term debt	$	11,839		$	33,500
Trade accounts payable		121,553			152,662
Accrued expenses and other current liabilities		313,754			273,260
Total current liabilities		447,146			459,422
Long-term debt		742,312			756,753
Pension and postretirement medical benefit obligations		719,355			682,991
Asset retirement obligations		209,987			190,724
Deferred income taxes		249,408			301,307
Other non-current liabilities		155,039			137,857
Total liabilities		2,523,247			2,529,054
Commitments and Contingencies (Note 18)
Stockholders' Equity
Preferred stock - par value $0.01, 10.0 million shares authorized, none issued		-			-
Common stock - par value $0.01, 200.0 million shares authorized, 124.3 million issued and 120.5 million outstanding at December 31, 2010 and 123.2 million issued and 120.5 million outstanding at December 31, 2009		1,242			1,232
Additional paid-in capital		2,238,526			2,194,281
Accumulated other comprehensive income (loss)		(27,583	)		5,812
Treasury stock, at cost: 3.8 million and 2.7 million shares at December 31, 2010 and December 31, 2009, respectively		(50,538	)		(8,874	)
Retained earnings		494,389			398,838
Total stockholders' equity		2,656,036			2,591,289
Total liabilities and stockholders' equity	$	5,179,283		$	5,120,343

See accompanying Notes to Consolidated Financial Statements.

88

ALPHA NATURAL RESOURCES INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Amounts in thousands)

	Years Ended
	December 31,
	2010			2009			2008
Operating activities:
Net income attributable to Alpha Natural Resources, Inc.	$	95,551		$	58,005		$	165,701
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		371,103			253,736			172,570
Amortization of acquired coal supply agreements, net		226,793			127,608			-
Amortization of debt issuance costs and accretion of debt discount		18,552			16,205			12,045
Mark-to-market adjustments for derivatives		11,316			(3,647	)		47,265
Accretion of asset retirement obligations		17,621			12,101			7,499
Stock-based compensation		33,255			37,802			17,871
Employee benefit plans, net		55,771			30,696			8,673
Loss on early extinguishment of debt		1,349			5,641			14,702
Deferred income taxes		(70,579	)		(49,754	)		(17,107	)
Gain on sale of discontinued operations		-			-			(13,622	)
Gain on sale of coal reserves		-			-			(12,936	)
Mine closure/asset impairment charges		3,875			-			34,706
Other, net		(8,651	)		547			(1,601	)
Changes in operating assets and liabilities:
Trade accounts receivable, net		(48,507	)		14,574			19,674
Inventories, net		(21,886	)		(11,609	)		(16,037	)
Prepaid expenses and other current assets		59,075			(40,037	)		(1,438	)
Other non-current assets		(7,468	)		1,080			(2,736	)
Trade accounts payable		(21,755	)		(26,735	)		14,324
Accrued expenses and other current liabilities		42,730			(22,384	)		13,864
Pension and postretirement medical benefit obligations		(70,770	)		(37,450	)		164
Asset retirement obligations		(5,593	)		(7,298	)		(4,825	)
Other non-current liabilities		11,819			(2,861	)		(713	)
Net cash provided by operating activities		693,601			356,220			458,043
Investing activities:
Capital expenditures		(308,864	)		(187,093	)		(137,751	)
Acquisition of mineral rights under federal lease		(36,108	)		-			-
Purchases of marketable securities		(372,790	)		(119,419	)		-
Sales of marketable securities		214,240			-			-
Purchase of equity-method investment		(5,000	)		-			(2,824	)
Cash acquired from a merger		-			23,505			-
Proceeds from disposition of property and equipment		4,025			1,197			16,649
Proceeds from sale of discontinued operations		-			-			45,000
Proceeds from sale of investment in coal terminal		-			-			1,500
Other, net		(4,000	)		-			(199	)
Net cash used in investing activities		(508,497	)		(281,810	)		(77,625	)
Financing activities:
Proceeds from issuance of long-term debt		-			-			287,500
Payments of bank overdraft		-			-			(160	)
Principal repayments of note payable		-			(18,288	)		(595	)
Principal repayments on long-term debt		(56,854	)		(249,875	)		(193,973	)
Debt issuance costs		(8,594	)		(13,067	)		(10,861	)
Premium payment on early extinguishment of debt		-			-			(10,736	)
Excess tax benefit from stock-based awards		5,505			434			1,980
Proceeds from issuance of common stock, net of offering costs of $7,834		-			-			164,666
Common stock repurchases		(41,664	)		(8,874	)		-
Proceeds from exercise of stock options		5,521			5,171			3,586
Other, net		(115	)		(232	)		-
Net cash (used in) provided by financing activities		(96,201	)		(284,731	)		241,407
Net increase (decrease) in cash and cash equivalents		88,903			(210,321	)		621,825
Cash and cash equivalents at beginning of period		465,869			676,190			54,365
Cash and cash equivalents at end of period	$	554,772		$	465,869		$	676,190
Supplemental cash flow information:
Cash paid for interest	$	61,056		$	40,437		$	33,110
Cash paid for income taxes	$	42,289		$	20,643		$	35,018
Supplemental disclosure of non-cash investing and financing activities:
Issuance of common stock in connection with the Foundation Merger	$	-		$	1,628,601		$	-

See accompanying Notes to Consolidated Financial Statements.

89

 ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

 CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME

(Amounts in thousands, except per share data)

Alpha Natural Resources, Inc. Common Stockholders

	Common Stock				Additional Paid-in			Treasury Stock at			Accumulated Other Comprehensive Income			Retained		Total Alpha Natural Resources Inc.			Noncontrolling			Total
	Shares		Amount		Capital			Cost			(Loss)			Earnings		Equity			Interest			Equity
	(In thousands)
Balances, December 31, 2007		65,769	$	658	$	227,336		$	-		$	(22,290	)	$	175,132	$	380,836		$	1,573		$	382,409
Comprehensive income:
Net income (loss)		-		-		-			-			-			165,701		165,701			(490	)		165,211
Unrealized losses related to cash flow hedges, net of income tax benefit of $4,335		-		-		-			-			(12,908	)		-		(12,908	)		-			(12,908	)
Amounts reclassified to earnings related to settlements of derivative instruments, net of income tax of ($1,224)		-		-		-			-			3,682			-		3,682			-			3,682
Adjustments to unrecognized gains and losses and amortization of employee benefit costs, net of income tax of ($478)		-		-		-			-			1,409			-		1,409			-			1,409
Total comprehensive income (loss)																	157,884			(490	)		157,394
Initial impact of Accounting Standards Codification 470-20, net of income tax of ($23,429)		-		-		69,851			-			-			-		69,851			-			69,851
Contribution of noncontrolling interest in Gallatin in exchange for cash		-		-		-			-			-			-		-			(1,083	)		(1,083	)
Proceeds from public offering of common shares ($41.25 per share), net of offering costs of ($7,834)		4,182		42		164,624			-			-			-		164,666			-			164,666
Exercise of stock options		213		2		3,584			-			-			-		3,586			-			3,586
Stock-based compensation and net issuance of common stock for share vesting		350		3		18,866			-			-			-		18,869			-			18,869
Balances, December 31, 2008		70,514	$	705	$	484,261		$	-		$	(30,107	)	$	340,833	$	795,692		$	-		$	795,692
Comprehensive income:
Net income		-		-		-			-			-			58,005		58,005			-			58,005
Unrealized gains related to cash flow hedges, net of income tax of ($552)		-		-		-			-			4,192			-		4,192			-			4,192
Amounts reclassified to earnings related to the termination of hedge accounting, net of income tax of ($6,968)		-		-		-			-			17,668			-		17,668			-			17,668
Change in fair value of available-for-sale marketable securities, net of income tax benefit of $140		-		-		-			-			(220	)		-		(220	)		-			(220	)
Adjustments to unrecognized gains and losses and amortization of employee benefit costs, net of income tax of ($9,092)		-		-		-			-			14,279			-		14,279			-			14,279
Total comprehensive income																	93,924			-			93,924
Equity consideration for the Foundation acquisition		48,904		489		1,666,850			-			-			-		1,667,339			-			1,667,339
Exercise of stock options		564		6		5,165			-			-			-		5,171			-			5,171
Stock-based compensation and net issuance of common stock for share vesting		801		8		38,029			(8,874	)		-			-		29,163			-			29,163
Treasury stock adjustment		2,434		24		(24	)										-						-
Balances, December 31, 2009		123,217	$	1,232	$	2,194,281		$	(8,874	)	$	5,812		$	398,838	$	2,591,289		$	-		$	2,591,289
Comprehensive income:
Net income		-		-		-			-			-			95,551		95,551			-			95,551
Unrealized gains related to cash flow hedges, net of income tax of ($4,664)		-		-		-			-			7,821			-		7,821			-			7,821
Amounts reclassified to earnings related to the termination of hedge accounting, net of income tax benefit of $181		-		-		-			-			(277	)		-		(277	)		-			(277	)
Change in fair value of available-for-sale marketable securities, net of income tax of ($142)		-		-		-			-			223			-		223			-			223
Adjustments to unrecognized gains and losses and amortization of employee benefit costs, net of income tax benefit of $25,834		-		-		-			-			(41,162	)		-		(41,162	)		-			(41,162	)
Total comprehensive income																	62,156			-			62,156
Exercise of stock options		452		4		5,517			-			-			-		5,521			-			5,521
Stock-based compensation and net issuance of common stock for share vesting		623		6		38,728			(16,665	)		-			-		22,069			-			22,069
Stock repurchase program		-		-		-			(24,999	)							(24,999	)		-			(24,999	)
Balances, December 31, 2010		124,292	$	1,242	$	2,238,526		$	(50,538	)	$	(27,583	)	$	494,389	$	2,656,036		$	-		$	2,656,036

See accompanying Notes to Consolidated Financial Statements.

90

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(1)   Business and Basis of Presentation

Business

Alpha Natural Resources, Inc. and its consolidated subsidiaries (the “Company”) are primarily engaged in the business of extracting, processing and marketing steam and metallurgical coal from surface and deep mines, and mainly sell to electric utilities, steel and coke producers, and industrial customers. The Company, through its subsidiaries, is also involved in marketing coal produced by others to supplement its own production and, through blending, provides its customers with coal qualities beyond those available from its own production.

On July 31, 2009, Alpha Natural Resources, Inc. (“Old Alpha”) and Foundation Coal Holdings, Inc. (“Foundation”) merged (the “Foundation Merger”) with Foundation continuing as the surviving legal corporation of the Foundation Merger. Subsequent to the Foundation Merger, Foundation was renamed Alpha Natural Resources, Inc. (the “Company” or “Alpha”). For financial accounting purposes, the Foundation Merger was treated as a reverse acquisition and Old Alpha was treated as the accounting acquirer. Accordingly, Old Alpha’s results of operations for the year ended December 31, 2008 do not include financial results for Foundation. For the year ended December 31, 2009, Foundation’s financial results are included for the five month period August 1, 2009 through December 31, 2 009.  See Note 19 for further disclosures related to the Foundation Merger.

At December 31, 2010, the Company’s operations consisted of 38 deep and 28 surface mines, which are located in Virginia, West Virginia, Pennsylvania, Kentucky and Wyoming.  At December 31, 2010, the Company had approximately 6,500 employees, of which 21% are affiliated with union representation with the United Mine Workers of America (“UMWA”). The Company’s union represented employees are primarily located in Virginia, West Virginia and Pennsylvania.

On April 7, 2008, the Company completed concurrent public offerings of 4,181,817 shares of common stock at $41.25 per share and $287,500 aggregate principal amount of 2.375% convertible senior notes due 2015 (the “Convertible Notes”). The aggregate net proceeds from the common stock offerings and the notes offerings were $443,262 after commissions and expenses.

Basis of Presentation

The consolidated financial statements include Alpha and its majority owned and controlled subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

During 2008, Old Alpha announced the permanent closure of the Whitetail Kittanning Mine, an adjacent coal preparation plant and other ancillary facilities (“Kingwood”) and sold its interest in Gallatin Materials LLC (“Gallatin”). The results of Kingwood and Gallatin have been reported as discontinued operations for all periods presented. See Note 23 for further disclosures related to discontinued operations.

On January 1, 2009, the Company retrospectively applied accounting guidance for its outstanding 2.375% convertible senior notes due 2015 (“the Convertible Notes”) to separately account for the liability and equity components in a manner reflective of its nonconvertible debt borrowing rate.  The deferred loan fees and debt discount are being amortized and accreted, respectively, over the term of the convertible notes. Interest expense of $12,681, $11,704, and $8,318 was recorded for the years ended December 31, 2010, 2009 and 2008, respectively, related to amortization of the deferred loan fees and accretion of the debt discount.

Reclassifications

During the year ended December 31, 2010, the Company finalized the purchase price allocation for the Foundation Merger and recorded an immaterial correction to the December 31, 2009 consolidated balance sheet to reflect these adjustments as if they were recorded on the acquisition date.  See Note 19 for further details.  Additionally, the Company reclassified $11,500 related to the current portion of interest rate swaps from other non-current liabilities to accrued expenses and other current liabilities in the accompanying Consolidated Balance Sheets as of December 31, 2009.

91

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

(2)   Summary of Significant Accounting Policies

Use of Estimates

The Company’s consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of the Company’s consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Significant items subject to such estimates and assumptions include inventories; mineral reserves; allowance for non-recoupable advanced mining royalties; asset impairments; environmental and reclamation obligations; acquisition accounting; pensions, postemployment, postretirement medical and other employee bene fit obligations; useful lives for depreciation, depletion, and amortization; workers’ compensation and black lung claims; current and deferred income taxes; reserves for contingencies and litigation; revenue recognized using the percentage of completion method; and fair value of financial instruments.  Estimates are based on facts and circumstances believed to be reasonable at the time; however, actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of cash held with reputable depository institutions and highly liquid, short-term investments with original maturities of three months or less. Cash and cash equivalents are stated at cost, which approximates fair market value.  The Company’s cash equivalents consist of money market funds that are maintained in highly rated funds at December 31, 2010.

Marketable Securities

The Company classifies its marketable securities as available-for-sale. These securities are recorded initially at cost and adjusted to fair value at each reporting date. Unrealized gains and losses resulting from the fair value adjustments are classified as a separate component of stockholders’ equity. Realized gains and losses on available-for-sale securities are computed using the specific identification method.  Marketable securities with maturities of one year or less are reported in prepaid expenses and other current assets. Marketable securities with maturities of greater than one year are reported in other non-current assets.  See Notes 5 and 7 for further disclosures related to marketable securities.

Trade Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company's best estimate of the amount of probable credit losses in the Company's existing accounts receivable. The Company establishes provisions for losses on accounts receivable when it is probable that all or part of the outstanding balance will not be collected. The Company regularly reviews its accounts receivable balances and establishes or adjusts the allowance as necessary using the specific identification method.

Account balances are written off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The allowance for doubtful accounts was $90 and $104 at December 31, 2010 and 2009, respectively.  Credit losses were insignificant for the three-year period ended December 31, 2010. A decline in current economic conditions, a prolonged global, national or regional economic recession or other similar events that have occurred in the past may significantly impact the creditworthiness of the Company’s customers.  If any of those factors change, the estimates made by management could also change, which may affect the level of the Company’s future provision for doubtful accounts. The Company does not have off-balance sheet credit exposure relate d to its customers.

Inventories

Coal inventories are stated at the lower of average cost or market. The cost of coal inventories is determined based on average cost of production, which includes all costs incurred to extract, transport and process the coal. Market represents the estimated replacement cost, subject to a floor and ceiling, which considers the future sales price of the product as well as remaining estimated preparation and selling costs.  Coal is reported as inventory at the point in time the coal is extracted from the mine and weighed at a loading facility.

92

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Material and supplies inventories are valued at average cost, less an allowance for obsolete and surplus items.

Deferred Longwall Move Expenses

The Company defers the direct costs, including labor and supplies, associated with moving longwall equipment and the related equipment refurbishment costs in prepaid expenses and other current assets.  These deferred costs are amortized on a units-of-production basis into cost of coal sales over the life of the subsequent panel of coal mined by the longwall equipment.  See Note 5 for further disclosures related to deferred longwall move expenses.

Advanced Mining Royalties

Lease rights to coal lands are often acquired in exchange for royalty payments. Advance mining royalties are advance payments made to lessors under terms of mineral lease agreements that are recoupable against future production. These advance payments are deferred and charged to operations as the coal reserves are mined. The Company regularly reviews recoverability of advance mining royalties and establishes or adjusts the allowance for advance mining royalties as necessary using the specific identification method. In instances where advance payments are not expected to be offset against future production royalties, the Company establishes a provision for losses on the advance payments that have been paid and the scheduled future minimum payments are expensed and recognized as liabilities. Advance royalty balances are charged off against the allowance when the lease rights are either terminated or expire.

The changes in the allowance for advance mining royalties were as follows:

Balance at December 31, 2007	$	5,536
Provision for non-recoupable advance mining royalties		4,453
Write-offs of advance mining royalties		(2,060	)
Balance at December 31, 2008		7,929
Provision for non-recoupable advance mining royalties		961
Write-offs of advance mining royalties(1)		(4,482	)
Balance at December 31, 2009		4,408
Provision for non-recoupable advance mining royalties		679
Write-offs of advance mining royalties		(1,274	)
Balance at December 31, 2010	$	3,813
(1)      Includes $4.1 million reported in discontinued operations.

Property, Equipment and Mine Development Costs

Costs for mineral properties and mine development incurred to expand capacity of operating mines or to develop new mines are capitalized and charged to operations on the units-of-production method over the estimated proven and probable reserve tons directly benefiting from the capital expenditures. Mine development costs include costs incurred for site preparation and development of the mines during the development stage. Mobile mining equipment and other fixed assets are stated at cost and depreciated on either a straight-line basis over estimated useful lives ranging from 1 to 20 years; or on a units-of-production basis. Leasehold improvements are amortized using the straight-line method, over the shorter of the estimated useful lives or term of the lease. Major repairs and betterments that significantly extend original useful liv es or improve productivity are capitalized and depreciated over the period benefitted. Maintenance and repairs are expensed as incurred.   When equipment is retired or disposed, the related cost and accumulated depreciation are removed from the respective accounts and any profit or loss on disposal is recognized in cost of coal sales.

The Company also capitalizes certain costs incurred in the development of internal-use software, including external direct material and service costs, and employee payroll and payroll-related costs.  All capitalized internal-use software costs are amortized using the straight-line method over the estimated useful life of the asset.

93

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Owned and Leased Mineral Rights

Costs to obtain coal lands and leased mineral rights are capitalized and amortized to operations as depletion expense using the units-of-production method.  Only proven and probable reserves are included in the depletion base.  Depletion expense is included in depreciation, depletion and amortization on the accompanying Consolidated Statements of Operations and was $111,846, $69,779 and $47,843 for the years ended December 31, 2010, 2009, and 2008, respectively.

Acquired Coal Supply Agreements

Application of acquisition accounting in connection with the Foundation Merger resulted in the recognition of a significant asset for above market-priced coal supply agreements and a liability for below market-priced coal supply agreements on the date of the acquisition. The coal supply agreements were valued based on the present value of the difference between the expected contract revenues based on the stated contract terms, net of royalties and taxes imposed on sales revenues, and the estimated net contract revenues derived from applying forward market prices at the acquisition date for new contracts of similar duration and coal qualities. The coal supply agreement assets and liabilities are being amortized over the actual amount of tons shipped under each contract.  The coal supply agreement liability is reported in other n on-current liabilities in the Consolidated Balance Sheets. Amortization of coal supply agreement assets was $234,094 and $133,016 of expense and amortization of coal supply agreement liabilities was a credit to expense of ($7,301) and ($5,408), equating to a net expense of $226,793 and $127,608 for the years ended December 31, 2010 and 2009, respectively, and reported as amortization of acquired coal supply agreements, net in the Consolidated Statements of Operations. Future net amortization expense related to acquired coal supply agreements, net is expected to be $119,498, $31,706, and ($1,709) for the years ending December 31, 2011, 2012, and 2013, respectively.

Asset Impairment and Disposal of Long-Lived Assets

Long-lived assets, such as property, equipment, mine development costs, owned and leased mineral rights and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized equal to the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed would separately be presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and would no longer be depreciated. The assets and liabilities of a disposal group classified as held for sale would be presented separately in the Consolidated Balance Sheets.

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the net identifiable tangible and intangible assets of acquired companies. Goodwill is not amortized; instead, it is tested for impairment annually or more frequently if indicators of impairment exist. The Company has routinely performed its goodwill impairment testing as of August 31 of each year.  Subsequent to the impairment test performed on August 31, 2010, the Company decided to change its impairment testing date to October 31.  The Company believes the change in the impairment testing date more closely aligns the impairment testing date with the Company’s long-range planning and forecasting process.  The change in the impairment testing date, which represents a change in the method of applying an accounting principle, is believed by the Company to be preferable.  The Company performed a goodwill impairment test as of October 31, 2010 and absent any indicators of impairment, will continue to perform an annual impairment test on October 31 in subsequent years.

The Company tests its consolidated goodwill for impairment using a fair value approach at the reporting unit level, and performs the goodwill impairment test in two steps. Step one compares the fair value of each reporting unit to its carrying amount. If step one indicates that an impairment potentially exists, the second step is performed to measure the amount of impairment, if any. Goodwill impairment exists when the estimated fair value of goodwill is less than its carrying value.

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

94

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Asset Retirement Obligations

Minimum standards for mine reclamation have been established by various regulatory agencies and dictate the reclamation requirements at the Company's operations. The Company’s asset retirement obligations consist principally of costs to reclaim acreage disturbed at surface operations and estimated costs to reclaim support acreage and perform other related functions at underground mines.  The Company records these reclamation obligations at fair value in the period in which the legal obligation associated with the retirement of the long-lived asset is incurred. When the liability is initially recorded, the offset is capitalized by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. To settle the liability, the obligation is paid, and to the extent there is a difference between the liability and the amount of cash paid, a gain or loss upon settlement is recorded. The Company annually reviews its estimated future cash flows for its asset retirement obligations. See Note 10 for further disclosures related to the Company’s asset retirement obligations.

Income Taxes

The Company recognizes deferred tax assets and liabilities using enacted tax rates for the effect of temporary differences between the book and tax bases of recorded assets and liabilities. Deferred tax assets are reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized. In evaluating the need for a valuation allowance, the Company takes into account various factors, including objective evidence obtained from historical earnings, future sales commitments, the expected level of future taxable income and available tax planning strategies, and the impact the alternative minimum tax has on utilization of deferred tax assets. If future taxable income is lower than expected or if expected tax planning strategies are not available as anticipated, the Company would rec ord a change to the valuation allowance through income tax expense in the period the determination is made. See Note 14 for further disclosures related to the Company’s income taxes.

Revenue Recognition

The Company earns revenues primarily through the sale of coal, but also earns other revenues from sales of parts, equipment, filters, rebuild and refurbishment services, sales of coalbed methane and natural gas and road construction. With the exception of road construction revenue, the Company recognizes revenue using the following general revenue recognition criteria: 1) persuasive evidence of an arrangement exists; 2) delivery has occurred or services have been rendered; 3) the price to the buyer is fixed or determinable; and 4) collectability is reasonably assured. Revenue from road construction contracts is recognized under the percentage of completion method of accounting.

Delivery on our coal sales is determined to be complete for revenue recognition purposes when title and risk of loss has passed to the customer in accordance with stated contractual terms and there are no other future obligations related to the shipment. For domestic shipments, title and risk of loss generally passes as the coal is loaded into transport carriers for delivery to the customer. For international shipments, title generally passes at the time coal is loaded onto the shipping vessel. In the event that a new contract is negotiated with a customer which incorporates an old contract with different pricing, the Company applies a single contract accounting concept and recognizes as revenue the lower of the cumulative amount billed or an amount based on the weighted average price of the new and old contracts applied to the tons sold .

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

Deferred Financing Costs

The costs to obtain new debt financing or amend existing financing agreements are deferred and amortized to interest expense over the life of the related indebtedness or credit facility using the straight-line method which approximates the effective interest method. Unamortized deferred financing costs are included in other non-current assets in the Consolidated Balance Sheets.

Virginia Coalfield Employment Enhancement Tax Credit

For tax years 1996 through 2014, Virginia companies with an economic interest in coal earn tax credits based upon tons sold, seam thickness, and employment levels. The maximum credit earned equals $0.40 per ton for surface mined coal and $1.00 or $2.00 per ton for deep mined coal depending on seam thickness. Credits allowable are reduced from the maximum amounts if employment levels are not maintained from the previous year, and no credit is allowed for coal sold to Virginia utilities. Currently, the cash benefit of the credit is realized three years after being earned and either offsets taxes imposed by Virginia at 100% or is refundable by the state at 85% of the face value to the extent taxes are not owed. The Company records the present value of the portion of the credit that is refundable as a reduction of operating costs a s it is earned.  

95

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Workers’ Compensation and Pneumoconiosis (Black Lung) Benefits  

Workers' Compensation

The Company is self-insured for workers' compensation claims at certain of its operations in West Virginia, Pennsylvania and certain idled or closed mines. Workers' compensation at all other locations is covered by a third-party insurance provider.

The liabilities for workers' compensation claims that are self-insured by the Company are estimates of the ultimate losses incurred based on the Company's experience, and include a provision for incurred but not reported losses. Adjustments to the probable ultimate liabilities are made either semi-annually or annually based on an actuarial study and adjustments to the liability are recorded based on the results of this study. These obligations are included in the Consolidated Balance Sheets as accrued expenses and other current liabilities and other non-current liabilities.

Black Lung Benefits

The Company is required by federal and state statutes to provide benefits to employees for awards related to black lung. The Company is self insured at certain locations and covered by a third party insurance provider at other locations.  Charges are made to operations for self-insured black lung claims, as determined by an independent actuary at the present value of the actuarially computed liability for such benefits over the employee's applicable term of service. The Company recognizes in its balance sheet the amount of the Company's unfunded Accumulated Benefit Obligation (“ABO”) at the end of the year. Amounts recognized in accumulated other comprehensive income (loss) are adjusted out of accumulated other comprehensive income (loss) when they are subsequently recognized as components of net periodic benefit co st.

Pension and Other Postretirement Benefits

The Company is required to recognize the overfunded or underfunded status of a defined benefit pension plan as an asset or liability in its Consolidated Balance Sheets and to recognize changes in that funded status in the year in which the changes occur through other comprehensive income (loss). The Company is required to measure plan assets and benefit obligations as of the date of the Company’s fiscal year-end balance sheet and provide the required disclosures as of the end of each fiscal year.  See Note 15 for further disclosures related to pensions.

The Company accounts for health care benefits provided for current and certain retired employees and their dependents by accruing the cost of such benefits over the service lives of employees. Unrecognized actuarial gains and losses are amortized over the estimated average remaining service period for active employees and over the estimated average remaining life for retirees. The Company recognizes in its balance sheet the amount of the Company's unfunded Accumulated Postretirement Benefit Obligation (“APBO”) at the end of the year. Amounts recognized in accumulated other comprehensive loss are adjusted out of accumulated other comprehensive loss when they are subsequently recognized as components of net periodic benefit cost.  See Note 15 for further disclosures related to other postretirement benefits.

Earnings Per Share

Basic earnings per share is computed by dividing net income by the weighted-average number of outstanding common shares for the period. Diluted earnings per share reflects the potential dilution that could occur if instruments that may require the issuance of common shares in the future were settled and the underlying common shares were issued.  Diluted earnings per share is computed by increasing the weighted-average number of outstanding common shares computed in basic earnings per share to include the additional common shares that would be outstanding after issuance and adjusting net income from changes that would result from the issuance.  Only those securities that are dilutive are included in the calculation.   See Note 3 for further disclosures related to earnings per share.

96

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Stock-Based Compensation

The Company recognizes expense for stock-based compensation awards based on the estimated grant-date fair value. For all grants, the amount of compensation expense to be recognized is adjusted for an estimated forfeiture rate which is based in part on historical data and other relevant factors. Compensation expense for awards with cliff vesting provisions is recognized on a straight-line basis from the measurement date through the vesting date. Compensation expense for awards with graded vesting provisions is recognized using the accelerated attribution method. See Note 16 for further disclosures related to the Company’s stock-based compensation arrangements.

Derivative Instruments and Hedging Activities

Derivative financial instruments are recognized as either assets or liabilities in the Consolidated Balance Sheets and measured at fair value. On the date a derivative instrument is entered into, the Company generally designates a qualifying derivative instrument as a hedge of the variability of cash flows to be received or paid related to a recognized asset or liability or forecasted transaction (cash flow hedge). The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to specific firm commitments or forecasted transactions. The Company also formally assesses both at the hedge’s inception and on an ongoing basis , whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of the related hedged items. When it is determined that a derivative is not highly effective as a hedge or that it has ceased to be a highly effective hedge, the Company discontinues hedge accounting prospectively and records all future changes in fair value in current period earnings or losses.

For derivative instruments that have not been designated as cash flow hedges, changes in fair value are recorded in current period earnings or losses. For derivative instruments that have been designated as cash flow hedges, the effective portion of the changes in fair value are recorded in accumulated other comprehensive income (loss) and any portion that is ineffective is recorded in current period earnings or losses. Amounts recorded in accumulated other comprehensive income (loss) are reclassified to earnings or losses in the period the underlying hedged transaction affects earnings or when the underlying hedged transaction is no longer probable of occurring. See Note 13 for further disclosures related to the Company’s derivative financial instruments and hedging activities.

Equity-Method Investments

Investments in unconsolidated affiliates that the Company has the ability to exercise significant influence over, but not control, the affiliate’s operating activities are accounted for under the equity-method of accounting. Under the equity method of accounting, the Company records its proportionate share of the entity’s net income or loss at each reporting period in the Consolidated Statements of Operations in miscellaneous income (expense), net, with a corresponding entry to increase or decrease the carrying value of the investment.

Other Comprehensive Income (Loss)

In addition to net income, other comprehensive income (loss) includes changes to accumulated other comprehensive income (loss) such as adjustments to unrecognized gains and losses and amortization of employee benefit plan costs, the effective portion of changes in fair value of derivative instruments that qualify as cash flow hedges and changes in fair value of available-for-sale marketable securities.

New Accounting Pronouncements Adopted

In June 2009, the FASB issued Statement of Financial Accounting Standards No. 167, Amendments to FASB Interpretation No. 46(R), which modifies how a company determines when an entity that is insufficiently capitalized or is not controlled through voting (or similar rights) should be consolidated. The guidance clarifies that the determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. The guidance requires an ongoing reassessment of whether a company is the primary beneficiary of a variable interest entity. It also requires additional disclosures about a c ompany’s involvement in variable interest entities and any significant changes in risk exposure due to that involvement. The guidance is applicable for annual periods beginning after November 15, 2009 (January 1, 2010 for the Company). The adoption of the guidance did not have a material impact on the Company’s financial position, results of operations and cash flows.

In June 2009, the FASB issued ASC 860, Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140 (“ASC 860”), which amends the criteria for a transfer of a financial asset to be accounted for as a sale, redefines a participating interest for transfers of portions of financial assets, eliminates the qualifying special-purpose entity concept and provides for new disclosures. ASC 860 is effective for fiscal years beginning after November 15, 2009. The adoption of the guidance did not have a material effect on the Company’s financial position, results of operations or cash flows.

97

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Updated (“ASU”) 2010-6, Improving Disclosures About Fair Value Measurements (“ASU 2010-6”),which requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair- value measurements. ASU 2010-6 is effective for annual reporting periods beginning after December 15, 2009, except for Level 3 reconciliation disclosures which are effective for annual periods beginning after December 15, 2010. ASU 2010-6 relat es solely to disclosures in the notes to the financial statements.  The adoption of the applicable provisions in 2010 did not have an effect on the Company’s financial position, results of operations or cash flows.  The adoption of the applicable provisions subsequent to 2010 will not have an effect on the Company’s financial position, results of operations or cash flows.

(3)     Earnings Per Share

The number of shares used to calculate basic earnings (loss) per common share is based on the weighted average number of the Company’s outstanding common shares during the respective periods. The number of shares used to calculate diluted earnings (loss) per share is based on the number of common shares used to calculate basic earnings (loss) per share plus the dilutive effect of stock options and other stock-based instruments held by the Company’s employees and directors during each period and the Convertible Notes when these are convertible into the Company’s common stock. The Convertible Notes, which were issued in April 2008, become dilutive for earnings per share calculations in certain circumstances.  The shares that would be issued to settle the conversion spread are included in the diluted earning s per common share calculation when the conversion option is in the money.  For the years ended December 31, 2010 and 2009, the conversion option for the Convertible Notes was not in the money, and therefore there was no dilutive earnings per share impact. For the year ended December 31, 2008, there were 734,613 shares included in the computation of year-to-date diluted earnings per share for the period when the Convertible Notes were in the money during the year.

For the year ended December 31, 2010, there were 32,795 shares excluded from the computation of year-to-date diluted earnings per share as the shares were anti-dilutive, related to restricted stock awards and restricted stock units.

The following table provides a reconciliation of weighted average shares outstanding used in the basic and diluted earnings per share computations for the periods presented:

	Years Ended December 31,
	2010		2009		2008
Weighted average shares - basic		119,808,514		90,662,718		68,453,724
Dilutive effect of stock equivalents		1,949,435		1,039,910		1,806,011
Weighted average shares- diluted		121,757,949		91,702,628		70,259,735

98

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

(4)     Inventories, net

Inventories, net consisted of the following:

	December 31,
	2010		2009
Raw coal	$	14,115	$	19,180
Saleable coal		130,364		112,004
Materials and supplies and other, net		53,693		45,188
Total inventories, net	$	198,172	$	176,372

(5)     Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consisted of the following:

	December 31,
	2010		2009
Marketable securities - short term (1)	$	217,191	$	29,501
Prepaid insurance		3,292		33,776
Notes and other receivables		17,951		28,402
Deferred income taxes - current		29,652		-
Deferred longwall move expenses		6,313		3,186
Advanced mining royalties, net		3,533		3,522
Refundable income taxes		9,918		29,590
Derivative financial instruments		13,558		7,939
Construction costs in excess of billings		8,201		19,535
Prepaid freight		23,330		13,229
Other prepaid expenses		8,816		8,273
Total prepaid expenses and other current assets	$	341,755	$	176,953

(1) Short-term marketable securities consisted of the following:

		December 31, 2010
				Unrealized
	Cost			Gain			Loss				Fair value
Short-term marketable securities:
U.S. treasury and agency securities		$	71,777		$	158		$	-			$	71,935
Corporate debt securities			145,237			24			(5	)			145,256
Total short-term marketable securities		$	217,014		$	182		$	(5	)		$	217,191

99

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

		December 31, 2009
				Unrealized
	Cost			Gain			Loss				Fair value
Short-term marketable securities:
U.S. treasury and agency securities		$	22,338		$	-		$	(23	)		$	22,315
Corporate debt securities			7,180			6			-				7,186
Total short-term marketable securities		$	29,518		$	6		$	(23	)		$	29,501

(6)     Property, Equipment and Mine Development Costs

Property, equipment, and mine development costs consisted of the following:

	December 31,
	2010		2009
Plant and mining equipment	$	1,647,217	$	1,453,837
Mine development		209,898		125,541
Coalbed methane equipment		10,153		6,211
Office equipment and software		33,416		30,005
Vehicles and other		17,041		14,814
Construction in progress		84,143		67,201
		2,001,868		1,697,609
Less accumulated depreciation and amortization		869,881		615,163
Total property, equipment and mine development costs, net	$	1,131,987	$	1,082,446

Depreciation and amortization expense from continuing operations associated with property, equipment and mine development costs was $257,649, $182,616, and $121,102 for the years ended December 31, 2010, 2009, and 2008, respectively.

Interest costs applicable to major asset additions are capitalized during the construction period. During the years ended December 31, 2010, 2009, and 2008, interest costs of $2,152, $492, and $942 were capitalized, respectively.

As of December 31, 2010, the Company had commitments to purchase approximately $88,636 of new equipment, expected to be acquired at various dates in 2011 and 2012.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

(7)     Other Non-current Assets

Other non-current assets consisted of the following:

	December 31,
	2010		2009
Marketable securities - long term (1)	$	60,159	$	89,485
Unamortized deferred financing costs, net		17,041		14,702
Advance mining royalties, net		14,408		13,357
Virginia tax credit, net		16,317		18,025
Equity-method investments		15,130		11,688
Derivative financial instruments		3,045		2,763
Other		17,626		7,004
Total other non-current assets	$	143,726	$	157,024

(1) Long-term marketable securities, with maturity dates between one and three years, consisted of the following:

	December 31, 2010
				Unrealized
	Cost			Gain			Loss				Fair value
Long-term marketable securities:
US treasury and agency securities		$	60,326		$	44		$	(211	)		$	60,159

	December 31, 2009
				Unrealized
	Cost			Gain			Loss				Fair value
Long-term marketable securities:
US treasury and agency securities		$	89,828		$	-		$	(343	)		$	89,485

(8)     Accrued Expenses and Other Current Liabilities

Accrued expenses and other current liabilities consisted of the following:

	December 31,
	2010		2009
Wages and employee benefits	$	111,631	$	75,936
Current portion of asset retirement obligations		13,006		14,908
Deferred income taxes - current		-		10,237
Taxes other than income taxes		62,041		58,245
Freight		16,446		8,827
Current portion of self insured workers' compensation obligations		7,935		10,893
Interest payable		10,590		11,215
Derivative financial instruments		19,929		26,461
Current portion of postretirement medical benefit obligations		28,265		27,393
Income taxes payable		6,278		-
Other		37,633		29,145
Total accrued expenses and other current liabilities	$	313,754	$	273,260

101

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

(9)     Long-Term Debt

Long-term debt consisted of the following:

	December 31,
	2010			2009
Term loan due 2014	$	227,896		$	284,750
7.25% senior notes due 2014		298,285			298,285
2.375% convertible senior notes due 2015		287,500			287,500
Other		7,819			-
Debt discount		(67,349	)		(80,282	)
Total long-term debt	$	754,151		$	790,253
Less current portion		11,839			33,500
Long-term debt, net of current portion	$	742,312		$	756,753

Alpha Credit Facility

On April 15, 2010, the Company and its lenders amended and restated (the “Amend and Extend”) the Alpha Credit Facility (the “Facility”). The Amend and Extend, among other things, extended the maturity of $236,800 of the then-outstanding term loans and $554,000 of existing revolving credit facility (the “revolver”) commitments from July 7, 2011 to July 31, 2014.  The Amend and Extend added $300,400 of additional borrowing capacity with a maturity of July 31, 2014, to increase the aggregate principal amount available to be drawn under the revolver to $950,400. Subsequently, the Company terminated $96,000 of commitments under the revolver and prepaid $39,600 of the term loans, both of which related to lenders that chose not to extend their commitments beyond the original expiration date of July 7, 2011. Additionally, the Amend and Extend (1) increased the amount of the “accordion” feature of the Facility to $400,000, all of which was available for the Company to exercise following the closing of the Amend and Extend; and, (2) also made other changes to the Facility, including amendments to certain of the negative covenants in the Facility to provide the Company greater financial and operating flexibility.

As of December 31, 2010, the total borrowing capacity under the revolver was $854,400. Borrowings under the revolver bear interest at a base rate plus an applicable margin or at an adjusted London interbank offered rate (“LIBOR”) plus an applicable margin.  The applicable margin is subject to adjustment based on leverage ratios. There were no borrowings outstanding under the revolver at December 31, 2010 or December 31, 2009.  The revolver can also be used to secure outstanding letters of credit.  Letters of credit in the amount of $7,650 and $113,633 were outstanding under the revolver as of December 31, 2010 and December 31, 2009, respectively. The amount available under the revolver as of December 31, 2010 was $846,750 after giving effect to the outstanding letters of credit.  Additi onally, the Company is required to pay a commitment fee of 0.5% on unused borrowings.

The Facility’s secured term loan bears interest at a base rate plus an applicable margin or at an adjusted LIBOR rate plus an applicable margin. The interest rate approximated 3.56% and 3.50% at December 31, 2010 and December 31, 2009, respectively. As of December 31, 2010, the Company’s secured term loan had a carrying value of $226,705, net of debt discount of $1,191, with $11,839 classified as current portion of long-term debt. As of December 31, 2009, the Company’s secured term loan had a carrying value of $282,739, net of debt discount of $2,011, with $33,500 classified as current portion of long-term debt.

7.25% Senior Notes Due August 1, 2014

Foundation PA Coal Company, LLC (“Foundation PA”), one of the Company’s subsidiaries, has notes that mature on August 1, 2014 (the “2014 Notes”) in the aggregate principal amount of $298,285 as of December 31, 2010 and December 31, 2009. The 2014 Notes are guaranteed on a senior unsecured basis by Alpha Natural Resources, Inc. and all of its subsidiaries other than Foundation PA and ANR Receivables Funding LLC.  The 2014 Notes pay interest semi-annually and are redeemable at Foundation PA’s option, at a redemption price equal to 102.417%, 101.208% and 100% of the principal amount if redeemed during the twelve month periods beginning August 1, 2010, 2011 and 2012, respectively, plus accrued interest.  As of December 31, 2010, the carrying value of the 2014 Notes was $297,272, net of debt discount of $1,013.  As of December 31, 2009, the carrying value of the 2014 Notes was $296,990, net of debt discount of $1,295.

102

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

2.375% Convertible Senior Notes Due April 15, 2015

As of December 31, 2010 and 2009, the Company had $287,500 aggregate principal amount of 2.375% convertible senior notes due April 15, 2015.  The Convertible Notes bear interest at a rate of 2.375% per annum, payable semi-annually in arrears on April 15 and October 15 of each year, and will mature on April 15, 2015, unless previously repurchased by the Company or converted.  The Company separately accounts for the liability and equity components of its Convertible Notes in a manner reflective of its nonconvertible debt borrowing rate.  The related deferred loan costs and discount are being amortized and accreted, respectively, over the seven-year term of the Convertible Notes, and provide for an effective interest rate of 8.64%.  As of December 31, 2010 and 2009, the carrying amounts of the debt co mponent were $222,355 and $210,524, respectively.  As of December 31, 2010 and 2009, the unamortized debt discount was $65,145 and $76,976, respectively.  As of December 31, 2010 and 2009, the carrying amount of the equity component was $69,851.

The Convertible Notes are the Company’s senior unsecured obligations and rank equally with all of the Company’s existing and future senior unsecured indebtedness. The Convertible Notes are effectively subordinated to all of the Company’s existing and future secured indebtedness and all existing and future liabilities of the Company’s subsidiaries, including trade payables.  The Convertible Notes are convertible in certain circumstances and in specified periods at an initial conversion rate of 18.2962 shares of common stock per one thousand principal amount of Convertible Notes, subject to adjustment upon the occurrence of certain events set forth in the Indenture. Upon conversion of the Convertible Notes, holders will receive cash up to the principal amount of the notes to be converted, and any excess co nversion value will be delivered in cash, shares of common stock or a combination thereof, at the Company's election.

The Convertible Notes Indenture contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee, Union Bank of California (“UBOC”), or the holders of not less than 25% in aggregate principal amount of the Convertible Notes then outstanding may declare the principal of Convertible Notes and any accrued and unpaid interest thereon immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to the Company, the principal amount of the Convertible Notes together with any accrued and unpaid interest thereon will automatically become due and be immediately payable.

As a result of the Foundation Merger, the Convertible Notes became convertible at the option of the holders beginning on June 18, 2009, and remained convertible through the 30th day after the effective date of the Foundation Merger, which was July 31, 2009.  There were no notes converted during the conversion period. The Convertible Notes were not convertible as of December 31, 2010 and 2009 and therefore have been classified as long-term debt.

Accounts Receivable Securitization

The Company and certain subsidiaries are a party to an $150,000 accounts receivable securitization facility with a third party financial institution (the “A/R Facility”). The Company formed ANR Receivables Funding, LLC (the “SPE”), a special-purpose, bankruptcy-remote wholly-owned subsidiary to purchase trade receivables generated by certain of the Company’s operating and sales subsidiaries, without recourse (other than customary indemnification obligations for breaches of specific representations and warranties), and then transfer senior undivided interests in up to $150,000 of those accounts receivable to a financial institution for the issuance of letters of credit or for cash borrowings for the ultimate benefit of the Company.

The SPE is consolidated into the Company’s financial statements, and therefore the purchase and sale of trade receivables by the SPE from the Company’s operating and sales receivables has no impact on the Company’s consolidated financial statements. The assets of the SPE, however, are not available to the creditors of the Company or any other subsidiary. The SPE pays facility fees, program fees and letter of credit fees (based on amounts of outstanding letters of credit), as defined in the definitive agreements for the A/R Facility.  Available borrowing capacity is based on the amount of eligible accounts receivable as defined under the terms of the definitive agreements for the A/R Facility and varies over time. Unless extended by the parties, the receivables purchase agreement supporting the borrowings under the A/R Facility expires December 9, 2015, or earlier upon the occurrence of certain events customary for facilities of this type, including the failure for any reason by liquidity providers to the A/R Facility’s financial institutions to renew their commitments not less often than annually.

As of December 31, 2010 and 2009, letters of credit in the amount $63,805 and $143,474 were outstanding under the A/R Facility, respectively, and no cash borrowing transactions had taken place. If outstanding letters of credit exceed borrowing capacity, the Company is required to provide additional collateral in the form of restricted cash to secure outstanding letters of credit. Under the A/R Facility, the SPE is subject to certain affirmative, negative and financial covenants customary for financings of this type, including restrictions related to, among other things, liens, payments, merger or consolidation and amendments to the agreements underlying the receivables pool. Alpha Natural Resources, Inc. has agreed to guarantee the performance by its subsidiaries, other than the SPE, of their obligations under the A/R Facility. The Compa ny does not guarantee repayment of the SPE’s debt under the A/R Facility. The financial institution, which is the administrator, may terminate the A/R Facility upon the occurrence of certain events that are customary for facilities of this type (with customary grace periods, if applicable), including, among other things, breaches of covenants, inaccuracies of representations and warranties, bankruptcy and insolvency events, changes in the rate of default or delinquency of the receivables above specified levels, a change of control and material judgments. A termination event would permit the administrator to terminate the program and enforce any and all rights and remedies, subject to cure provisions, where applicable.

103

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Other

In 2010, the Company entered into certain agreements to develop, build and subsequently lease its new corporate headquarters. The Company has provided certain financial guarantees in connection with the development and construction of the building and is considered the owner of the building from an accounting perspective. The Company has recorded $7,819 as a liability and corresponding asset in its consolidated financial statements for amounts expended and guaranteed by the Company through December 31, 2010. The Company expects to record approximately $12,500 in 2011 for additional amounts anticipated to be expended for the construction of the building and guaranteed by the Company. The building is expected to be completed at the end of 2011.

Old Alpha Credit Agreement

On July 31, 2009, in conjunction with the Foundation Merger (Note 19), Old Alpha terminated its then-existing senior secured credit facilities, which consisted of a $250,000 term loan facility, of which $233,125 was outstanding at July 31, 2009 (and due in 2012), and a $375,000 revolving credit facility. On July 31, 2009, the Company repaid the outstanding balance under the term loan and recorded a loss on early extinguishment of debt to write off the remaining balance of deferred loan costs in the amount of $5,641.

Future maturities of long-term debt as of December 31, 2010 are as follows:

2011	$	11,839
2012		20,763
2013		23,722
2014		469,998
2015		287,559
Thereafter		7,619
Total long-term debt	$	821,500

(10)     Asset Retirement Obligations

As of December 31, 2010 and 2009, the Company had recorded asset retirement obligation accruals for mine reclamation and closure costs totaling $222,993 and $205,632, respectively. The portion of the costs expected to be paid within a year of $13,006 and $14,908, as of December 31, 2010 and 2009, respectively, is included in accrued expenses and other current liabilities. There were no assets that were legally restricted for purposes of settling asset retirement obligations at December 31, 2010 or 2009. The Company is self-bonded for its asset retirement obligations in West Virginia and Wyoming, subject to periodic evaluation of the Company’s financial position by the applicable state and meeting certain financial ratios defined by each state. Asset retirement obligations for states other than Wyoming and West Virginia ar e secured by surety bonds.

104

 

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Changes in the asset retirement obligations were as follows:

Total asset retirement obligations at December 31, 2008	$	98,940
Accretion for the period		12,101
Acquisitions during the period (including amounts related to the Foundation Merger)		99,910
Sites added during the period		3,092
Revisions in estimated cash flows		(1,113	)
Expenditures for the period		(7,298	)
Total asset retirement obligations at December 31, 2009		205,632
Accretion for the period		17,621
Sites added during the period		2,290
Revisions in estimated cash flows (1)		3,043
Expenditures for the period		(5,593	)
Total asset retirement obligations at December 31, 2010	$	222,993
Less current portion		(13,006	)
Long-term portion	$	209,987

(1) Revisions in estimated cash flows include $4,538 of a reduction in the asset retirement obligation resulting from the transfer of the related property to a third party.

(11)     Other Non-current Liabilities

Other non-current liabilities consisted of the following:

	December 31,
	2010		2009
Self insured workers' compensation obligations	$	43,767	$	32,989
Black lung obligations		45,021		30,261
Acquired coal supply agreements, net		13,031		20,202
Derivative financial instruments		9,050		16,866
Income taxes		13,960		13,960
Deferred production tax		12,230		12,294
Other		17,980		11,285
Total other non-current liabilities	$	155,039	$	137,857

(12)     Fair Value of Financial Instruments and Fair Value Measurements

The estimated fair values of financial instruments are determined based on relevant market information. These estimates involve uncertainty and cannot be determined with precision. The following methods and assumptions are used to estimate the fair value of each class of financial instrument.

The carrying amounts for cash and cash equivalents, trade accounts receivable, net, prepaid expenses and other current assets, trade accounts payable, and accrued expenses and other current liabilities approximate fair value due to the short maturity of these instruments.

Long-term Debt: The fair value of the Convertible Notes was estimated using observable market prices as these securities are traded. The fair value of the 2014 Notes and the term loan due 2014 is estimated based on a current market rate of interest offered to the Company for debt of similar maturities.

105

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The estimated fair values of long-term debt were as follows:

	December 31, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
Term loan due 2014(1)	$	226,705	$	231,475	$	282,739	$	279,055
7.25% senior notes due 2014(2)		297,272		303,505		296,990		302,014
2.375% convertible senior notes due 2015(3)		222,355		383,094		210,524		325,953
Total long-term debt	$	746,332	$	918,074	$	790,253	$	907,022

(1)  Net of debt discount of $1,191 and $2,011 as of December 31, 2010 and December 31, 2009, respectively.

(2)  Net of debt discount of $1,013 and $1,295 as of December 31, 2010 and December 31, 2009, respectively.

(3)  Net of debt discount of $65,145 and $76,976 as of December 31, 2010 and December 31, 2009, respectively.

ASC 820 requires disclosures about how fair value is determined for assets and liabilities and a hierarchy for which these assets and liabilities must be grouped, based on significant levels of inputs as follows:

Level 1 - Quoted prices in active markets for identical assets or liabilities;

Level 2 - Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and

Level 3 - Unobservable inputs in which there is little or no market data which require the reporting entity to develop its own assumptions.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).  

The following tables set forth by level, within the fair value hierarchy, the Company’s financial and non-financial assets and liabilities that were accounted for at fair value on a recurring and non-recurring basis as of December 31, 2010 and 2009, respectively. As required by ASC 820, financial and non-financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the determination of fair value for assets and liabilities and their placement within the fair value hierarchy levels.

	December 31, 2010
	Total Fair Value			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Financial assets (liabilities):
U.S. treasury and agency securities	$	132,094		$	132,094	$	-		$	-
Corporate debt securities	$	145,256		$	-	$	145,256		$	-
Forward coal sales	$	2,674		$	-	$	2,674		$	-
Forward coal purchases	$	(3,958	)	$	-	$	(3,958	)	$	-
Commodity swaps	$	10,523		$	-	$	10,523		$	-
Commodity options	$	(264	)	$	-	$	(264	)	$	-
Interest rate swaps	$	(21,304	)	$	-	$	(21,304	)	$	-
Freight swaps	$	(47	)	$	-	$	(47	)	$	-

106

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

	December 31, 2009
	Total Fair Value			Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Financial assets (liabilities):
U.S. treasury and agency securities	$	111,800		$	111,800	$	-		$	-
Corporate debt securities	$	7,186		$	-	$	7,186		$	-
Forward coal sales	$	3,414		$	-	$	3,414		$	-
Forward coal purchases	$	(2,861	)	$	-	$	(2,861	)	$	-
Commodity swaps	$	(8,691	)	$	-	$	(8,691	)	$	-
Commodity options	$	(255	)	$	-	$	(255	)	$	-
Interest rate swaps	$	(24,232	)	$	-	$	(24,232	)	$	-

The following methods and assumptions were used to estimate the fair values of the assets and liabilities in the tables above. 

Level 1 Fair Value Measurements

U.S. Treasury and Agency Securities – The fair value of marketable securities is based on observable market data.

Level 2 Fair Value Measurements

Corporate Debt Securities – The fair values of the Company’s corporate debt securities are obtained from a third-party pricing service provider.  The fair values provided by the pricing service provider are estimated using pricing models, where the inputs to those models are based on observable market inputs including credit spreads and broker-dealer quotes, among other inputs.  The Company classifies the prices obtained from the pricing services within Level 2 of the fair value hierarchy because the underlying inputs are directly observable from active markets.  However, the pricing models used do entail a certain amount of subjectivity and therefore differing judgments in how the underlying inputs are modeled could result in different est imates of fair value.

Forward Coal Sales and Purchases – The fair values of the forward coal purchase and sale contracts were estimated using discounted cash flow calculations based upon actual contract prices and forward commodity price curves. The curves were obtained from independent pricing services reflecting broker market quotes. The fair values are adjusted for counter-party risk, when applicable.

Commodity Swaps – The fair values of commodity swaps are estimated using valuation models which include assumptions about commodity prices based on those observed in the underlying markets. The fair values are adjusted for counter-party risk, when applicable.

Commodity Options – The fair values of the commodity options were estimated using an option pricing model that incorporates historical volatility of the underlying commodity, the strike price, notional amount, current market price and risk free interest rate. The fair values are adjusted for counter-party risk, when applicable.

Interest Rate Swaps – The fair values of the interest rate swaps were estimated using discounted cash flow calculations based upon forward interest-rate yield curves. The curves were obtained from independent pricing services reflecting broker market quotes. The fair values are adjusted for counter-party risk, when applicable.

Freight Swaps – The fair values of freight swaps are estimated using valuation models which include assumptions about freight prices based on those observed in the underlying markets. The fair values are adjusted for counter-party risk, when applicable.

(13)     Derivative Financial Instruments

Forward Contracts

The Company manages price risk for coal sales and purchases through the use of coal supply agreements. The Company evaluates each of its coal sales and coal purchase forward contracts to determine whether they meet the definition of a derivative and if so, whether they qualify for the normal purchase normal sale (“NPNS”) exception prescribed by ASC 815-10-10. The majority of the Company’s forward contracts do not qualify as derivatives. For those contracts that do meet the definition of a derivative, certain contracts also qualify for the NPNS exception based on management’s intent and ability to physically deliver or take physical delivery of the coal. Contracts that meet the definition of a derivative and do not qualify for the NPNS exception are accounted for at fair value and, accordingly, the Company includes the unrealized gains and losses in current period earnings or losses.

107

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Swap Agreements

Commodity Swaps

The Company uses diesel fuel and explosives in its production process and incurs significant expenses for the purchase of these commodities. Diesel fuel and explosives expenses represented approximately 7%, 8%, and 8% of cost of coal sales for the years ended December 31, 2010, 2009 and 2008, respectively. The Company is subject to the risk of price volatility for these commodities and as a part of its risk management strategy, the Company enters into swap agreements with financial institutions to mitigate the risk of price volatility for both diesel fuel and explosives. The terms of the swap agreements allow the Company to pay a fixed price and receive a floating price, which provides a fixed price per unit for the volume of purchases being hedged. As of December 31, 2010, the Company had swap agreements outstanding to hedge the variabl e cash flows related to 68% and 39% of anticipated diesel fuel usage for calendar years 2011 and 2012, respectively. The average fixed price per swap for diesel fuel hedges is $2.40 per gallon and $2.44 per gallon for calendar years 2011 and 2012, respectively. As of December 31, 2010, the Company had swap agreements outstanding to hedge the variable cash flows related to approximately 28% of anticipated explosives usage in the Powder River Basin for calendar year 2011. All cash flows associated with derivative instruments are classified as operating cash flows in the Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008.

The Company also sells coalbed methane. The revenues derived from the sale of coalbed methane are subject to volatility based on the changes in natural gas prices.  In order to reduce that risk, the Company enters into “pay variable, receive fixed” natural gas swaps for a portion of its anticipated gas production in order to fix the selling price for a portion of its production.  The natural gas swaps have been designated as qualifying cash flow hedges. As of December 31, 2010, the Company had swap agreements outstanding to hedge the variable cash flows related to approximately 62% and 22% of anticipated natural gas production in 2011 and 2012, respectively.

Interest Rate Swaps

The Company has variable rate debt outstanding and is subject to interest rate risk based on volatility in underlying interest rates. The Company previously entered into pay fixed, receive variable interest rate swaps to convert the Company’s previous variable-rate term loan into fixed-rate debt.  The interest rate swaps were designated as qualifying cash flow hedges. During the year ended December 31, 2009, the Company repaid the related term loan and de-designated the swaps as cash flow hedges. Accordingly, the Company reclassified $17,668 (net of income taxes of $5,881) from accumulated other comprehensive income (loss) into interest expense. The Company did not terminate the interest rate swaps due to the swaps’ potential benefit in offsetting a portion of the effect of interest rate changes in the Company’ ;s other variable rate debt. Subsequent changes in fair value are recorded in interest expense.

The following tables present the fair values and location of the Company’s derivative instruments within the Consolidated Balance Sheets:

	Asset Derivatives
Derivatives designated as cash flow hedging instruments	December 31, 2010		December 31, 2009
Commodity swaps (1)	$	13,910	$	2,222

Derivatives not designated as cash flow hedging instruments	December 31, 2010		December 31, 2009
Forward coal sales (2)	$	2,674	$	3,414
Commodity swaps (3)		19		5,066
Total	$	2,693	$	8,480
Total asset derivatives	$	16,603	$	10,702

(1) As of December 31, 2010, $10,865 is recorded in prepaid expenses and other current assets and $3,045 is recorded in other non-current assets in the Consolidated Balance Sheets.  As of December 31, 2009, $390 is recorded in prepaid expenses and other current assetsand $1,832 is recorded in other non-current assets in the Consolidated Balance Sheets.

(2) As of December 31, 2010, $2,674 is recorded in prepaid expenses and other current assets in the Consolidated Balance Sheets.  As of December 31, 2009, $3,216 is recorded in prepaid expenses and other current assets and $198 is recorded in other non-current assets in the Consolidated Balance Sheets.

(3) As of December 31, 2010, $19 is recorded in prepaid expenses and other current assets in the Consolidated Balance Sheets. As of December 31, 2009, $4,333 is recorded in prepaid expenses and other current assets and $733 is recorded in other non-current assets in the Consolidated Balance Sheets.

108

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

	Liability Derivatives
Derivatives designated as cash flow hedging instruments	December 31, 2010		December 31, 2009
Commodity swaps (1)	$	3,370	$	1,148

Derivatives not designated as cash flow hedging instruments	December 31, 2010		December 31, 2009
Forward coal purchases (2)	$	3,958	$	2,861
Commodity swaps (3)		36		14,831
Commodity options-coal (4)		264		255
Interest rate swaps (5)		21,304		24,232
Freight swap (6)		47		-
Total	$	25,609	$	42,179
Total liability derivatives	$	28,979	$	43,327

(1) As of December 31, 2010, $3,256 is recorded in accrued expenses and other current liabilities and $114 is recorded in other non-current liabilities in the Consolidated Balance Sheets. As of December 31, 2009, $1,148 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets.

(2) As of December 31, 2010 and 2009, $3,958 and $2,861, respectively, is recorded in accrued expenses and other current liabilitiesin the Consolidated Balance Sheets.

(3) As of December 31, 2010, $36 is recorded in accrued expenses in the Consolidated Balance Sheets. As of December 31, 2009, $10,833 is recorded in accrued expenses and other current liabilitiesand $3,998inother non-current liabilitiesin the Consolidated Balance Sheets.

(4) As of December 31, 2010, $40 is recorded in accrued expenses and other current liabilities and $224 is recorded inother non-current liabilitiesin the Consolidated Balance Sheets. As of December 31, 2009, $119 is recorded in accrued expenses and other current liabilitiesand $136in other non-current liabilitiesin the Consolidated Balance Sheets.

(5) As of December 31, 2010, $12,592 is recorded in accrued expenses and other current liabilities and $8,712 is recorded in other non-current liabilities in the Consolidated Balance Sheets. As of December 31, 2009, $11,500 is recorded in accrued expenses and other current liabilities and $12,732 is recorded in other non-current liabilities in the Consolidated Balance Sheets.

(6) As of December 31, 2010, $47 is recorded in accrued expenses and other current liabilities in the Consolidated Balance Sheets.

The following table presents the gains and losses from derivative instruments for the years ended December 31, 2010, 2009 and 2008 and their location within the Consolidated Financial Statements:

Derivatives designated as	(Gain) loss reclassified from accumulated other comprehensive income (loss) to earnings							Loss recorded in earnings related to derivative ineffectiveness							Gain (loss) recorded in accumulated other comprehensive income (loss) (3)
cash flow hedging instruments	2010			2009		2008		2010		2009			2008		2010		2009		2008
Commodity swaps (1), (3)	$	(277	)	$	-	$	-	$	-	$	(1	)	$	-	$	7,821	$	899	$	-
Interest rate swaps (2), (3)		-			17,668		3,682		-		-			-		-		3,293		(12,908	)
Total	$	(277	)	$	17,668	$	3,682	$	-	$	(1	)	$	-	$	7,821	$	4,192	$	(12,908	)

(1) Amounts recorded in other expenses in the Consolidated Statements of Operations.

(2) Amounts are recorded as a component of interest expense in the Consolidated Statements of Operations.

(3) Net of tax.

109

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

	Gain (loss) recorded in earnings
Derivatives not designated as cash flow hedging instruments	2010			2009			2008
Forward coal sales (1)	$	(739	)	$	332		$	4,993
Forward coal purchases (1)		(1,099	)		2,361			(14,297	)
Commodity swaps (2)		(428	)		26,604			(38,519	)
Commodity options-diesel fuel (2)		(94	)		(1,281	)		558
Commodity options-coal (1)		(8	)		(137	)		-
Interest rate swaps (3)		(8,901	)		(24,232	)		-
Freight swap (2)		(47	)		-			-
Total	$	(11,316	)	$	3,647		$	(47,265	)

(1) Amounts are recorded as a component of other revenues in the Consolidated Statements of Operations.

(2)  Amounts are recorded as a component of other expenses in the Consolidated Statements of Operations.

(3) Amounts are recorded as a component of interest expense in the Consolidated Statements of Operations.

Unrealized losses recorded in accumulated other comprehensive income (loss) are reclassified to income or loss as the financial swaps settle and the Company purchases the underlying items that are being hedged. During the next twelve months, the Company expects to reclassify approximately $(704), net of tax, to earnings.  The following table summarizes the changes to accumulated other comprehensive income (loss) related to hedging activities during the years ended December 31, 2010, 2009 and 2008:

	Years Ended December 31,
	2010			2009			2008
Balance at beginning of period	$	899		$	(20,961	)	$	(11,735	)
Net change associated with current year hedging transactions		7,821			4,192			(12,908	)
Net amounts reclassified to earnings		(277	)		17,668			3,682
Balance at end of period	$	8,443		$	899		$	(20,961	)

(14)     Income Taxes

The total income tax expense (benefit) provided on pre-tax income was allocated as follows:

	Years Ended December 31,
	2010			2009			2008
Continuing operations	$	4,218		$	(33,023	)	$	52,242
Discontinued operations		(1,052	)		(5,476	)		(11,035	)
	$	3,166		$	(38,499	)	$	41,207

110

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Significant components of income tax expense (benefit) from continuing operations were as follows:

	Years Ended December 31,
	2010			2009			2008
Current tax expense (benefit):
Federal	$	63,045		$	19,644		$	49,470
State		11,367			(1,629	)		13,526
	$	74,412		$	18,015		$	62,996
Deferred tax expense (benefit):
Federal	$	(68,169	)	$	(51,583	)	$	(9,678	)
State		(2,025	)		545			(1,076	)
	$	(70,194	)	$	(51,038	)	$	(10,754	)
Total income tax expense (benefit):
Federal	$	(5,124	)	$	(31,939	)	$	39,792
State		9,342			(1,084	)		12,450
	$	4,218		$	(33,023	)	$	52,242

A reconciliation of the statutory federal income tax expense at 35% to income from continuing operations before income taxes and the actual income tax expense (benefit) is as follows:

	Years Ended December 31,
	2010			2009			2008
Federal statutory income tax expense	$	35,503		$	11,824		$	87,795
Increases (reductions) in taxes due to:
Percentage depletion allowance		(47,917	)		(29,286	)		(22,508	)
State taxes, net of federal tax impact		(2,092	)		(767	)		7,906
State tax rate and NOL change, net of federal tax benefit		7,437			-			-
Deduction for domestic production activities		(2,201	)		-			(4,233	)
Change in valuation allowances		25			(21,324	)		(16,966	)
Change in law - Medicare Part D Subsidy (1)		25,566			-			-
Non-deductible lobbying		2,014			-			-
Non-deductible transaction costs		-			3,214			-
Extraterritorial income exclusion		-			-			(1,945	)
Loss disallowance		-			-			2,147
Reversal of reserves for uncertain tax positions (2)		(14,018	)		-			-
Other, net		(99	)		3,316			46
Income tax expense (benefit)	$	4,218		$	(33,023	)	$	52,242

(1) Includes federal tax expense and state tax expense (net of federal tax benefit) of $23,454 and $2,112, respectively.

(2) Includes federal tax benefits, state tax benefits and interest expense of $11,695, $2,807 and ($484), respectively.

The Patient Protection and Affordable Care Act (the “PPACA”) and the Reconciliation Act were signed into law in March 2010. As a result of these two acts, tax benefits available to employers that receive the Medicare Part D subsidy will be eliminated starting in years ending after December 31, 2012. Since these acts were signed into law during the year ended December 31, 2010, ASC 740 – Income Taxes, required that the effect of the tax law change be recorded immediately as a component of tax expense. The income tax effect related to these acts was a reduction of $25,566 to the deferred tax asset related to the postretirement prescription drug benefits.

IRS examinations for the years 2005-2007 were determined to be effectively settled during the year ended December 31, 2010, in addition to certain statutes of limitations expiring.  The reversal of reserves provided an income tax benefit, net of interest, of $14,018.

111

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Deferred income taxes result from temporary differences between the reporting of amounts for financial statement purposes and income tax purposes. The net deferred tax assets and liabilities included in the Consolidated Balance Sheets include the following amounts:

	December 31,
	2010			2009
Deferred tax assets
Asset retirement obligations	$	87,904		$	79,157
Other liabilities		48,989			58,388
Pension and postretirement medical obligations		280,490			280,243
Alternative minimum tax credit carryforwards		120,431			80,676
Goodwill		10,848			11,849
Workers' compensation obligations		38,928			16,952
Derivatives		-			3,648
Other assets		13,012			12,373
Net operating loss carryforwards		18,251			40,547
Gross deferred tax assets		618,853			583,833
Less valuation allowance		(10,975	)		(10,950	)
Total net deferred tax assets		607,878			572,883
Deferred tax liabilities
Property and equipment		(707,616	)		(683,613	)
Acquired coal supply agreements		(55,408	)		(129,749	)
Other assets		(1,663	)		-
Prepaid insurance and other prepaid expenses		(17,852	)		(30,832	)
Advanced mining royalties		(6,906	)		(1,291	)
Virginia tax credit		(8,642	)		(7,990	)
Debt discount		(26,549	)		(30,952	)
Derivative financial instruments		(2,998	)		-
Total deferred tax liabilities		(827,634	)		(884,427	)
Net deferred tax liability	$	(219,756	)	$	(311,544	)

The breakdown of the net deferred tax liability as recorded in the accompanying Consolidated Balance Sheets is as follows:

	December 31,
	2010			2009
Current asset	$	29,652		$	-
Current liability		-			(10,237	)
Noncurrent liability		(249,408	)		(301,307	)
Total net deferred tax liability	$	(219,756	)	$	(311,544	)

Changes in the valuation allowance during the years ended December 31, 2010 and 2009 were as follows:

	December 31,
	2010		2009
Valuation allowance beginning of period	$	10,950	$	21,324
Increase in valuation allowance not affecting income tax expense		-		10,950
Decrease in valuation allowance recorded as a reduction to income tax expense-continuing operations		-		(21,324	)
Increase in valuation allowance recorded as an increase to income tax expense-continuing operations		25		-
Valuation allowance end of period	$	10,975	$	10,950

The Company has concluded that it is more likely than not that deferred tax assets, net of valuation allowances, currently recorded will be realized. The Company monitors the valuation allowance each quarter and makes adjustments to the allowance as appropriate.

112

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The Company has gross net operating loss carry-forwards for state income taxes of $260,935 which are available to offset future state taxable income generally through 2029. A valuation allowance has been provided for $126,551 of the state net operating losses. The Company also has alternative minimum tax credit carry-forwards of approximately $120,431, which are available to reduce federal regular income tax in excess of the alternative minimum tax, if any, over an indefinite period.

The total amount of unrecognized tax benefits after the reversal of $14,502 ($14,018 net, without interest) that would affect the Company’s effective tax rate if recognized is $25,442 as of December 31, 2010. The Company believes that it is unlikely that total unrecognized benefits recorded as of December 31, 2010 will significantly change during the next twelve months.

The Company’s policy is to classify interest and penalties related to uncertain tax positions as part of income tax expense. As of December 31, 2010, the Company has recorded accrued interest expense of $81. 

The following reconciliation illustrates the Company’s liability for uncertain tax positions:

	December 31,
	2010			2009		2008
Unrecognized tax benefits – beginning of period	$	39,944		$	7,229	$	5,500
Gross adjustments - Foundation Merger		-			3,400		-
Gross increases – tax positions in prior periods		-			2,983		14
Gross decreases – tax positions in prior periods		-			-		(642	)
Gross increases – current period tax positions		-			26,332		2,357
Gross decreases – settlements with taxing authorities		(12,114	)		-		-
Reduction as a result of a lapse of the applicable statute of limitations		(2,388	)		-		-
Unrecognized tax benefits - end of period	$	25,442		$	39,944	$	7,229

Tax years 2008-2010 remain open to federal and state examination. The Internal Revenue Service initiated a corporate income tax audit during the first quarter of 2007 for the Company’s 2005 tax year and during the first quarter of 2009 for the Company’s 2006 and 2007 tax years. These audits are effectively settled. 

(15)     Employee Benefit Plans

The Company sponsors or participates in several benefit plans for its employees, including postemployment health care and life insurance, defined benefit and defined contribution pension plans, and workers’ compensation and black lung benefits.  In connection with the Foundation Merger, the Company assumed all of the employee benefit plans of Foundation (the “Foundation Plans”) and was contractually obligated to continue to provide similar or improved benefits to those Foundation Plans for a period of eighteen months after the Foundation Merger date. During the third quarter of 2010, the Company internally announced comprehensive integrated employee benefits programs which align the employee benefits of Old Alpha and Foundation employees. As a result, the Company’s defined benefit pension plans and the S upplemental Executive Retirement Plan assumed in the Foundation Merger (the “Plans”) were frozen, resulting in a curtailment gain of $5,051 being recognized in 2010. The Company re-measured the obligations related to the Plans and the Company’s other postretirement medical benefit plan at the time of the announcement, resulting in estimated increases of $100,351 and $24,405, to the other postretirement benefit and pension obligations, respectively, with an offset to accumulated other comprehensive income (loss), net of taxes.

In March 2010, the PPACA was enacted, potentially impacting the costs to provide healthcare benefits to the Company’s eligible active and certain retired employees and workers’ compensation benefits related to occupational disease resulting from coal workers’ pneumoconiosis (“Black Lung”). The PPACA has both short-term and long-term implications on healthcare benefit plan standards.  Implementation of this legislation is planned to occur in phases, with plan standard changes taking effect beginning in 2010, but to a greater extent with the 2011 benefit plan year and extending through 2018. Plan standard changes that could affect the Company in the short term include raising the maximum age for covered dependents to receive benefits, the elimination of lifetime dollar limits per covered individual a nd restrictions on annual dollar limits per covered individual, among other standard requirements. Plan standard changes that are expected to affect the Company in the long term include an excise tax on “high cost” plans and the elimination of annual dollar limits per covered individual, among other standard requirements.

113

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Beginning in 2018, the PPACA will impose a 40% excise tax on employers to the extent that the value of their healthcare plan coverage exceeds the certain dollar thresholds. The Company re-measured its retiree welfare plan obligations during the second quarter of 2010 in order to account for the estimated impact of the excise tax and updated other assumptions related to anticipated retirement ages and health care cost trend rates. The re-measurement resulted in an additional $27,100 increase to the retiree welfare plan obligation, which is included in pension and postretirement medical benefit obligations on the accompanying Consolidated Balance Sheets, with an offset to accumulated other comprehensive income (loss). The Company anticipates that certain government agencies will provide additional regulations or interpretations concerning the application of this excise tax. The Company will need to continue to evaluate the impact of the PPACA in future periods, and when these regulations or interpretations are published, the Company will evaluate its assumptions in light of the new information.

The PPACA also amended previous legislation related to coal workers’ Black Lung, providing automatic extension of awarded lifetime benefits to surviving spouses and providing changes to the legal criteria used to assess and award claims.  The Company evaluated the impact of these changes to its current population of beneficiaries and possible future claimants, and as a result re-measured the obligations for its self-insured black lung plans during the first quarter of 2010. The re-measurement resulted in an estimated $6,658 increase to the obligation included in other non-current liabilities in the accompanying Consolidated Balance Sheets, with an offset to accumulated other comprehensive income (loss).

(a) Company Administered Postretirement Health Care and Life Insurance Benefits

The Company provides postretirement medical and life insurance benefits to certain eligible employees under various plans. Certain of the plans are contributory while others are noncontributory. Additionally, certain of the plans are established by collective bargaining agreements.

114

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The components of the change in accumulated benefit obligations of the plans for postretirement medical benefits were as follows:

	December 31,
	2010			2009
Change in benefit obligations:
Accumulated benefit obligation-beginning period:	$	614,436		$	61,292
Assumption of obligations due to Foundation Merger		-			556,726
Service cost		10,933			5,779
Interest cost		35,860			17,446
Actuarial (gain) loss		90,894			(15,292	)
Benefits paid		(28,593	)		(10,425	)
Less:  Federal subsidy on benefits paid		1,848			837
Curtailment		-			(1,927	)
Change in plan provisions		(10,899	)		-
Change in plan assumptions		(8,144	)		-
Accumulated benefit obligation-end of period	$	706,335		$	614,436
Change in fair value of plan assets:
Employer contributions	$	(28,593	)	$	(10,425	)
Benefits paid		28,593			10,425
Fair value of plan assets at December 31		-			-
Funded status	$	(706,335	)	$	(614,436	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(28,265	)	$	(27,393	)
Long-term liabilities		(678,070	)		(587,043	)
	$	(706,335	)	$	(614,436	)
Amounts recognized in accumulated other comprehensive income (loss):
Prior service cost (credit)	$	(1,192	)	$	10,822
Net actuarial (gain) loss		63,704			(18,039	)
	$	62,512		$	(7,217	)

The following table details the components of the net periodic benefit cost for postretirement medical benefits:

	Year Ended December 31,
	2010		2009			2008
Service cost	$	10,933	$	5,779		$	2,777
Interest cost		35,860		17,446			3,421
Amortization of net actuarial loss (gain)		1,010		(150	)		-
Amortization of prior service cost		1,114		2,202			2,367
Other		-		(712	)		-
Net periodic benefit cost	$	48,917	$	24,565		$	8,565

115

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Other changes in plan assets and benefit obligations recognized in other comprehensive (loss) income are as follows:

	Year Ended December 31,
	2010			2009			2008
Current year actuarial (gain) loss	$	82,752		$	(15,292	)	$	657
Prior service cost (credit) for period		(10,899	)		(1,215	)		-
Amortization of net gain (loss)		(1,010	)		150			-
Amortization of prior service (cost) credit		(1,114	)		(2,202	)		(2,367	)
Total recognized in other comprehensive (loss) income	$	69,729		$	(18,559	)	$	(1,710	)
Total recognized in net periodic pension cost and other comprehensive income	$	118,646		$	6,006		$	6,855

The estimated amount that will be amortized from Accumulated other comprehensive (loss) income into net period benefit cost in 2011 is as follows:

Prior service cost $ (800 )

The weighted-average assumptions used to determine the postretirement plans’ benefit obligation as of December 31, 2010 and 2009 were as follows:

	December 31,
	2010	2009
Discount rate	5.21%	5.83% - 5.88%

The discount rates used in determining net periodic postretirement medical benefit cost for the years ended December 31, 2010, 2009 and 2008 were as follows:

	Year Ended December 31,
	2010	2009	2008
Discount rate	4.59% - 5.88%	5.83% - 6.17%	5.92%

The discount rate assumption is determined from a published yield-curve table matched to timing of the Company’s projected cash out flows.

The following presents information about the postretirement plans’ weighted-average annual rate of increase in the per capita cost of covered benefits (i.e., health care cost trend rate):

Health care cost trend rate assumed for the next year	8.00%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	5.00%
Year that the rate reaches the ultimate trend rate	2016

116

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Assumed health care trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care trend rates would have the following effects as of and for the year ended December 31, 2010:

	One Percentage Point Increase		One Percentage Point Decrease
Effect on total service and interest cost components	$	5,753	$	(4,667	)
Effect on accumulated postretirement benefit obligation	$	84,506	$	(70,355	)

In December 2003, the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MMA”) was enacted in the United States. The MMA introduced a prescription drug benefit under Medicare Part D as well as a federal subsidy to sponsors of benefit plans such as the Foundation postretirement plans as long as the provided benefits are actuarially equivalent to Medicare Part D. The MMA reduced the Company’s net periodic benefit cost for the years ended December 31, 2010 and 2009 by approximately $300 and $2,230, respectively.

The Company continues to provide primary prescription drug benefits to Medicare eligible participants in the Foundation postretirement plans, pursuant to final regulations issued on the MMA by the Centers for Medicare and Medicaid Services (“CMS”) on January 21, 2005. The Company is also a participant in the federal subsidy payment program under the MMA, and the Federal subsidies received in the years ended December 31, 2010 and 2009 were $1,848 and $837, respectively.

Employer contributions for the Company’s postretirement medical and life insurance benefit plans paid for the years ended December 31, 2010, 2009 and 2008 were $26,745, $9,588 and $241, respectively, net of federal subsidies received under the MMA. Employee contributions are not expected to be made and the Company’s plans are unfunded. The Company expects to contribute approximately $28,265 to its postretirement medical and life insurance plans in 2011.

The following represents the Company’s expected future postretirement medical and life insurance benefit payments for the next ten years, which reflect expected future service, as appropriate, and the expected federal subsidy related to MMA:

	Postretirement Medical and Life Insurance Benefits		Expected Federal Subsidy
2011	$	33,042	$	2,224
2012		36,357		2,547
2013		39,523		2,817
2014		42,633		3,189
2015		45,895		3,575
2016-2020		269,929		24,614
	$	467,379	$	38,966

(b) Company Administered Defined Benefit Pension Plans

In conjunction with the Foundation Merger, the Company assumed Foundation’s two non-contributory defined benefit retirement plans (the “Pension Plan(s)”) covering certain salaried and non-union hourly employees and a non-qualified Supplemental Executive Retirement Plan (“SERP”). Benefits are based on either the employee’s compensation prior to retirement or “plan specified” amounts for each year of service with the Company.

Annual funding contributions to the Pension Plans are made as recommended by consulting actuaries based upon the Employee Retirement Income Security Act (“ERISA”) funding standards. Plan assets consist of equity and fixed income funds, real estate funds, private equity funds and alternative investment funds.

117

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The following tables set forth the plans’ benefit obligations, fair value of plan assets and funded status:

	December 31,
	2010			2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	253,365		$	-
Assumption of obligations due to Foundation Merger	��	-			250,949
Service cost		7,453			3,511
Interest cost		13,634			5,884
Actuarial loss		17,707			3,755
Benefits paid		(13,559	)		(10,058	)
Curtailment		(25,670	)		(676	)
Benefit obligation at end of period	$	252,930		$	253,365
Change in fair value of plan assets:
Fair value of plan assets at beginning of period	$	157,417		$	-
Assumption of pension assets due to Foundation Merger		-			126,624
Actual return on plan assets		24,309			12,865
Employer contributions		43,478			27,986
Benefits paid		(13,559	)		(10,058	)
Fair value of plan assets at end of period		211,645			157,417
Funded status		(41,285	)		(95,948	)
Accrued benefit cost at end of year	$	(41,285	)	$	(95,948	)

Gross amounts recognized in accumulated other comprehensive income (loss) were as follows:

	Year Ended December 31,
	2010			2009
Unamortized net gain	$	(19,198	)	$	(5,141	)

The following table details the components of net periodic benefit cost:

	Year Ended December 31,
	2010			2009
Service cost	$	7,453		$	3,511
Interest cost		13,634			5,884
Expected return on plan assets		(13,396	)		(4,646	)
Amortization of actuarial loss		232			-
Curtailment (gain)/loss		(5,051	)		-
Total	$	2,872		$	4,749

Other changes in plan assets and benefit obligations recognized in other comprehensive (loss) income are as follows:

	Year Ended December 31,
	2010			2009
Current year actuarial loss	$	(18,876	)	$	(5,141	)
Amortization of:
Actuarial loss		4,819			-
Total recognized in other comprehensive income	$	(14,057	)	$	(5,141	)
Total recognized in net periodic benefit cost and other comprehensive (loss) income	$	(11,185	)	$	(392	)

118

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The estimated amount that will be amortized from Accumulated other comprehensive (loss) income into net period benefit cost in 2011 is as follows:

Actuarial loss $ 1,040

The following table presents information applicable to plans with accumulated benefit obligations in excess of plan assets:

	December 31,
	2010		2009
Projected benefit obligation	$	252,930	$	253,365
Accumulated benefit obligation	$	252,930	$	226,133
Fair value of plan assets	$	211,645	$	157,417

The current portion of the Company’s Pension Plan liability is the amount by which the actuarial present value of benefits included in the benefit obligation payable in the next twelve months exceeds the fair value of plan assets. However, even though the plan may be underfunded, if there are sufficient plan assets to make expected benefit payments to plan participants in the succeeding twelve months, no current liability should be recognized. Accordingly, there was no current pension liability reflected in the Consolidated Balance Sheets as of December 31, 2010 and 2009.

The weighted-average actuarial assumptions used in determining the benefit obligations as of December 31, 2010 and 2009 were as follows:

	December 31,
	2010	2009
Discount rate	5.12%	5.76%
Rate of increase in future compensation	N/A	5.00%

The weighted-average actuarial assumptions used to determine net periodic benefit cost for the years ended December 31, 2010 and 2009 were as follows:

	December 31,
	2010	2009
Discount rate	5.39%	5.73%
Rate of increase in future compensation	5.00%	5.00%
Expected long-term return on plan assets	7.92%	8.00%
Measurement date	December 31, 2010	July 31, 2009

The discount rate assumption is determined from a published yield-curve table matched to timing of the Company’s projected cash out flows.

The expected long-term return on Pension Plan assets is established at the beginning of each year by the Company’s Benefits Committee in consultation with the plans’ actuaries and outside investment advisor. This rate is determined by taking into consideration the Pension Plans’ target asset allocation, expected long-term rates of return on each major asset class by reference to long-term historic ranges, inflation assumptions and the expected additional value from active management of the Pension Plans’ assets. For the determination of net periodic benefit cost in 2011, the Company will utilize an expected long-term return on plan assets of 7.75%.

119

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Assets of the Pension Plans are commingled in the Foundation Coal Defined Benefit Plans Master Trust (“Master Trust”) and are invested in accordance with investment guidelines that have been established by the Company’s Benefits Committee in consultation with the Master Trust’s outside investment advisor. The Pension Plans’ target allocation for 2011 and the actual asset allocation as reported at December 31, 2010 are as follows:

	Target Allocation Percentages 2011			Percentage of Plan Assets 2010
Equity funds		64.5	%		61.8	%
Fixed income funds		35.5	%		33.1	%
Alternative investment funds/private equity funds		0.0	%		2.6	%
Real estate funds		0.0	%		2.5	%
Total		100.0	%		100.0	%

The asset allocation targets have been set with the expectation that the Pension Plans’ assets will fund the expected liabilities within an appropriate level of risk. In determining the appropriate target asset allocations the Benefits Committee considers the demographics of the Pension Plans’ participants, the funding status of each plan, the Company’s contribution philosophy, the Company’s business and financial profile and other associated risk factors. The Pension Plans’ assets are periodically rebalanced among the major asset categories to maintain the asset allocation within a specified range of the target allocation percentage.

For the years ended December 31, 2010 and 2009, $43,478 and $27,986, respectively, of cash contributions were made to the Pension Plans and SERP. The Company expects to contribute approximately $40,000 to the Pension Plans in 2011.

The following represents expected future pension benefit and SERP payments for the next ten years, which reflect expected future service, as appropriate:

	Pension Benefits
2011	$	13,814
2012		15,374
2013		14,888
2014		15,995
2015		16,837
2016-2020		83,495
	$	160,403

120

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The fair values of the Company’s Pension Plans’ assets at December 31, 2010, by asset category are as follows:

Fair Value Measurements at December 31, 2010
Asset Category	Total		Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Equity securities:
U.S. large-cap structured fund	$	50,667	$	-	$	50,667	$	-
U.S. small-cap fund		10,698		-		10,698		-
U.S. growth fund		14,473		-		14,473		-
U.S. value fund		14,592		-		14,592		-
International fund		34,282		-		34,282		-
Emerging markets fund		6,065		-		6,065		-
Real estate equity fund		5,268		-		-		5,268
Fixed income securities:
Bond fund (a)		69,988		-		69,988		-
Other types of investments:
Private equity funds (b)		4,879		-		-		4,879
Diversified alternatives fund (c)		148		-		-		148
Total	$	211,060	$	-	$	200,765	$	10,295
Receivable (d)		585
Total	$	211,645

(a) This fund contains bonds representing a diversity of sectors and maturities. This fund also includes mortgage-backed securities and U.S. Treasuries.

(b) This category includes several private equity funds that invest primarily in U.S. and European markets.

(c) This fund contains several underlying funds that invest primarily in U.S. markets and other world markets.

(d) Receivable for investments sold at December 31, 2010, which approximates fair value.

121

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The fair values of the Company’s Pension Plans’ assets at December 31, 2009, by asset category are as follows:

Fair Value Measurements at December 31, 2009
Asset Category	Total		Quoted Market Prices in Active Market for Identical Assets (Level 1)		Significant  Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Equity securities:
U.S. large-cap structured fund	$	34,267	$	-	$	34,267	$	-
U.S. small-cap fund		8,136		-		8,136		-
U.S. growth fund		10,641		-		10,641		-
U.S. value fund		10,640		-		10,640		-
International fund		24,663		-		24,663		-
Emerging markets fund		4,965		-		4,965		-
Real estate equity fund		5,727		-		-		5,727
Fixed income securities:
Bond fund (a)		52,540		-		52,540		-
Other types of investments:
Private equity funds (b)		3,877		12		-		3,865
Diversified alternatives fund (c)		1,312		-		-		1,312
Total	$	156,768	$	12	$	145,852	$	10,904
Receivable (d)		649
Total	$	157,417

(a) This fund contains bonds representing a diversity of sectors and maturities. This fund also includes mortgage-backed securities and U.S. Treasuries.

(b) This category includes several private equity funds that invest primarily in U.S. and European markets.

(c) This fund contains several underlying funds that invest primarily in U.S. markets and other world markets.

(d) Receivable for investments sold at December 31, 2009, which approximates fair value.

122

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Changes in level 3 plan assets for the year ended December 31, 2010 were as follows:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Real estate Equity Fund			Private Equity Funds		Diversified Alternative Fund			Total
Beginning balance, December 31, 2009	$	5,727		$	3,865	$	1,312		$	10,904
Actual return on plan assets:
Relating to assets still held at the reporting date		399			228		(400	)		227
Relating to assets sold during the period		120			81		(261	)		(60	)
Purchases, sales, and settlements		(978	)		705		(503	)		(776	)
Transfers in and/or out of Level 3		-			-		-			-
Ending balance, December 31, 2010	$	5,268		$	4,879	$	148		$	10,295

Changes in level 3 plan assets for the five months ended December 31, 2009 were as follows:

	Fair Value Measurements Using Significant
	Unobservable Inputs (Level 3)
	Real estate Equity Fund			Private Equity Funds		Diversified Alternative Fund			Total
Beginning balance, July 31, 2009	$	6,611		$	3,355	$	1,733		$	11,699
Actual return on plan assets:
Relating to assets still held at the reporting date		(854	)		356		(228	)		(726	)
Relating to assets sold during the period		3			-		(62	)		(59	)
Purchases, sales, and settlements		(33	)		154		(131	)		(10	)
Transfers in and/or out of Level 3		-			-		-			-
Ending balance, December 31, 2009	$	5,727		$	3,865	$	1,312		$	10,904

The following is a description of the valuation methodologies used for assets measured at fair value:

Level 1 Plan Assets: Assets consist of individual security positions which are easily traded on recognized market exchanges.  These securities are priced and traded daily, and therefore the fund is valued daily.

Level 2 Plan Assets: Funds consist of individual security positions which are mostly securities easily traded on recognized market exchanges. These securities are priced and traded daily, and therefore the fund is valued daily.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Level 3 Plan Assets: Assets are valued monthly or quarterly based on the Net Asset Value “NAV” provided by managers of the underlying fund investments. The NAVs provided typically reflect the fair value of each underlying fund investment, including unrealized gains and losses.

(c)    Multi-Employer Pension Plans

Certain of the Company’s subsidiaries are subject to collective bargaining agreements that require them to participate in an United Mine Workers of America (“UMWA”) pension plan. The plan is a multi-employer pension plan administered by the UMWA, and the Company is required to make contributions to the plan at rates defined by the various contracts. For the years ended December 31, 2010, 2009, and 2008 the Company incurred expense related to the UMWA pension plan of $19,915, $8,387, and $2,236, respectively.

In connection with the Foundation Merger, the Company assumed Foundation’s obligations to the Coal Industry Retiree Health Benefit Act of 1992 (“Coal Act”), that provides for the funding of medical and death benefits for certain retired members of the UMWA through premiums to be paid by assigned operators (former employers). The Company treats its obligations under the Coal Act as participation in a multi-employer plan and recognizes the expense as premiums are paid. Expense relative to premiums paid for the year ended December 31, 2010 and the five months ended December 31, 2009, was $865 and $28, respectively. As required under the Coal Act, the Company’s obligation to pay retiree medical benefits to its UMWA retirees is secured by letters of credit in the amount of $9,693 as of December 31, 2010.

(d)    Workers’ Compensation and Pneumoconiosis (Black lung)

The Company is required by federal and state statutes to provide benefits to employees for awards related to workers’ compensation and black lung.  The Company’s subsidiaries are insured for worker’s compensation and black lung obligations by a third-party insurance provider in all locations with the exception of West Virginia, where certain subsidiaries are self-insured for workers’ compensation state black lung related obligations. Due to the Foundation Merger, the Company assumed the workers’ compensation and black lung obligations of the Foundation subsidiaries (the “Foundation subsidiaries”). The Foundation subsidiaries acquired in the Foundation Merger are self-insured for black lung benefits and fund benefit payments through a Section 501(c)(21) tax-exempt trust fund.   Provisions are made for estimated benefits based on annual evaluations prepared by independent actuaries. The Foundation subsidiaries are also self-insured for worker’s compensation benefits with the exception of benefits to employees located in Wyoming where the Company participates in a compulsory state-run fund.

The liability for self-insured workers’ compensation claims is an actuarially determined estimate of the undiscounted ultimate losses to be incurred on such claims based on the Company’s experience, and includes a provision for incurred but not reported losses. The liability for self-insured black lung benefits is an estimate of such benefit as determined by an independent actuary at the present value of the actuarially computed liability over the employee's applicable term of service. Adjustments to the probable ultimate liability for workers’ compensation and black lung are made annually/semi-annually based on actuarial valuations and are included in operations as these are determined.

For the Company’s subsidiaries that are fully insured for workers' compensation and black lung claims, the insurance premium expense for the years ended December 31, 2010, 2009 and 2008 was $16,901, $19,134, and $18,920, respectively.

For the Company’s subsidiaries that are self-insured for workers’ compensation claims, the liability at December 31, 2010 and 2009 was $51,702 and $43,882, respectively, including a current portion of $7,935 and $10,893, respectively. Self-insured workers' compensation expense from continuing operations for the years ended December 31, 2010, 2009, and 2008 was $15,573, $6,768, and $3,331, respectively.  Certain of the Company’s subsidiaries’ self-insured workers’ compensation obligations are secured by letters of credit in the amount of $30,738 and surety bonds in the amount of $8,799.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The following tables set forth the accumulated black lung benefit obligations, fair value of plan assets and funded status for the year ended December 31, 2010:

	December 31,
	2010			2009
Change in benefit obligation:
Benefit obligation at beginning of period	$	34,555		$	1,540
Assumption of obligation due to Foundation Merger		-			32,648
Service cost		1,412			500
Interest cost		2,235			838
Actuarial loss (gain)		11,971			322
Benefits paid		(3,751	)		(1,386	)
Change in assumptions		(285	)		93
Benefit obligation at end of period	$	46,137		$	34,555
Change in fair value of plan assets:
Fair value of plan assets at beginning of period	$	4,294		$	-
Assumption of assets due to Foundation Merger		-			5,510
Actual return on plan assets		26			43
Benefits paid		(3,751	)		(1,386	)
Employer contributions		547			127
Fair value of plan assets at end of period (1)		1,116			4,294
Funded status		(45,021	)		(30,261	)
Accrued benefit cost at end of year	$	(45,021	)	$	(30,261	)

(1) Assets of the plan are held in a Section 501(c)(21) tax-exempt trust fund and consist primarily of government debt securities.  All assets are classified as Level 1 and valued based on quoted market prices.

Gross amounts related to the black lung obligations recognized in accumulated other comprehensive (loss) income consisted of the following as of December 31, 2010 and 2009:

	December 31,
	2010		2009
Net actuarial loss	$	12,447	$	1,121

The following table details the components of the net periodic benefit cost for black lung obligations:

	Year Ended December 31,
	2010		2009			2008
Service cost	$	1,412	$	500		$	44
Interest cost		2,235		838			87
Expected return on plan assets		107		(54	)		92
Amortization of actuarial loss		229		98			-
Net periodic expense (1)	$	3,983	$	1,382		$	223

(1) The net periodic benefit cost from continuing operations was $108 for the year ended December 31, 2008.

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ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Other changes in the black lung plan assets and benefit obligations recognized in Other comprehensive (loss) income are as follows:

	Year Ended December 31,
	2010			2009			2008
Current year actuarial loss	$	11,729		$	426		$	19
Amortization of actuarial loss		(405	)		(98	)		(92	)
Total recognized in other comprehensive (loss) income	$	11,324		$	328		$	(73	)
Total recognized in net periodic benefit cost and other comprehensive (loss) income	$	15,307		$	1,710		$	150

The estimated amount that will be amortized from Accumulated other comprehensive (loss) income into net period benefit cost in 2011 is as follows:

Expected amortization of net (gain)/loss $ 832

The weighted-average assumptions related to black lung obligations used to determine the benefit obligation as of December 31, 2010 and 2009 were as follows:

	2010	2009
Discount rate	5.17% - 5.23%	4.01% - 5.78%
Rate of increase in future compensation	3.00%	3.00%

The weighted-average assumptions related to black lung obligations used to determine net periodic benefit cost were as follows:

	Year Ended December 31,
	2010	2009	2008
Discount rate	4.01% - 5.73%	5.48% - 5.81%	5.56%
Rate of increase in future compensation	3.00%	3.00%	N/A
Expected long-term return on plan assets	3.00%	3.00%	N/A

Estimated future cash payments related to black lung obligations for the fiscal years ending after December 31, 2010 are as follows:

Year ending December 31:
2011	$	2,811
2012		2,001
2013		2,109
2014		2,346
2015		2,616
2016-2020		15,788
	$	27,671

(e)    Defined Contribution and Profit Sharing Plans

The Company sponsors multiple defined contribution and profit sharing plans to assist its eligible employees in providing for retirement.  Generally, under the terms of these plans, employees make voluntary contributions through payroll deductions and the Company makes matching and/or discretionary contributions, as defined by each plan. The Company’s total contributions to these plans for the years ended December 31, 2010, 2009 and 2008 were $20,205, $12,352 and $10,670, respectively.

(f)    Self-Insured Medical Plan

Certain subsidiaries of the Company are principally self-insured for health insurance coverage provided for all of its active employees.  In addition, certain of these subsidiaries utilize commercial insurance to cover specific claims in excess of $500. Estimated liabilities for health and medical claims are recorded based on the Company’s historical experience and include a component for incurred but not reported claims.  During the years ended December 31, 2010, 2009 and 2008, the Company incurred total claims expense of $92,058, $63,081 and $35,188, respectively, which represents claims processed and an estimate for claims incurred but not reported.

126

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

(16)     Stock-Based Compensation Awards

The Company’s primary stock-based compensation plan is the Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (the “2010 LTIP”), which was approved on May 19, 2010 by the Company’s stockholders. The principal purpose of the 2010 LTIP is to advance the interest of the Company and its stockholders by providing incentives to certain employees and individuals who contribute significantly to the strategic and long-term performance objectives and growth of the Company. The 2010 LTIP provides for a variety of awards, including stock options, stock appreciation rights, restricted stock, restricted stock units and other share-based awards. Awards are granted at 100% of the fair market value of the underlying common stock on the date of grant. Awards generally vest ratably over a three year period or cliff vest aft er three years. The 2010 LTIP is currently authorized for the issuance of awards for up to 3,250,000 shares of common stock. At December 31, 2010, 3,248,485 shares of common stock were available for grant under the 2010 LTIP. The Company also has stock-based awards outstanding under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (the “2005 LTIP”) and the Foundation Amended and Restated 2004 Stock Incentive Plan (the “2004 SIP”).

Upon vesting of  restricted stock and restricted share units (both time-based and performance-based) or the exercise of options, shares are issued from the 2010 LTIP, the 2005 LTIP and the 2004 SIP, respective of which plan the awards were granted from.

In November 2008, the Board of Directors authorized the Company to repurchase common shares from employees (upon the election by the employee) to satisfy the employees’ minimum statutory tax withholdings upon the vesting of restricted stock and restricted share units (both time-based and performance-based). During the year ended December 31, 2010 and 2009, the Company repurchased 367,860 and 309,457 common shares, respectively, from employees at an average price paid per share of $45.30 and $28.68. Shares that are repurchased to satisfy the employees’ minimum statutory tax withholdings are recorded in Treasury stock at cost, and these shares are not added back into the pool of shares available for grant of the respective plans the shares were granted from.

At December 31, 2010, the Company had three types of stock-based awards outstanding: restricted stock, restricted share units (both time-based and performance-based), and stock options. Stock-based compensation expense from continuing operations totaled $33,255, $37,802, and $17,344, for the years ended December 31, 2010, 2009, and 2008, respectively. For the years ended December 31, 2010, 2009, and 2008, approximately 75%, 78%, and 52%, respectively, of stock-based compensation expense from continuing operations is reported as selling, general and administrative expenses and approximately 25%, 22%, and 48%, respectively, of the stock-based compensation expense from continuing operations was recorded as a component of cost of coal sales. The total excess tax benefit recognized for stock-based compensation for the years ending Decemb er 31, 2010, 2009, and 2008 was $5,505, $434, and $3,608, respectively.

Restricted Stock Awards

Restricted stock awards granted to executive officers and key employees, generally vest ratably over three-years or cliff vest after three years (with accelerated vesting upon a change of control), depending on the recipients’ position with the company. Restricted stock awards granted to the Company’s directors generally vest at the time of grant, but are restricted until six months after termination of such director’s service on the Company’s Board of Directors (with accelerated vesting upon a change of control).  

During the years ended December 31, 2010, 2009, and 2008, the Company granted restricted stock awards to its executive officers, directors and key employees in the amount of 0, 921,901, and 399,561, respectively, of which 780,015 remain outstanding at December 31, 2010.

127

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Restricted stock award activity for the year ended December 31, 2010 is summarized in the following table:

	Number of Shares			Weighted-Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2009		1,189,271		$	18.97
Vested		(403,516	)	$	16.03
Forfeited/Expired		(5,740	)	$	23.71
Non-vested shares outstanding at December 31, 2010		780,015		$	20.54

The fair value of restricted stock awards that vested for the years ended December 31, 2010, 2009, and 2008 was $20,062, $11,453, and $11,874, respectively. As of December 31, 2010, there was $4,108 of unrecognized compensation cost related to non-vested restricted stock awards which is expected to be recognized as expense over a weighted-average period of 1.09 years.

Restricted Share Units

Time-Based Share Units

Time-based share units awarded to executive officers and key employees generally vest, subject to continued employment, ratably over three-year periods or cliff vest after three years (with accelerated vesting upon a change of control), depending on the recipients’ position with the Company. Time-based restricted share units granted to the Company’s directors generally vest at the time of grant, but are restricted until six months after termination of such director’s service on the Company’s Board of Directors (with accelerated vesting upon a change of control). Upon vesting of time-based share units, the Company issues authorized and unissued shares of the Company’s common stock to the recipient.

During the year ended December 31, 2010, the Company granted time-based share units under the 2010 LTIP to certain directors in the amount of 1,515, which were outstanding at December 31, 2010.

During the years ended December 31, 2010, 2009, and 2008, the Company granted time-based share units under the 2005 LTIP to certain executive officers, directors and key employee's in the amount of 221,466 , 218,750, and 5,925, respectively, of which 385,481 remained outstanding at December 31, 2010.

During the years ended December 31, 2010 and 2009, the Company granted time-based share units under the 2004 SIP to certain executive officers, directors and key employee's in the amount of 141,692 and 139,650, respectively, from the 2004 SIP, of which 273,912 remained outstanding at December 31, 2010.

On July 31, 2009, the Company assumed 540,002 former Foundation performance share unit awards that converted to time-based share units upon change of control due to the Foundation Merger. These awards vest over various periods through February 29, 2012.  The Company determined the fair value of these share units at the time of the Foundation Merger was $8,541, which is being recognized over the requisite service periods of the awards.  At December 31, 2010, 407,734 of these time-based share units remained outstanding.

128

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Time-based share unit activity for the year ended December 31, 2010 is summarized in the following table:

	Number of Shares			Weighted-Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2009		886,214		$	33.17
Granted		364,673		$	49.22
Vested		(176,473	)	$	33.60
Forfeited/Expired		(5,772	)	$	22.65
Non-vested shares outstanding at December 31, 2010		1,068,642		$	38.50

The fair value of time-based share unit awards that vested in the year ended December 31, 2010, 2009 and 2008 was $7,754, $374 and $0, respectively. As of December 31, 2010, there was $13,793 of unrecognized compensation cost related to non-vested time-based share units which is expected to be recognized as expense over a weighted-average period of 1.64 years.

Performance-Based Share Units

Performance-based share units awarded to executive officers and key employees generally cliff vest after three years, subject to continued employment (with accelerated vesting upon a change of control). Performance-based share units granted represent the number of shares of common stock to be awarded based on the achievement of targeted performance levels related to pre-established operating income goals, strategic goals, and total shareholder return goals over a three year period and may range from 0 percent to 200 percent of the targeted amount, except in the case of outstanding performance units granted in 2008, in which case may range from 0 to 150 percent. The grant date fair value of the awards related to operating income and strategic goals targets is based on the closing price of the Company’s common sto ck on the established grant date and is amortized over the performance period. The grant date fair value of the awards related to the total shareholder return target is based upon a Monte Carlo simulation and is amortized over the performance period. The Company reassesses at each reporting date whether achievement of each of the performance conditions is probable, as well as estimated forfeitures, and adjusts the accruals of compensation expense as appropriate. Upon vesting of performance-based share units, the Company issues authorized and unissued shares of the Company’s common stock to the recipient.

During 2010, the Company awarded 265,636 performance-based share units, of which 261,843 remain outstanding as of December 31, 2010. At December 31, 2010, the Company had assessed the operating income and total shareholder return targets as probable of achievement. As of December 31, 2010, there was $10,072 of unamortized compensation cost related to the 2010 performance-based share units which is expected to be recognized as expense over a weighted-average period of 2.00 years.

During 2009, the Company awarded 355,672 performance-based share units, of which 334,597 remain outstanding as of December 31, 2010. Prior to November 18, 2009, the portion of the awards related to strategic goals did not meet the definition of a grant date. After the successful completion of the Foundation Merger, the Company determined that attainment of the strategic goals of the awards was achieved on November 18, 2009, thus requiring the Company to recognize the associated expense based on the closing stock price on that date. At December 31, 2010, the Company had assessed the operating income, strategic goals and total shareholder return targets as probable of achievement. As of December 31, 2010, there was $4,081 of unrecognized compensation cost related to the 2009 performance-based share units which is expected to be recognized as expense over a weighted-average period of 1.00 years.

During 2008, the Company awarded 165,045 performance-based share units, of which 150,585 remain outstanding as of December 31, 2010. Prior to November 18, 2009, the portion of the awards related to strategic goals did not meet the definition of a grant date. After the successful completion of the Foundation Merger, the Company determined that attainment of the strategic goals of the awards was achieved on November 18, 2009, thus requiring the Company to recognize the associated expense based on the closing stock price on that date. At December 31, 2010, the Company had assessed the operating income, strategic goals and total shareholder return targets as probable of achievement. As of December 31, 2010, all compensation cost related to the 2008 performance-based share units had been recognized.

During the fourth quarter of 2010, the Company modified the performance criteria for certain restricted share units granted in 2009 and 2008 and remeasured the affected stock-based awards. Additional compensation expense of approximately $4,012 will be recognized over the remaining vesting periods. For the year ended December 31, 2010, approximately $1,525 of the additional compensation expense was recognized.

129

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Performance-based share unit activity for the year ended December 31, 2010 is summarized in the following table:

	Number of Shares			Weighted-Average Grant Date Fair Value
Non-vested shares outstanding at December 31, 2009		1,352,429		$	29.43
Granted		531,272		$	50.32
Earned		(451,913	)	$	21.08
Forfeited or expired		(13,031	)	$	44.09
Non-vested shares outstanding at December 31, 2010		1,418,757		$	37.56

Shares in the table above are based on the maximum shares that can be awarded based on the achievement of the performance criteria. The fair value of performance-based share unit awards granted in 2007 and vested on February 10, 2010 was $18,841.

Non-Qualified Stock Options

On July 31, 2009, in connection with the Foundation Merger, the Company assumed 1,118,546 options from Foundation that were fully vested upon change of control due to the Foundation Merger. Of the 1,118,546 options assumed, 196,457 have a merger ratio adjusted exercise price of $4.50 and 922,089 have a merger ratio adjusted exercise price of $7.87. These options have an expiration date of August 10, 2014. The Company determined the fair value of these options at the time of the Foundation Merger and recognized a one-time charge of $600 for stock-based compensation in the third quarter of 2009. As of December 31, 2010, 58,609 of the $4.50 options were outstanding and exercisable and 350,770 of the $7.87 options were outstanding and exercisable.

The fair value of the Foundation options assumed on July 31, 2009 was estimated using the Black-Scholes option-pricing model using the following assumptions:

· Price of the underlying stock:

o Closing stock price for Foundation on July 31, 2009 – $35.93

o Closing stock price for Alpha on July 31, 2009 – $33.31

· Option exercise price:

o Pre-conversion option exercise prices – $4.87 and $8.53

o Post-conversion option exercise prices – $4.50 and $7.87 (Adjusted for the Foundation Merger ratio of 1.084)

· Expected life in years – 2.51 years

· Risk-free interest rate – 1.38%

· Dividend yield – 0.00%

· Expected volatility – 65.83%

Insufficient data existed to develop a reliable expected stock option life, therefore, the simplified method was utilized to estimate the expected life of these options. The expected life in years was determined by using the midpoint between the valuation date and the expiration date.  Expected volatility was based on both Alpha’s and Foundation’s pre-merger implied future stock price volatilities derived from exchange traded options and actual historic stock price volatilities.

The weighted-average fair value of the Foundation options assumed on July 31, 2009 was $26.74.

130

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Stock option activity for the year ended December 31, 2010 is summarized in the following table:

	Number of Shares			Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Term (Years)
Outstanding at December 31, 2009		1,048,405		$	11.32
Exercised		(452,439	)	$	12.23
Outstanding at December 31, 2010		595,966		$	10.60		3.74
Exercisable at December 31, 2010		595,966		$	10.60		3.74

As of December 31, 2010, the options outstanding and exercisable had an aggregate intrinsic value of $29,451. Cash received from the exercise of stock options during the years ended December 31, 2010, 2009, and 2008 was $5,536, $5,169, and $3,586, respectively. As of December 31, 2010, all compensation cost related to stock options has been recognized as expense.

The total intrinsic value of options exercised during the years ended December 31, 2010, 2009, and 2008 was $17,449, $15,186, and $6,692, respectively. The Company currently uses authorized and unissued shares to satisfy share award exercises.

A summary of the Company’s options outstanding and exercisable at December 31, 2010 follows:

		Options Outstanding and Exercisable
Exercise Price		Shares		Weighted- Average Remaining Life (yrs)		Weighted- Average Exercise Price
$	12.73		40,847		3.90	$	12.73
$	19.00		143,740		4.10	$	19.00
$	24.85		2,000		4.30	$	24.85
$	4.50		58,609		3.60	$	4.50
$	7.87		350,770		3.60	$	7.87

(17)     Related Party Transactions

For the years ended December 31, 2010, 2009 and 2008, there were no material related party transactions.

(18)     Commitments and Contingencies

(a) General

Estimated losses from loss contingencies and legal expenses associated with the contingency are accrued by a charge to income when information available indicates that it is probable that an asset has been impaired or a liability has been incurred and the amount of the loss can be reasonably estimated. If a loss contingency is not probable or reasonably estimable, disclosure of the loss contingency is made in the consolidated financial statements when it is at least reasonably possible that a loss will be incurred and the loss is material.

(b) Commitments and Contingencies

Commitments

The Company leases coal mining and other equipment under long-term operating leases with varying terms. In addition, the Company leases mineral interests and surface rights from land owners under various terms and royalty rates.

131

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

As of December 31, 2010, aggregate future minimum non-cancelable lease payments under operating leases and minimum royalties under coal leases were as follows:

	Operating Leases		Coal Royalties		Total
Year Ending December 31:
2011	$	5,857	$	16,676	$	22,533
2012		3,753		17,050		20,803
2013		1,832		14,754		16,586
2014		1,337		10,483		11,820
2015		794		8,167		8,961
Thereafter		1,226		40,797		42,023
Total	$	14,799	$	107,927	$	122,726

For the years ended December 31, 2010, 2009 and 2008, net rent expense from continuing operations amounted to $18,659, $11,463,and $5,065, respectively, and coal royalty expense from continuing operations amounted to $192,834, $117,895, and $83,707, respectively.

Other Commitments

As of December 31, 2010, the Company had commitments to purchase 2,285 tons and 72 tons of coal at a cost of approximately $227,195 and $8,280 during 2011 and 2012, respectively.

The Company has obligations for a federal coal lease, which contains an estimated 224.0 million tons of proven and probable coal reserves in the Powder River Basin. The lease bid was $180,540, payable in five equal annual installments of $36,108. The first two installments were paid in 2009 and 2008 by Foundation. The third installment was paid in 2010 by the Company. The two remaining annual installments of $36,108 each are due on May 1, the anniversary date of the lease in 2011 and 2012.

Also, see Note 9 regarding the Company’s Other debt.

Contingencies

Extensive regulation of the impacts of mining on the environment and of maintaining workplace safety, and related litigation, has had or may have a significant effect on the Company’s costs of production and results of operations. Further regulations, legislation or litigation in these areas may also cause the Company’s sales or profitability to decline by increasing costs or by hindering the Company’s ability to continue mining at existing operations or to permit new operations.

(c) Guarantees and Financial Instruments with Off-Balance Sheet Risk

In the normal course of business, the Company is a party to certain guarantees and financial instruments with off-balance sheet risk, such as bank letters of credit, performance or surety bonds, and other guarantees and indemnities related to the obligations of affiliated entities which are not reflected in the Company's Consolidated Balance Sheets. Management does not expect any material losses to result from these guarantees or other off-balance sheet financial instruments. The amount of outstanding surety bonds related to the Company’s reclamation obligations as of December 31, 2010 is $498,484.

Letters of Credit

The amount of outstanding bank letters of credit issued under the Company’s accounts receivable securitization program as of December 31, 2010 is presented in Note 9. As of December 31, 2010, the Company had $7,650 of additional letters of credit outstanding under its revolving credit facility.

(d) Legal Proceedings

The Company is a party to a number of legal proceedings incident to its normal business activities. While the Company cannot predict the outcome of these proceedings, the Company does not believe that any liability arising from these matters individually or in the aggregate should have a material impact upon its consolidated cash flows, results of operations or financial condition.

132

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Nicewonder Litigation

In December 2004, prior to Old Alpha’s Nicewonder acquisition in October 2005, the Affiliated Construction Trades Foundation brought an action against the West Virginia Department of Transportation, Division of Highways (“WVDOH”) and Nicewonder Contracting, Inc. ("NCI"), which became our wholly-owned indirect subsidiary as a result of the Nicewonder acquisition, in the United States District Court in the Southern District of West Virginia. The plaintiff sought a declaration that the contract between NCI and the State of West Virginia related to NCI's road construction project was illegal as a violation of applicable West Virginia and federal competitive bidding and prevailing wage laws. The plaintiff also sought an injunction prohibiting performance of the contract but has not sought monetary damages.

In September 2007, the Court ruled that the WVDOH and the Federal Highway Administration (which is now a party to the suit) could not, under the circumstances of this case, enter into a contract that did not require the contractor to pay the prevailing wages as required by the Davis-Bacon Act. In anticipation of a potential Court directive that the contract be renegotiated for such payment, for which the WVDOH had committed to reimburse NCI, the Company recorded a $9,000 long-term liability for the potential obligations under the ruling and an offsetting $9,000 long-term receivable for the recovery of these costs from the WVDOH.

On September 30, 2009, the Court issued an order that dismissed or denied for lack of standing all of the plaintiff’s claims under federal law and remanded the remaining state claims to circuit court in Kanawha County, WV for resolution. The Court also vacated portions of its September 2007 order, and held that the plaintiff lacked standing to pursue the Davis-Bacon Act claim and further concluded that no private right of action exists to challenge the absence of a provision in a contract for highway construction requiring payment of prevailing wages established by the Davis-Bacon Act. As a result of the September 30, 2009 ruling, the previously established long-term liability and offsetting long-term receivable of $9,000 have been reversed.

On May 7, 2010, the Circuit Court of Kanawha County entered Summary Judgment in favor of NCI.  The plaintiffs filed a petition for appeal with the West Virginia Supreme Court of Appeals and the Court of Appeals accepted the appeal by order dated November 17, 2010.  A final decision on the appeal is not expected until later in 2011.

Cliffs Proposed Acquisition

On July 15, 2008, the Company entered into a definitive merger agreement pursuant to which, and subject to the terms and conditions thereof, Cliffs would acquire all of the Company’s outstanding shares. On November 3, 2008, the Company commenced litigation against Cliffs by filing an action in the Delaware Court of Chancery to obtain an order to require Cliffs to hold its shareholder meeting as scheduled. On November 17, 2008, the Company and Cliffs mutually terminated the merger agreement and settled the litigation. The terms of the settlement agreement included a $70,000 payment from Cliffs to the Company, which net of transaction costs, resulted in a gain of $56,315.

(19)     Mergers and Acquisitions

Merger with Foundation Coal Holdings, Inc.

On May 11, 2009, Old Alpha and Foundation executed an agreement and plan of merger pursuant to which Old Alpha was to be merged with and into Foundation, with Foundation continuing as the surviving corporation of the Foundation Merger. On July 31, 2009, the Foundation Merger was completed and Foundation was renamed Alpha Natural Resources, Inc.

During the year ended December 31, 2010, the Company finalized the purchase price allocation for the Foundation Merger and recorded an immaterial correction to the December 31, 2009 consolidated balance sheet to reflect the adjustments as if they were recorded on the acquisition date. The increase to goodwill is reported in the Company’s Eastern Coal Operations, Western Coal Operations and All Other category as of December 31, 2010 and December 31, 2009.

133

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The following table presents the details of the preliminary purchase price allocation reported as of December 31, 2009, the adjustments made in the year ended December 31, 2010 and the final purchase price allocation.

	Preliminary December 31, 2009			Adjustments(1)			Final December 31, 2009
Cash	$	23,505		$	-		$	23,505
Trade accounts receivable		83,531			-			83,531
Coal inventories		47,433			-			47,433
Other current assets		61,269			-			61,269
Property and equipment		716,749			-			716,749
Owned lands		76,134			-			76,134
Owned and leased mineral rights		1,873,347			(27,000	)		1,846,347
Coal supply agreements		529,507			-			529,507
Other non-current assets		14,296			-			14,296
Goodwill		337,321			24,572			361,893
Total assets		3,763,092			(2,428	)		3,760,664
Current liabilities		(176,233	)		(12,729	)		(188,962	)
Long-term debt, net (including current portion)		(595,817	)		-			(595,817	)
Asset retirement obligation (including current portion)		(99,574	)		-			(99,574	)
Deferred income taxes		(443,744	)		15,157			(428,587	)
Pension and post retirement obligations (including current portion)		(713,095	)		-			(713,095	)
Other non-current liabilities		(66,231	)		-			(66,231	)
Total liabilities		(2,094,694	)		2,428			(2,092,266	)
Net tangible and intangible assets acquired	$	1,668,398		$	-		$	1,668,398

(1) Adjustments include an immaterial correction recorded in the year ended December 31, 2010 which increased accrued expenses and goodwill $3,468 and $2,145, respectively, and decreased deferred income taxes $1,323.

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

The unaudited pro forma results for the years ended December 31, 2009 and 2008 are as follows:

	Years Ended December 31,
	2009			2008
Total revenues
As reported	$	2,495,507		$	2,468,753
Pro forma	$	3,402,678		$	4,041,014
Income (loss) from continuing operations
As reported	$	66,807		$	198,599
Pro forma	$	(58,187	)	$	1,420
Earnings per share from continuing operations-basic
As reported	$	0.74		$	2.90
Pro forma	$	(0.49	)	$	0.01
Earnings per share from continuing operations-diluted
As reported	$	0.73		$	2.83
Pro forma	$	(0.49	)	$	0.01

134

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Total revenues reported in the Consolidated Statements of Operations for the year ended December 31, 2009 included total revenues of $716,764 related to Foundation. The amount of earnings from continuing operations related to Foundation included in the Consolidated Statement of Operations for the year ended December 31, 2009 is not readily determinable due to various intercompany transactions and allocations that have occurred in connection with the operations of the combined company.

Sale of Coal Reserves

On September 30, 2008, the Company completed the sale of approximately 17.6 million tons of underground coal reserves in eastern Kentucky to a private coal producer for $13,041 in cash. The reserves were a portion of an estimated 73 million tons of reserves and other assets acquired from Progress Fuels Corporation in May 2006. The Company recorded a gain of $12,936 on the sale.

(20)     Concentration of Credit Risk and Major Customers

The Company markets its coal principally to electric utilities in the United States and international and domestic steel producers. Credit is extended based on an evaluation of the customer's financial condition and collateral is generally not required. Credit losses are provided for in the consolidated financial statements and historically have been minimal. The Company is committed under long-term contracts to supply coal that meets certain quality requirements at specified prices. The prices for some multi-year contracts are adjusted based on economic indices or the contract may include year-to-year specified price changes. Qualities and volume for coal are stipulated in coal supply agreements, and may vary from year to year within certain limits at the option of the customer. For the years ended December 31, 2010, 2009, and 2008, the Company’s 10 largest customers accounted for approximately 42%, 47% and 54% of total revenues, respectively. Sales to the Company's largest customer accounted for approximately 9% of total revenues for the year ended December 31, 2010 and 12% of total revenues for the years ended December 31, 2009 and 2008. Steam coal accounted for approximately 86%, 83% and 58% of our coal sales volume during 2010, 2009 and 2008, respectively. Metallurgical coal accounted for approximately 14%, 17% and 42% of our coal sales volume during 2010, 2009 and 2008, respectively.

(21)     Segment Information

The Company discloses information about operating segments using the management approach, where segments are determined and reported based on the way that management organizes the enterprise for making operating decisions and assessing performance. The Company periodically evaluates its application of accounting guidance for reporting its segments.

The Company extracts, processes and markets steam and metallurgical coal from surface and deep mines for sale to electric utilities, steel and coke producers, and industrial customers. The Company operates only in the United States with mines in Central Appalachia, Northern Appalachia, and the Powder River Basin. Prior to the Foundation Merger, Old Alpha had only one reportable segment, Coal Operations, which included operations in Central and Northern Appalachia. As a result of the Foundation Merger, the Company changed its organizational structure and re-evaluated its reportable segments. Based on a review of the required economic characteristics, the Company aggregated its operating segments into two reportable segments: Western Coal Operations, which consists of two Powder River Basin surface mines as of December 31, 2010 and Eastern Coal Operations, which consists of 38 underground mines and 26 surface mines in Central and Northern Appalachia as of December 31, 2010, as well as the Company’s road construction business which operates in Central Appalachia and its coal brokerage activities.

In addition to the two reportable segments, the All Other category includes an idled underground mine in Illinois; expenses associated with closed mines; Dry Systems Technologies; revenues and royalties from the sale of coalbed methane and natural gas extraction; equipment sales and repair operations; terminal services; the leasing of mineral rights; general corporate overhead and corporate assets and liabilities. The Company evaluates the performance of its segments based on EBITDA from continuing operations, which the Company defines as income from continuing operations plus interest expense, income tax expense, amortization of coal supply agreements, net and depreciation, depletion and amortization, less interest income and income tax benefit.

135

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Segment operating results and capital expenditures from continuing operations for the year ended December 31, 2010 were as follows:

	Eastern Coal Operations		Western Coal Operations		All Other			Consolidated
Total revenues	$	3,324,548	$	544,058	$	48,550		$	3,917,156
Depreciation, depletion, and amortization	$	298,163	$	58,888	$	13,844		$	370,895
Amortization of acquired coal supply agreements, net	$	136,501	$	90,292	$	-		$	226,793
EBITDA from continuing operations	$	678,339	$	97,583	$	(6,793	)	$	769,129
Capital expenditures	$	214,652	$	46,654	$	47,558		$	308,864
Acquisition of mineral rights under federal lease	$	-	$	36,108	$	-		$	36,108

The following table presents a reconciliation of EBITDA from continuing operations to income from continuing operations for the year ended December 31, 2010:

	Eastern Coal Operations			Western Coal Operations			All Other			Consolidated
EBITDA from continuing operations	$	678,339		$	97,583		$	(6,793	)	$	769,129
Interest expense		(41,434	)		(1,464	)		(30,565	)		(73,463	)
Interest income		(7,808	)		100			11,166			3,458
Income tax expense		-			-			(4,218	)		(4,218	)
Depreciation, depletion and amortization		(298,163	)		(58,888	)		(13,844	)		(370,895	)
Amortization of acquired coal supply agreements, net		(136,501	)		(90,292	)		-			(226,793	)
Income (loss) from continuing operations	$	194,433		$	(52,961	)	$	(44,254	)	$	97,218

Segment operating results and capital expenditures from continuing operations for the year ended December 31, 2009 were as follows:

	Eastern Coal Operations		Western Coal Operations		All Other			Consolidated
Total revenues	$	2,249,027	$	218,613	$	27,867		$	2,495,507
Depreciation, depletion, and amortization	$	219,047	$	25,562	$	7,786		$	252,395
Amortization of acquired coal supply agreements, net	$	78,537	$	49,071	$	-		$	127,608
EBITDA from continuing operations	$	524,042	$	39,278	$	(68,477	)	$	494,843
Capital expenditures	$	157,121	$	18,310	$	11,662		$	187,093

The following table presents a reconciliation of EBITDA from continuing operations to income from continuing operations for the year ended December 31, 2009:

	Eastern Coal Operations			Western Coal Operations			All Other			Consolidated
EBITDA from continuing operations	$	524,042		$	39,278		$	(68,477	)	$	494,843
Interest expense		(18,843	)		(2,275	)		(61,707	)		(82,825	)
Interest income		(2,887	)		-			4,656			1,769
Income tax benefit		-			-			33,023			33,023
Depreciation, depletion and amortization		(219,047	)		(25,562	)		(7,786	)		(252,395	)
Amortization of acquired coal supply agreements, net		(78,537	)		(49,071	)		-			(127,608	)
Income (loss) from continuing operations	$	204,728		$	(37,630	)	$	(100,291	)	$	66,807

136

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Segment operating results and capital expenditures from continuing operations for the year ended December 31, 2008 were as follows:

	Eastern Coal Operations		Western Coal Operations		All Other		Consolidated
Total revenues	$	2,454,702	$	-	$	14,051	$	2,468,753
Depreciation, depletion, and amortization	$	162,902	$	-	$	2,067	$	164,969
EBITDA from continuing operations	$	421,572	$	-	$	26,699	$	448,271
Capital expenditures	$	125,049	$	-	$	1,574	$	126,623

The following table presents a reconciliation of EBITDA from continuing operations to income from continuing operations for the year ended December 31, 2008:

	Eastern Coal Operations			Western Coal Operations		All Other			Consolidated
EBITDA from continuing operations	$	421,572		$	-	$	26,699		$	448,271
Interest expense		(78	)		-		(39,734	)		(39,812	)
Interest income		713			-		6,638			7,351
Income tax expense		-			-		(52,242	)		(52,242	)
Depreciation, depletion and amortization		(162,902	)		-		(2,067	)		(164,969	)
Income (loss) from continuing operations	$	259,305		$	-	$	(60,706	)	$	198,599

The following table presents total assets and goodwill:

	Total Assets						Goodwill
	December 31,		December 31,		December 31,		December 31,		December 31,		December 31,
	2010		2009		2008		2010		2009		2008
Eastern Coal Operations	$	3,382,335	$	3,627,842	$	873,565	$	323,220	$	323,220	$	20,547
Western Coal Operations		651,479		722,082		-		53,308		53,308		-
All Other		1,145,469		770,419		836,273		5,912		5,912		-
Total	$	5,179,283	$	5,120,343	$	1,709,838	$	382,440	$	382,440	$	20,547

The Company sells produced, processed and purchased coal to customers in the United States and in international markets, primarily Brazil, Italy, India, Turkey, and Ukraine.  Export coal revenues from continuing operations, which includes freight and handling revenues, totaled $1,351,001 or approximately 34% of total revenues from continuing operations for the year ended December 31, 2010; $767,793 or approximately 31% of total revenues from continuing operations for the year ended December 31, 2009; and $1,290,553 or approximately 52% of total revenues from continuing operations for the year ended December 31, 2008.

(22)    Supplemental Guarantor and Non-Guarantor Financial Information

On July 30, 2004, Foundation’s subsidiary, Foundation PA (the “2014 Notes Issuer”), issued the 2014 Notes. The 2014 Notes were guaranteed on a senior unsecured basis by Foundation Coal Corporation (“FCC”), an indirect parent of Foundation PA, and certain of its subsidiaries. As a result of the Foundation Merger, Foundation PA and FCC became subsidiaries of Alpha Natural Resources, Inc.

On August 1, 2009, in connection with the Foundation Merger, Foundation PA, Alpha Natural Resources, Inc. and certain of its subsidiaries (which were also former subsidiaries of Old Alpha) (the “New Subsidiaries”) executed a supplemental indenture (the “Third Supplemental Indenture”), which supplements the indenture dated as of July 30, 2004 as supplemented, governing the 2014 Notes.

Pursuant to the Third Supplemental Indenture, Alpha Natural Resources, Inc. assumed the obligations of FCC in respect of the 2014 Notes and, along with the New Subsidiaries, became obligated as guarantors on the indenture governing the 2014 Notes. On August 1, 2009, in connection with the Foundation Merger, FCC merged with and into Alpha Natural Resources, Inc. In accordance with the indenture governing the 2014 Notes, the “Guarantor Subsidiaries” under the 2014 Notes, referred to as the “2014 Notes Guarantor Subsidiaries”, are each of the direct and indirect wholly owned subsidiaries of Alpha Natural Resources, Inc., other than the 2014 Notes Issuer and the Non-Guarantor Subsidiary.  Alpha Natural Resources, Inc. and the 2014 Notes Guarantor Subsidiaries have fully and unconditionally guaranteed th e 2014 Notes, jointly and severally, on a senior unsecured basis.

137

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Presented below are consolidating financial statements as of December 31, 2010 and 2009 and for the years ended December 31, 2010, 2009, and 2008, respectively, based on the guarantor structure that was in place at December 31, 2010. As the Foundation Merger was treated as a “reverse acquisition” and Old Alpha was treated as the accounting acquirer, Old Alpha’s historical financial statements are the historical financial statements of the Company for comparative purposes. As a result, “Parent” in the tables below refers to Old Alpha in reference to dates prior to the Foundation Merger and to Alpha Natural Resources, Inc. in reference to dates following the Foundation Merger, and refers to Old Alpha or Alpha Natural Resources, Inc., as applicable, as a guarantor of the 2014 Notes; information is presented for “2014 Notes Issuer” only for dates following the Foundation Merger because the 2014 Notes Issuer was a subsidiary of Foundation prior to the Foundation Merger; and information for “2014 Notes Guarantor Subsidiaries” prior to the Foundation Merger includes only those 2014 Notes Guarantor Subsidiaries that were subsidiaries of Old Alpha prior to the Foundation Merger. "Non-Guarantor Subsidiary" refers, for the tables below dated as of and for the periods ended December 31, 2010 and 2009, to ANR Receivables Funding LLC, a wholly-owned indirect subsidiary of Old Alpha and Alpha Natural Resources, Inc. formed on March 25, 2009 in connection with the A/R Facility, that was not and is not a guarantor of the 2014 Notes.  Separate consolidated financial statements and other disclosures concerning the 2014 Notes Guarantor Subsidiaries are not presented because management believes that such information is not material to holders of the 2014 Notes or related guarantees.

138

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Balance Sheet

December 31, 2010

	Parent		2014 Notes Issuer		2014 Notes Guarantor Subsidiaries		Non-Guarantor Subsidiary		Eliminations			Total Consolidated
Assets
Current assets:
Cash and cash equivalents	$	20,331	$	-	$	534,441	$	-	$	-		$	554,772
Trade accounts receivable, net		-		-		18,432		262,706		-			281,138
Inventories, net		-		-		198,172		-		-			198,172
Prepaid expenses and other current assets		-		-		341,755		-		-			341,755
Total current assets		20,331		-		1,092,800		262,706		-			1,375,837
Property, equipment and mine development costs, net		-		-		1,131,987		-		-			1,131,987
Owned and leased mineral rights, net		-		-		1,884,169		-		-			1,884,169
Owned lands		-		-		98,727		-		-			98,727
Goodwill		-		-		382,440		-		-			382,440
Acquired coal supply agreements, net		-		-		162,397		-		-			162,397
Other non-current assets		5,167,187		1,578,118		3,719,826		4,705		(10,326,110	)		143,726
Total assets	$	5,187,518	$	1,578,118	$	8,472,346	$	267,411	$	(10,326,110	)	$	5,179,283
Liabilities and Stockholders' Equity
Current liabilities:
Current portion of long-term debt	$	-	$	11,839	$	-	$	-	$	-		$	11,839
Trade accounts payable		2,091		-		119,462		-		-			121,553
Accrued expenses and other current liabilities		1,423		10,195		302,110		26		-			313,754
Total current liabilities		3,514		22,034		421,572		26		-			447,146
Long-term debt		222,355		512,138		7,819		-		-			742,312
Pension and postretirement medical benefit obligations		-		-		719,355		-		-			719,355
Asset retirement obligations		-		-		209,987		-		-			209,987
Deferred income taxes		-		-		249,408		-		-			249,408
Other non-current liabilities		2,305,613		671,273		1,528,008		261,372		(4,611,227	)		155,039
Total liabilities		2,531,482		1,205,445		3,136,149		261,398		(4,611,227	)		2,523,247
Stockholders' Equity
Total stockholders' equity		2,656,036		372,673		5,336,197		6,013		(5,714,883	)		2,656,036
Total liabilities and stockholders' equity	$	5,187,518	$	1,578,118	$	8,472,346	$	267,411	$	(10,326,110	)	$	5,179,283

139

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Balance Sheet

December 31, 2009

	Parent		2014 Notes Issuer		2014 Notes Guarantor Subsidiaries		Non-Guarantor Subsidiary		Eliminations			Total Consolidated
Assets
Current assets:
Cash and cash equivalents	$	69,410	$	-	$	396,459	$	-	$	-		$	465,869
Trade accounts receivable, net		-		-		18,541		214,090		-			232,631
Inventories, net		-		-		176,372		-		-			176,372
Prepaid expenses and other current assets		-		-		176,953		-		-			176,953
Total current assets		69,410		-		768,325		214,090		-			1,051,825
Property, equipment and mine development costs, net		-		-		1,082,446		-		-			1,082,446
Owned and leased mineral rights, net		-		-		1,958,855		-		-			1,958,855
Owned lands		-		-		91,262		-		-			91,262
Goodwill		-		-		382,440		-		-			382,440
Acquired coal supply agreements, net		-		-		396,491		-		-			396,491
Other non-current assets		4,121,982		1,659,341		2,560,143		49,472		(8,233,914	)		157,024
Total assets	$	4,191,392	$	1,659,341	$	7,239,962	$	263,562	$	(8,233,914	)	$	5,120,343
Liabilities and Stockholders' Equity
Current liabilities:
Current portion of long-term debt	$	-	$	33,500	$	-	$	-	$	-		$	33,500
Trade accounts payable		1,469		-		151,193		-		-			152,662
Accrued expenses and other current liabilities		1,423		9,552		262,217		68		-			273,260
Total current liabilities		2,892		43,052		413,410		68		-			459,422
Long-term debt		210,524		546,229		-		-		-			756,753
Pension and postretirement medical benefit obligations		-		-		682,991		-		-			682,991
Asset retirement obligations		-		-		190,724		-		-			190,724
Deferred income taxes		-		-		301,307		-		-			301,307
Other non-current liabilities		1,386,687		671,273		594,099		259,172		(2,773,374	)		137,857
Total liabilities		1,600,103		1,260,554		2,182,531		259,240		(2,773,374	)		2,529,054
Stockholders' Equity
Total stockholders' equity		2,591,289		398,787		5,057,431		4,322		(5,460,540	)		2,591,289
Total liabilities and stockholders' equity	$	4,191,392	$	1,659,341	$	7,239,962	$	263,562	$	(8,233,914	)	$	5,120,343

140

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Consolidating Statement of Operations

Year Ended December 31, 2010

	Parent			2014 Notes Issuer			2014 Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Total Consolidated
Revenues:
Coal revenues	$	-		$	-		$	3,497,847		$	-		$	-		$	3,497,847
Freight and handling revenues		-			-			332,559			-			-			332,559
Other revenues		-			-			78,066			8,684			-			86,750
Total revenues		-			-			3,908,472			8,684			-			3,917,156
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)		-			-			2,566,825			-			-			2,566,825
Freight and handling costs		-			-			332,559			-			-			332,559
Other expenses		-			-			65,498			-			-			65,498
Depreciation, depletion and amortization		-			-			370,895			-			-			370,895
Amortization of acquired coal supply agreements, net		-			-			226,793			-			-			226,793
Selling, general and administrative expenses
(exclusive of depreciation, depletion and amortization shown separately above)		-			-			177,979			2,996			-			180,975
Total costs and expenses		-			-			3,740,549			2,996			-			3,743,545
Income from operations		-			-			167,923			5,688			-			173,611
Other income (expense):
Interest expense		(19,570	)		(43,226	)		(7,751	)		(2,916	)		-			(73,463	)
Interest income		-			-			3,458			-			-			3,458
Loss on early extinguishment of debt		-			-			(1,349	)		-			-			(1,349	)
Miscellaneous expense, net		-			-			(821	)		-			-			(821	)
Total other expense, net		(19,570	)		(43,226	)		(6,463	)		(2,916	)		-			(72,175	)
Income (loss) from continuing operations before income taxes and equity in earnings of investments in Issuer and Guarantor Subsidiaries		(19,570	)		(43,226	)		161,460			2,772			-			101,436
Income tax benefit (expense)		7,632			16,858			(27,627	)		(1,081	)		-			(4,218	)
Equity in earnings of investments in Issuer and Guarantor Subsidiaries		107,489			2,365			-			-			(109,854	)		-
Income (loss) from continuing operations		95,551			(24,003	)		133,833			1,691			(109,854	)		97,218
Discontinued operations:
Loss from discontinued operations before income taxes		-			-			(2,719	)		-			-			(2,719	)
Income tax benefit		-			-			1,052			-			-			1,052
Loss from discontinued operations		-			-			(1,667	)		-			-			(1,667	)
Net income (loss)	$	95,551		$	(24,003	)	$	132,166		$	1,691		$	(109,854	)	$	95,551
Less:  Net loss from discontinued operations attributable to noncontrolling interest		-			-			-			-			-			-
Net income attributable to Alpha Natural Resources, Inc.	$	95,551		$	(24,003	)	$	132,166		$	1,691		$	(109,854	)	$	95,551

141

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Operations

Year Ended December 31, 2009

	Parent			2014 Notes Issuer			2014 Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Total Consolidated
Revenues:
Coal revenues	$	-		$	-		$	2,210,629		$	-		$	-		$	2,210,629
Freight and handling revenues		-			-			189,874			-			-			189,874
Other revenues		-			-			91,135			3,869			-			95,004
Total revenues		-			-			2,491,638			3,869			-			2,495,507
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)		-			-			1,616,905			-			-			1,616,905
Freight and handling costs		-			-			189,874			-			-			189,874
Other expenses		-			-			21,016			-			-			21,016
Depreciation, depletion and amortization		-			-			252,395			-			-			252,395
Amortization of acquired coal supply agreements, net		-			-			127,608			-			-			127,608
Selling, general and administrative expenses
(exclusive of depreciation, depletion and amortization shown separately above)		78			-			169,236			1,100			-			170,414
Total costs and expenses		78			-			2,377,034			1,100			-			2,378,212
(Loss) Income from operations		(78	)		-			114,604			2,769			-			117,295
Other income (expense):
Interest expense		(18,758	)		(17,559	)		(45,086	)		(1,422	)		-			(82,825	)
Interest income		-			-			1,769			-			-			1,769
Loss on early extinguishment of debt		-			-			(5,641	)		-			-			(5,641	)
Miscellaneous income, net		-			-			3,186			-			-			3,186
Total other expense, net		(18,758	)		(17,559	)		(45,772	)		(1,422	)		-			(83,511	)
Income (loss) from continuing operations before income taxes and equity in earnings of investments in Issuer and Guarantor Subsidiaries		(18,836	)		(17,559	)		68,832			1,347			-			33,784
Income tax benefit (expense)		7,346			6,848			19,354			(525	)		-			33,023
Equity in earnings of investments in Issuer and Guarantor Subsidiaries		69,495			32,534			-			-			(102,029	)		-
Income (loss) from continuing operations		58,005			21,823			88,186			822			(102,029	)		66,807
Discontinued operations:
Loss from discontinued operations before income taxes		-			-			(14,278	)		-			-			(14,278	)
Income tax benefit		-			-			5,476			-			-			5,476
Loss from discontinued operations		-			-			(8,802	)		-			-			(8,802	)
Net income (loss)	$	58,005		$	21,823		$	79,384		$	822		$	(102,029	)	$	58,005
Less:  Net loss from discontinued operations attributable to noncontrolling interest		-			-			-			-			-			-
Net income (loss) attributable to Alpha Natural Resources, Inc.	$	58,005		$	21,823		$	79,384		$	822		$	(102,029	)	$	58,005

142

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Operations

Year Ended December 31, 2008

	Parent			2014 Notes Issuer		2014 Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Total Consolidated
Revenues:
Coal revenues	$	-		$	-	$	2,140,367		$	-		$	-		$	2,140,367
Freight and handling revenues		-			-		279,853			-			-			279,853
Other revenues		-			-		48,533			-			-			48,533
Total revenues		-			-		2,468,753			-			-			2,468,753
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)		-			-		1,627,960			-			-			1,627,960
Gain on sale of coal reserves		-			-		(12,936	)		-			-			(12,936	)
Freight and handling costs		-			-		279,853			-			-			279,853
Other expenses		-			-		91,461			-			-			91,461
Depreciation, depletion and amortization		-			-		164,969			-			-			164,969
Selling, general and administrative expenses
(exclusive of depreciation, depletion and amortization shown separately above)		-			-		71,923			-			-			71,923
Total costs and expenses		-			-		2,223,230			-			-			2,223,230
Income from operations		-			-		245,523			-			-			245,523
Other income (expense):
Interest expense		(13,295	)		-		(26,517	)		-			-			(39,812	)
Interest income		-			-		7,351			-			-			7,351
Loss on early extinguishment of debt		-			-		(14,702	)		-			-			(14,702	)
Gain on termination of Cliffs' merger, net		56,315			-		-			-			-			56,315
Miscellaneous income (expense), net		20			-		(3,854	)		-			-			(3,834	)
Total other income (expense), net		43,040			-		(37,722	)		-			-			5,318
Income from continuing operations before income taxes and equity in earnings of investments in Issuer and Guarantor Subsidiaries		43,040			-		207,801			-			-			250,841
Income tax expense		(16,786	)		-		(35,456	)		-			-			(52,242	)
Equity in earnings of investments in Issuer and Guarantor Subsidiaries		139,447			-		4,192			-			(143,639	)		-
Income (loss) from continuing operations		165,701			-		176,537			-			(143,639	)		198,599
Discontinued operations:
Loss from discontinued operations before income taxes		-			-		(19,600	)		(8,273	)		-			(27,873	)
Mine closure/asset impairment charges		-			-		(30,172	)		-			-			(30,172	)
Gain on sale of discontinued operations		-			-		-			13,622			-			13,622
Income tax benefit (expense)		-			-		12,682			(1,647	)		-			11,035
(Loss) income from discontinued operations		-			-		(37,090	)		3,702			-			(33,388	)
Net income (loss)	$	165,701		$	-	$	139,447		$	3,702		$	(143,639	)	$	165,211
Less:  Net loss from discontinued operations attributable to noncontrolling interest		-			-		-			(490	)		-			(490	)
Net income (loss) attributable to Alpha Natural Resources, Inc.	$	165,701		$	-	$	139,447		$	4,192		$	(143,639	)	$	165,701

143

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2010

	Parent			2014 Notes Issuer			2014 Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Total Consolidated
Net cash (used in) provided by operating activities	$	(7,511	)	$	(36,690	)	$	729,118		$	8,684		$	693,601
Investing activities:
Capital expenditures	$	-		$	-		$	(308,864	)	$	-		$	(308,864	)
Acquisition of mineral rights under federal lease		-			-			(36,108	)		-			(36,108	)
Purchase of equity-method investment		-			-			(5,000	)		-			(5,000	)
Purchases of marketable securities, net		-			-			(158,550	)		-			(158,550	)
Other, net		-			-			25			-			25
Net cash used in investing activities	$	-		$	-		$	(508,497	)	$	-		$	(508,497	)
Financing activities:
Principal repayments on long-term debt	$	-		$	(56,854	)	$	-		$	-		$	(56,854	)
Debt issuance costs		-			(8,594	)		-			-			(8,594	)
Excess tax benefit from stock-based awards		-			-			5,505			-			5,505
Common stock repurchases		(41,664	)		-			-			-			(41,664	)
Proceeds from exercise of stock options		5,521			-			-			-			5,521
Other, net		-			-			(115	)		-			(115	)
Transactions with affiliates		(5,425	)		102,138			(88,029	)		(8,684	)		-
Net cash (used in) provided by financing activities	$	(41,568	)	$	36,690		$	(82,639	)	$	(8,684	)	$	(96,201	)
Net decrease in cash and cash equivalents	$	(49,079	)	$	-		$	137,982		$	-		$	88,903
Cash and cash equivalents at beginning of period		69,410			-			396,459			-			465,869
Cash and cash equivalents at end of period	$	20,331		$	-		$	534,441		$	-		$	554,772

144

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2009

	Parent			2014 Notes Issuer			2014 Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Total Consolidated
Net cash (used in) provided by operating activities	$	(5,359	)	$	(16,122	)	$	373,832		$	3,869		$	356,220
Investing activities:
Capital expenditures	$	-		$	-		$	(187,093	)	$	-		$	(187,093	)
Cash acquired from a merger		-			-			23,505			-			23,505
Proceeds from disposition of property and equipment		-			-			1,197						1,197
Purchases of marketable securities		-			-			(119,419	)					(119,419	)
Net cash used in investing activities	$	-		$	-		$	(281,810	)	$	-		$	(281,810	)
Financing activities:
Principal repayments of note payable	$	-		$	-		$	(18,288	)	$	-		$	(18,288	)
Principal repayments on long-term debt		-			(16,750	)		(233,125	)		-			(249,875	)
Debt issuance costs		-			-			(11,253	)		(1,814	)		(13,067	)
Excess tax benefit from stock-based awards		-			-			434			-			434
Common stock repurchases		(8,874	)		-			-			-			(8,874	)
Proceeds from exercise of stock options		5,171			-			-			-			5,171
Other, net		-			-			(232	)		-			(232	)
Transactions with affiliates		5,151			32,872			(35,968	)		(2,055	)		-
Net cash provided by (used in) financing activities	$	1,448		$	16,122		$	(298,432	)	$	(3,869	)	$	(284,731	)
Net decrease in cash and cash equivalents	$	(3,911	)	$	-		$	(206,410	)	$	-		$	(210,321	)
Cash and cash equivalents at beginning of period		73,321			-			602,869			-			676,190
Cash and cash equivalents at end of period	$	69,410		$	-		$	396,459		$	-		$	465,869

145

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2008

	Parent			2014 Notes Issuer		2014 Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Total Consolidated
Net cash (used in) provided by operating activities	$	(3,698	)	$	-	$	475,870		$	(14,129	)	$	458,043
Investing activities:
Capital expenditures	$	-		$	-	$	(137,751	)	$	-		$	(137,751	)
Proceeds from disposition of property and equipment		-			-		16,649			-			16,649
Proceeds from sale of discontinued operations		-			-		-			45,000			45,000
Proceeds from sale of investment in coal terminal		-			-		1,500			-			1,500
Investment in Dominion Terminal Facility		-			-		(2,824	)		-			(2,824	)
Other, net		-			-		(199	)		-			(199	)
Net cash (used in) provided by investing activities	$	-		$	-	$	(122,625	)	$	45,000		$	(77,625	)
Financing activities:
Proceeds from issuance of long-term debt	$	287,500		$	-	$	-		$	-		$	287,500
Payments of bank overdraft		-			-		(160	)		-			(160	)
Principal repayments of note payable		-			-		(595	)		-			(595	)
Principal repayments on long-term debt		-			-		(175,473	)		(18,500	)		(193,973	)
Debt issuance costs		(10,861	)		-		-			-			(10,861	)
Premium payment on early extinguishment of debt		-			-		(10,736	)		-			(10,736	)
Excess tax benefit from stock-based awards		1,980			-		-			-			1,980
Proceeds from issuance of common stock, net		164,666			-		-			-			164,666
Proceeds from exercise of stock options		3,586			-		-			-			3,586
Transactions with affiliates		(369,865	)		-		389,447			(19,582	)		-
Net cash provided by (used in) financing activities	$	77,006		$	-	$	202,483		$	(38,082	)	$	241,407
Net increase (decrease) in cash and cash equivalents	$	73,308		$	-	$	555,728		$	(7,211	)	$	621,825
Cash and cash equivalents at beginning of period		13			-		47,141			7,211			54,365
Cash and cash equivalents at end of period	$	73,321		$	-	$	602,869		$	-		$	676,190

The Company may issue new registered debt securities (the “New Notes”) in the future that will be fully and unconditionally guaranteed, jointly and severally, on a senior or subordinated unsecured basis by the 2014 Notes Guarantor Subsidiaries and the 2014 Notes Issuer (collectively, the “New Notes Guarantor Subsidiaries”).

Presented below are condensed consolidating financial statements as of December 31, 2010 and December 31, 2009 and for the years ended December 31, 2010, 2009 and 2008, respectively, based on the guarantor structure that would be in place in the event the Company issues New Notes in the future. As the Foundation Merger is treated as a “reverse acquisition” and Old Alpha is treated as the accounting acquirer, Old Alpha’s historical financial statements became the historical financial statements of the Company for comparative purposes. As a result, “Parent” in the tables below refers to Old Alpha in reference to dates prior to the Foundation Merger and to the Company in reference to dates following the Foundation Merger, and refers to the Company as the issuer of any New Notes that may be issued in the future; and information for “New Notes Guarantor Subsidiaries” prior to the Foundation Merger includes only those New Notes Guarantor Subsidiaries that were subsidiaries of Old Alpha prior to the Foundation Merger. "Non-Guarantor Subsidiary" refers, for the tables below dated as of and for the periods ended December 31, 2010, to ANR Receivables Funding LLC, a wholly-owned indirect subsidiary of the Company formed on March 25, 2009 in connection with the A/R Facility, that was not and would not be a guarantor of the New Notes. Separate consolidated financial statements and other disclosures concerning the New Notes Guarantor Subsidiaries are not presented because management believes that such information would not be material to holders of any New Notes or related guarantees that may be issued by the Company.

146

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Balance Sheet

December 31, 2010

	Parent (Issuer)		New Notes Guarantor Subsidiaries		Non-Guarantor Subsidiary		Eliminations			Total Consolidated
Assets
Current assets:
Cash and cash equivalents	$	20,331	$	534,441	$	-	$	-		$	554,772
Trade accounts receivable, net		-		18,432		262,706		-			281,138
Inventories, net		-		198,172		-		-			198,172
Prepaid expenses and other current assets		-		341,755		-		-			341,755
Total current assets		20,331		1,092,800		262,706		-			1,375,837
Property, equipment and mine development costs, net		-		1,131,987		-		-			1,131,987
Owned and leased mineral rights, net		-		1,884,169		-		-			1,884,169
Owned lands		-		98,727		-		-			98,727
Goodwill		-		382,440		-		-			382,440
Acquired coal supply agreements, net		-		162,397		-		-			162,397
Other non-current assets		5,167,187		5,297,944		4,705		(10,326,110	)		143,726
Total assets	$	5,187,518	$	10,050,464	$	267,411	$	(10,326,110	)	$	5,179,283
Liabilities and Stockholders' Equity
Current liabilities:
Current portion of long-term debt	$	-	$	11,839	$	-	$	-		$	11,839
Trade accounts payable		2,091		119,462		-		-			121,553
Accrued expenses and other current liabilities		1,423		312,305		26		-			313,754
Total current liabilities		3,514		443,606		26		-			447,146
Long-term debt		222,355		519,957		-		-			742,312
Pension and postretirement medical benefit obligations		-		719,355		-		-			719,355
Asset retirement obligations		-		209,987		-		-			209,987
Deferred income taxes		-		249,408		-		-			249,408
Other non-current liabilities		2,305,613		2,199,281		261,372		(4,611,227	)		155,039
Total liabilities		2,531,482		4,341,594		261,398		(4,611,227	)		2,523,247
Stockholders' Equity
Total stockholders' equity		2,656,036		5,708,870		6,013		(5,714,883	)		2,656,036
Total liabilities and stockholders' equity	$	5,187,518	$	10,050,464	$	267,411	$	(10,326,110	)	$	5,179,283

147

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Balance Sheet

December 31, 2009

	Parent (Issuer)		New Notes Guarantor Subsidiaries		Non-Guarantor Subsidiary		Eliminations			Total Consolidated
Assets
Current assets:
Cash and cash equivalents	$	69,410	$	396,459	$	-	$	-		$	465,869
Trade accounts receivable, net		-		18,541		214,090		-			232,631
Inventories, net		-		176,372		-		-			176,372
Prepaid expenses and other current assets		-		176,953		-		-			176,953
Total current assets		69,410		768,325		214,090		-			1,051,825
Property, equipment and mine development costs, net		-		1,082,446		-		-			1,082,446
Owned and leased mineral rights, net		-		1,958,855		-		-			1,958,855
Owned lands		-		91,262		-		-			91,262
Goodwill		-		382,440		-		-			382,440
Acquired coal supply agreements, net		-		396,491		-		-			396,491
Other non-current assets		4,121,982		4,219,484		49,472		(8,233,914	)		157,024
Total assets	$	4,191,392	$	8,899,303	$	263,562	$	(8,233,914	)	$	5,120,343
Liabilities and Stockholders' Equity
Current liabilities:
Current portion of long-term debt	$	-	$	33,500	$	-	$	-		$	33,500
Trade accounts payable		1,469		151,193		-		-			152,662
Accrued expenses and other current liabilities		1,423		271,769		68		-			273,260
Total current liabilities		2,892		456,462		68		-			459,422
Long-term debt		210,524		546,229		-		-			756,753
Pension and postretirement medical benefit obligations		-		682,991		-		-			682,991
Asset retirement obligations		-		190,724		-		-			190,724
Deferred income taxes		-		301,307		-		-			301,307
Other non-current liabilities		1,386,687		1,265,372		259,172		(2,773,374	)		137,857
Total liabilities		1,600,103		3,443,085		259,240		(2,773,374	)		2,529,054
Stockholders' Equity
Total stockholders' equity		2,591,289		5,456,218		4,322		(5,460,540	)		2,591,289
Total liabilities and stockholders' equity	$	4,191,392	$	8,899,303	$	263,562	$	(8,233,914	)	$	5,120,343

148

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Consolidating Statement of Operations

Year Ended December 31, 2010

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Total Consolidated
Revenues:
Coal revenues	$	-		$	3,497,847		$	-		$	-		$	3,497,847
Freight and handling revenues		-			332,559			-			-			332,559
Other revenues		-			78,066			8,684			-			86,750
Total revenues		-			3,908,472			8,684			-			3,917,156
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)		-			2,566,825			-			-			2,566,825
Freight and handling costs		-			332,559			-			-			332,559
Other expenses		-			65,498			-			-			65,498
Depreciation, depletion and amortization		-			370,895			-			-			370,895
Amortization of acquired coal supply agreements, net		-			226,793			-			-			226,793
Selling, general and administrative expenses
(exclusive of depreciation, depletion and amortization shown separately above)		-			177,979			2,996			-			180,975
Total costs and expenses		-			3,740,549			2,996			-			3,743,545
Income from operations		-			167,923			5,688			-			173,611
Other income (expense):
Interest expense		(19,570	)		(50,977	)		(2,916	)		-			(73,463	)
Interest income		-			3,458			-			-			3,458
Loss on early extinguishment of debt		-			(1,349	)		-			-			(1,349	)
Miscellaneous expense, net		-			(821	)		-			-			(821	)
Total other expense, net		(19,570	)		(49,689	)		(2,916	)		-			(72,175	)
Income (loss) from continuing operations before income taxes and equity in earnings of investments in Issuer and Guarantor Subsidiaries		(19,570	)		118,234			2,772			-			101,436
Income tax benefit (expense)		7,632			(10,769	)		(1,081	)		-			(4,218	)
Equity in earnings of investments in Issuer and Guarantor Subsidiaries		107,489			2,365			-			(109,854	)		-
Income (loss) from continuing operations		95,551			109,830			1,691			(109,854	)		97,218
Discontinued operations:
Loss from discontinued operations before income taxes		-			(2,719	)		-			-			(2,719	)
Income tax benefit		-			1,052			-			-			1,052
Loss from discontinued operations		-			(1,667	)		-			-			(1,667	)
Net income (loss)	$	95,551		$	108,163		$	1,691		$	(109,854	)	$	95,551
Less:  Net loss from discontinued operations attributable to noncontrolling interest		-			-			-			-			-
Net income attributable to Alpha Natural Resources, Inc.	$	95,551		$	108,163		$	1,691		$	(109,854	)	$	95,551

149

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Consolidating Statement of Operations

Year Ended December 31, 2009

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Total Consolidated
Revenues:
Coal revenues	$	-		$	2,210,629		$	-		$	-		$	2,210,629
Freight and handling revenues		-			189,874			-			-			189,874
Other revenues		-			91,135			3,869			-			95,004
Total revenues		-			2,491,638			3,869			-			2,495,507
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)		-			1,616,905			-			-			1,616,905
Freight and handling costs		-			189,874			-			-			189,874
Other expenses		-			21,016			-			-			21,016
Depreciation, depletion and amortization		-			252,395			-			-			252,395
Amortization of acquired coal supply agreements, net		-			127,608			-			-			127,608
Selling, general and administrative expenses
(exclusive of depreciation, depletion and amortization shown separately above)		78			169,236			1,100			-			170,414
Total costs and expenses		78			2,377,034			1,100			-			2,378,212
(Loss) Income from operations		(78	)		114,604			2,769			-			117,295
Other income (expense):
Interest expense		(18,758	)		(62,645	)		(1,422	)		-			(82,825	)
Interest income		-			1,769			-			-			1,769
Loss on early extinguishment of debt		-			(5,641	)		-			-			(5,641	)
Miscellaneous income, net		-			3,186			-			-			3,186
Total other expense, net		(18,758	)		(63,331	)		(1,422	)		-			(83,511	)
Income (loss) from continuing operations before income taxes and equity in earnings of investments in Issuer and Guarantor Subsidiaries		(18,836	)		51,273			1,347			-			33,784
Income tax benefit (expense)		7,346			26,202			(525	)		-			33,023
Equity in earnings of investments in Issuer and Guarantor Subsidiaries		69,495			32,534			-			(102,029	)		-
Income (loss) from continuing operations		58,005			110,009			822			(102,029	)		66,807
Discontinued operations:
Loss from discontinued operations before income taxes		-			(14,278	)		-			-			(14,278	)
Income tax benefit		-			5,476			-			-			5,476
Loss from discontinued operations		-			(8,802	)		-			-			(8,802	)
Net income (loss)	$	58,005		$	101,207		$	822		$	(102,029	)	$	58,005
Less:  Net loss from discontinued operations attributable to noncontrolling interest		-			-			-			-			-
Net income (loss) attributable to Alpha Natural Resources, Inc.	$	58,005		$	101,207		$	822		$	(102,029	)	$	58,005

150

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Consolidating Statement of Operations

Year Ended December 31, 2008

	Parent (Issuer)			New Notes Guarantor Subsidiaries			Non-Guarantor Subsidiary			Eliminations			Total Consolidated
Revenues:
Coal revenues	$	-		$	2,140,367		$	-		$	-		$	2,140,367
Freight and handling revenues		-			279,853			-			-			279,853
Other revenues		-			48,533			-			-			48,533
Total revenues		-			2,468,753			-			-			2,468,753
Costs and expenses:
Cost of coal sales (exclusive of items shown separately below)		-			1,627,960			-			-			1,627,960
Gain on sale of coal reserves		-			(12,936	)		-			-			(12,936	)
Freight and handling costs		-			279,853			-			-			279,853
Other expenses		-			91,461			-			-			91,461
Depreciation, depletion and amortization		-			164,969			-			-			164,969
Selling, general and administrative expenses
(exclusive of depreciation, depletion and amortization shown separately above)		-			71,923			-		��	-			71,923
Total costs and expenses		-			2,223,230			-			-			2,223,230
Income from operations		-			245,523			-			-			245,523
Other income (expense):
Interest expense		(13,295	)		(26,517	)		-			-			(39,812	)
Interest income		-			7,351			-			-			7,351
Loss on early extinguishment of debt		-			(14,702	)		-			-			(14,702	)
Gain on termination of Cliffs' merger, net		56,315			-			-			-			56,315
Miscellaneous income (expense), net		20			(3,854	)		-			-			(3,834	)
Total other income (expense), net		43,040			(37,722	)		-			-			5,318
Income from continuing operations before income taxes and equity in earnings of investments in Issuer and Guarantor Subsidiaries		43,040			207,801			-			-			250,841
Income tax expense		(16,786	)		(35,456	)		-			-			(52,242	)
Equity in earnings of investments in Issuer and Guarantor Subsidiaries		139,447			4,192			-			(143,639	)		-
Income (loss) from continuing operations		165,701			176,537			-			(143,639	)		198,599
Discontinued operations:
Loss from discontinued operations before income taxes		-			(19,600	)		(8,273	)		-			(27,873	)
Mine closure/asset impairment charges		-			(30,172	)		-			-			(30,172	)
Gain on sale of discontinued operations		-			-			13,622			-			13,622
Income tax benefit (expense)		-			12,682			(1,647	)		-			11,035
(Loss) income from discontinued operations		-			(37,090	)		3,702			-			(33,388	)
Net income (loss)	$	165,701		$	139,447		$	3,702		$	(143,639	)	$	165,211
Less:  Net loss from discontinued operations attributable to noncontrolling interest		-			-			(490	)		-			(490	)
Net income (loss) attributable to Alpha Natural Resources, Inc.	$	165,701		$	139,447		$	4,192		$	(143,639	)	$	165,701

151

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2010

				New Notes
	Parent			Guarantor			Non-Guarantor			Total
	(Issuer)			Subsidiaries			Subsidiary			Consolidated
Net cash (used in) provided by operating activities	$	(7,511	)	$	692,428		$	8,684		$	693,601
Investing activities:
Capital expenditures	$	-		$	(308,864	)	$	-		$	(308,864	)
Acquisition of mineral rights under federal lease		-			(36,108	)		-			(36,108	)
Purchase of equity-method investment		-			(5,000	)		-			(5,000	)
Purchases of marketable securities, net		-			(158,550	)		-			(158,550	)
Other, net		-			25			-			25
Net cash used in investing activities	$	-		$	(508,497	)	$	-		$	(508,497	)
Financing activities:
Principal repayments on long-term debt	$	-		$	(56,854	)	$	-		$	(56,854	)
Debt issuance costs		-			(8,594	)		-			(8,594	)
Excess tax benefit from stock-based awards		-			5,505			-			5,505
Common stock repurchases		(41,664	)		-			-			(41,664	)
Proceeds from exercise of stock options		5,521			-			-			5,521
Other, net		-			(115	)		-			(115	)
Transactions with affiliates		(5,425	)		14,109			(8,684	)		-
Net cash (used in) provided by financing activities	$	(41,568	)	$	(45,949	)	$	(8,684	)	$	(96,201	)
Net decrease in cash and cash equivalents	$	(49,079	)	$	137,982		$	-		$	88,903
Cash and cash equivalents at beginning of period		69,410			396,459			-			465,869
Cash and cash equivalents at end of period	$	20,331		$	534,441		$	-		$	554,772

152

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2009

				New Notes
	Parent			Guarantor			Non-Guarantor			Total
	(Issuer)			Subsidiaries			Subsidiary			Consolidated
Net cash (used in) provided by operating activities	$	(5,359	)	$	357,710		$	3,869		$	356,220
Investing activities:
Capital expenditures	$	-		$	(187,093	)	$	-		$	(187,093	)
Cash acquired from a merger		-			23,505			-			23,505
Proceeds from disposition of property and equipment		-			1,197			-			1,197
Purchases of marketable securities		-			(119,419	)		-			(119,419	)
Net cash used in investing activities	$	-		$	(281,810	)	$	-		$	(281,810	)
Financing activities:
Principal repayments of note payable	$	-		$	(18,288	)	$	-		$	(18,288	)
Principal repayments on long-term debt		-			(249,875	)		-			(249,875	)
Debt issuance costs		-			(11,253	)		(1,814	)		(13,067	)
Excess tax benefit from stock-based awards		-			434			-			434
Common stock repurchases		(8,874	)		-			-			(8,874	)
Proceeds from exercise of stock options		5,171			-			-			5,171
Other, net		-			(232	)		-			(232	)
Transactions with affiliates		5,151			(3,096	)		(2,055	)		-
Net cash provided by (used in) financing activities	$	1,448		$	(282,310	)	$	(3,869	)	$	(284,731	)
Net decrease in cash and cash equivalents	$	(3,911	)	$	(206,410	)	$	-		$	(210,321	)
Cash and cash equivalents at beginning of period		73,321			602,869			-			676,190
Cash and cash equivalents at end of period	$	69,410		$	396,459		$	-		$	465,869

153

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

Alpha Natural Resources, Inc. and Subsidiaries

Supplemental Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2008

				New Notes
	Parent			Guarantor			Non-Guarantor			Total
	(Issuer)			Subsidiaries			Subsidiary			Consolidated
Net cash (used in) provided by operating activities	$	(3,698	)	$	475,870		$	(14,129	)	$	458,043
Investing activities:
Capital expenditures	$	-		$	(137,751	)	$	-		$	(137,751	)
Proceeds from disposition of property and equipment		-			16,649			-			16,649
Proceeds from sale of discontinued operations		-			-			45,000			45,000
Proceeds from sale of investment in coal terminal		-			1,500			-			1,500
Investment in Dominion Terminal Facility		-			(2,824	)		-			(2,824	)
Other, net		-			(199	)		-			(199	)
Net cash (used in) provided by investing activities	$	-		$	(122,625	)	$	45,000		$	(77,625	)
Financing activities:
Proceeds from issuance of long-term debt	$	287,500		$	-		$	-		$	287,500
Payments of bank overdraft		-			(160	)		-			(160	)
Principal repayments of note payable		-			(595	)		-			(595	)
Principal repayments on long-term debt		-			(175,473	)		(18,500	)		(193,973	)
Debt issuance costs		(10,861	)		-			-			(10,861	)
Premium payment on early extinguishment of debt		-			(10,736	)		-			(10,736	)
Excess tax benefit from stock-based awards		1,980			-			-			1,980
Proceeds from issuance of common stock, net		164,666			-			-			164,666
Proceeds from exercise of stock options		3,586			-			-			3,586
Transactions with affiliates		(369,865	)		389,447			(19,582	)		-
Net cash provided by (used in) financing activities	$	77,006		$	202,483		$	(38,082	)	$	241,407
Net increase (decrease) in cash and cash equivalents	$	73,308		$	555,728		$	(7,211	)	$	621,825
Cash and cash equivalents at beginning of period		13			47,141			7,211			54,365
Cash and cash equivalents at end of period	$	73,321		$	602,869		$	-		$	676,190

(23)     Discontinued Operations

Gallatin Materials, LLC

On September 26, 2008, the Company completed the sale of its interest in Gallatin for cash in the amount of $45,000 and recorded a gain on the sale of $13,622. The results of operations for prior periods have been reported as discontinued operations. Previously, the results of operations were reported in the All Other segment of Old Alpha.

154

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The following table reflects the activities for Gallatin’s discontinued operations for the year ended December 31, 2008:

	For The
	Year Ended
	December 31,
	2008
Total revenues	$	6,863
Total costs and expenses		(13,206	)
Interest income (expense)		(1,930	)
Gain on sale of discontinued operations		13,622
Income (loss) from operations	$	5,349
Income tax (expense) benefit from discontinued operations		(1,647	)
Noncontrolling interest in loss from discontinued operations		490
Income (loss) from discontinued operations	$	4,192

In connection with the sale of Gallatin on September 26, 2008, the noncontrolling interest holders contributed their interests in Gallatin in exchange for cash, thereby eliminating the noncontrolling interest.

Kingwood Mining Company, LLC

On December 3, 2008, the Company announced the permanent closure of Kingwood. The decision was a result of adverse geologic conditions and regulatory requirements that rendered the coal seam unmineable at this location. The mine stopped producing coal in early January 2009 and Kingwood ceased equipment recovery operations at the end of April 2009. Beginning in the first quarter of 2009, the results of operations for the current and prior periods have been reported as discontinued operations. 

The following table reflects the activities for Kingwood’s discontinued operations for the years ended December 31, 2010, 2009 and 2008:    

	For the Years Ended December 31,
	2010			2009			2008
Total revenues	$	17		$	3,496		$	88,710
Total costs and expenses		(2,736	)		(17,774	)		(138,486	)
Loss from operations		(2,719	)		(14,278	)		(49,776	)
Other expense		-			-			4
Income tax benefit from discontinued operations		1,052			5,476			12,682
Loss from discontinued operations	$	(1,667	)	$	(8,802	)	$	(37,090	)

155

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

The assets and liabilities of Kingwood Mining Company, LLC as of December 31, 2010 and 2009 are shown below:

	December 31,
	2010			2009
Property, plant, and equipment, net	$	340		$	1,636
Other assets		440			442
Assets of discontinued operations	$	780		$	2,078
Current liabilities	$	4,841		$	4,830
Noncurrent liabilities		9,255			10,166
Liabilities of discontinued operations	$	14,096		$	14,996
Net liability	$	(13,316	)	$	(12,918	)

(24)     Quarterly Financial Information (Unaudited)

	Year Ended December 31, 2010
		First		Second			Third			Fourth
		Quarter		Quarter			Quarter			Quarter
Total revenues from continuing operations		$	922,004		$	1,000,405		$	1,001,632		$	993,115
Income from continuing operations			14,670			39,182			32,361			11,005
Loss from discontinued operations attributable to Alpha Natural Resources, Inc.			(629)			(385)			(487)			(166)
Net income attributable to Alpha Natural Resources, Inc.			14,041			38,797			31,874			10,839
Basic earnings per share - income from continuing operations			0.12			0.33			0.27			0.09
Basic earnings per share - loss from discontinued operations			-			-			-			-
Diluted earnings per share - income from continuing operations			0.12			0.32			0.27			0.09
Diluted earnings per share - loss from discontinued operations			-			-			-			-
Basic earnings per share - net income			0.12			0.33			0.27			0.09
Diluted earnings per share - net income			0.12			0.32			0.27			0.09

	Year Ended December 31, 2009
		First		Second			Third			Fourth
		Quarter		Quarter			Quarter			Quarter (1)
Total revenues from continuing operations		$	485,959		$	387,015		$	729,246		$	893,287
Income (loss) from continuing operations			46,621			16,678			(16,740)			20,248
Income (loss) from discontinued operations attributable to Alpha Natural Resources, Inc.			(5,657)			(1,319)			475			(2,301)
Net income (loss) attributable to Alpha Natural Resources, Inc.			40,964			15,359			(16,265)			17,947
Basic earnings per share - income (loss) from continuing operations			0.67			0.24			(0.16)			0.17
Basic earnings per share - loss from discontinued operations			(0.08)			(0.02)			-			(0.02)
Diluted earnings per share - income (loss) from continuing operations			0.66			0.24			(0.16)			0.17
Diluted earnings per share - loss from discontinued operations			(0.08)			(0.02)			-			(0.02)
Basic earnings per share - net income (loss)			0.59			0.22			(0.16)			0.15
Basic earnings per share - net income (loss)			0.58			0.22			(0.16)			0.15

(1) Total revenue from continuing operations in the fourth quarter of 2009 includes a gain of $18,100 related to the modification of a coal supply agreement.

156

ALPHA NATURAL RESOURCES, INC. AND SUBSIDIARIES

NOTES to CONSOLIDATED FINANCIAL STATEMENTS

(Dollars in thousands, except share and per share data)

(Continued)

(25)     Subsequent Events

On January 28, 2011, the Company and its wholly owned subsidiary Mountain Merger Sub, Inc. (“Merger Sub”) entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Massey Energy Company (“Massey”) providing for the acquisition of Massey by the Company. Subject to the terms and conditions of the Merger Agreement, which has been approved by the boards of directors of the respective parties, Merger Sub will be merged with and into Massey (the “Massey Merger”), with Massey surviving the merger as a wholly owned subsidiary of Alpha. Under the terms of the Merger Agreement, Massey stockholders will receive, upon the consummation of the Massey Merger, 1.025 shares of Alpha common stock and $10.00 in cash for each share of Massey common stock. The consummation of the Massey Merger is subject to certain conditions, including (i) the adoption by the Massey stockholders of the Massey Merger Agreement and (ii) the approval by the Alpha stockholders of (x) an amendment to Alpha’s certificate of incorporation to increase the number of shares of Alpha common stock that Alpha is authorized to issue in order to permit issuance of the Alpha common stock in connection with the Massey Merger and (y) the issuance of Alpha common stock in connection with the Massey Merger. In addition, the Massey Merger is subject to clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and certain foreign antitrust laws, as well as other customary closing conditions. The Merger Agreement provides for customary breakage fees under certain circumstances in the event the merger is not consummated.

157

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

None.

Item 9A. Controls and Procedures

Evaluation of disclosure controls and procedures.

Our Disclosure Committee has responsibility for ensuring that there is an adequate and effective process for establishing, maintaining and evaluating disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in our SEC reports is timely recorded, processed, summarized and reported. In addition, we have established a Code of Business Ethics designed to provide a statement of the values and ethical standards to which we require our employees and directors to adhere. The Code of Business Ethics provides the framework for maintaining the highest possible standards of professional conduct. We also maintain an ethics hotline for employees. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we evaluated the effectiveness of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, as of the end of the period covered by this report, in ensuring that material information relating to Alpha Natural Resources, Inc., required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934, is recorded, processed, summarized and reported within the requisite time periods and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure.  

Changes in internal controls over financial reporting

There were no changes that occurred during the fourth quarter of the fiscal year covered by this Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Management's Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

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

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

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on management’s assessment and those criteria, management has concluded that the Company maintained effective internal control over financial reporting as of December 31, 2010.

158

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

Alpha Natural Resources, Inc.:

We have audited Alpha Natural Resources, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Alpha Natural Resources, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2010, and our report dated February 25, 2011 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Roanoke, Virginia

February 25, 2011

159

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The sections of our Proxy Statement entitled “Proposal 1—Election of Directors—Nominees for Directors,” “Corporate Governance And Related Matters—Director Independence,” “Corporate Governance And Related Matters—Board and its Committees,” “Corporate Governance And Related Matters—Audit Committee,” “Executive Officers,” “Section 16(a) Beneficial Ownership Reporting Compliance,” and “Corporate Governance And Related Matters—Code of Business Ethics” are incorporated herein by reference.

The Company has a written Code of Business Ethics that applies to the Company’s Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer) and others. The Code of Business Ethics is available on the Company’s website at www.alphanr.com. Any amendments to, or waivers from, a provision of our Code of Business Ethics that applies to our Principal Executive Officer, Principal Financial Officer or persons performing similar functions and that relates to any element of the code of ethics enumerated in paragraph (b) of Item 406 of Regulation S-K shall be disclosed by posting such information on our website.

Item 11. Executive Compensation

The sections of our Proxy Statement entitled “Corporate Governance and Related Matters—Director Compensation in 2010,” “Corporate Governance And Related Matters—Additional Information Regarding Our Director Compensation Table,” “Compensation Committee Interlocks and Insider Participation,” “Executive Compensation—Summary Compensation Table,” “Executive Compensation—Grants of Plan Based Awards in 2010,” “ Executive Compensation— Additional Information Regarding Our Summary Compensation Table and Grants of Plan Based Awards Table”, “Executive Compensation—Outstanding Equity Awards at 2010 Fiscal Year-End,” “Executive Compensation—Compensation Discussion and Analysis,” “Executive Compensation— Compensation Committee Report,” “Executive Compensation—Option Exercises and Stock Vested in 2010,” “Executive Compensation—Additional Information Regarding Our Pension Benefits Table,” “Nonqualified Deferred Compensation in 2010,” “Additional Information Regarding Our Nonqualified Deferred Compensation Plan,” “Executive Compensation —Potential Payments Upon Termination or Change in Control,” “Executive Compensation—Additional Information Regarding the Tables Relating to Potential Payments Upon Employment Termination or Change in Control,” “Executive Compensation —Pension Benefits in 2010,” are incorporated herein by reference.

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

The sections of our Proxy Statement entitled “Security Ownership of Certain Beneficial Owners and Management” and “Executive Compensation— Equity Compensation Plan Information” are incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions and Director Independence

The sections of our Proxy Statement entitled “Corporate Governance and Related Matters—Director Independence” and “Policy With Respect To Related Person Transactions” are incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

The section of our Proxy Statement entitled “Fees of Independent Registered Public Accounting Firm” and “Policy for Approval of Audit and Permitted Non-audit Services” are incorporated herein by reference.

Additional Information

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (“SEC”). You may access and read our SEC filings through our website, at www.alphanr.com, or the SEC’s website, at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. You may also request copies of our filings, at no cost, by telephone at (276) 619-4410 or by mail at: Alpha Natural Resources, Inc., One Alpha Place, P.O. Box 2345, Abingdon, Virginia 24212, attention: Investor Relations.

160

Our Audit Committee Charter, Compensation Committee Charter, Nominating and Corporate Governance Committee Charter, Corporate Governance Practices and Policies, and Code of Business Ethics are also available on our website and available in print to any stockholder who requests them.

PART IV

Item 15. Exhibits and Financial Statement Schedules

Pursuant to the rules and regulations of the Securities and Exchange Commission, the Company has filed certain agreements as exhibits to this Annual Report on Form 10-K. These agreements may contain representations and warranties by the parties. These warranties have been made solely for the benefit of the other party or parties to such agreements and (i) may been qualified by disclosure made to such other party or parties, (ii) were made only as of the date of such agreements or such other date(s) as may be specified in such agreements and are subject to more recent developments, which may not be fully reflected in such Company's public disclosure, (iii) may reflect the allocation of risk among the parties to such agreements and (iv) may apply materiality standards different from what may be viewed as material to investors. Accordingly, these representations and warranties may not describe the Company's actual state of affairs at the date hereof and should not be relied upon.

(a) Documents filed as part of this Annual Report on Form 10-K:

(1) The following financial statements are filed as part of this Annual Report on Form 10-K under Item 8-Financial Statements and Supplementary Data:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets, December 31, 2010 and 2009

Consolidated Statements of Operations, Years ended December 31, 2010, 2009 and 2008

Consolidated Statements of Stockholders' Equity and Comprehensive Income, Years ended December 31, 2010, 2009 and 2008

Consolidated Statements of Cash Flows, Years ended December 31, 2010, 2009 and 2008

Notes to Consolidated Financial Statements

(2) Financial Statement Schedules. All schedules are omitted because they are not required or because the information is immaterial or provided elsewhere in the Consolidated Financial Statements and Notes thereto.

(3) Listing of Exhibits. See Exhibit Index following the signature page of this Annual Report on Form 10-K.

161

SIGNATURES

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

ALPHA NATURAL RESOURCES, INC.
By:	/s/    Frank J. Wood
Name:	Frank J. Wood
Title:	Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Date: February 25, 2011

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Frank J. Wood and Vaughn R. Groves, and each of them, his or her true and lawful attorneys-in-fact, each with full power of substitution, for him or her in any and all capacities, to sign any amendments to this Annual Report on Form 10-K and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, hereby ratifying and confirming all that each of said attorneys-in-fact or their substitute or substitutes may do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Date	Title
/s/    Kevin S. Crutchfield	February 25, 2011	Chief Executive Officer (Principal Executive Officer) and Director
Kevin S. Crutchfield
/s/    Frank J. Wood	February 25, 2011	Executive Vice President and Chief Financial Officer,
Frank J. Wood		(Principal Financial and Accounting Officer)
/s/    Michael J. Quillen	February 25, 2011	Chairman of the Board of Directors
Michael J. Quillen
/s/    William J. Crowley, Jr.	February 25, 2011	Director
William J. Crowley, Jr.
/s/     E. Linn Draper, Jr.	February 25, 2011	Director
E. Linn Draper, Jr.
/s/    Glenn A. Eisenberg	February 25, 2011	Director
Glenn A. Eisenberg
/s/    P. Michael Giftos	February 25, 2011	Director
P. Michael Giftos
/s/    Joel Richards, III	February 25, 2011	Director
Joel Richards, III
/s/    James F. Roberts	February 25, 2011	Director
James F. Roberts
/s/    Ted G. Wood	February 25, 2011	Director
Ted G. Wood

162

10-K EXHIBIT INDEX

Exhibit No.	Description of Exhibit
2.1	Agreement and Plan of Merger, dated as of May 11, 2009, by and among Alpha Natural Resources, Inc. and Foundation Coal Holdings, Inc. (Incorporated by reference to Exhibit 2.1 of the Current Report on Form 8-K of Alpha Natural Resources, Inc., (File No. 1-32331) filed on May 12, 2009.)
2.2	Acquisition Agreement dated as of September 23, 2005 among Alpha Natural Resources, LLC, Mate Creek Energy of W. Va., Inc., Virginia Energy Company, the unit holders of Powers Shop, LLC, and the shareholders of White Flame Energy, Inc., Twin Star Mining, Inc. and Nicewonder Contracting, Inc. (the “Acquisition Agreement”) (Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.3	Membership Unit Purchase Agreement dated as of September 23, 2005 among Premium Energy, LLC and the unitholders of Buchanan Energy Company, LLC (the “Membership Unit Purchase Agreement”) (Incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.4	Agreement and Plan of Merger dated as of September 23, 2005 among Alpha Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC, Premium Energy, Inc. and the shareholders of Premium Energy, Inc. (the “Premium Energy Shareholders”) (the “Merger Agreement”) (Incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.5	Indemnification Agreement dated as of September 23, 2005 among Alpha Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC, the other parties to the Acquisition Agreement, the Premium Energy Shareholders, and certain of the unit holders of Buchanan Energy Company, LLC (Incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.6	Letter Agreement dated of as September 23, 2005 among Alpha Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC and the other parties to the Acquisition Agreement, the Membership Unit Purchase Agreement and the Merger Agreement (Incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on September 26, 2005.)
2.7	Letter Agreement dated October 26, 2005 (the “Letter Agreement”) among Alpha Natural Resources, Inc., Alpha Natural Resources, LLC, Premium Energy, LLC, Premium Energy, Inc. and the Sellers Representative named therein amending certain provisions of (i) the Acquisition Agreement dated September 23, 2005, among certain parties to the Letter Agreement and certain other parties named therein, (ii) the Agreement and Plan of Merger dated September 23, 2005, among the parties to the Letter Agreement and certain other parties named therein and (iii) the Indemnification Agreement dated September 23, 2005, among the parties to the Letter Agreement and certain other parties named therein. (Incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Alpha Natural Resources, I nc. /Old (File No. 1-32423) filed on October 31, 2005.)
2.8	Assignment of Rights Under Certain Agreements executed as of October 26, 2005 among Alpha Natural Resources, LLC, Mate Creek Energy, LLC, Callaway Natural Resources, Inc., Premium Energy, LLC and Virginia Energy Company, LLC (Incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on October 31, 2005.)
3.1	Amended and Restated Certificate of Incorporation of Alpha Natural Resources, Inc. (Incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on August 5, 2009.)
3.2	Amended and Restated Bylaws of Alpha Natural Resources, Inc. (Incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 001-32331) filed on November 18, 2010.)
4.1	Form of certificate of Alpha Natural Resources, Inc. common stock (Incorporated by reference to Amendment No. 3 to the Registration Statement on Form S-1 of Alpha Natural Resources, Inc./Old (File No. 333-121002) filed on February 10, 2005.)
4.2	Indenture, dated as of April 7, 2008, between Alpha Natural Resources, Inc. (File No. 1-32423) and Union Bank of California, N.A., as Trustee (Incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on April 9, 2008.)
4.3	Supplemental Indenture No. 1 dated as of April 7, 2008, between Alpha Natural Resources, Inc. (File No. 1-32423) and Union Bank of California, N.A., as Trustee (Incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. /Old (File No. 1-32423) filed on April 9, 2008.)

163

10-K EXHIBIT INDEX – (Continued)

Exhibit No	Description of Exhibit
4.4	Form of 2.375% Convertible Senior Note due 2015 (Incorporated by reference to Exhibit 4.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old/ (File No. 1-32423) filed on April 9, 2008.)
4.5	Supplemental Indenture No. 2 dated as of July 31, 2009, between Alpha Natural Resources, Inc. and Union Bank of California, N.A., as Trustee (Incorporated by reference to Exhibit 4.4 of the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 5, 2009.)
4.6	Subordinated Indenture dated as of April 7, 2008, between Alpha Natural Resources, Inc. and Union Bank of California, N.A. as Trustee (Incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on April 9, 2008.)
4.7	Supplemental Indenture No. 1 dated as of July 31, 2009, between Alpha Natural Resources, Inc. and Union Bank, N.A., as Trustee (Incorporated by reference to Exhibit 4.6 the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 7, 2009).
4.8	Senior Notes Indenture dated as of July 30, 2004, among Foundation PA Coal Company (nka Foundation PA Coal Company, LLC), the Guarantors named therein and The Bank of New York, as Trustee, (Incorporated by reference to Exhibit 10.4 to the Registration Statement on Form S-1/A (File No. 333-118427) of Alpha Natural Resources, Inc. filed on December 7, 2004.)
4.9	Supplemental Indenture dated as of September 6, 2005 among Foundation Mining LP, a subsidiary of Foundation Coal Corporation, Foundation PA Coal Company, LLC and The Bank of New York, as Trustee (Incorporated by reference to Exhibit 10.12 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 14, 2005.)
4.10	Supplemental Indenture dated as of October 5, 2007 among Foundation PA Coal Terminal, LLC, a subsidiary of Foundation Coal Corporation, Foundation PA Coal Company, LLC and The Bank of New York, as Trustee (Incorporated by reference to Exhibit 4.3.2 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 9, 2007.)
4.11	Third Supplemental Indenture dated as of August 1, 2009 among Foundation PA Coal Company, LLC, Alpha Natural Resources, Inc., certain subsidiaries of Alpha Natural Resources, Inc. and The Bank of New York, as Trustee (Incorporated by reference to Exhibit 4.8 of the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 5, 2009.)
10.1	Second Amended and Restated Credit Agreement, dated as of July 30, 2004, as amended and restated as of July 7, 2006, as further amended effective July 31, 2009, and as further amended and restated as of April 15, 2010, by and among Alpha Natural Resources, Inc., Foundation PA Coal Company, LLC, Citicorp North America, Inc. as administrative agent and lender and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on April 16, 2010).
10.3	Credit Agreement dated as of October 26, 2005, among Alpha NR Holding, Inc., Alpha Natural Resources, LLC, the Lenders and Issuing Banks party thereto from time to time, Citicorp North America, Inc., as administrative agent and as collateral agent for the Lenders and Issuing Banks, UBS Securities LLC as syndication agent, the co-documentation agents party thereto, Citigroup Global Markets Inc. and UBS Securities LLC, as joint lead arrangers and joint book managers (the “Old Alpha Credit Agreement”) (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on October 31, 2005.)

164

10-K EXHIBIT INDEX – (Continued)

Exhibit No	Description of Exhibit
10.4	Guarantee and Collateral Agreement, dated as of October 26, 2005, made by each of the Grantors as defined therein, in favor of Citicorp North America, Inc., as administrative agent and as collateral agent for the banks and other financial institutions or entities from time to time parties to the Credit Agreement and the other Secured Parties, as defined therein (Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on October 31, 2005.)
10.5	Waiver and Consent, dated as of August 14, 2006, to the Old Alpha Credit Agreement (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on August 18, 2006.)
10.6	Amendment and Consent, dated as of December 22, 2006, to the Old Alpha Credit Agreement (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on December 29, 2006.)
10.7	Second Amendment and Consent, dated June 28, 2007, to the Old Alpha Credit Agreement, as amended (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on July 5, 2007.)
10.8	Third Amendment and Joinder Agreement, dated March 28, 2008, to the Old Alpha Credit Agreement, as amended (Incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on April 3, 2008.)
10.9	Fourth Amendment and Consent, dated March 31, 2008, to the Old Alpha Credit Agreement, as amended (Incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on April 3, 2008.)
10.10	Fifth Amendment and Consent, dated October 6, 2008, to the Old Alpha Credit Agreement, as amended (Incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on February 27, 2009.)
10.11†	Coal Mining Lease dated April 9, 2003, effective as of April 1, 2003, by and between CSTL LLC (subsequently renamed ACIN LLC) and Alpha Land and Reserves, LLC, as amended (the “ACIN Lease”) (Incorporated by reference to Exhibit 10.12 to Amendment No. 1 to the Registration Statement on Form S-1 of Alpha Natural Resources, Inc./Old (File No. 333-121002) filed on January 12, 2005.)
10.12	Two Partial Surrender Agreements and Fourth Amendment to Coal Mining Lease, each dated September 1, 2005, by and between ACIN LLC and Alpha Land and Reserves, LLC, amending the ACIN Lease (Incorporated by reference to Exhibit 10.17 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on March 28, 2006.)
10.13	Partial Surrender Agreement dated November 1, 2005, by and between ACIN LLC and Alpha Land and Reserves, LLC, amending the ACIN Lease (Incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on March 28, 2006.)
10.14	Amendment to Coal Mining Lease dated January 1, 2006, by and between ACIN LLC and Alpha Land and Reserves, LLC, amending the ACIN Lease (Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on May 12, 2006.)
10.15	Amended and Restated Agreement dated January 13, 2009, between ACIN LLC; Alpha Land and Reserves, LLC; Paramont Coal Company Virginia, LLC; and Virginia Electric and Power Company for mutual interests as to parties’ rights and obligations with regard to certain land (Incorporated by reference to Exhibit 10.19 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010)

165

10-K EXHIBIT INDEX – (Continued)

Exhibit No	Description of Exhibit
10.16	Federal Coal Lease WYW-0317682: Belle Ayr Mine (Incorporated by reference to Exhibit 10.14 to the Registration Statement on Form S-1 (File No. 333-118427) of Alpha Natural Resources, Inc. filed on August 20, 2004.)
10.17	Federal Coal Lease WYW-78629: Belle Ayr Mine (Incorporated by reference to Exhibit 10.15 to the Registration Statement on Form S-1 (File No. 333-118427) of Alpha Natural Resources, Inc. filed on August 20, 2004.)
10.18	Federal Coal Lease WYW-80954: Belle Ayr Mine (Incorporated by reference to Exhibit 10.16 to the Registration Statement on Form S-1 (File No. 333-118427) of Alpha Natural Resources, Inc. filed on August 20, 2004.)
10.19	Federal Coal Lease WYW-0313773: Eagle Butte Mine (Incorporated by reference to Exhibit 10.17 to the Registration Statement on Form S-1 (File No. 333-118427) of Alpha Natural Resources, Inc. filed on August 20, 2004.)
10.20	Federal Coal Lease WYW-78631: Eagle Butte Mine (Incorporated by reference to Exhibit 10.18 to the Registration Statement on Form S-1 (File No. 333-118427) of Alpha Natural Resources, Inc. filed on August 20, 2004.)
10.21	Federal Coal Lease WYW-124783: Eagle Butte Mine (Incorporated by reference to Exhibit 10.19 to the Registration Statement on Form S-1 (File No. 333-118427) of Alpha Natural Resources, Inc. filed on August 20, 2004.)
10.22	Federal Coal Lease WYW 1155132: Eagle Butte Mine, (Incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on May 9, 2008.)
10.23‡	Alpha Natural Resources, Inc. Annual Incentive Bonus (AIB) Plan (Restated as of November 20, 2007) (Incorporated by reference to Exhibit 10.16 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 29, 2008.)
10.24*‡	Alpha Operating Companies Rabbi Trust Agreement
10.25*‡	Alpha Natural Resources, Inc. 2008 Annual Incentive Bonus Plan (effective May 14, 2008, and last amended on November 16, 2010.)
10.26‡	Alpha Natural Resources, Inc. Annual Incentive Performance Plan (dated as of March 8, 2008) (Incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on May 29, 2008.)
10.27*‡	Non-Employee Director Compensatory Arrangements
10.28‡	Alpha Natural Resources, Inc. Key Employee Separation Plan (as Amended and Restated effective July 31, 2009) (Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.29‡	Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan, As Amended and Restated Effective January 1, 2011 (Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 5, 2010.)
10.30‡	Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan – Distribution Election Form, Retirement and SRP Account Balances (Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 5, 2010)
10.31‡	Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan – Distribution Election Form, In-Service Account Balances (Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 5, 2010)

166

10-K EXHIBIT INDEX – (Continued)

Exhibit No	Description of Exhibit
10.32‡	Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan – Other Compensation Deferral Agreement Form (Incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed November 5, 2010)
10.33‡	Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan – Annual Bonus Deferral Agreement Form (Incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed November 5, 2010)
10.34‡	Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan – Base Salary Deferral Agreement  Form (Incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed November 5, 2010)
10.35*‡	Amended and Restated Legacy Foundation Rabbi Trust Agreement
10.36‡	Alpha Natural Resources, Inc. and Subsidiaries Deferred Compensation Plan (Amended and Restated on November 8, 2007) (Incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 29, 2008.)
10.37‡	Alpha Natural Resources, Inc. Non-Employee Directors Deferred Compensation Plan (effective January 1, 2010.) (Incorporated by reference to Exhibit 10.33 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed March 1, 2010)
10.38‡	Alpha Natural Resources, Inc. Non-Employee Directors Deferred Compensation Plan Deferral Commitment and Beneficiary Designation Form (effective January 1, 2010.) (Incorporated by reference to Exhibit 10.34 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed March 1, 2010)
10.39‡	Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-8 (File No. 333-166959) filed on May 19, 2010.)
10.40‡	Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan Restricted Stock Unit Award Agreement for Employees (Grades 22-30) (Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 9, 2010.)
10.41‡	Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan Performance Share Unit Award Agreement for Employees (Grades 22-30) (Incorporated by reference to Exhibit 10.3 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 9, 2010.)
10.42‡	Alpha Natural Resources, Inc. 2010 Long-Term Incentive Plan Restricted Stock Unit Award Agreement for Non-Employee Directors (Incorporated by reference to Exhibit 10.4 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on August 9, 2010.)
10.43‡	Alpha Natural Resources, Inc. Amended and Restated 2004 Long-Term Incentive Plan (Restated as of November 8, 2007) (Incorporated by reference to Exhibit 10.17 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 29, 2008.)
10.44‡	Form of Grantee Stock Option Agreement under the Alpha Natural Resources, Inc. Amended and Restated  2004 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc./Old (File No. 1-32423) filed on August 9, 2007.)

167

10-K EXHIBIT INDEX – (Continued)

Exhibit No	Description of Exhibit
10.45‡	Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Restated as of May 14, 2008 and as further amended on November 18, 2009.) (Incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010)
10.46‡	Form of Grantee Stock Option Agreement under the 2005 Long-Term Incentive Plan (Amended and Restated as of November 8, 2007) (Incorporated by reference to Exhibit 10.21 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 29, 2008.)
10.47‡	Form of Restricted Stock Agreement for Non-Employee Directors under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Restated as of November 8, 2007) (Incorporated by reference to Exhibit 10.24 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 29, 2008.)
10.48‡	Form of Restricted Stock Unit Award Agreement for Non-Employee Directors under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.11 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.49‡	Form of Director Deferred Compensation Agreement under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Amended and Restated on December 12, 2008) (Incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.50‡	Form of Amendment to Director Deferred Compensation Agreement (Incorporated by reference to Exhibit 10.37 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.51‡	Form of Performance Share Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (For Employees) (Restated as of December 12, 2008) (Incorporated by reference to Exhibit 10.26 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.52‡	Form of Performance Share Unit Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (for awards effective after January 1, 2010.) (Incorporated by reference to Exhibit 10.44 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010)
10.53‡	Form of Restricted Stock Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Restated as of February 10, 2009) (Incorporated by reference to Exhibit 10.24 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.54‡	Form of Retention Plan Restricted Stock Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.41 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc./Old (File No. 001-32423) filed on February 27, 2009.)
10.55‡	Form of Retention Plan Restricted Stock Unit Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.17 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.56‡	Form of Restricted Stock Unit Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.18 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.57‡	Form of Restricted Stock Unit Award Agreement for Employees under the Alpha Natural Resources, Inc. 2005 Long-Term Incentive Plan (for awards effective after January 1, 2010.) (Incorporated by reference to Exhibit 10.49 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010)
10.58‡	Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (as amended and restated July 31, 2009 and further amended on November 18, 2009) (Incorporated by reference to Exhibit 10.50 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010)

168

10-K EXHIBIT INDEX – (Continued)

Exhibit No	Description of Exhibit
10.59‡	Award Agreement by and among Foundation Coal Holdings, Inc. and James F. Roberts (effective January 12, 2009) (Incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 14, 2009.)
10.60‡	Award Agreement by and among Foundation Coal Holdings, Inc. and Kurt D. Kost (effective January 12, 2009) (Incorporated by reference to Exhibit 99.2 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 14, 2009.)
10.61‡	Award Agreement by and among Foundation Coal Holdings, Inc. and Frank J. Wood (effective January 12, 2009) (Incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 14, 2009.)
10.62‡	Award Agreement by and among Foundation Coal Holdings, Inc. and James J. Bryja (effective January 12, 2009) (Incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 14, 2009.)
10.63‡	Award Agreement by and among Foundation Coal Holdings, Inc. and Michael R. Peelish (effective January 12, 2009) (Incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on May 7, 2009.)
10.64‡	Form of Executive Officer Non-Qualified Stock Option Agreement (Incorporated by reference to Exhibit 10.9 of the Form 10-Q of Foundation Coal Holdings, Inc. (File No. 001-32331) filed on November 14, 2005.)
10.65‡	Form of Amendment Number 1 to Executive Officer Non-Qualified Stock Option Agreement (Incorporated by reference to Exhibit 10.10 of the Form 10-Q of Foundation Coal Holdings, Inc. (File No. 001-32331) filed on November 14, 2005.)
10.66‡	Form of Rollover Nonqualified Stock Option Agreement under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 99.4 to the Registration Statement on Form S-8 (File No. 333-160937) of Alpha Natural Resources, Inc. filed on July 31, 2009.)
10.67‡	Form of Rollover Restricted Stock Unit Agreement under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 99.5 to the Registration Statement on S-8 (File No. 333-160937) of Alpha Natural Resources, Inc. filed on July 31, 2009.)
10.68‡	Form of Rollover Restricted Stock Unit Agreement under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 99.6 to the Registration Statement on S-8 (File No. 333-160937) of Alpha Natural Resources, Inc. filed on July 31, 2009.)
10.69‡	Form of Retention Plan Restricted Stock Unit Agreement for Employees under the Alpha Natural Resources, Inc. Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 10.23 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.70‡	Form of Restricted Stock Unit Award Agreement for Employees under the Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 10.24 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.71‡	Form of Restricted Stock Unit Award Agreement for Employees under the Amended and Restated 2004 Stock Incentive Plan (for awards effective after January 1, 2010.) (Incorporated by reference to Exhibit 10.63 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010)
10.72‡	Form of Independent Directors Initial Restricted Stock Unit Agreement under the Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on May 7, 2009.)

169

10-K EXHIBIT INDEX – (Continued)

Exhibit No	Description of Exhibit
10.73‡	Form of Independent Directors Annual Restricted Stock Unit Agreement under the Amended and Restated 2004 Stock Incentive Plan (Incorporated by reference to Exhibit 10.8 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on May 7, 2009.)
10.74‡	Form of Restricted Stock Unit Award Agreement for Non-Employee Directors under the Amended and Restated 2004 Stock Incentive Plan (for awards effective after July 31, 2009) (Incorporated by reference to Exhibit 10.25 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.75‡	Form of Performance Share Unit Award Agreement for Employees under the Amended and Restated 2004 Stock Incentive Plan. (Incorporated by reference to Exhibit 10.67 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010)
10.76‡	Foundation Coal Deferred Compensation Plan (effective January 1, 2009) (Incorporated by reference to Exhibit 10.68 to the Annual Report on Form 10-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on March 1, 2010)
10.77‡	Employment Agreement by and among Foundation Coal Corporation and James F. Roberts (effective January 1, 2009) (Incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 7, 2009.)
10.78‡	Employment Agreement by and among Foundation Coal Corporation and James J. Bryja (effective January 1, 2009) (Incorporated by reference to Exhibit 99.3 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 7, 2009.)
10.79‡	Employment Agreement by and among Foundation Coal Corporation and Frank J. Wood (effective January 1, 2009) (Incorporated by reference to Exhibit 99.4 to the Current Report on Form 8-K of Alpha Natural Resources, Inc. (File No. 1-32331) filed on January 7, 2009.)
10.80‡	Employment Agreement by and among Foundation Coal Corporation and Michael R. Peelish (effective January 1, 2009) (Incorporated by reference to Exhibit 10.5 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on May 7, 2009.)
10.81‡	Agreement by and between Alpha Natural Resources Services, LLC and Michael J. Quillen, dated as of July 31, 2009 (Incorporated by reference to Exhibit 10.27 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.82‡	Agreement by and between Foundation Coal Corporation and James F. Roberts, dated July 31, 2009 (Incorporated by reference to Exhibit 10.28 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.83‡	Third Amended and Restated Employment Agreement by and between Alpha Natural Resources Services, LLC and Kevin S. Crutchfield, dated as of July 31, 2009 (Incorporated by reference to Exhibit 10.29 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.84‡	First Amended and Restated Employment Agreement by and between Alpha Natural Resources, Inc. and Kurt D. Kost, dated as of August 1, 2009 (Incorporated by reference to Exhibit 10.30 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.85‡	Consent Agreement by and between Foundation Coal Corporation, Alpha Natural Resources, Inc. and Frank J. Wood (Incorporated by reference to Exhibit 10.31 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)

170

10-K EXHIBIT INDEX – (Continued)

Exhibit No	Description of Exhibit
10.86‡	Consent Agreement by and between Foundation Coal Corporation, Alpha Natural Resources, Inc. and James J. Bryja (Incorporated by reference to Exhibit 10.32 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.87‡	Key Employee Retention Letter from Alpha Natural Resources, Inc. with James J. Bryja (Incorporated by reference to Exhibit 10.34 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.88‡	Form of Indemnification Agreement by and between Alpha Natural Resources, Inc. and each of its current and future directors and officers (Incorporated by reference to Exhibit 10.37 to the Quarterly Report on Form 10-Q of Alpha Natural Resources, Inc. (File No. 1-32331) filed on November 10, 2009.)
10.89*‡	Alpha Service Companies Rabbi Trust Agreement.
12.1*	Computation of Ratio of Earnings to Fixed Charges.
12.2*	Computation of Other Ratios.
18.1*	Preferability letter from KPMG LLP regarding change in accounting principle.
21.1*	List of Subsidiaries.
23*	Consent of KPMG LLP.
31(a)*	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to §302 of the Sarbanes-Oxley Act of 2002.
31(b)*	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, as adopted pursuant to §302 of the Sarbanes-Oxley Act of 2002.
32(a)*	Certification Pursuant to 18 U.S.C. §1350, As Adopted Pursuant to §906 of the Sarbanes-Oxley Act of 2002.
32(b)*	Certification Pursuant to 18 U.S.C. §1350, As Adopted Pursuant to §906 of the Sarbanes-Oxley Act of 2002.
99.1*	Mine Safety and Health Administration Data

*	Filed herewith.
†	Confidential treatment has been granted with respect to portions of the exhibit. Confidential portions have been omitted from this public filing and have been filed separately with the Securities and Exchange Commission.
‡	Management contract of compensatory plan or arrangement

171